**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

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FORM 10-K

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

**Forthe fiscal year ended December 31, 2004**

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

**forthe transition periodfrom                to                **

**CommissionFile No. 1-7792**

**Pogo Producing Company**

(Exact name of registrantas specified in its charter)

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

 

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Securities registered pursuantto Section 12(b) of the Act:

| Title of each class:                                                           | ** ** | **Name of each exchange on which registered:** |
|--------------------------------------------------------------------------------|------------|------------------------------------------------|
| **Common  Stock, $1 par value**                                                | ** ** | **New  York Stock Exchange  Pacific Exchange** |
| **Preferred Stock Purchase Rights**                                            | ** ** | **New York Stock Exchange**                    |
| Securities  registered pursuant to Section 12(g) of the Act:**None** |

 

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

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment to this Form 10-K.x

Indicate by check markwhether the registrant is an accelerated filer (as defined in Rule 12b-2of the Act). Yes x     Noo

The aggregate market valueof the Common Stock held by non-affiliates of the registrant (treating allexecutive officers and directors of the registrant, for this purpose, as ifthey may be affiliates of the registrant) was approximately $3,200,000,000 asof June 30, 2004 (based on $49.40 per share, the last saleprice of the Common Stock as reported on the New York Stock Exchange CompositeTape on such date).

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

**DOCUMENTINCORPORATED BY REFERENCE**

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

 

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**FORWARD LOOKINGSTATEMENTS**

The statements included or incorporated by referencein this Annual Report on Form 10-K for the year ended December 31,2004 (this “Annual Report”) include “forward-looking statements” within themeaning of Section 27A of the Securities Act of 1933, as amended, and Section 21Eof the Securities 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 the Company’sforward-looking statements 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” regarding the Company’s anticipated future financialposition and cash requirements. Although the Company believes that theexpectations reflected in these forward-looking statements are reasonable, itcan give no assurance that such expectations will prove to have been correct.Important factors that could cause actual results to differ materially from theCompany’s expectations (“Cautionary Statements”) are disclosed in this AnnualReport and in other filings by the Company with the Securities and ExchangeCommission (the “Commission”). All subsequent written and oral forward-lookingstatements attributable to the Company or persons acting on its behalf areexpressly qualified in their entirety by the Cautionary Statements. The Company’sactual results could differ materially from those anticipated in theseforward-looking statements as a result of the risk factors set forth below andother factors set forth in or incorporated by reference in this Annual Report.These factors include:

·       thecyclical nature of the oil and natural gas industries

·       theCompany’s ability to successfully and profitably find, produce and market oiland gas

·       uncertaintiesassociated with the United States and worldwide economies

·       currentand potential governmental regulatory actions in countries where the Companyoperates

·       substantialcompetition from larger companies

·       theCompany’s ability to implement cost reductions

·       theCompany’s ability to acquire additional oil and gas reserves

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

·       fluctuationsin foreign 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 abilityto control or predict. Management cautions against putting undue reliance onforward-looking statements or projecting any future results based on suchstatements or present or prior earnings levels.

All subsequent written andoral forward-looking statements attributable to the Company and persons actingon the Company’s behalf are qualified in their entirety by the CautionaryStatements contained in this section and elsewhere in this Annual Report.

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**CERTAIN DEFINITIONS**

As used in this AnnualReport, “Mcf” means thousand cubic feet, “MMcf” means million cubic feet, “Bcf”means billion cubic feet, “Bbl” means barrel, “MBbls” means thousand barrelsand “MMBbls” means million barrels. “BOE” means barrel of oil equivalent, “Mcfe”means thousand cubic feet of natural gas equivalent, “MMcfe” means millioncubic feet of natural gas equivalent and “Bcfe” means billion cubic feet ofnatural gas equivalent. Natural gas equivalents and crude oil equivalents aredetermined using the ratio of six Mcf of natural gas to one Bbl of crude oil,condensate or natural gas liquids (“NGL”). References to “$” and “dollars”refer to United States dollars. All estimates of reserves and information related to productioncontained in this Annual Report, unless otherwise noted, are reported on a “net”basis. Information regardingacreage and numbers of wells are set forth on a gross basis, unless otherwisenoted.

**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, New Zealand and in Hungary. As of December 31,2004, the Company had interests in 91 lease blocks offshore Louisiana andTexas, approximately 705,000 gross acres onshore in the United States,approximately 588,000 gross acres offshore in the Kingdom of Thailand,approximately 778,000 gross acres in Hungary, and approximately 1,044,000 grossacres in New Zealand.

The Company organizes itsexploration and production activities principally into five operating regionsand a New Ventures Group. The operating regions are its Gulf of Mexico region,which is responsible for the Company’s operations offshore Texas and Louisianain the Gulf of Mexico; its Western U.S. region, which is active in the PermianBasin area in New Mexico and West Texas, the Panhandle of Texas, the San JuanBasin in New Mexico and in the Madden Field in Wyoming; its Gulf Coast region,which includes the Company’s onshore operations principally in South Texas andLouisiana; the Asia and Pacific region, which has responsibility for theCompany’s operations on its Block B8/32 Concession in the Kingdom of Thailand(the “Thailand Concession”) and in New Zealand; and its Europe region, whichcurrently oversees activity principally in Hungary. The Company’s New VenturesGroup is primarily responsible for identifying new projects and opportunitiesfor the Company outside the United States.

**Domestic OffshoreOperations**

*Gulf ofMexico Region.  *Approximately 18% of the Company’sproved reserves as of December 31, 2004 were located in the Gulf ofMexico. During 2004, approximately 18% of the Company’s natural gas productionand 44% of its oil and condensate production came from the Company’s domesticoffshore properties, contributing approximately 33% of the Company’sconsolidated oil and gas revenues. The Company’s exploration and developmentefforts in this region are primarily focused in the shallower waters of thecontinental shelf.

*Exploration andDevelopment*

The scope of exploration and development programsrelating to the Company’s domestic offshore interests is affected by prices foroil and gas, and by federal, state and local legislation, regulations andordinances applicable to the petroleum industry. The Company’s domesticoffshore capital and exploration expenditures for 2004 were approximately $150,300,000, or 148%higher than the Company’s domestic offshore capital and explorationexpenditures of approximately $60,500,000 for 2003, and 15%higher than the Company’s domestic offshore capital and explorationexpenditures of approximately $130,265,000 for 

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

The Company maintains a significant presence in theGulf of Mexico where it participated in drilling 12 wells during 2004, 83% ofwhich were considered successful. At December 31, 2004, the Company heldvarying interests in 175 producing oil and gas wells in the Gulf of Mexico.

Leases acquired by the Company and other participantsin its bidding groups are customarily committed, on a block-by-block basis, toseparate operating agreements under which the appointed operator supervisesexploration and development operations for the account and at the expense ofthe group. These agreements usually contain terms and conditions that havebecome relatively standardized in the industry. Major decisions regardingdevelopment and operations typically require the consent of at least a majority(in working interest) of the participants. Because the Company generally has ameaningful working interest position, the Company believes it can significantlyinfluence (but not always control) decisions regarding development andoperations on most of the leases in which it has a working interest, eventhough it may not be the operator of a particular lease. The Company is theoperator on all or a portion of 59 of the 91 offshore leases in which it had aninterest as of December 31, 2004.

Platforms and relatedfacilities are installed on an offshore lease block when, in the judgment ofthe lease interest owners, the necessary capital expenditures are justified. Adecision to install a platform generally is made after the drilling of one ormore exploratory wells with contracted drilling equipment. Platform costs varydepending on, among other factors, the number of well slots, water depth,currents, and sea floor conditions.

*Lease Acquisitions*

The Company has participated, either on its own orwith other companies, in bidding on and acquiring interests in federal andstate leases offshore in the Gulf of Mexico since 1970. As a result of suchpurchases and subsequent activities, as of December 31, 2004, the Companyowned interests in 78 federal leases and 13 state leases offshore Louisiana andTexas. Federal leases generally have primary terms of five, eight or ten years,depending on water depth, and state leases generally have terms of three orfive years, depending on location, in each case subject to extension bydevelopment and production operations.

As part of its strategy,the Company intends to continue an active lease evaluation program in the Gulfof Mexico in order to identify exploration and exploitation opportunities. TheCompany acquires leases through participation in federal and state lease sales,farmouts and by acquisition. For example, the Company acquired 14 offshoreleases at the lease sale conducted by the Minerals Management Service of theDepartment of the Interior (the “MMS”) on March 17, 2004. The Company alsomaintains an asset rationalization process through which it seeks to sell orfarmoutblocks that the Company believes have little or no remaining upside potential,or that face significant future expenditures that would likely result in a rateof return that does not meet the Company’s internal criteria. The extent towhich the Company participates in future bidding on federal or state offshorelease sales or otherwise acquires additional lease blocks will depend on theavailability of funds and its estimates of hydrocarbon deposits, operatingexpenses and future revenues that may reasonably be expected from availablelease blocks. Such estimates typically take into account, among other things,estimates of future hydrocarbon prices, federal regulations and taxationpolicies applicable to the petroleum industry. It is also the Company’sobjective to acquire 

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producingleasehold properties in areas where additional low-risk exploration anddevelopment drilling or improved production methods can provide attractiverates of return.

**Domestic OnshoreOperations**

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

*Exploration andDevelopment*

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

The Company generally conducts its onshore activitiesthrough joint ventures and other interest sharing arrangements with major andindependent oil companies. The Company and its subsidiaries operate many oftheir onshore properties using both independent contractors and field personnelthat are employed by the Company or its subsidiaries.

*Western U.S. Region.  *TheCompany’s Western U.S. region has actively explored inWest Texas and New Mexico for more than 25 years and, during this period, hasparticipated in the discovery or development of over 31 oil and gas fields. In2004, the Company participated in the drilling of 159 wells in these areas (97%of which were successfully completed). The Company believes that, during thepast decade, it has been one of the more active companies drilling for oil andnatural gas in the Permian Basin of West Texas and southeastern New Mexico.

During 2005, the Company plans to drill approximately84 wells in various known fields and exploratory prospects located in thePermian Basin and Texas Panhandle. Drilling objectives for these wells range invertical depth from 3,200 feet to 18,500 feet below the surface and targetnumerous formations, including, among others, the Brown Dolomite, Canyon,Delaware (Brushy Canyon), Bone Spring, Spraberry, Wolfcamp, Granite &Atoka Wash, and Pennsylvanian pay zones.

The Company’s Western U.S. regionalso actively participates in the exploration and development of the MaddenDeep Unit in central Wyoming, where the Company currently is credited withvarying working interests that average approximately 14.5% across the unitarea. Recent drilling activity in the Madden Deep Unit has focused on the LowerFort Union formation (where productive zones are historically found fromapproximately 5,500 feet to 9,500 feet below the surface). Additionally, a16,950-foot Cody test well has been drilled in this Unit and is currentlyawaiting completion.

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

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

*Gulf Coast Region.  *TheCompany’s Gulf Coast region is actively exploring for, acquiring and developingoil and gas reserves in the coastal onshore areas of Louisiana and Texas.During 2004, the Gulf Coast region participated in drilling 54 wells, 91% ofwhich were successfully completed.

The Company’s most active drilling in its Gulf Coastregion during 2004 drilling took place on its 65,000 gross acres of leaseholdin South Texas’ Webb and Zapata Counties. The Company has been developing gasreserves primarily in its Los Mogotes, Hundido and South Hundido Fields thatproduce from Asche, Charco and Lobo members of the Wilcox formation, found atdepths ranging from 7,000 to 14,000 feet below the surface. At its Los MogotesField, where its working interest averages 71%, the Company drilled 37 wells in2004. There were 62 locations identified to drill at Los Mogotes at thebeginning of 2005, and the Company has already successfully drilled six ofthose. A total of six wells were drilled in the Company’s 100%-owned SouthHundido Field in 2004 and one has already been drilled in 2005. A newexploratory well was recently completed successfully by the Company on theSouth Rosita Prospect in Duvall County, Texas. Additional exploratory anddevelopment drilling is planned for this prospect. The Company intends toactively explore in various portions of the Wilcox trend of Texas during 2005.

During 2004, the Companyparticipated in drilling several Miocene wells and several Oligocene wells inSouth Louisiana. In the Upper Texas Gulf Coast, the Company is activelyexploring the Woodbine Formation for new gas reserves in Polk and TylerCounties, Texas.

*PropertyAcquisitions*

In four transactions in2004, the Company acquired interests in producing properties located primarilyin Hidalgo and Lavaca Counties in the Texas Gulf Coast area, the San Juan Basinin New Mexico and in several counties in West Texas. In two additionaltransactions during 2004, the Company increased its working interest in theMyette Point Field from approximately 25% to 50%, and in the Thibodaux Fieldfrom approximately 48% to 60%.

**InternationalOperations**

The Company has conducted international explorationactivities since the late 1970s in numerous oil and gas areas throughout theworld. The Company currently holds licenses in the Kingdom of Thailand, Hungaryand New Zealand. The Company’s explorationists continue to evaluate otherinternational opportunities that are consistent with its exploration strategyand expertise.

Substantial portions ofthe Company’s international operations are grouped under its wholly owned Dutchsubsidiary, Pogo Overseas Production B.V. Two subsidiaries of Pogo OverseasProduction B.V., Thaipo Limited (“Thaipo”) and Pogo Hungary Ltd. (“Pogo Hungary”),maintain offices in Bangkok, Thailand and in Budapest, Hungary, respectively.

*Thailand andHungary Disposition*

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

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*Exploration andDevelopment*

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

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

*Asia and PacificRegion*

The Company’s Thailand Concession consists ofapproximately 588,000 acres in the central portions of the Gulf of Thailand,about 250 miles south southeast of Bangkok in approximately 230 feet of water.The Company currently owns, directly or indirectly, a 46.34% working interestin the entire Thailand Concession. The remainder of the working interest isprimarily owned, directly or indirectly, by subsidiaries of ChevronTexacoCorporation, including Chevron Offshore (Thailand) Limited (“Chevron”), andPalang Sophon Limited (“Palang”). Chevron owns, directly and indirectly, a51.66% working interest in the Thailand Concession and is currently theoperator of the Thailand Concession. The remaining 2% working interest in theThailand Concession is owned by Palang Sophon Two Limited, a private entitycontrolled by members of the Sophonpanich family. Through voting procedures inthe joint operating agreement governing the Thailand Concession, and the closeworking relationship between Chevron’s and Thaipo’s exploration staff, Thaipoexerts substantial influence over the development of the Thailand Concession.As of December 31, 2004, the Company’s proved reserves located in theKingdom of Thailand accounted for approximately 19% of the Company’s totalproved reserves. During 2004, approximately 25% of the Company’s natural gasproduction and 35% of its oil and condensate production came from itsoperations on the Thailand Concession, contributing approximately 26% of theCompany’s consolidated oil and gas revenues.

*Benchamas Field.  *Aportion of the Thailand Concession comprising approximately 132,000 acres isdesignated as the Benchamas and Pakakrong production area and another portionis known as the Benchamas North production area. Collectively, these twoproduction areas are called the “Benchamas Field.” There are 14 productionplatforms installed in the Benchamas Field. An additional four platforms forthe Benchamas Field are currently under construction and expected to be setcommencing in late 2005. Natural gas and oil from these platforms are deliveredby undersea pipeline to a central processing and compression platform where theoil, condensate and natural gas is processed and separated. The natural gas issold to PTT Public Company Limited (“PTT”) and delivered into export pipelinesfor transportation to shore, while the crude oil and condensate produced fromthe field is stored on board a Floating Storage and Offloading system (“FSO”)known as the “Benchamas Explorer” for sale and ultimate transfer to shore byoil tanker. The FSO is moored in the Benchamas Field. Its capacity isapproximately 1,400,000 Bbls of crude oil and condensate. See “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—CrudeOil and Condensate—Production.” During 2004, 49 productive development wells,including one horizontal well, were drilled in the Benchamas Field. Inaddition, in early January 2005, an exploration well, the Benchamas 28,encountered 365 feet of pay confirming the need for 

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at least one additionalplatform there. For 2005, an active development drilling campaign is currentlyplanned in the field.

*Tantawan Field.  *Aportion of the Thailand Concession comprising approximately 68,000 acres isdesignated as the Tantawan production area or the “Tantawan Field.” Oil and gasproduction from the Tantawan Field is gathered through pipelines from theplatforms into a Floating Production Storage and Offloading system (an “FPSO”)named the “Tantawan Explorer.” The FPSO is a converted oil tanker with acapacity of slightly less than 1,000,000 Bbls, and is moored in the TantawanField, on which hydrocarbon processing, separation, dehydration, compression,metering and other production-related equipment is installed. Followingprocessing on board the FPSO, natural gas produced from the field is deliveredto PTT through an export pipeline. Oil and condensate produced from the fieldis stored on board the FPSO until sold and transferred to shore by oil tanker.See “Management’s Discussion and Analysis of Financial Condition and Results ofOperations—Crude Oil and Condensate—Production.” During 2004, 15 productivedevelopment wells were drilled in the field. Currently, there is productionfrom six platforms. During the fourth quarter of 2003, an additional 20,000acres, comprising the adjacent Block 9A, were assigned to Thaipo and its jointventure partners. Two successful exploration wells were promptly drilled andBlock 9A was designated a production area in 2004. It is planned to bedeveloped from and through existing Tantawan Field facilities. Current planscall for 2005 to be the most active development drilling program in the historyof the field, with over 30 wells currently planned from five platforms.

*Maliwan Field.  *Approximately91,000 acres of the Thailand Concession are designated as the Maliwanproduction area or the “Maliwan Field.” Eleven exploration wells have beendrilled to delineate this field. An additional exploration well is currentlyplanned for the latter half of 2005. In addition, seven production wells havebeen drilled from the first platform set in the field, the Maliwan “A”platform. Production from this platform is delivered to the central BenchamasField production handling facilities for processing and sale. Current planscall for an additional eight development wells to be drilled from this platformin 2005. In addition, a second platform should be set in this field late in2005. Final development plans for the remainder of the field are currentlybeing finalized with our partners with the intent of sanctioning this projectwithin the next several months.

*Jarmjuree Field.  *Approximately124,000 acres of the Thailand Concession, known as the “Jarmjuree Field,” aredesignated as a production area. The first platform in this field, the NorthJarmjuree “A” platform, was set in the second quarter of 2004 and 12development wells were successfully drilled there. Additional exploration anddevelopment drilling is currently expected to occur in 2005. Production fromthis platform is delivered to the central Benchamas Field production handlingfacilities for processing and sale. Development plans for the remainder of thefield are still being formulated in conjunction with the development plans forthe Maliwan Field.

*Other Portions of the ThailandConcession.  *Thaipo and its joint venture partners haveidentified other potentially promising areas on the Thailand Concession andsurrounding acreage. During 2004, Thaipo and its joint venture partners drilledtwo exploratory wells and have currently budgeted to drill an additional fourexploratory wells during 2005. Two of these wells, the Benchamas 28 discussedearlier, and the Chaba 4 have already been drilled. Each of these two wellsencountered potentially commercial quantities of hydrocarbons. Two more wellsare planned for later this year. Interpretation of the data provided by thesewells and existing 3-D seismic and other data covering the ThailandConcession is ongoing.

Platforms are installed onthe Thailand Concession in fields where, in the judgment of Thaipo and itsjoint venture partners, the necessary capital expenditures are justified. Adecision to install a platform generally is made after the drilling of one ormore exploratory wells with contracted drilling equipment and the area wherethe platform would be located has been designated a production area by thegovernment of the Kingdom of Thailand. See “Contractual Terms Governing theThailand Concession and Related 

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Production.”Platforms are used to accommodate both development drilling and additionalexploratory drilling. A key focus of Thaipo and its joint venture partners hasbeen to reduce the average cost of the platforms installed to improve theoverall economics of the project. The gross cost of the first fourteenproduction platforms and related facilities installed in the Tantawan,Benchamas and Maliwan Fields averaged approximately $17,400,000 per platform.The gross cost of each of the five “third generation” platforms currently underconstruction is currently expected to average approximately $10,000,000 perplatform. Efforts are currently underway to design and construct even lessexpensive platforms. Platform costs vary, and more (or less) expensiveplatforms could be required in the future depending on, among other factors,the number of slots, water depth, ocean currents and sea floor conditions andthe amount of facilities required to be placed on the platform.

*Contractual TermsGoverning the Thailand Concession and Related Production*

The Thailand Concession was granted in August 1991.The initial exploratory term for the Thailand Concession expired on July 31,2000. However, through a series of one-year extensions, Thaipo and its jointventure partners have been granted an extension of the exploratory term throughJuly 31, 2005. No more extensions can be obtained. On July 31, 2005,all acreage for which production area status has not been granted or appliedfor will revert to the government of Thailand. Prior to that date, the Companyand its joint venture partners currently intend to apply for a production areadesignation for all remaining acreage in the Thailand Concession that has notalready been designated a production area. For those portions of the ThailandConcession that have been designated as production areas, the initialproduction period term is 20 years, which is also subject to extension,generally for a term of ten years. To date, the Benchamas Field (including theNorth Benchamas area), Tantawan Field (including Block 9A), Maliwan Field andJarmjuree Field have been designated as production areas. The earliest date atwhich any of these production areas could revert to the government is June 15,2017 (with respect to portions of the Tantawan Field).

Production resulting from the Thailand Concession isgenerally subject to a royalty ranging from 5% to 15% of oil and gas sales.Slightly different terms apply to production from Block 9A, but the differenceis not expected to be material to the results of operations of the Company.Profits from production in Thailand are also subject to a Special RemunerationBenefit (“SRB”). The SRB rate, which can range from 20% to 75%, is calculatedbased on a complex formula using discounted revenue, meters drilled and otherfactors specified in the Thailand Concession license agreement. This rate isthen applied toward the net proceeds derived by each joint venture partner’sThailand subsidiaries. SRB payments are then treated as a deductible expensefor Thailand income tax calculations by such subsidiaries. The Company madesignificant SRB payments during 2004 and expects to be obligated to payadditional SRB during 2005. See “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations—Results of Operations: Productionand Other Taxes.”

Thaipo and its joint venture partners have enteredinto a thirty-year Gas Sales Agreement with PTT (the “Gas Sales Agreement”),governing gas production from the Tantawan Field and the Benchamas Field. Theterms of the Gas Sales Agreement currently include a minimum daily contractquantity (“DCQ”) of 125 MMcf per day, subject to certain exceptions, and willin the future be based on a percentage of the remaining proved reserves, but inany event will not be less than 125 MMcf per day. In addition, the Gas SalesAgreement gives PTT the right to nominate in any given week 115% of DCQ orapproximately 145 MMcf per day. The Gas Sales Agreement provides that PTT maytake up to an additional approximate 177 billion cubic feet of gas through December 31,2007 at production rates that, until the end of such supplemental period (“SupplementalDCQ”), equates to 85 MMcf per day or approximately 40 MMcf net to the Company.During 2004, gas production averaged approximately 197 MMcf per day (80 MMcfper day net to the Company).

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Thaipo and its joint venture partners are subject topenalties if they are unable to meet the DCQ or the Supplemental DCQ under theGas Sales Agreement. Failure to meet DCQ results in a decrease in the salesprice for gas sold under the Gas Sales Agreement of up to 25% of thethen-current sales price and failure to meet the Supplemental DCQ will resultin a credit against the next month’s supplemental production of 12% (6% throughJanuary 1, 2006) of the then-current sales price of the gas not delivered.Thaipo currently meets the minimum DCQ, but due to facilities constraints andprocess-related issues, has recently been unable to meet all of itsSupplemental DCQ requirements. The price that the Company receives for its naturalgas under the Gas Sales Agreement reflects the Company’s underdelivery ofSupplemental DCQ. However, the reduction in revenue related penalty is notconsidered significant by the Company, amounting to a discount on delivered gas(net to the Company) of less than approximately $499,000 for all of 2004. Therecan be no assurance that Thaipo will be able to meet its DCQ and SupplementalDCQ obligations in the future, in which case these penalty provisions wouldreduce the price received by Thaipo for its gas sold to PTT under the Gas SalesAgreement.

The sales price for thebase DCQ production under the Gas Sales Agreement is subject to automaticsemi-annual adjustments based upon a formula that takes into account changesin: Singapore fuel oil prices; the U.S. Bureau of Labor Statistics OilfieldMachinery and Tool Index; the Thai wholesale producer price index; and theU.S./Thai currency exchange rate. However, the Gas Sales Agreement provides foradjustment on a more frequent basis in the event that certain indices andfactors on which the price is based fluctuate outside a given range. The salesprice for Supplemental DCQ production is 88% of the then-current sales pricefor DCQ production. As of December 31, 2004, the Company was receiving ablended average price of approximately $2.46 per Mcf under the Gas SalesAgreement for DCQ and Supplemental DCQ production. See “Management’s Discussionand Analysis of Financial Condition and Results of Operations—Results ofOperations” and “Liquidity and Capital Resources; Other Matters; Southeast AsiaEconomic Issues.”

*Other Areas of the World*

*Hungary.  *On April 20,1999, the Company’s subsidiary, Pogo Hungary, was awarded a license to explorefor oil and gas in the Szolnok and Tompa areas of central and south centralHungary. This license area currently consists of approximately 778,000 acres.The exploration term of the license is currently set to expire on April 20,2007. Areas where commercial accumulation of hydrocarbons are identified maythen be designated as “mining plots” and held through the economic productivelife of such reserves. One of the Company’s 3-D surveys coversapproximately 97,000 acres, a substantial portion of the Tompa area, and theother covers approximately 42,000 acres of the Szolnok area and is referred toas the Kenderes 3-D survey. During its drilling program that commenced in2003, Pogo Hungary has drilled nine wells, seven of which were eithertemporarily or permanently abandoned.

*North Sea.  *OnAugust 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. One well was drilled during2004 pursuant to this license, which has been abandoned. This license interestwas held by the Company’s Danish subsidiary, Pogo Denmark ApS, and expired on September 14,2004.

During 2003, Pogo North Sea Limited, a Britishsubsidiary of the Company, together with two joint venture partners, held alicense governing approximately 113,000 acres in the British sector of theNorth Sea. The joint venture relinquished its interest in the license area backto the Department of Trade and Industry on December 23, 2003.

*NewZealand.  *During 2004, the Company was granted threepetroleum exploration licenses over approximately 1,044,000 acres in theoffshore Northern Taranaki Basin. The primary exploration term of theselicenses is for five years, subject to extension for up to an additional tenyears, provided that at least 

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half of the acreageunder each license has been relinquished and the permit holder hassubstantially complied with the terms of its permits. The Company has committedto acquire 3-D seismic data over at least 1,000 square kilometers of thelicenses within the first two years of their primary term and to reprocess 433miles of existing 2-D seismic data. During 2004 and early 2005, theCompany exceeded its work obligations with respect to both 3-D dataacquisition and 2-D seismic data reprocessing. The 3-D seismic dataacquired by the Company is currently being processed and will then be analyzedlater this year with a goal of committing to drill multiple exploration wellsas early as the first half of 2006. The Company has a contingent commitment todrill one well on each of the three licenses by the end of 2007. Productionpermits of up to 40 years may be applied for if a commercial field isdiscovered.

**Geographic Information**

For financial informationabout geographic areas, see Note 6—Geographic Segment Information in the Notesto Consolidated Financial Statements, which is incorporated herein byreference.

**Miscellaneous**

*Other Assets*

The Company and asubsidiary, Pogo Offshore Pipeline Co., own interests in eight pipelines(excluding field gathering pipelines) through which offshore hydrocarbonproduction is transported. As previously discussed, the Company also owns anapproximate 15% interest in the Lost Cabin Gas Plant located in the MaddenField, which currently has the capacity to process 313 MMcf of natural gas perday.

*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. The Company’sdomestic onshore and offshore properties are generally located in areas where apipeline infrastructure or other transportation alternatives are well developedand there is adequate availability in such pipelines or other transportationalternatives to transport the Company’s current and projected futureproduction.

The Company may not be able to market successfully allof the oil and natural gas found and produced on the Thailand Concession.Currently, the only purchaser of natural gas is PTT, which maintains a monopolyover gas transmission and distribution in Thailand, including ownership of thetwo major natural gas pipelines (34 inches and 36 inches in diameter,respectively) that traverse the Thailand Concession. All oil and condensateproduction from the Tantawan Field is initially stored aboard the FPSO and thensold to various third parties, including PTT, on a tanker load by tanker loadbasis at prices based on then-current world oil prices, typically withreference to the Malaysian Tapis Blend crude oil benchmark price. Crude oil andcondensate production from the Benchamas Field and the first platforms locatedin the northern portion of the Maliwan Field and the Jarmjuree Field,respectively, are initially stored aboard the FSO. A portion of this productionis sold under a term sales agreement with Pacific Petroleum and Trading Co.,Ltd. that expires in August 2005. The remaining production from theBenchamas Field is sold on a tanker load by tanker load basis, similar to theway Tantawan Field crude oil is currently marketed.

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The prices that the Company receives for crude oilsales from its Thailand Concession are influenced by a number of factorsincluding, among others, tanker availability, world-wide crude oil demand, sizeof the lifting and the perceived quality of crude oil produced. For example,crude oil produced from the Gulf of Thailand is generally perceived as havinghigh mercury levels. The crude oil from the Benchamas Field has high waxcontent. Therefore, it is sought after by some refineries and is less desirableto others. 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 2004, the price that theCompany received for its crude oil production from the Thailand Concessionranged between a $1.50 per Bbl premium and a $1.65 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 further long-term contracts for aportion of its production. In addition, because much of the oil produced fromthe Thailand Concession is associated with natural gas, limitations on Thaipo’sability to produce natural gas could limit crude oil production as well. Thecrude oil purchaser is generally responsible for sending a tanker to offloadthe oil and condensate it has purchased. See “International Operations;Contractual Terms Governing the Thailand Concession and Related Production.”

Most of the Company’sNorth American natural gas sales 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”) and the crude oil contractsdiscussed above, the Company has no existing contracts that require thedelivery of fixed quantities of oil or natural gas, other than on a bestefforts basis. In 2004, crude oil sales to two customers (Pacific Petroleum andTrading Co., Ltd. and Shell Trading Company) constituted more than 10% of theCompany’s consolidated revenues.

*Risks Associatedwith Acquisitions*

From time to time the Company acquires additionalinterests in oil and gas properties, either through acquisition of theproperties themselves or, indirectly through the purchase of an equity interestin the entity owning such properties. The successful acquisition of suchproperties requires an assessment of several factors, including recoverablereserves, development and exploratory potential, projected future cash flowsthat are, in part, based upon future oil and gas prices, current and projectedoperating, general and administrative and other costs, and contingentliabilities associated with the properties or entities acquired, includingpotential environmental and other liabilities.

The accuracy of theCompany’s assessment of these factors is inherently uncertain. To the extentreasonably practicable under the specific circumstances of each acquisition,the Company performs a review of the properties or entities prior to anacquisition. The Company believes that its review procedures are generallyconsistent with current industry practices. The Company’s review and assessmentprocess will not reveal all existing or potential problems nor will it permitthe Company to become sufficiently familiar with the properties or entities tofully assess their deficiencies and capabilities. Even when problems areidentified, the other party may be unwilling or unable to provide effectivecontractual protection against all or part of the problems. Occasionally, theCompany may not be entitled to contractual indemnification for certainliabilities, acquiring the properties on an “as is, where is” basis. Inaddition, successful acquisitions frequently require the successful integrationof operations, equipment and 

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personnel.There can be no assurance that the Company will be able to successfullyintegrate operations and properties that it acquires and still achieve theanticipated synergies, cost savings and efficiencies.

*Competitionand Market Conditions*

The Company experiences competition from other oil andgas companies in all phases of its operations, as well as competition fromother energy-related industries. The Company’s profitability and cash flow arehighly dependent upon the prices of oil and natural gas, which historicallyhave been seasonal, cyclical and volatile. In general, prices of oil and gasare dependent upon numerous factors beyond the control of the Company,including various weather, economic, political and regulatory conditions. Inaddition, the decisions of the Organization of Petroleum Exporting Countriesrelating to export quotas also affect the price of crude oil. A future drop inoil or gas prices could have a material adverse effect on the Company’s cash flowand profitability. Sustained periods of low prices could cause the Company toshut in existing production and also have a material adverse effect on itsoperations and financial condition. It could also result in a reduction offunds available under the Company’s bank credit facilities. See “Management’sDiscussion and Analysis of Financial Condition and Results ofOperations—Liquidity and Capital Resources; Credit Facility.”

Because it is impossibleto predict future oil and gas price movements with any certainty, the Companyfrom time to time enters into contracts to hedge against future market pricechanges on a portion of its production. Such hedging transactions,historically, have never exceeded 50% of the Company’s total oil and gasproduction on an energy equivalent basis for any given period. While intendedto limit the negative effect of price declines, some forms of hedgingtransactions could effectively limit the Company’s participation in priceincreases, which could be significant, for the covered period. As of December 31,2004, the Company was a party to certain natural gas or crude oil optioncontracts (see “Management’s Discussion and Analysis of Financial Condition andResults of Operations—Current Hedging Activity”). When the Company does engagein certain types of hedging activities, it may satisfy its obligations with itsown production or by the purchase (or sale) of third-party production. TheCompany may also offset delivery obligations under these hedging transactionsrequiring physical delivery with equivalent agreements, thereby effecting apurely cash transaction.

*Operating and Uninsured Risks*

The Company’s operations are subject to risks inherentin the exploration for and production of oil and natural gas, such as blowouts,cratering, explosions, uncontrollable flows of oil, natural gas or well fluids,fires, pollution and other environmental risks. Offshore oil and gas 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 risk that no commercially productive hydrocarbon reserves will beencountered. The cost of drilling, completing and operating wells and ofinstalling production facilities and pipelines is often uncertain. The Company’sdrilling operations may be curtailed, delayed or canceled as a result ofnumerous factors, including title problems, weather conditions, compliance withgovernmental requirements and shortages or delays in the delivery oravailability of material, equipment and fabrication yards. In periods of increaseddrilling activity resulting from high commodity prices, demand exceedsavailability for drilling rigs, drilling vessels, supply boats and personnelexperienced in the oil and gas industry in general, and the offshore oil andgas industry in particular. For example, the Company is currently experiencingsome difficulty in obtaining additional drilling rigs for its Thailandoperations due to lack of suitable rigs in the region. This may lead todifficulty and delays in 

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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.

In periods during whichthe industry experiences a substantial decline in oil and gas prices, many ofthe Company’s partners, particularly the smaller ones, can experience liquidityand cash flow problems. These problems may lead to the smaller companies’ attemptsto delay or slow down the pace of drilling or project development in order toconserve cash, to a point that the Company believes is detrimental to theproject. In most cases, the Company has the ability to influence the pace ofdevelopment through joint operating agreements. Some partners may be unwillingor unable to pay their share of the costs of projects as they become due. Atworst, a partner may declare bankruptcy and refuse or be unable to pay itsshare of the costs of a project. The Company would then be required to pay thispartner’s share of the project costs. In most instances, the Company believesthat it is contractually protected from such an event through its ability totake over the non-paying partner’s share of the project and by applicable oiland gas lien laws and bankruptcy laws. The Company believes that it wouldultimately recover any sums that it is owed by non-paying partners that do notmeet their share of the costs of a project in a timely fashion.

*Risks of ForeignOperations*

Ownership of propertyinterests and production operations in Thailand, Hungary, New Zealand and inany other areas outside the United States in which the Company may choose to dobusiness are subject to the various risks inherent in foreign operations. Theserisks may include, among other things, currency restrictions and exchange ratefluctuations, loss of revenue, property and equipment as a result of hazardssuch as expropriation, nationalization, war, insurrection and other politicalrisks, risks of increases in taxes and governmental royalties, renegotiation ofcontracts with governmental entities, changes in laws and policies governingoperations of foreign-based companies and other uncertainties arising out offoreign government sovereignty over the Company’s international operations. See“Management’s Discussion and Analysis of Financial Condition and Results ofOperations,” and “Liquidity and Capital Resources; Other Matters; SoutheastAsia Economic Issues.” The Company’s international operations may also beadversely affected by laws and policies of the United States affecting foreigntrade, taxation and investment. In addition, in the event of a dispute arisingfrom foreign operations, the Company may be subject to the exclusivejurisdiction of foreign courts or may not be successful in subjecting foreignpersons to the jurisdiction of the courts of the United States. The Companyseeks to manage these risks by concentrating its international explorationefforts in areas where the Company believes that the existing government isstable and favorably disposed towards United States exploration and productioncompanies.

**Exploration andProduction Data**

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

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*Acreage*

TheCompany owns interests in developed and undeveloped oil and gas acreage invarious parts of the world. These ownership interests generally take the formof “working interests” in oil and gas leases that have varying terms. Thefollowing table shows the Company’s interest in developed and undeveloped oiland gas acreage under lease as of December 31, 2004:
| ** **              | ** ** | **Developed Acreage(a)** | ** ** | **Undeveloped Acreage(b)** | ** ** |
|-------------------------|------------|-------------------------------|------------|---------------------------------|------------|
| ** **              | ** ** | **Gross**                     | ** ** | **Net**                         | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Domestic Offshore       |       |                          |       |                            |       |   |   |   |   |
| Louisiana               |       | 138,374                       |       | 57,059                          |       | 184,155 |   | 160,706 |   |
| Texas                   |       | 17,280                        |       | 8,101                           |       | 5,760 |   | 1,152 |   |
| Total Domestic Offshore |       | 155,654                       |       | 65,160                          |       | 189,915 |   | 161,858 |   |
| Domestic Onshore        |       |                          |       |                            |       |   |   |   |   |
| Louisiana               |       | 15,570                        |       | 4,440                           |       | 8,286 |   | 4,802 |   |
| New Mexico              |       | 89,455                        |       | 69,137                          |       | 78,400 |   | 60,524 |   |
| Texas                   |       | 241,823                       |       | 139,113                         |       | 116,138 |   | 91,987 |   |
| Wyoming                 |       | 29,645                        |       | 3,716                           |       | 119,066 |   | 83,837 |   |
| Other                   |       | 6,520                         |       | 2,211                           |       | — |   | — |   |
| Total Domestic Onshore  |       | 383,013                       |       | 218,617                         |       | 321,890 |   | 241,150 |   |
| Total Domestic          |       | 538,667                       |       | 283,777                         |       | 511,805 |   | 403,008 |   |
| International           |       |                          |       |                            |       |   |   |   |   |
| Gulf of Thailand        |       | 415,603                       |       | 192,597                         |       | 172,503 |   | 79,940 |   |
| New Zealand             |       | —                        |       | —                          |       | 1,043,806 |   | 1,043,806 |   |
| Hungary                 |       | —                        |       | —                          |       | 777,588 |   | 777,588 |   |
| Total International     |       | 415,603                       |       | 192,597                         |       | 1,993,897 |   | 1,901,334 |   |
| Total Company           |       | 954,270                       |       | 476,374                         |       | 2,505,702 |   | 2,304,342 |   |

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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,North Benchamas, Tantawan, Block 9A, Maliwan and Jarmjuree production licenses.

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

In addition, the Companyholds certain other types of mineral interests, including fee interests (whichnever expire) and royalty interests (which generally terminate when theunderlying mineral lease expires). The Company owns varying fee and royaltyinterests in approximately 1,190,600 gross acres (26,875 net acres) in variousparts of the United States.

*Average Production(Lifting) Costs per Unit of Production*

Thefollowing table shows the average production (lifting) costs per unit ofproduction during the periods indicated. For a discussion of the Company’saverage daily production and the average sales prices 

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received by the Company for such production, see “SelectedFinancial Data—Production (Sales) Data” and “Management’s Discussion andAnalysis of Financial Condition and Results of Operations—Results ofOperations; Oil and Gas Revenues.” Production (lifting) costs are defined asthe sum of lease operating expenses (which include insurance and producing welloverhead), production and other taxes and transportation costs.
| ** **                                       | ** ** | **2004**   | ** ** | **2003**   | ** ** | **2002**   | ** ** |
|--------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Average  Production (Lifting) Costs per Mcfe(a): | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Located in the United States                     |       | $          | 0.97       |       | $          | 0.68       |       | $ | 0.69 |   |
| Located in the Kingdom of Thailand               |       | $          | 1.00       |       | $          | 0.67       |       | $ | 0.59 |   |
| Total Company                                    |       | $          | 0.98       |       | $          | 0.68       |       | $ | 0.66 |   |

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

*Productive Wellsand Drilling Activity*

Thefollowing table shows the Company’s interest in productive oil and natural gaswells as of December 31, 2004. For purposes of this table “productivewells” are defined as wells producing hydrocarbons and wells “capable ofproduction” (e.g., natural gas wells waiting for pipeline connections or necessarygovernmental certification to commence deliveries and oil wells waiting to beconnected to currently installed production facilities). “Net wells” forpurposes of this table are defined to mean the sum of the Company’s workinginterest net of royalties and other burdens. This table does not includeexploratory or development wells which have located commercial quantities ofoil or natural gas but which are not capable of commercial production withoutthe installation of material production facilities or which, for a variety ofreasons, the Company does not currently believe will be placed on production.
| ** **           | ** ** | **Oil Wells(a)(b)** | ** ** | **Natural  Gas Wells(a)(b)** | ** ** | **Total** | ** ** |
|----------------------|------------|--------------------------|------------|-----------------------------------|------------|-----------|------------|
| ** **           | ** ** | **Gross**                | ** ** | **Net**                           | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Offshore**         | ** ** | **120**                  | ** ** | **61.30**                         | ** ** | **55**    | ** ** | **27.5** | ** ** | **175** | ** ** | **88.8** | ** ** |
| Operated             |       | 50                       |       | 23.00                             |       | 23        |       | 17.0 |   | 73 |   | 40.0 |   |
| Nonoperated          |       | 70                       |       | 38.30                             |       | 32        |       | 10.5 |   | 102 |   | 48.8 |   |
| **Domestic Onshore** | ** ** | **1407**                 | ** ** | **862.63**                        | ** ** | **1531**  | ** ** | **892.3** | ** ** | **2938** | ** ** | **1754.9** | ** ** |
| Operated             |       | 842                      |       | 769.94                            |       | 953       |       | 795.2 |   | 1795 |   | 1565.1 |   |
| Nonoperated          |       | 565                      |       | 92.69                             |       | 578       |       | 97.1 |   | 1143 |   | 189.8 |   |
| **Thailand**         | ** ** | **102**                  | ** ** | **47.27**                         | ** ** | **71**    | ** ** | **32.9** | ** ** | **173** | ** ** | **80.2** | ** ** |
| Operated             |       | —                   |       | —                            |       | —    |       | — |   | — |   | — |   |
| Nonoperated          |       | 102                      |       | 47.27                             |       | 71        |       | 32.9 |   | 173 |   | 80.2 |   |
| **Total**            | ** ** | **1629**                 | ** ** | **971.20**                        | ** ** | **1657**  | ** ** | **952.7** | ** ** | **3286** | ** ** | **1923.9** | ** ** |
| Operated             |       | 892                      |       | 792.94                            |       | 976       |       | 812.2 |   | 1868 |   | 1605.1 |   |
| Nonoperated          |       | 737                      |       | 178.26                            |       | 681       |       | 140.5 |   | 1418 |   | 318.8 |   |

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

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

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Thefollowing table shows the number of successful gross and net exploratory anddevelopment wells in which the Company has participated and the number of grossand net wells abandoned as dry holes during the periods indicated. An onshorewell is considered successful upon the installation of permanent equipment forthe production of hydrocarbons or when electric logs run to evaluate such wellsindicate the presence of commercially producible hydrocarbons and the Companycurrently intends to complete such wells. Successful offshore wells consist ofexploratory or development wells that have been completed or are “suspended”pending completion (which has been determined to be feasible and economic) andexploratory test wells that were not intended to be completed and thatencountered commercially producible hydrocarbons. For accounting purposes, awell is considered a dry hole when the above criteria indicates that provedreserves have not been found. For purposes of this table, a well is classifiedas a dry hole in the period in which the Company reports permanent abandonmentto the appropriate agency.
| ** **                    | ** ** | **2004**       | ** ** | **2003** | ** ** | **2002**       | ** ** |
|-------------------------------|------------|----------------|------------|----------|------------|----------------|------------|
| ** **                    | ** ** | **Productive** | ** ** | **Dry**  | ** ** | **Productive** | ** ** | **Dry** | ** ** | **Productive** | ** ** | **Dry** | ** ** |
| **Gross Wells:**              |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Offshore  United States       |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory                   |       |           | 2.0        |     |       | 2.0            |       |   | 5.0 |   |   | 2.0 |   |   | 5.0 |   |   | 2.0 |   |
| Development                   |       |           | 8.0        |     |       | —         |       |   | 3.0 |   |   | — |   |   | 13.0 |   |   | — |   |
| Onshore  North America        |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory                   |       |           | 1.0        |     |       | 5.0            |       |   | 9.0 |   |   | 3.0 |   |   | 1.0 |   |   | 4.0 |   |
| Development                   |       |           | 248.0      |     |       | 9.0            |       |   | 169.0 |   |   | 9.0 |   |   | 83.0 |   |   | 5.0 |   |
| Offshore  Kingdom of Thailand |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory                   |       |           | 1.0        |     |       | 1.0            |       |   | 5.0 |   |   | 1.0 |   |   | 6.0 |   |   | — |   |
| Development                   |       |           | 76.0       |     |       | —         |       |   | 40.0 |   |   | 1.0 |   |   | 51.0 |   |   | 2.0 |   |
| Europe                        |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory                   |       |           | 1.0        |     |       | 9.0            |       |   | 1.0 |   |   | — |   |   | — |   |   | — |   |
| Development                   |       |           | —     |     |       | —         |       |   | — |   |   | — |   |   | — |   |   | — |   |
| Total                         |       |           | 337.0      |     |       | 26.0           |       |   | 232.0 |   |   | 16.0 |   |   | 159.0 |   |   | 13.0 |   |
| **Net Wells:**                |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Offshore  United States       |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory                   |       |           | 1.6        |     |       | 1.8            |       |   | 2.3 |   |   | 2.0 |   |   | 5.0 |   |   | 2.0 |   |
| Development                   |       |           | 6.2        |     |       | —         |       |   | 2.2 |   |   | — |   |   | 8.8 |   |   | — |   |
| Onshore  North America        |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory                   |       |           | 0.6        |     |       | 3.8            |       |   | 5.9 |   |   | 2.0 |   |   | 0.8 |   |   | 3.2 |   |
| Development                   |       |           | 122.4      |     |       | 4.6            |       |   | 75.9 |   |   | 3.5 |   |   | 54.7 |   |   | 3.4 |   |
| Offshore  Kingdom of Thailand |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory                   |       |           | 0.5        |     |       | 0.5            |       |   | 2.3 |   |   | 0.5 |   |   | 2.8 |   |   | — |   |
| Development                   |       |           | 35.2       |     |       | —         |       |   | 18.5 |   |   | 0.5 |   |   | 23.5 |   |   | 0.9 |   |
| Europe                        |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory                   |       |           | 1.0        |     |       | 8.4            |       |   | 1.0 |   |   | — |   |   | — |   |   | — |   |
| Development                   |       |           | —     |     |       | —         |       |   | — |   |   | — |   |   | — |   |   | — |   |
| Total                         |       |           | 167.5      |     |       | 19.1           |       |   | 108.1 |   |   | 8.5 |   |   | 95.6 |   |   | 9.5 |   |

 

*Reserves*

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

17

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

TheCompany does not currently believe that the calculation of estimated future netrevenues using the assumptions prescribed by Commission guidelines andgenerally described below is representative of the true value of future netrevenues from the Company’s proved reserves. The future prices received by theCompany for the sales of its production may be higher or lower than the pricesused in calculating the estimates of future net revenues, and the operatingcosts and other costs relating to such production may also increase or decreasefrom existing levels.
| ** **                                                                          | ** ** | **As of December 31,** | ** ** |
|-------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                          | ** ** | **2004**                              | ** ** | **2003** | ** ** | **2002** | ** ** |
| **Total Proved Reserves:**                                                          |       |                                  |       |   |   |   |   |
| Oil, condensate  and natural gas liquids (MBbls)                                    |       |                                  |       |   |   |   |   |
| Located in North America                                                            |       | 83,866                                |       | 77,553 |   | 80,092 |   |
| Located in the Kingdom of Thailand                                                  |       | 32,517                                |       | 37,307 |   | 38,087 |   |
| Located in Hungary                                                                  |       | —                                |       | 10 |   | — |   |
| Total Company                                                                       |       | 116,383                               |       | 114,870 |   | 118,179 |   |
| Natural Gas (MMcf)                                                                  |       |                                  |       |   |   |   |   |
| Located in North America                                                            |       | 933,981                               |       | 837,004 |   | 713,906 |   |
| Located in the Kingdom of Thailand                                                  |       | 145,689                               |       | 165,188 |   | 159,604 |   |
| Located in Hungary                                                                  |       | —                                |       | 10,131 |   | — |   |
| Total Company                                                                       |       | 1,079,670                             |       | 1,012,323 |   | 873,510 |   |
| Present value of estimated future net revenues,  before income taxes (in thousands) |       |                                  |       |   |   |   |   |
| Located in North America                                                            |       | $                                     | 3,639,307  |   | $ | 2,928,663 |   | $ | 2,495,558 |   |
| Located in the Kingdom of Thailand                                                  |       | 932,615                               |       | 744,822 |   | 602,798 |   |
| Located in Hungary                                                                  |       | —                                |       | 16,516 |   | — |   |
| Total Company                                                                       |       | $                                     | 4,571,922  |   | $ | 3,690,001 |   | $ | 3,098,356 |   |
| **Total Proved Developed Reserves:**                                                |       |                                  |       |   |   |   |   |
| Oil, condensate and natural gas liquids (MBbls)                                     |       |                                  |       |   |   |   |   |
| Located in North America                                                            |       | 72,967                                |       | 67,391 |   | 74,041 |   |
| Located in the Kingdom of Thailand                                                  |       | 19,607                                |       | 19,878 |   | 23,832 |   |
| Located in Hungary                                                                  |       | —                                |       | — |   | — |   |
| Total Company                                                                       |       | 92,574                                |       | 87,269 |   | 97,873 |   |
| Natural Gas (MMcf)                                                                  |       |                                  |       |   |   |   |   |
| Located in North America                                                            |       | 769,754                               |       | 702,836 |   | 600,255 |   |
| Located in the Kingdom of Thailand                                                  |       | 83,095                                |       | 77,938 |   | 87,301 |   |
| Located in Hungary                                                                  |       | —                                |       | — |   | — |   |
| Total Company                                                                       |       | 852,849                               |       | 780,774 |   | 687,556 |   |
| Present value of estimated future net revenues,  before income taxes (in thousands) |       |                                  |       |   |   |   |   |
| Located in North America                                                            |       | $                                     | 3,122,860  |   | $ | 2,455,495 |   | $ | 2,239,781 |   |
| Located in the Kingdom of Thailand                                                  |       | 629,541                               |       | 458,511 |   | 422,219 |   |
| Located in Hungary                                                                  |       | —                                |       | — |   | — |   |
| Total Company                                                                       |       | $                                     | 3,752,401  |   | $ | 2,914,006 |   | $ | 2,662,000 |   |

 

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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 Commissionguidelines is not necessarily indicative of the true fair value of the Company’sreserves. Moreover, due to the fact that essentially all of the Company’sdomestic natural gas production is currently sold on the spot market, while allof the Company’s Thailand natural gas production is sold pursuant to a long-termgas sales contract, the estimates of future net revenues from the Company’sdomestic and Thailand reserves are of limited value for comparative purposes.The present value amounts set forth in the above table are, as indicated,before income taxes. For the Company’s standardized measure of discountedfuture net cash flows from production of proved reserves, calculated *after* the estimated effect of futureincome taxes, see “Unaudited Supplementary Financial Data—Oil and Gas ProducingActivities.”

Natural gas liquids comprised approximately 13% of theCompany’s total proved liquids reserves and approximately 13% of the Company’sproved developed liquids reserves as of December 31, 2004. All hydrocarbonliquid reserves are expressed in standard 42 gallon Bbls. All gas volumes andgas sales are expressed in MMcf at the pressure and temperature bases of thearea where the gas reserves are located.

Inaccordance with Commission guidelines, the prices used by the Company tocalculate the present value of estimated future revenues are determined on awell or field-by-field basis, as applicable, as described above and were heldconstant over the productive life of the reserves. The initial weighted averageprices used by Ryder Scott and Miller & Lents were as follows:
| ** **                                         | ** ** | **As of December 31,** | ** ** |
|----------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                         | ** ** | **2004**                              | ** ** | **2003** | ** ** | **2002** | ** ** |
| Initial Weighted Average  Price (in Dollars):      |       |                                  |       |   |   |   |   |
| Oil, condensate  and natural gas liquids (per Bbl) |       |                                  |       |   |   |   |   |
| Located in North America                           |       | $                                     | 40.82      |   | $ | 31.34 |   | $ | 28.72 |   |
| Located in the Kingdom of Thailand                 |       | $                                     | 40.86      |   | $ | 30.27 |   | $ | 32.41 |   |
| Located in Hungary                                 |       | $                                     | —     |   | $ | 26.00 |   | $ | — |   |
| Natural Gas (per  Mcf)                             |       |                                  |       |   |   |   |   |
| Located in North America                           |       | $                                     | 6.04       |   | $ | 5.70 |   | $ | 4.70 |   |
| Located in the Kingdom of Thailand                 |       | $                                     | 2.70       |   | $ | 2.51 |   | $ | 2.24 |   |
| Located in  Hungary                                |       | $                                     | —     |   | $ | 4.82 |   | $ | — |   |

 

In computing future revenues from gas reservesattributable to the Company’s domestic interests, prices in effect at December 31,2004, were used, including current market prices, contract prices and fixed anddeterminable 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 through to depletion of the reserves. In computing futurerevenues from liquids attributable to the Company’s domestic interests, pricesin effect at December 31, 2004, were used and these prices were heldconstant through to depletion of the properties. The future net revenues areadjusted to reflect the Company’s net revenue interest in these reserves aswell as any ad valorem and other severance taxes but do not include anyprovisions for corporate income taxes.

In computing future revenues from the Company’s gasreserves attributable to the Company’s interests in the Kingdom of Thailand, ablended price that took into account the current contract price under the GasSales Agreement for the base production (currently 145 MMcf per day) and theprice for excess sales volumes (which equals 88% of the then-current price forbase production) was used, without 

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giving effect to any ofthe future adjustments provided for in the Gas Sales Agreement, due to theirindeterminate nature as of December 31, 2004, in accordance withCommission guidelines. In computing future revenues from liquids attributableto the Company’s interests in the Kingdom of Thailand, a price was used thatthe Company believes approximates the price that the Company would havereceived for its production from the Thailand Concession based upon the worldmarket price for Malaysian Tapis Blend benchmark crude on December 31,2004, and this price was held constant until depletion of the Company’sreserves in the Kingdom of Thailand. The future net revenues are adjusted toreflect the Company’s net revenue interest in these reserves and the Company’sobligations under the Thailand Concession, including the payment of SRB, but donot include any provisions 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 setforth above includes estimated production for the last few months of 2004. Thefuture production rates from reservoirs now on production may be more or lessthan estimated because of, among other reasons, mechanical breakdowns andchanges in market demand or allowables set by regulatory bodies. Propertiesthat are not currently producing may start producing earlier or later thananticipated in the estimates of future production rates.

There are numerous uncertainties in estimating thequantity of proved reserves and in projecting the future rates of productionand timing of development expenditures. Oil and gas reserve engineering must berecognized as a subjective process of estimating underground accumulations ofoil and gas that cannot be measured in an exact way, and estimates of otherengineers might differ materially from those of the Company, Ryder Scott andMiller & Lents. The accuracy of any reserve estimate is a function ofthe quality of available data and of engineering and geological interpretationand judgment. Results of drilling, testing and production subsequent to thedate of the estimate may justify revision of such estimate, which may bematerial. Accordingly, reserve estimates are often different from thequantities of oil and gas that are ultimately recovered.

The Company is periodicallyrequired to file estimates of its oil and gas reserve data with various U.S.governmental regulatory authorities and agencies, including the Department ofEnergy, the Federal Energy Regulatory Commission (“FERC”) and the Federal TradeCommission and, with respect to reserves located in Thailand, the Kingdom ofThailand’s Department of Mineral Fuels and PTT, which the Company considers aquasi-governmental authority. In addition, estimates are from time to timefurnished to governmental agencies in connection with specific matters pendingbefore such agencies. The basis for reporting reserves to these agencies, insome cases, is not comparable to that used as a basis for the estimates setforth above in accordance with Commission guidelines because of the nature ofthe various reports required. The major differences generally includedifferences in the timing of such estimates, differences in the definition ofreserves, requirements to report in some instances on a gross, net or totaloperator basis and requirements to report in terms of smaller geographicalunits. Since January 1, 2004, no estimates by the Company of its totalproved net oil or gas reserves were filed with or included in reports to anyFederal authority or agency other than the Commission.

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**GovernmentRegulations**

*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’salternative minimum tax.

*American JobsCreation Act of 2004*

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

*EnvironmentalMatters*

Domestic oil and gas operations are subject toextensive federal regulation and, with respect to federal leases, tointerruption or termination by governmental authorities on account ofenvironmental and other considerations such as the Comprehensive EnvironmentalResponse, Compensation and Liability Act (“CERCLA”) also known as the “SuperfundLaw.” The trend towards stricter standards in environmental legislation andregulation could increase costs to the Company and others in the industry. Oiland gas lessees are subject to liability for the costs of clean-up of pollutionresulting from a lessee’s operations, and may also be subject to liability forpollution damages. The Company maintains insurance against costs of clean-upoperations, but is not fully insured against all such risks. A serious incidentof pollution 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 Company has numerous applications pending beforethe Environmental Protection Agency (the “EPA”) for National PollutionDischarge Elimination System (“NPDES”) water discharge permits with respect tooffshore drilling and production operations. NPDES permits are required toensure that effluent discharges from each facility or installation comply withthe applicable federal regulations.

The Oil Pollution Act of 1990 (the “OPA”) andregulations thereunder impose a variety of regulations on “responsible parties”related to the prevention of oil spills and liability for damages resultingfrom such spills in United States waters. The OPA assigns liability to eachresponsible party for oil removal costs and a variety of public and privatedamages. While liability limits apply in some circumstances, a party cannottake advantage of liability limits if the spill was caused by gross negligenceor willful misconduct or resulted 

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from violation of federalsafety, construction or operating regulations. Few defenses exist to theliability imposed by the OPA. In addition, to the extent the Company’s offshorelease operations affect state waters, the Company may be subject to additionalstate and local clean-up requirements or incur liability under state and locallaws. 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. However, the Company cannot predictwhether these financial responsibility requirements under the OPA amendmentswill result in the imposition of substantial additional annual costs to theCompany in the future or otherwise materially adversely affect the Company. Theimpact, however, should not be any more adverse to the Company than it will beto other similarly situated or less capitalized owners or operators in the Gulfof Mexico.

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. Such laws and regulations, among other things,impose absolute 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 tocomment on the costs it incurred during the prior year on capital expendituresfor environmental control facilities and the amount it anticipates incurringduring the coming year. The Company believes that, in the course of conductingits oil and gas operations, many of the costs attributable to environmentalcontrol facilities would have been incurred absent environmental regulations asprudent, safe oilfield practice. During 2004, the Company incurred capitalexpenditures of approximately $6,343,000 for environmental control facilities,primarily relating to the cost of installing environmental equipment, theinstallation of pit and firewall spill liners, and routine site restorationcosts. The Company has budgeted approximately $1,475,000 for expendituresinvolving environmental control facilities during 2005, including, among otherthings, anticipated site restoration costs and the installation ofenvironmental control equipment.

*Other Laws andRegulations*

Various laws and regulations often require permits fordrilling wells and also cover spacing of wells, the prevention of waste of oiland gas including maintenance of certain gas/oil ratios, rates of productionand other matters. The effect of these laws and regulations, as well as otherregulations that could be promulgated by the jurisdictions in which the Companyhas production, could be to limit the number of wells that could be drilled onthe Company’s properties and to limit the allowable production from thesuccessful wells completed on the Company’s properties, thereby limiting theCompany’s revenues.

The MMS administers the oil and gas leases held by theCompany on federal onshore lands and offshore tracts in the Outer ContinentalShelf. The MMS holds a royalty interest in these federal leases on behalf ofthe federal government. While the royalty interest percentage is fixed at thetime that the lease is entered into, from time to time the MMS changes orreinterprets the applicable regulations governing its royalty interests, andsuch action can indirectly affect the actual royalty obligation that theCompany is 

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required to pay. However,the Company believes that the regulations generally do not impact the Companyto any greater extent than other similarly situated producers.

The FERC has embarked onwide-ranging regulatory initiatives relating to gas transportation rates andservices, including the availability of market-based and other alternative ratemechanisms to pipelines for transmission and storage services. In addition, theFERC has announced and implemented a policy allowing pipelines andtransportation customers to negotiate rates above the otherwise applicablemaximum lawful cost-based rates on the condition that the pipelinesalternatively offer so-called recourse rates equal to the maximum lawful cost-basedrates. With respect to gathering services, the FERC has issued orders declaringthat certain facilities owned by interstate pipelines primarily perform agathering function, and may be transferred to affiliated and non-affiliatedentities that are not subject to the FERC’s rate jurisdiction. The Companycannot predict the ultimate outcome of these developments, or the effect ofthese developments on transportation rates. Inasmuch as the rates for thesepipeline services can affect the gas prices received by the Company for thesale of its production, the FERC’s actions may have an impact on the Company.However, the impact should not be substantially different on the Company thanit will on other similarly situated gas producers and sellers.

**Employees**

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

**AvailableInformation**

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

·       TheCompany’s Code of Business Conduct and Ethics

·       TheCompany’s Corporate Governance Guidelines

·       TheCharters of the Company’s Audit, Compensation and Nominating and CorporateGovernance Committees

Any shareholder who sorequests may obtain a printed copy of any of these documents from the Company. Changesin or waivers to the Company’s Code of Business Conduct and Ethics required tobe disclosed by rules of the Commission or the New York Stock Exchangewill be posted on the Company’s Internet website within five business days andmaintained for at least twelve months.

**ITEM 2.**   *Properties.*

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

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

The Company is a party tovarious legal proceedings consisting of routine litigation incidental to itsbusinesses, but believes that any potential liabilities resulting from theseproceedings are adequately covered by insurance or are otherwise not material.See “Business—Government Regulation; Other Laws and Regulations.”

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

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

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

Officers of the Company areappointed annually by the Company’s Board of Directors to serve for the ensuingyear or until their successors have been elected or appointed. The officers ofthe Company that have been designated as “executive officers” for purposes ofItem 401(b) of Regulation S-K and “officers” for purposes of Section 16of the Exchange Act, their age as of December 31, 2004, and the year eachwas elected to his current position are as follows:
| **Executive Officer**   | ** ** | ** **                                                                | ** ** | **Executive Office** | ** ** | **Age** | ** ** | **Year  Elected** |
|-------------------------|------------|---------------------------------------------------------------------------|------------|----------------------|------------|---------|------------|-------------------|
| Paul G. Van Wagenen     |       | Chairman, President and Chief Executive Officer                           |       | 58                   |       | 1991    |
| Stephen R. Brunner      |       | Executive Vice President—Operations                                  |       | 46                   |       | 2002    |
| Jerry A. Cooper         |       | Executive Vice  President and Regional Manager—Western United States |       | 56                   |       | 2002    |
| John O. McCoy, Jr. |       | Executive Vice President and Chief Administrative  Officer                |       | 53                   |       | 2002    |
| David R. Beathard       |       | Senior Vice President—Engineering                                    |       | 46                   |       | 2002    |
| Gerald A. Morton        |       | Senior Vice  President and Regional Manager—Asia and Pacific         |       | 46                   |       | 2003    |
| James P. Ulm, II   |       | Senior Vice President and Chief Financial Officer                         |       | 41                   |       | 2002    |
| Thomas E. Hart          |       | Vice President and Chief Accounting Officer                               |       | 61                   |       | 1999    |
| Michael J. Killelea     |       | Vice President, General Counsel and Corporate  Secretary                  |       | 42                   |       | 2001    |

 

Mr. Van Wagenen, who joined the Company in 1979,has served in his current position since 1991. Prior to assuming their presentpositions with the Company, the business experience of each of the otherexecutive officers for at least the last five years was as follows: Mr. Brunner,who joined the Company in 1994, served as Vice President—Operations since 1997;Mr. Cooper, who joined the Company in 1979, served as Senior VicePresident and Western Division Manager since 1998 and prior thereto served asVice President and Western Division Manager since 1990; Mr. McCoy, whojoined the Company in 1978, served as Senior Vice President and ChiefAdministrative Officer of the Company since 1998 and prior thereto as VicePresident 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 and Regional Manager—Asiaand Pacific since 2002 and Vice President—Law, Chief Regulatory Officerand Corporate Secretary since 2001, and prior thereto was Vice President—Lawand Corporate Secretary since 1997; Mr. Ulm served as Treasurer ofNewfield Exploration Company from 1995 until joining the Company as its VicePresident and Chief Financial Officer in 1999; Mr. Hart joined the Companyin 1977 and served as Vice President and Controller since 1988; and Mr. Killeleawas Chief Counsel of the Company since he joined the Company in 2000 and priorthereto served as Chief Counsel of CMS Oil and Gas Company for more than threeyears.

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**PART II**

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

Thefollowing table shows the range of low and high sales prices of the Company’sCommon Stock (the “Common Stock”) on the New York Stock Exchange composite tapewhere the Common Stock trades under the symbol PPP. The Common Stock is alsolisted on the Pacific Exchange under the same symbol.
| ** **  | ** ** | **Low** | ** ** | **High** | ** ** |
|-------------|------------|---------|------------|----------|------------|
| **2003**    |       |    |       |     |       |
| 1st Quarter |       | $       | 34.29      |     | $          | 39.98 |   |
| 2nd Quarter |       | $       | 38.68      |     | $          | 45.41 |   |
| 3rd Quarter |       | $       | 40.30      |     | $          | 46.42 |   |
| 4th Quarter |       | $       | 41.63      |     | $          | 49.50 |   |
| **2004**    |       |    |       |     |       |
| 1st Quarter |       | $       | 39.25      |     | $          | 50.45 |   |
| 2nd Quarter |       | $       | 44.85      |     | $          | 51.34 |   |
| 3rd Quarter |       | $       | 41.19      |     | $          | 49.71 |   |
| 4th Quarter |       | $       | 43.35      |     | $          | 51.33 |   |

 

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

In 2003, the Company paid four quarterly dividends of$0.05 per share on its Common Stock. In 2004, the Company paid three quarterlydividends of $0.05 per share on its Common Stock. On October 19, 2004, theCompany’s dividend was increased by 25% to $0.0625 per share on its CommonStock and it paid one quarterly dividend at that amount during 2004. Thedeclaration and payment of future dividends, and the amount of such dividends,will depend upon, among other things, the Company’s future earnings andfinancial condition, liquidity and capital requirements, the general economicand regulatory climate and other factors deemed relevant by the Company’s Boardof Directors.

The Company entered into a new revolving creditfacility on December 16, 2004 (the “Facility”), under which the Companyhas borrowed funds. The Facility and the Indenture relating to the Company’s81⁄4% Senior Subordinated Notes due 2011 (the “2011 Notes”) contain covenantsthat may restrict the ability of the Company to pay future dividends on theCompany’s Common Stock. The Company does not believe that either of theseagreements will restrict the Company’s ability to pay dividends on its CommonStock in the reasonably foreseeable future.

No equity securities of the Company not registeredunder the Securities Act of 1933 were sold by the Company during the year endedDecember 31, 2004.

During the fourth quarterof the year ended December 31, 2004, no equity securities of the Companyof any class registered by the Company pursuant to Section 12 of theSecurities Exchange Act of 1934 were purchased by or on behalf of the Companyor any “affiliated purchaser” of the Company, as defined in Rule 10b-18(a)(3) underthe Securities Exchange Act.

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

In thefollowing table, the Company’s financial, production and other data for 2001through 2004 reflect the Company’s acquisition of North Central from and on March 14,2001. The selected financial data should be read in conjunction with “Item 7—Management’sDiscussion and Analysis of Financial Condition and Results of Operations” andthe audited consolidated financial statements and notes thereto included under “Item8—Financial Statements and Supplementary Data.”
| ** **                                                                | ** ** | **For the Year Ended December 31,**                                               | ** ** |
|---------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                | ** ** | **2004**                                                                                                   | ** ** | **2003** | ** ** | **2002** | ** ** | **2001(a)** | ** ** | **2000(a)** | ** ** |
| ** **                                                                | ** ** | **(Expressed in thousands, except per share and production data)** | ** ** |
| **Financial Data**                                                        |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Revenues:                                                                 |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Crude oil and condensate                                                  |       | $                                                                                                          | 680,492    |   | $ | 651,334 |   | $ | 431,769 |   | $ | 261,226 |   | $ | 272,932 |   |
| Natural gas                                                               |       | 584,341                                                                                                    |       | 475,834 |   | 294,206 |   | 322,390 |   | 190,401 |   |
| Natural gas liquids                                                       |       | 43,392                                                                                                     |       | 32,376 |   | 24,426 |   | 12,461 |   | 15,869 |   |
| Oil and gas revenues                                                      |       | 1,308,225                                                                                                  |       | 1,159,544 |   | 750,401 |   | 596,077 |   | 479,202 |   |
| Other                                                                     |       | 14,754                                                                                                     |       | 2,452 |   | 4,453 |   | 14,040 |   | 18,789 |   |
| Total                                                                     |       | $                                                                                                          | 1,322,979  |   | $ | 1,161,996 |   | $ | 754,854 |   | $ | 610,117 |   | $ | 497,991 |   |
| Income before cumulative  effect of change in accounting principle        |       | $                                                                                                          | 261,754    |   | $ | 295,107 |   | $ | 107,031 |   | $ | 87,954 |   | $ | 89,023 |   |
| Cumulative effect of  change in accounting principle                      |       | —                                                                                                     |       | (4,166 | )(b) | — |   | — |   | (1,768 | )(c) |
| Net income                                                                |       | $                                                                                                          | 261,754    |   | $ | 290,941 |   | $ | 107,031 |   | $ | 87,954 |   | $ | 87,255 |   |
| Per share data:                                                           |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Income before cumulative  effect of change in  accounting principle— |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Basic                                                                     |       | $                                                                                                          | 4.10       |   | $ | 4.72 |   | $ | 1.85 |   | $ | 1.72 |   | $ | 2.20 |   |
| Diluted                                                                   |       | $                                                                                                          | 4.06       |   | $ | 4.60 |   | $ | 1.77 |   | $ | 1.62 |   | $ | 1.99 |   |
| Cash dividends on common  stock                                           |       | $                                                                                                          | 0.2125     |   | $ | 0.20 |   | $ | 0.12 |   | $ | 0.12 |   | $ | 0.12 |   |
| Price range of common stock:                                              |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| High                                                                      |       | $                                                                                                          | 51.34      |   | $ | 49.50 |   | $ | 39.28 |   | $ | 34.50 |   | $ | 33.19 |   |
| Low                                                                       |       | $                                                                                                          | 39.25      |   | $ | 34.29 |   | $ | 23.00 |   | $ | 20.45 |   | $ | 18.00 |   |
| Basic weighted average number of  common shares outstanding               |       | 63,848                                                                                                     |       | 62,538 |   | 57,963 |   | 51,031 |   | 40,445 |   |
| Long-term debt at year  end                                               |       | $                                                                                                          | 755,000    |   | $ | 487,261 |   | $ | 722,903 |   | $ | 792,561 |   | $ | 365,000 |   |
| Minority interest at  year end                                            |       | $                                                                                                          | —     |   | $ | — |   | $ | — |   | $ | 145,086 |   | $ | 144,913 |   |
| Shareholders’ equity at  year end                                    |       | $                                                                                                          | 1,727,895  |   | $ | 1,453,653 |   | $ | 1,077,784 |   | $ | 824,885 |   | $ | 358,271 |   |
| Total assets at year end                                                  |       | $                                                                                                          | 3,481,109  |   | $ | 2,758,651 |   | $ | 2,491,593 |   | $ | 2,423,979 |   | $ | 1,114,649 |   |
| **Production (Sales) Data**                                               |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Net daily average production and weighted average  price:                 |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Natural gas (Mcf per  day)                                                |       | 324,000                                                                                                    |       | 297,000 |   | 279,000 |   | 237,800 |   | 164,600 |   |
| Price (per Mcf)                                                           |       | $                                                                                                          | 4.93       |   | $ | 4.39 |   | $ | 2.89 |   | $ | 3.71 |   | $ | 3.16 |   |
| Crude oil and condensate  (Bbl per day)                                   |       | 47,137                                                                                                     |       | 62,121 |   | 47,360 |   | 29,590 |   | 25,788 |   |
| Price (per Bbl)                                                           |       | $                                                                                                          | 39.23      |   | $ | 29.10 |   | $ | 24.89 |   | $ | 23.99 |   | $ | 28.92 |   |
| Natural gas liquids (Bbl  per day)                                        |       | 4,220                                                                                                      |       | 4,109 |   | 4,480 |   | 2,118 |   | 2,141 |   |
| Price (per Bbl)                                                           |       | $                                                                                                          | 28.09      |   | $ | 21.59 |   | $ | 14.94 |   | $ | 16.12 |   | $ | 20.25 |   |

 

26

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| ** **                                                 | ** ** | **For the Year Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2004**                                                     | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** | **2000** | ** ** |
| ** **                                                 | ** ** | **(Expressed in thousands)**                       | ** ** |
| **Capital Expenditures  (including interest capitalized)** |       |                                                         |       |   |   |   |   |   |   |   |   |
| Oil and gas:                                               |       |                                                         |       |   |   |   |   |   |   |   |   |
| Domestic Offshore—                                    |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | $                                                            | 54,300     |   | $ | 28,100 |   | $ | 33,600 |   | $ | 18,000 |   | $ | 18,700 |   |
| Development                                                |       | 74,000                                                       |       | 23,900 |   | 100,700 |   | 169,000 |   | 43,700 |   |
| Purchase of reserves                                       |       | 24,700                                                       |       | — |   | — |   | 87,700 |   | — |   |
| Onshore North  America—                               |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | 29,000                                                       |       | 26,200 |   | 14,500 |   | 38,300 |   | 19,700 |   |
| Development                                                |       | 159,500                                                      |       | 118,000 |   | 117,200 |   | 113,600 |   | 34,700 |   |
| Purchase of reserves                                       |       | 583,800                                                      |       | 177,700 |   | — |   | 1,027,200 |   | 8,400 |   |
| International—                                        |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | 33,100                                                       |       | 20,900 |   | 3,100 |   | 11,500 |   | 9,400 |   |
| Development                                                |       | 121,700                                                      |       | 123,000 |   | 109,300 |   | 64,700 |   | 51,500 |   |
| Total oil and gas                                          |       | 1,080,100                                                    |       | 517,800 |   | 378,400 |   | 1,530,000 |   | 186,100 |   |
| Other                                                      |       | 6,200                                                        |       | 2,500 |   | 3,300 |   | 4,800 |   | 700 |   |
| Total                                                      |       | $                                                            | 1,086,300  |   | $ | 520,300 |   | $ | 381,700 |   | $ | 1,534,800 |   | $ | 186,800 |   |

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(a)           The Company’s financialstatements for 2000—2001 were audited by Arthur Andersen LLP, who have ceasedoperations.

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

(c)           Crude oil andcondensate from the Company’s producing fields located in the Kingdom ofThailand are produced into storage vessels and are sold and recognized asrevenue periodically as economic quantities are accumulated. Effective January 1,2000, the Company adopted the provisions of the Securities and ExchangeCommission’s (the “SEC”) Staff Accounting Bulletin No. 101, RevenueRecognition, and revised its long-standing historical practice of recordingsuch product inventories at their net realizable value. The cumulative effectof 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.

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

Statements in thefollowing discussion may be forward-looking and involve risks anduncertainties. The Company’s financial results are most directly affected by changingprices for its production. Changing prices can influence not only currentresults of operations but the determination of the Company’s proved reservesand available sources of financing, including the determination of theborrowing base under its bank credit facility. The Company’s results depend notonly on hydrocarbon prices generally, but on its ability to market itsproduction on favorable terms in the areas in which it is produced, includingforeign areas such as Thailand where the Company’s operations may be subject tolocal constraints on demand, currency restrictions, exchange rate fluctuations,the possibility of increases in taxes or other charges and non-renewal or otheradverse action relating to concessions or contracts, and other political risks.On a longer term basis, the Company’s financial condition and results ofoperations are affected by its ability to replace reserves as they are producedthrough successful exploration, development and acquisition activities. TheCompany’s results could also be adversely affected by adverse regulatorydevelopments and operational risks associated with oil and gas operations. Someof the other risks and uncertainties that may affect the Company’s results arementioned in the discussion that follows.

**Executive Overview**

The Company’s objective is to cost effectively explorefor, develop, acquire and produce oil and gas in select locations worldwide. Inpursuit of that objective, the Company’s goal for each year is to add more oiland gas reserves than it produces. 2004 marked the thirteenth consecutive yearof reserve replacement for the Company.

The Company pursues a balanced approach in core areaslocated in major oil and gas provinces in the United States and internationally.The Company follows a strict set of criteria when selecting areas of the worldin which to explore. Areas selected are viewed as having proven oil and gasresources, having reasonable economic terms and possessing low political risk. Followingthese criteria, the Company operates internationally in several selectedareas:  Gulf of Thailand, Hungary andoffshore New Zealand. The Company also seeks to maintain a balanced mixture ofthe gas/oil ratio of its proven reserves base.

At the end of 2004, proven reserves topped 1,778 Bcfeand production for the year averaged more than 105,000 BOE per day (632,000Mcfe per day). Oil and gas pricing and production volumes are importantcomponents of an exploration and development company’s growth in net income andcash flow. In 2004, oil and gas pricing for the Company was strong, with theaverage price increasing 24% over 2003 on an equivalent barrel basis.

The Company continues to have a strong balance sheetand to improve its financial leverage, although long-term debt increased,primarily as a result of acquisitions, to $755 million at December 31,2004 from $487 million at year-end 2003. Interest charges were reduced from$46.3 million in 2003 to $29.3 million in 2004. The Company’s debt to totalcapitalization ratio, an indicator of a company’s financial strength, was 30%. Cashand cash equivalents increased from $179 million to $221 million at year-end2004. Company management believes being fiscally conservative is essential toposition the Company for future growth.

Oil and gas capital andexploration expenditures for 2004 were approximately $1,080 million. Exploration &development operations were allocated approximately $472 million, andapproximately $608 million was spent on selective acquisitions in the Company’score areas of operations. During 2004, approximately 309 bcfe of provenreserves were added to the Company’s reserves ledger.

*Hurricane IvanUpdate*

Company operated Gulf ofMexico platforms did not sustain major damage as a result of Hurricane Ivan. However,damages to outside owned and operated platforms and pipelines are continuing tocause a 

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portionof the Company’s Gulf of Mexico production to remain shut-in. As of February22, 2005 some 4,500 barrels of oil per day and 27 million cubic feet of naturalgas per day from Main Pass, South Pass and Viosca Knoll areas remain shut-in. Repairsto the infrastructure are underway, and the Company expects to restore approximately70% of the production from these fields by the end of March, 2005. In order toprotect its cash flow, the Company has business interruption insurance forcertain of the blocks affected by the shut-in; the Company expects to receivepayment from its business interruption insurance policy until production isfully restored for a period of up to one year. The daily indemnity amountexpected to be paid to the Company is approximately $600,000 per day for theMain Pass 61/62 Blocks and approximately $50,000 per day for other blocksaffected by the shut-in. These amounts will be reduced by cash flow frompartially restored production.

*2005 Capital Budget*

The Company hasestablished a $345 million exploration and development budget (excludingproperty acquisitions). The Company expects to spend approximately $187 millionon exploration and $158 million on development activities. The capital budgetcalls for the drilling of approximately 226 wells during 2005.

*Thailand andHungary Disposition*

The Company announcedduring the first quarter of 2005 that it would consider the sale or swap of theCompany’s operations in Thailand and Hungary and has retained Goldman, Sachs & Co. toadvise it on the potential transactions. International asset saleproceeds could be favorably treated by the tax provisions of the “American JobsCreation Act of 2004”, if completed by year-end 2005. Exploration activities inThailand and development activities in both Thailand and Hungary will run concurrently with the Company’sconsideration of the sale of its operations.

*Share Repurchase*

During the first quarterof 2005, the Company announced a share repurchase plan. The Company expects toexpend not less than $275 million nor more than $375 million dollars to effectthe repurchases. Based on recent stock prices, the repurchase could representapproximately 9% to 12% of the shares outstanding at December 31, 2004.

*2005 ProductionOutlook Update*

The Company currentlyexpects that 2005 equivalent hydrocarbon production should reach within 2% ofthe Company’s 2004 production levels, subject to changes in circumstances,acquisitions, divestitures and many other factors.

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**Results ofOperations**

*Oil and GasRevenues*

TheCompany’s oil and gas revenues for 2004 were $1,308,225,000, an increase ofapproximately 13% from oil and gas revenues of $1,159,544,000 for 2003, whichwere an increase of approximately 55% from oil and gas revenues of $750,401,000for 2002. The following table reflects an analysis of variances in the Company’soil and gas revenues (expressed in thousands) between years:
| ** **                                                                | ** ** | **2004   Compared to  2003** | ** ** | **2003  Compared to  2002** | ** ** |
|---------------------------------------------------------------------------|------------|----------------------------------------|------------|----------------------------------|------------|
| Increase  (decrease) in oil and gas revenues resulting from variances in: |       |                                   |       |                             |       |   |   |   |   |
| **Natural gas—**                                                     |       |                                   |       |                             |       |   |   |   |   |
| Price                                                                     |       |                                   | $          | 58,308                           |       |   |   | $ | 152,879 |   |   |
| Production                                                                |       |                                   | 50,199     |                             |       |   | 28,749 |   |   |
|                                                                      |       |                                   | 108,507    |                             |       |   | 181,628 |   |   |
| **Crude oil and condensate—**                                        |       |                                   |       |                             |       |   |   |   |   |
| Price                                                                     |       |                                   | 226,564    |                             |       |   | 72,984 |   |   |
| Production                                                                |       |                                   | (197,406   | )                                |       |   | 146,581 |   |   |
|                                                                      |       |                                   | 29,158     |                             |       |   | 219,565 |   |   |
| **Natural gas liquids (“NGL”)**                                 |       |                                   | 11,016     |                             |       |   | 7,950 |   |   |
| Increase in oil  and gas revenues                                         |       |                                   | $          | 148,681                          |       |   |   | $ | 409,143 |   |   |

 

The increase in theCompany’s oil and gas revenues in 2004, compared to 2003, is related toincreases in both the average price that the Company received for itshydrocarbon production volumes and an increase in the Company’s natural gasproduction volumes, partially offset by a decrease in crude oil and condensateproduction volumes. The increase in the Company’s oil and gas revenues in 2003,compared to 2002, is related to increases in both the average price that theCompany received for its hydrocarbon production volumes and an increase in theCompany’s natural gas and crude oil and condensate production volumes. Theincrease in oil and gas revenues for 2004, compared to 2003 and  2002, was also the result of an increase inthe average price that the Company received for its NGL production volumes from$14.94 and $21.59 in 2002 and 2003, respectively, to $28.09 in 2004.

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*Other Revenues*

Otherrevenue is revenue derived from sources other than the current production ofhydrocarbons. This revenue includes, among other items, insurance proceeds(excluding those related to operating expenses, which are credited against theappropriate expense category), pipeline imbalance settlements and revenue fromsalt water disposal activities. The increase in the Company’s other revenues in2004, compared to either 2003 or 2002, is related primarily to $11.1 million ofbusiness interruption insurance recorded in 2004 with no comparable insuranceclaims in either 2003 or 2002. The business interruption insurance claimrelates to the shut-in of a significant portion of the Company’s Gulf of Mexicoproduction during the fourth quarter of 2004 as a result of the infrastructuredamage caused by Hurricane Ivan. Repairs to the infrastructure are underway,and the Company expects to restore approximately 70% of the production from theaffected fields by the end of March, 2005.
| ** **                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | **% Change  2004  to** | ** ** | ** ** | ** ** | **% Change  2003  to** | ** ** |
|---------------------------------------------------------------|------------|------------|------------|------------|------------|-----------------------------|------------|------------|------------|-----------------------------|------------|
| ** **                                                    | ** ** | **2004**   | ** ** | **2003**   | ** ** | **2003**                    | ** ** | **2002**   | ** ** | **2002**                    | ** ** |
| **Comparison of Increases  (Decreases) in:**                  | ** ** | ** ** | ** ** | ** ** | ** ** |                        | ** ** | ** ** |       | ** **                  | ** ** |   | ** ** | ** ** |   |
| **Natural Gas—**                                         | ** ** | ** ** | ** ** | ** ** | ** ** |                        | ** ** | ** ** |       | ** **                  | ** ** |   | ** ** | ** ** |   |
| Average prices                                                | ** ** | ** ** | ** ** | ** ** | ** ** |                        | ** ** | ** ** |       | ** **                  | ** ** |   | ** ** | ** ** |   |
| North America(a)                                              | ** ** | **$**      | **5.73**   |       | $          | 5.17                        | ** ** |       | **11**     | **%**                       |       | $ | 3.15 | ** ** |   | **64** | **%** |   |
| Kingdom of Thailand(b)                                        | ** ** | **$**      | **2.46**   |       | $          | 2.49                        | ** ** |       | **(1**     | **)%**                      |       | $ | 2.22 | ** ** |   | **12** | **%** |   |
| Company-wide average price                                    | ** ** | **$**      | **4.93**   |       | $          | 4.39                        | ** ** |       | **12**     | **%**                       |       | $ | 2.89 | ** ** |   | **52** | **%** |   |
| Average daily  production volumes  (MMcf per day):            | ** ** | ** ** | ** ** | ** ** | ** ** |                        | ** ** | ** ** |       | ** **                  | ** ** |   | ** ** | ** ** |   |
| North America                                                 | ** ** | **244.3**  |       | 210.4      | ** ** |                        | **16**     | **%**      |       | 201.3                       | ** ** |   | **5** | **%** |   |
| Kingdom of Thailand                                           | ** ** | **79.7**   |       | 86.5       | ** ** |                        | **(8**     | **)%**     |       | 77.8                        | ** ** |   | **11** | **%** |   |
| Company-wide average daily production                         | ** ** | **324.0**  |       | 296.9      | ** ** |                        | **9**      | **%**      |       | 279.1                       | ** ** |   | **6** | **%** |   |
| **Crude Oil and Condensate—**                            | ** ** | ** ** | ** ** | ** ** | ** ** |                        | ** ** | ** ** |       | ** **                  | ** ** |   | ** ** | ** ** |   |
| Average prices(c)                                             | ** ** | ** ** | ** ** | ** ** | ** ** |                        | ** ** | ** ** |       | ** **                  | ** ** |   | ** ** | ** ** |   |
| North America                                                 | ** ** | **$**      | **38.59**  |       | $          | 29.08                       | ** ** |       | **33**     | **%**                       |       | $ | 24.95 | ** ** |   | **17** | **%** |   |
| Kingdom of Thailand                                           | ** ** | **$**      | **40.28**  |       | $          | 29.14                       | ** ** |       | **38**     | **%**                       |       | $ | 24.80 | ** ** |   | **18** | **%** |   |
| Company-wide average price                                    | ** ** | **$**      | **39.23**  |       | $          | 29.10                       | ** ** |       | **35**     | **%**                       |       | $ | 24.89 | ** ** |   | **17** | **%** |   |
| Average daily  production volumes  (Bbls per day):            | ** ** | ** ** | ** ** | ** ** | ** ** |                        | ** ** | ** ** |       | ** **                  | ** ** |   | ** ** | ** ** |   |
| North America                                                 | ** ** | **29,530** |       | 40,173     | ** ** |                        | **(26**    | **)%**     |       | 30,971                      | ** ** |   | **30** | **%** |   |
| Kingdom of Thailand(d)                                        | ** ** | **17,607** |       | 21,948     | ** ** |                        | **(20**    | **)%**     |       | 16,389                      | ** ** |   | **34** | **%** |   |
| Company-wide average daily production                         | ** ** | **47,137** |       | 62,121     | ** ** |                        | **(24**    | **)%**     |       | 47,360                      | ** ** |   | **31** | **%** |   |
| **Total Liquid Hydrocarbons—**                           |       |       |       |       |       |                        | ** ** | ** ** |       |                        |       |   | ** ** | ** ** |   |
| Company-wide average daily production (Bbls per  day)(d) | ** ** | **51,357** |       | 66,230     | ** ** |                        | **(22**    | **)%**     |       | 51,840                      | ** ** |   | **28** | **%** |   |

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(a)           North American averageprices reflect the impact of the Company’s price hedging activity. The Companyhad no price hedging activity related to 2004 production.  Price hedging activity reduced the averageprice $0.17 during 2003 and added $0.04 to the average price of the Company’sNorth American natural gas production during 2002.

(b)          The Company is paid forits natural gas production in the Kingdom of Thailand in Thai baht. The averageprices are presented in U.S. dollars based on the revenue recorded in theCompany’s financial records.

31

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(c)           Average prices arecomputed on production that is actually sold during the period and include theimpact of the Company’s price hedging activity. The Company had no pricehedging activity related to 2004 production. Price hedging activity reduced theaverage price of the Company’s North American crude oil and condensateproduction $0.69 during 2003 and added $0.08 to the average price during 2002. ForNorth American average prices, sales volumes equate to actual production. However,in the Gulf of Thailand, crude oil and condensate sold may be more or less thanactual production. See footnote (d).

(d)          Oiland condensate production in the Gulf of Thailand is produced and stored on theFPSO and FSO pending sale and is sold in tanker loads that typically averagebetween 300,000 and 750,000 barrels per sale. Therefore, oil and condensatesales volumes for a given period in the Gulf of Thailand may notequate to actual production. In accordance with generally accepted accountingprinciples, reported revenues are based on sales volumes. However, the Companybelieves that actual production volumes also provide a meaningful measure ofthe Company’s operating results. The Company produced 96,000 barrels less thanit sold in 2004, 293,000 barrels more than it sold in 2003 and 58,000 barrelsless than it sold in 2002.

*Natural Gas*

*Thailand Prices.  *TheCompany has a long-term Gas Sales Agreement for its Kingdom of Thailand naturalgas production. This agreement covered approximately 25% of the Company’s 2004natural gas production. The price that the Company receives under its Gas SalesAgreement with the Petroleum Authority of Thailand (“PTT”) is based upon aformula that takes into account a number of factors including, among otheritems, changes in the baht/dollar exchange rate and fuel oil prices inSingapore. The contract price is also subject to adjustments for quality. PTThas further agreed to purchase supplemental gas volumes (currently up to 85MMcf per day) over and above the base contractual amount (currently 145 MMcfper day) through December 31, 2007. These supplemental gas volumes over andabove the base contractual amounts are sold to PTT at a price equal to 88% ofthe then-current price calculated under the Gas Sales Agreement for the basecontractual volumes. See “Business—International Operations; Contractual TermsGoverning the Thailand Concession and Related Production.”

*Production.  *Theincrease in the Company’s natural gas production during 2004, compared to 2003,was primarily related to acquisitions made during 2004 and late 2003 and, to alesser extent, increased production from the continuing success of the Company’sexploration program at its Los Mogotes Field in South Texas. These productiongains were partially offset by shut-in production resulting from theinfrastructure damage caused by Hurricane Ivan in the final months of 2004 andnatural production declines at other properties. The increase in the Company’snatural gas production during 2003, compared to 2002, was primarily related toincreased production from the continuing success of the Company’s explorationprogram at its Los Mogotes Field in South Texas, combined with the Company’scontinued development of its Gulf of Thailand concession and, to a lesserextent, an increase in the production capacity of the Lost Cabin Gas Plantlocated on the Company’s Madden Field in Wyoming. These production gains werepartially offset by natural production declines at other properties.

*Crude Oil andCondensate*

*Thailand Prices.  *Pricesthat the Company receives for its crude oil and condensate production fromThailand are based on world benchmark prices, typically as a differential toMalaysian TAPIS or Dated

32

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Brent crude, and aredenominated in U.S. dollars. As discussed further under “Costs and Expenses,Lease Operating Expenses,” the Company records all crude oil held in the FPSOand the FSO at the end of an accounting period as inventory held at cost. Whensuch crude oil is sold, usually during the month following production, the costof the crude oil and the sales revenue are recognized in the income statement. Asof December 31, 2004, the Company had approximately 399,000 net barrelsstored on board the FPSO and FSO.

*Production.  *Thedecrease in the Company’s crude oil and condensate production during 2004,compared to 2003, resulted primarily from shut-in production related to theinfrastructure damage caused by Hurricane Ivan in the final quarter of 2004, thetemporary shutdown of the Benchamas field in the Gulf of Thailand during January andFebruary of 2004 to upgrade the Benchamas central processing platform,natural production declines at the Company’s Main Pass Blocks 61/62 Field inthe Gulf of Mexico and processing problems at its Gulf of Thailand concession. Theincrease in the Company’s crude oil and condensate production during 2003,compared to 2002, resulted primarily from the continued success of developmentprograms at the Company’s Main Pass Blocks 61/62 Field in the Gulf of Mexicoand its Gulf of Thailand concession, partially offset by natural productiondeclines at certain other properties.

*NGLProduction.  *The Company’s oil and gas revenues, and itstotal liquid hydrocarbon production, reflect the production and sale by theCompany of NGL, which are liquid products that are extracted from natural gasproduction. The increase in NGL revenues for 2004, compared with 2003, relatedto an increase in the average price that the Company received for its NGLproduction to $28.09 in 2004 from $21.59 in 2003, in addition to a slightincrease in NGL production volumes. The increase in NGL revenues for 2003,compared with 2002, related to an increase in the average price that theCompany received for its NGL production to $21.59 in 2003 from $14.94 in 2002,partially offset by a slight decline in NGL production volumes.

*Costs and Expenses*
| ** **                                     | ** ** | ** **      | ** **       | ** **  | ** ** | **% Change**               | ** ** | ** ** | ** ** | **% Change**          | ** ** |
|------------------------------------------------|------------|-----------------|------------------|-------------|------------|----------------------------|------------|------------|------------|----------------------------|------------|
| ** **                                     | ** ** | **2004**        | ** **       | **2003**    | ** ** | **2004 to 2003** | ** ** | **2002**   | ** ** | **2003 to 2002** | ** ** |
| **Comparison of Increases  (Decreases) in:**   | ** ** | ** **      | ** **       | ** **  | ** ** |                       | ** ** | ** ** |       | ** **                 | ** ** |   | ** ** | ** ** |   |
| **Lease Operating Expenses**                   | ** ** | ** **      | ** **       | ** **  | ** ** |                       | ** ** | ** ** |       | ** **                 | ** ** |   | ** ** | ** ** |   |
| North America                                  | ** ** | **$**           | **100,535,000**  |        | $          | 81,731,000                 | ** ** |       | **23**     | **%**                      |       | $ | 74,416,000 | ** ** |   | **10** | **%** |   |
| Kingdom of Thailand                            | ** ** | **$**           | **43,938,000**   |        | $          | 41,367,000                 | ** ** |       | **6**      | **%**                      |       | $ | 38,247,000 | ** ** |   | **8** | **%** |   |
| Total Lease Operating Expenses                 | ** ** | **$**           | **144,473,000**  |        | $          | 123,098,000                | ** ** |       | **17**     | **%**                      |       | $ | 112,663,000 | ** ** |   | **9** | **%** |   |
| **General and Administrative Expenses**        | ** ** | **$**           | **69,775,000**   |        | $          | 61,291,000                 | ** ** |       | **14**     | **%**                      |       | $ | 49,490,000 | ** ** |   | **24** | **%** |   |
| **Exploration Expenses**                       | ** ** | **$**           | **23,063,000**   |        | $          | 7,547,000                  | ** ** |       | **206**    | **%**                      |       | $ | 4,783,000 | ** ** |   | **58** | **%** |   |
| **Dry Hole and Impairment Expenses**           | ** ** | **$**           | **106,417,000**  |        | $          | 35,102,000                 | ** ** |       | **203**    | **%**                      |       | $ | 26,999,000 | ** ** |   | **30** | **%** |   |
| **Depreciation, Depletion and**                | ** ** | ** **      |             |        | ** ** |                       | ** ** | ** ** |       |                       | ** ** |   | ** ** | ** ** |   |
| **Amortization (DD&A) Expenses**           | ** ** | **$**           | **365,089,000**  |        | $          | 325,820,000                | ** ** |       | **12**     | **%**                      |       | $ | 287,809,000 | ** ** |   | **13** | **%** |   |
| DD&A rate                                  | ** ** | **$**           | **1.57**         |        | $          | 1.29                       | ** ** |       | **22**     | **%**                      |       | $ | 1.33 | ** ** |   | **(3** | **)%** |   |
| Mcfe sold                                      | ** ** | **231,937,152** |             | 253,422,703 | ** ** |                       | **(8**     | **)%**     |       | 215,728,000                | ** ** |   | **17** | **%** |   |
| **Production and Other Taxes**                 | ** ** | **$**           | **67,984,000**   |        | $          | 35,485,000                 | ** ** |       | **92**     | **%**                      |       | $ | 20,058,000 | ** ** |   | **77** | **%** |   |
| **Transportation and Other**                   | ** ** | **$**           | **21,699,000**   |        | $          | 25,924,000                 | ** ** |       | **(16**    | **)%**                     |       | $ | 12,879,000 | ** ** |   | **101** | **%** |   |
| **Interest—**                             | ** ** | ** **      |             |        | ** ** |                       | ** ** | ** ** |       |                       | ** ** |   | ** ** | ** ** |   |
| Charges                                        | ** ** | **$**           | **(29,333,000**  | **)**       | $          | (46,360,000                | )          |       | **(37**    | **)%**                     |       | $ | (57,450,000 | ) |   | **(19** | **)%** |   |
| Capitalized Interest Expense                   | ** ** | **$**           | **14,216,000**   |        | $          | 16,531,000                 | ** ** |       | **(14**    | **)%**                     |       | $ | 24,033,000 | ** ** |   | **(31** | **)%** |   |
| **Loss on debt extinguishment**                | ** ** | **$**           | **(13,759,000**  | **)**       | $          | (5,893,000                 | )          |       | **133**    | **%**                      |       | $ | — | ** ** |   | **N/M** | ** ** |   |
| **Minority Interest—Dividends and Costs** | ** ** | **$**           | **—**       |        | $          | —                     | ** ** |       | **N/M**    | ** **                 |       | $ | (4,140,000 | ) |   | **N/M** | ** ** |   |
| **Income  Tax Expense**                        | ** ** | **$**           | **(234,649,000** | **)**       | $          | (220,122,000               | )          |       | **7**      | **%**                      |       | $ | (97,780,000 | ) |   | **125** | **%** |   |

 

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*Lease OperatingExpenses*

The increase in North American lease operatingexpenses for 2004, compared to 2003, is due primarily to increased expensesincurred on the properties acquired by the Company during 2004 and the latterpart of 2003, increased maintenance expenses on several of the Company’ssignificant offshore properties related to the effects of Hurricane Ivan andalso to increased expenses incurred as the Company continues to expandproduction in the Los Mogotes field in South Texas. The increase in NorthAmerican lease operating expenses for 2003, compared to 2002, was due to higherproduction from the Company’s onshore properties and additional Gulf of Mexicoplatforms added during 2002 and the resulting increase in operating expenses asadditional wells were subsequently brought on production and, to a lesserextent, increased expenses at the Lost Cabin gas plant in the Madden Unit,which was expanded in late 2002.

The increase in lease operating expenses in theKingdom of Thailand for 2004, compared to 2003, primarily related to costsassociated with operating the five additional platforms which were added to theGulf of Thailand during 2003 and the resulting increase in operating expensesas additional wells were brought on production during 2003. The Company addedfive new platforms during 2004 and expects to add five new platforms in 2005. Theincrease in lease operating expenses in the Kingdom of Thailand for 2003,compared to 2002, primarily related to costs associated with operating the fiveadditional platforms which were added to the Gulf of Thailand primarily duringthe second half of 2002 and the resulting increase in operating expenses asadditional wells were subsequently brought on production. In accordance withgenerally accepted accounting principles, the portion of lifting costs that isattributable to crude oil and condensate stored on the FPSO and FSO is treatedas an inventoried cost until that crude oil 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 andoperating costs will result in variances in the amount of lease operatingexpense that is currently recognized as expense and the amount recorded asproduct inventory to be recognized in subsequent periods. A substantial portionof the Company’s lease operating expenses in the Kingdom of Thailand relates tothe lease payments made in connection with the bareboat charter of the FPSO forthe Tantawan field and the FSO for the Benchamas field. Collectively, theselease payments accounted for approximately $14,600,000 (net to the Company’sinterest) of the Company’s Thailand lease operating expenses for 2004 and approximately$14,500,000 (net to the Company’s interest) of the Company’s Thailand leaseoperating expenses for 2003 and 2002. The Company currently expects these leasepayments to remain relatively constant at approximately $14,500,000 (net to theCompany’s interest) for the next two 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 were $0.52 perMcfe for 2002, $0.49 per Mcfe for 2003 and $0.62 per Mcfe for 2004. Theincreased unit costs in 2004 were primarily related to the increased expenseassociated with Hurricane Ivan remediation efforts and the decreased productionvolumes discussed above.

*General andAdministrative Expenses*

The increase in generaland administrative expenses for 2004, compared with 2003, is primarily relatedto increases in compensation and related benefit expense and to increasedprofessional fees (due in part to compliance with Sarbanes-Oxley legislation). Theincrease in general and administrative expenses for 2003, compared with 2002,primarily related to higher benefit expenses, increases in professional fees,costs related to the start of operations in the Company’s Budapest office,increased insurance costs and expenses related to the Company’s decision,effective January 1, 2003, to expense stock-based compensation. On a perunit of production basis, the Company’s general and administrative expenseswere $0.30 per Mcfe in 2004, $0.24 per Mcfe in 2003 and $0.23 per Mcfe in 2002.

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*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 increase in explorationexpenses for 2004, compared to 2003, resulted primarily from increased 3-Dseismic acquisition activities in the Gulf of Mexico and seismic operations inthe Company’s Gulf Coast division. The increase in exploration expenses for2003, compared to 2002, resulted primarily from increased 3-D seismicacquisition activities in the Gulf of Mexico and seismic operations in theCompany’s Western region.

*Dry Hole andImpairment Expenses*

Dry hole and impairment expenses relate to costs ofunsuccessful exploratory wells drilled and impairment of oil and gasproperties. During 2004 the Company drilled 17 gross unsuccessful exploratorywells (14.50 net to the Company’s interest), in 2003 the Company drilled 6unsuccessful exploratory wells (4.46 net to the Company’s interest) and in 2002the Company drilled 6 unsuccessful exploratory wells (5.17 net to the Company’sinterest). The Company had exploratory and development drilling success ratesof 93% in 2004, 94% in 2003 and 92% in 2002. The Company had approximately $10,800,000of exploratory wells in progress or temporarily abandoned pending evaluation(located primarily in the Gulf of Mexico) at December 31, 2004 that hadnot been evaluated as of March 1, 2005. The Companyhas also suspended approximately $12,057,000 in exploratory wellcosts related to wells completed more than one year prior to December 31,2004 (located primarily in the Kingdom of Thailand) pending the determinationof whether proved reserves can be ultimately assigned. These costs will becharged to earnings in a future period if the Company determines that provedreserves cannot be assigned.

Generally acceptedaccounting principles require that if the expected future cash flow of theCompany’s reserves on a property fall below the cost that is recorded on theCompany’s books, these costs must be impaired and written down to the property’sfair value. Depending on market conditions, including the prices for oil andnatural gas, and the results of operations, a similar test may be conducted atany time to determine whether impairments are appropriate. Depending on theresults of this test, an impairment could be required on some of the Company’sproved properties and this impairment could have a material negative non-cashimpact on the Company’s earnings and balance sheet. Unproved properties arereviewed quarterly to determine if there has been impairment of the carryingvalue, with any such impairment charged to expense in the period. As a resultof these reviews, the Company recognized impairments to oil and gas propertiesof approximately $43,800,000 during 2004 (approximately $22,400,000 of whichwas related to the Company’s international operations), approximately$10,542,000 during 2003 and $6,191,000 during 2002.

*Depreciation,Depletion and Amortization Expenses*

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

The increase in the Company’s DD&A expense for2004, compared to 2003, resulted primarily from a decrease in the percentage ofthe Company’s production coming from fields that have DD&A rates that arelower than the Company’s recent historical composite DD&A rate (principallyproperties in the Gulf of Mexico which were shut-in due to hurricane downtime,and the Benchamas field in the Gulf of Thailand which was shut-in forprocessing upgrades) and a corresponding increase in the percentage of theCompany’s production coming from fields that have DD&A rates that arehigher than the Company’s 

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recent historicalcomposite rate (principally increased production from domestic onshoreproperties acquired by acquisition).

The increase in theCompany’s DD&A expense for 2003, compared to 2002, resulted primarily froman increase in the Company’s natural gas and liquid hydrocarbon production,partially offset by a decrease in the Company’s composite DD&A rate. Thedecrease in the composite DD&A rate for all of the Company’s producingfields for 2003, compared to 2002, resulted primarily from an increasedpercentage of the Company’s production coming from fields that have DD&Arates lower than the Company’s recent historical composite rate (principallycertain Gulf of Mexico properties and the Benchamas Field) and a correspondingdecrease in the percentage of the Company’s production coming from fields thathave DD&A rates higher than the Company’s recent historical compositeDD&A rate.

*Production andOther Taxes*

The increase in production and other taxes for 2004,compared to 2003, is primarily related to increased severance taxes due tohigher domestic onshore production volumes and prices. The increase alsorelates to the recognition during 2004 of $23,880,000 of the Special RemunitoryBenefit (“SRB”) obligation incurred on the Company’s Kingdom of Thailandconcession. During 2003, the Company incurred $11,750,000 of SRB. SRB is apayment to the Thai government required by the Company’s concession agreementafter certain specified revenue, expenditure and drilling criteria have beenachieved. It is currently anticipated that the Company will continue to pay SRBfor the foreseeable future. The amount of SRB to beincurred in 2005 is not currently determinable, as it will be computed using acomplex formula that includes various factors such as revenues, expendituresand meters drilled on the Thailand concession during the year but is expectedto be significant. See “Business—International Operations; Contractual TermsGoverning the Thailand Concession and Related Production.”

The increase in productionand other taxes for 2003, compared to 2002, relates to the recognition during2003 of $11,750,000 of SRB obligations incurred on the Company’s Kingdom ofThailand concession. No comparable SRB expenses were incurred in 2002. Theincrease is also related to increased severance taxes due to higher domesticonshore production volumes and prices.

*Transportation andOther*

Transportation and otherexpense includes the Company’s cost to move its products to market(transportation costs), accretion expense related to Company asset retirementobligations under an accounting pronouncement adopted on January 1, 2003,natural gas purchase costs, tubular inventory valuation write-offs andallowances, and various other operating expenses, none of which represents morethan 5% of this expense category. The decrease in transportation and otherexpense for 2004, compared to 2003, relates primarily to a reduction in theCompany’s transportation expenses, and the inclusion in 2003 of approximately$3.2 million more of valuation allowances and reserves on items discussed above,than were expensed in 2004. The increase in transportation and other expensefor 2003, compared to 2002, relates primarily to the inclusion of $4,972,000 ofexpense related to the accretion of the Company’s asset retirement obligationand a $2,407,000 write down of the cost ofthe Company’s tubular inventory stock, for which no comparable expenses wereincurred in 2002. The Company incurred transportation expense of $13,318,000 in2004, $12,980,000 in 2003 and $10,140,000 in 2002.

*Interest*

*Interest Charges.  *Thedecrease in the Company’s interest charges for 2004, compared to 2003, resultedprimarily from a decrease in the average amount of the Company’s outstandingdebt during the first eleven months of the year and the repayment of highercost debt during the year, resulting in a lower weighted average cost of debt. TheCompany did incur $317 million in additional debt during 

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December 2004primarily related to acquisitions, but this did not have a significant impacton the Company’s 2004 interest expense. The decrease in the Company’s interestcharges for 2003, compared to 2002, resulted primarily from a decrease ofapproximately $236 million in the Company’s outstanding debt during the year,partially offset by an increase in the average interest rate on the debt thatremained outstanding.

*CapitalizedInterest.  *Interest costs related to financing major oiland gas projects in progress are required to be capitalized until the projectsare substantially complete and ready for their intended use if projects areevaluated as successful. The decrease in capitalized interest for 2004,compared to 2003, resulted from a decrease in the weighted average rate onborrowings incurred by the Company (discussed above under “Results ofOperations—Interest Charges”) and applied to such capital expenditures toarrive at the total amount of capitalized interest, partially offset by anincrease in the amount of capital expenditures subject to interestcapitalization during 2004 (approximately $210,000,000) compared to 2003 (approximately$192,000,000). The decrease in capitalized interest for 2003, compared to 2002,resulted primarily from a decrease in the amount of capital expendituressubject to interest capitalization during 2003 (approximately $192,000,000)compared to 2002 (approximately $346,000,000). This decrease was also impactedby changes in the weighted average rate on borrowings incurred by the Companyand applied to such capital expenditures to arrive at the total amount ofcapitalized interest.

*Loss on Debt Extinguishment*

The loss on debtextinguishment for 2004 is related to redemption premiums paid and/orunamortized debt issuance costs which were expensed due to the redemption ofthe 2009 Notes and the replacement of the Company’s previous bank credit facilitywith a new credit facility. The loss on debt extinguishment for 2003 is relatedto redemption premiums paid and unamortized debt issuance costs which wereexpensed due to the redemption of the 2006 Notes and 2007 Notes. No comparablecosts were incurred in 2002.

*Minority Interest—Dividends and Costs Associated withMandatorily Redeemable Convertible Preferred Securities of a Subsidiary Trust*

Pogo Trust I, a businesstrust 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 Icalled 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, representingover $149,850,000 face value of Trust Preferred Securities, into 6,309,972shares 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 PreferredSecurities outstanding. The amounts recorded under Minority Interest—Dividendsand Costs Associated with Preferred Securities of a Subsidiary Trustprincipally reflect cumulative dividends and, to a lesser extent, theamortization of issuance expenses related to the offering and sale of the TrustPreferred Securities.

*Income Tax Expense*

Changes in the Company’sincome tax expense are a function of the Company’s consolidated effective taxrate and its pre-tax income and the jurisdiction in which the income is earned.The increase in the Company’s tax expense for 2004, compared to 2003, resultedprimarily from Hungarian exploration losses for which no tax benefit could berecognized. The increase in the Company’s tax expense for 2003, compared to2002, resulted primarily from increased pre-tax income derived from both theCompany’s U.S. and Thailand operations in 2003, partially offset by a decreasein the Company’s effective tax rate during the comparative periods. The Company’sconsolidated effective tax rate for 2004, 2003 and 2002 was 47%, 43% and 48%,respectively. The higher effective tax rate during 2004, compared to 2003, wasprimarily the result of the impairment of the Company’s Hungarian operationsfor which no tax benefit 

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wasrecognized due to the Company’s inability to offset the costs against expectedfuture taxable income in Hungary. The lower effective tax rate during 2003,compared to 2002, was the result of higher pre-tax income derived from theCompany’s North American operations during the comparative periods, relative toits pre-tax income from its Thailand operations which are taxed at a ratehigher than the U.S. statutory rate. The Company announced in January 2005that it would consider the disposition of its operations in Thailand andHungary and therefore cannot currently predict whether foreign taxes willcontinue to constitute a substantial portion of its overall tax burden infuture years. See “Liquidity and Capital Resources—American Jobs Creation Actof 2004”.

*Cumulative Effectof Change in Accounting Principle*

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

**Liquidity and Capital Resources**

The Company’s primary needs for cash are forexploration, development, acquisition and production of oil and gas properties,repayment of principal and interest on outstanding debt and payment of incometaxes. The Company funds its exploration and development activities primarilythrough internally generated cash flows and budgets capital expenditures basedon projected cash flows. The Company adjusts capital expenditures in responseto changes in oil and natural gas prices, drilling and acquisition results, andcash flow. The Company has historically utilized net cash provided by operatingactivities, available cash, debt, and equity as capital resources to obtainnecessary funding for all other cash needs.

The Company’s cash flow provided by operatingactivities for 2004 was $738,715,000. This compares to cash flow from operatingactivities of $744,559,000 in 2003 and $466,479,000 in 2002. The resultingchanges are attributable to the reasons described under “Results of Operations”above. Cash flow from operating activities in 2004 was sufficient to fund 82%of the $901,006,000 in cash expenditures for capital and exploration projectsand acquisitions for the year. To fund the remaining expenditures, the Companyborrowed approximately $208,218,000 of cash (net of repayments and theredemption discussed below). The Company paid $13,607,000 of dividends on itscommon stock during 2004. As of December 31, 2004, the Company had cashand current investments of$221,456,000 (including $195,669,000 in international subsidiaries which theCompany currently intends to reinvest in its foreign operations subject to itsevaluation of the new tax provisions discussed in “American Jobs Creation Actof 2004” below) and long-term debt obligations of $755,000,000 with noprincipal repayment obligations until 2009. On April 19, 2004, the Companypaid $157,782,000 (excluding accrued interest) in cash to holders of its 103¤8%Senior Subordinated Notes due 2009 (the “2009 Notes”). The redemption was madeat 105.188% of the face amount of the 2009 Notes. The cash redemption paymentwas funded through borrowings under the Company’s existing bank credit facility.The Company may elect to repurchase additional debt through markettransactions, privately negotiated transactions or otherwise, depending onmarket conditions, liquidity requirements, contractual restrictions and otherfactors.

On December 16, 2004the Company entered into a new Credit Agreement, replacing its then existingcredit agreement dated as of March 8, 2001, as amended. The new CreditAgreement is with various 

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financialinstitutions and provides for revolving credit borrowings up to a maximumprincipal amount of $750 million outstanding at any one time, with borrowingsnot to exceed a borrowing base determined at least semiannually. The borrowingbase is currently $900 million. The Credit Agreement provides that in specifiedcircumstances involving an increase in ratings assigned to the Company’s debt,the Company may elect for the borrowing base limitation to no longer apply torestrict available borrowings. As of March 1, 2005, the Companyhad an outstanding balance of $520,000,000 under its CreditAgreement See “Capital Structure—Credit Agreement”.

*American Jobs Creation Act of 2004*

On October 22, 2004, thePresident signed the American Jobs Creation Act of 2004 (the “Act”).  The Act creates a temporary incentive forU.S. corporations to repatriate accumulated income earned abroad by providingan 85% dividend received deduction for certain dividends from controlledforeign corporations.  The deduction issubject to a number of limitations and, as of March 1,2005, uncertainty remains as to how to interpret numerous provisions of theAct.  As a result, the Company is not yetin a position to decide whether, and to what extent, it might repatriateforeign earnings that have not yet been remitted to the U.S., therefore iftechnical corrections to the Act are passed the Company may repatriate in 2005an amount up to approximately $195.7 million of the cash and current investments held byinternational subsidiaries discussed in “Liquidity and Capital Resources”above.  Assuming 15% of such cash issubject to tax at the U.S. statutory rate, the repatriation would be subject toa tax liability of approximately $10.2 million. This amount excludes any proceeds that may be realized from thepotential sale of the Company’s Thailand and Hungarian operations.

*Future Capital and Other Expenditure Requirements*

The Company’s capital andexploration budget for 2005, which does not include any amounts that may beexpended for acquisitions or any interest which may be capitalized resultingfrom projects in progress, was established by the Company’s Board of Directorsat $345,000,000. The Company has included 226 gross wells in its 2005 capitaland exploration budget, including wells to be drilled in the United States andthe Kingdom of Thailand. The Company currently anticipates that its availablecash and cash investments, cash provided by operating activities and fundsavailable under its Credit Agreement will be sufficient to fund the Company’songoing operating, interest and general and administrative expenses, itsauthorized capital budget, and dividend payments at current levels for theforeseeable future. The declaration and amount of future dividends on theCompany’s common stock will depend upon, among other things, the Company’sfuture earnings and financial condition, liquidity and capital requirements,its ability to pay dividends and other payments under covenants contained inits debt instruments, the general economic and regulatory climate and otherfactors deemed relevant by the Company’s Board of Directors.

*Stock Repurchase*

On January 25, 2005,the Company announced a plan to repurchase, through open market or privatelynegotiated transactions, not less than $275 million nor more than $375 millionof its common stock. As of March 1, 2005, the Companyhad completed the purchase of 940,200 shares at a total cost of$41.5 million.

*Other Material Long-Term Commitments*

*ContractualObligations.  *The Company’s material contractualobligations include long-term debt, operating leases, and other contracts. Materialcontractual obligations for which the ultimate settlement amounts are not fixedand determinable include derivative contracts that are sensitive to futurechanges in commodity prices and other factors. See “Item 3. Quantitative andQualitative Disclosure about Market 

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Risk.” A summary ofthe Company’s known contractual obligations as of December 31, 2004 areset forth on the following table:
| ** **                       | ** ** | **Payments due by period (in millions)** | ** ** |
|----------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                       | ** ** | **Total**                                                         | ** ** | **Less than  1 Year** | ** ** | **1 - 3  Years** | ** ** | **3 - 5  Years** | ** ** | **More than  5 Years** | ** ** |
| Long Term Debt(a)                |       | $                                                                 | 858.7      |   |   | $ | 16.5 |   |   | $ | 33.0 |   | $ | 588.0 |   |   | $ | 221.2 |   |   |
| Operating Lease  Obligations(b)  |       | $                                                                 | 140.9      |   |   | $ | 23.5 |   |   | $ | 43.6 |   | $ | 26.7 |   |   | $ | 47.1 |   |   |
| Purchase  Obligations(c)         |       | $                                                                 | 55.9       |   |   | $ | 21.8 |   |   | $ | 21.6 |   | $ | 2.5 |   |   | $ | 10.0 |   |   |
| Asset Retirement  Obligations(d) |       | $                                                                 | 269.1      |   |   | $ | 4.0 |   |   | $ | 4.9 |   | $ | 7.0 |   |   | $ | 253.2 |   |   |
| Total                            |       | $                                                                 | 1,324.6    |   |   | $ | 65.8 |   |   | $ | 103.1 |   | $ | 624.2 |   |   | $ | 531.5 |   |   |

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(a)    Includes interest on fixed rate debt but excludes variable rate interest expense on theCompany’s bank credit facility.

(b)    Operatingleases principally include the lease of the FPSO and FSO in Thailand, theCompany’s office lease commitments and various other equipment rentals,including gas compressors. 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. See Note 5 to theConsolidated Financial Statements.

(c)    Thisrepresents: i) the Company’s share of the contractual commitments for two rigsdrilling in the Gulf of Thailand. No other drilling rigs working for theCompany are currently under contracts that have a term greater than six monthsor which cannot be terminated at the end of the well that is currently beingdrilled. Due to their short-term nature and the indeterminate nature of thedrilling time/liabilities remaining on rigs drilling on a well-by-well basis,such obligations have not been included in this table; and ii) firmtransportation agreements representing “ship-or-pay” arrangements whereby theCompany has committed to ship certain volumes of gas for a fixed transportationfee (principally from the Madden Field in Wyoming). The Company entered intothese arrangements to ensure its access to gas markets and currently expects toproduce sufficient volumes to satisfy substantially all of its firmtransportation obligations.

(d)    Thisrepresents the Company’s estimate of future asset retirement obligations on anundiscounted basis. Because these costs typically extend many years into the future,estimating these future costs requires management to make estimates andjudgments that are subject to future revisions based upon numerous factors,including the rate of inflation, changing technology and the political andregulatory environment. See Note 11 to the Consolidated Financial Statements.

*Commitments under Joint OperatingAgreements.  *The oil and gas industry operates in manyinstances through joint ventures under joint operating agreements, and theCompany’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, and in some cases advance, the funds necessary tomeet the contractual obligations entered into by the operator. Theseobligations are typically shared on a “working interest” basis. The jointoperating agreement provides remedies to the operator in the event that thenon-operator does not satisfy its share of the contractual obligations. Occasionally,the operator is permitted by the joint operating agreement to enter into leaseobligations and other contractual commitments that are then passed on to thenon-operating joint interest owners as lease operating expenses,frequently without any identification as to the long-term nature of anycommitments underlying such expenses. The contractual obligations set forthabove represent the Company’s working interest share of the contractualcommitments that it has entered into as operator and, to the extent that it isaware, the contractual commitments entered into by the operator of projectsthat the Company does not operate.

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*Surety Bonds.  *Inthe ordinary course of the Company’s business and operations, it is required topost surety bonds from time to time with third parties, including governmentalagencies, primarily to cover self insurance, site restoration, equipmentdismantlement, plugging and abandonment obligations. As of December 31,2004, the Company had obtained surety bonds from a number of insurance andbonding institutions covering certain operations in the United States in theaggregate amount of approximately $8,500,000 that are not included in the priortable. In connection with their administration of offshore leases in the Gulfof Mexico, the MMS annually evaluates each lessee’s plugging and abandonmentliabilities. The MMS reviews this information and applies certain financialtests including, but not limited to, current asset and net worth tests. The MMSdetermines whether each lessee is financially capable of paying the estimatedcosts of such plugging and abandonment liabilities. The Company must annuallyprovide the MMS with financial information. If the Company does not satisfy theMMS requirements, it could be required to post supplemental bonds. In the past,the Company has not been required to post supplemental bonds; however, therecan be no assurance that the Company will satisfy the financial tests andremain on the list of MMS lessees exempt from the supplemental bondingrequirements. The Company cannot predict or quantify the amount of any suchsupplemental bonds or the annual premiums related thereto and therefore has notincluded them in the prior table, but the amount could be substantial.

*Guaranteesand Letters of Credit.  *The Company has also issuedperformance guarantees related to the operations of its subsidiaries inThailand. If its subsidiaries do not fulfill their contractual obligations orlegal obligations under the relevant local laws, the Company could be obligatedto make payments to satisfy the subsidiaries’ obligations. Most of theseobligations relate to plugging, abandonment, site restoration and compliancewith environmental laws. The Company also has guaranteed performance of itssubsidiaries’ obligations under the FPSO lease. However, the Company’sguarantee of these obligations has not been so included. Currently, there areno material letters of credit that have been issued on the Company’s behalf.

*Credit Agreementand Borrowing Base Determination*

*CreditAgreement.  *The Company has a revolving credit facility(the “Credit Agreement”) that provides for a $750,000,000 revolving loanfacility terminating on December 16, 2009. The amount that may be borrowedunder the Credit Agreement may not exceed a borrowing base determined at leastsemiannually using the administrative agent’s usual and customary criteria foroil and gas reserve valuation, adjusted for incurrences of other indebtednesssince the last redetermination of the borrowing base. The borrowing base iscurrently $900 million. The credit agreement provides that in specifiedcircumstances involving an increase in ratings assigned to Pogo’s debt, Pogomay elect for the borrowing base limitation to no longer apply to restrictavailable borrowings. The next redetermination of the borrowing base isexpected to occur by May 1, 2005. A significant decline in the prices thatthe Company is expected to receive for its future oil and gas production couldhave a material negative impact on the borrowing base under the CreditAgreement which, in turn, could have a material negative impact on the Company’sliquidity. If at a redetermination of the borrowing base, the lenders reducethe borrowing base below the amount then outstanding under the Credit Agreementand other senior debt arrangements, the Company must repay the excess to thelenders in no more than four substantially equal monthly installments,commencing not later than 90 days after the Company is notified of the newborrowing base. The Credit Agreement includes procedures for additionalfinancial institutions selected by the Company to become lenders under theagreement, or for any existing lender to increase its commitment in an amountapproved by the Company and the lender, subject to a maximum of $250 millionfor all such increases in commitments of new or existing lenders. The CreditAgreement also permits short-term swing-line loans up to $10 million and theissuance of letters of credit up to $75 million, which in each case reduce thecredit available for revolving credit borrowings. As of March 1, 2005, there was $520,000,000outstanding under the Credit Agreement.

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**Application ofCritical Accounting Policies and Management’s Estimates**

Thediscussion and analysis of the Company’s financial condition and results ofoperations is based upon the consolidated financial statements, which have beenprepared in accordance with accounting principles generally accepted in theUnited States. The preparation of these financial statements requires us tomake 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 included in this Form 10-K.We have identified below policies that are of particular importance to theportrayal of our financial position and results of operations and which requirethe application of significant judgment by management. We analyze ourestimates, including those related to oil and gas revenues, bad debts, oil andgas properties, marketable securities, income taxes, derivatives, contingenciesand litigation, on a periodic basis and base our estimates on historicalexperience and various other assumptions that we believe to be reasonable underthe circumstances. Actual results may differ from these estimates underdifferent assumptions or conditions. We believe the following criticalaccounting policies affect our more significant judgments and estimates used inthe preparation of the Company’s financial statements:

*Successful Efforts Method Of Accounting*

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

The application of the successful efforts method ofaccounting requires management’s judgment to determine the proper designationof wells as either developmental or exploratory, which will ultimatelydetermine the proper accounting treatment of the costs incurred. The resultsfrom a drilling operation can take considerable time to analyze, and thedetermination that commercial reserves have been discovered requires bothjudgment and application of industry experience. Wells may be completed thatare assumed to be productive and actually deliver oil and gas in quantities insufficientto be economic, which may result in the abandonment of the wells at a laterdate. On occasion, wells are drilled which have targeted geologic structuresthat are both developmental and exploratory in nature, and in such instances anallocation of costs is required to properly account for the results.Delineation seismic costs incurred to select development locations within aproductive oil and gas field are typically treated as development costs andcapitalized, but often these seismic programs extend beyond the proved reserveareas and therefore management must estimate the portion of seismic costs toexpense as exploratory. The evaluation of oil and gas leasehold acquisitioncosts requires management’s judgment to estimate the fair value of exploratorycosts related to drilling activity in a given area. Drilling activities in anarea by other companies may also effectively condemn 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. The initial exploratory wells may be unsuccessful and theassociated costs will be expensed as dry hole costs. Seismic costs can besubstantial which will result in additional exploration expenses when incurred.

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*Reserve Estimates*

The Company’s estimates ofoil 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 are later determined to be uneconomic. Forthese reasons, estimates of the economically recoverable quantities of expectedoil and gas attributable to any particular group of properties, classificationsof such reserves based on risk of recovery, and estimates of the future netcash flows may vary substantially. Any significant variance in the assumptionscould materially affect the estimated quantity and value of the reserves, whichcould affect the carrying value of the Company’s oil and gas properties and/orthe rate of depletion of such oil and gas properties. Actual production,revenues and expenditures with respect to the Company’s reserves will likelyvary from estimates, and such variances may be material. The Company had upwardreserve revisions equivalent to 0.28%, 5.19% and 8.09% of proved reservesduring the years ended December 31, 2004, 2003 and 2002, respectively. Thesereserve revisions resulted primarily from improved performance from a varietyof sources such as additional recoveries below previously established lowestknown hydrocarbon levels, improved drainage from natural drive mechanisms, andthe realization of improved drainage areas. If the estimates of proved reserveswere to decline, the rate at which the Company records depletion expense wouldincrease. Holding all other factors constant, a reduction in the Company’sproved reserve estimate of 1% would result in an annual increase in DD&Aexpense of approximately $3.7 million.

*Impairment Of Oiland Gas Properties*

The Company reviews itsproved oil and gas properties for impairment on an annual basis or 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 Companyhas recognized impairment expense in each of the periods covered by this Form 10-K.Given the complexities associated with oil and gas reserve estimates and thehistory of price volatility in the oil and gas markets, events may arise thatwill require the Company to record an impairment of its oil and gas propertiesand there can be no assurance that such impairments will not be required in thefuture nor that they will not be material.

*Fair Values OfDerivative Instruments*

The estimated fair values of the Company’s derivativeinstruments are recorded on the Company’s consolidated balance sheet.Historically, substantially all of the Company’s derivative instruments have 

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represented cash flowhedges of the price of future oil and natural gas production. Therefore, whilefair values of such hedging instruments must be estimated at the end of eachreporting period, the related changes in such fair values are not included inthe Company’s consolidated results of operations, to the extent they areexpected to offset the future cash flows from oil and natural gas production.Instead, the changes in fair value of hedging instruments are recorded directlyto shareholders’ equity until the hedged oil or natural gas quantities areproduced and sold.

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. The estimated future prices are compared to theprices fixed by the hedge agreements, and the resulting estimated future cashinflows (outflows) over the lives of the hedges are discounted using theCompany’s current borrowing rates under its revolving credit facility. Thesepricing and discounting variables are sensitive to market volatility as well aschanges in future price forecasts, regional price differentials and interestrates. Historically, the majority of the Company’s derivative instruments havebeen hedges of the price of crude oil and natural gas production. The Companyis not involved in any derivative trading activities.

*BusinessCombinations/Acquisitions*

In 2004, the Company grew through the acquisition oftwo corporations. These acquisitions were accounted for using the purchasemethod of accounting. Under the purchase method, the acquiring company adds toits balance sheet the estimated fair values of the acquired company’s assetsand liabilities. Any excess of the purchase price over the fair values of thetangible and intangible net assets acquired is recorded as goodwill. Goodwilland other intangibles with an indefinite useful life are assessed forimpairment at least annually. The Company has never recorded any goodwill inconnection with its business combinations/acquisitions. However, there can beno assurance that the Company will 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 NGL reserves. Theseestimates are based on work performed by the Company’s engineers and outsidepetroleum reservoir consultants. The judgments associated with the estimationof reserves are described earlier in this section. The fair value of theestimated reserves acquired in a business combination is then calculated basedon the Company’s estimates of future oil, natural gas and NGL prices. TheCompany’s estimates of future prices are based on its own analysis of pricingtrends. These estimates are based on current data obtained with regard toregional and worldwide supply and demand dynamics, such as economic growthforecasts. They are also based on industry data regarding natural gas storageavailability, drilling rig activity, changes in delivery capacity and trends inregional pricing differentials. Future price forecasts from independent thirdparties are also taken into account in arriving at the Company’s own pricingestimates. The Company’sestimates of future prices are applied to the estimated reserve quantitiesacquired to arrive at estimated future net revenues. For estimated provedreserves, the future net revenues are then discounted to derive a fair valuefor such reserves. The Company also applies these same generalprinciples in arriving at the fair value of unproved reserves acquired in abusiness combination. These unproved reserves are generally classified aseither probable or possible reserves. Because of their very nature, probableand possible reserve estimates are less precise than those of proved reserves. Generally,in the Company’s business combinations, the determination of the fair values ofoil and gas properties requires more judgment than the estimates of fair valuesfor other acquired assets and liabilities.

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*Future Developmentand Abandonment Costs*

Future development costs include costs incurred toobtain access to proved reserves, including drilling costs and the installationof production equipment. Future abandonment costs include costs to dismantleand relocate or dispose of our production platforms, FPSOs, FSOs, gatheringsystems, wells and related structures and restoration costs of land and seabed.We develop estimates of these costs for each of our properties based upon thetype of production structure, depth of water, reservoir characteristics, depthof the reservoir, market demand for equipment, currently available proceduresand consultations with construction and engineering consultants. Because thesecosts typically extend many years into the future, estimating these futurecosts is difficult and requires management to make estimates and judgments thatare subject to future revisions based upon numerous factors, including changingtechnology, the ultimate settlement amount, inflation factors, credit adjusteddiscount rates, timing of settlement and changes in the political, legal,environmental and regulatory environment. The Company reviews its assumptionsand estimates of future abandonment costs on an annual basis. The accountingfor future abandonment costs changed on January 1, 2003, with the adoptionof SFAS 143. SFAS 143 requires that the fair value of a liability for an assetretirement obligation be recorded in the period in which it is incurred and thecorresponding cost capitalized by increasing the carrying amount of the relatedlong-lived asset. The liability is accreted to its present value each period,and the capitalized cost is depreciated over the useful life of the relatedasset. If the liability is settled for an amount other than the recordedamount, a gain or loss is recognized.

Holding all other factorsconstant, if the Company’s estimate of future abandonment costs is revisedupward, earnings would decrease due to higher DD&A expense. Likewise, ifthese estimates were revised downward, earnings would increase due to lowerDD&A expense. It would require an increase in the present value of theCompany’s estimated future abandonment cost of approximately $13 million(representing an increase of approximately 14% to the Company’s December 31,2004 asset retirement obligation) to increase the Company’s DD&A rate by$0.01 per Mcfe for the year ended December 31, 2004.

*Pension and OtherPost-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 Company develops itsdemographics and utilizes the work of actuaries to assist with the measurementof employee-related obligations. The assumptions used vary from year-to-year,which will affect future results of operations. Any differences among theseassumptions and the results actually experienced will also impact futureresults of operations. An analysis of the effect of a 1% change in health carecost trends on post-retirement benefits is included in Note 9 to theConsolidated Financial Statements.

*Income Taxes*

For financial reporting purposes, the Companygenerally provides taxes at the rate applicable for the appropriate taxjurisdiction. Where the Company’s present intention is to reinvest theunremitted earnings in its foreign operations, the Company does not provide forU.S. income taxes on unremitted earnings of foreign subsidiaries. Managementperiodically assesses the need to utilize these unremitted earnings to financethe foreign operations of the Company. This assessment is based on cash flowprojections that are the result of estimates of future production, commoditypricing and expenditures by tax jurisdiction for the Company’s operations. Suchestimates are inherently imprecise since many assumptions utilized in the cashflow projections are subject to revision in the future. See “Liquidity andCapital Resources—American Jobs Creation Act of 2004.”

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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.

*Other Matters*

*Inflation.  *Publiclyheld companies are asked to comment on the effects of inflation on theirbusiness. Currently annual inflation in terms of the decrease in the generalpurchasing power of the dollar is running well below the general annualinflation rates experienced in the past. While the Company, like othercompanies, continues to be affected by fluctuations in the purchasing power ofthe dollar due to inflation, such effect is not currently consideredsignificant.

*Southeast Asia Economic Issues.  *Asubstantial portion of the Company’s oil and gas operations are conducted inSoutheast Asia, and a substantial portion of its natural gas and liquidhydrocarbon production is sold there. As with most emerging market economies,the Thai economy is particularly sensitive to worldwide economic trends and tothe effect of the recent tsunami disaster in the Kingdom. The economic healthof the Thai economy and its effect on the volatility of the Thai Baht againstthe dollar will continue to have a material impact on the Company’s operationsin the Kingdom of Thailand, together with the prices that the Company receivesfor its oil and natural gas production there. See “Results of Operations; Oiland Gas Revenues.”

All of the Company’s current natural gas productionfrom the Thailand Concession is committed under a long-term Gas Sales Agreementin each case to PTT at prices denominated in Thai Baht which are determined inaccordance with a formula that is intended to ameliorate, at least in part, anydecline in the purchasing power of the Thai Baht against the dollar. See “BusinessInternational Operations; Contractual Terms Governing the Thailand Concession”and “Business Miscellaneous; Sales.” Although the Company currently believesthat PTT will honor its commitments under the Gas Sales Agreement, a failure byPTT to honor such commitments could have a material adverse effect on theCompany. During 2001, the government of Thailand partially privatized thePetroleum Authority of Thailand, forming PTT and retaining an ownership interestof approximately 70%. PTT is a publicly traded entity that currentlyconstitutes one of the largest public companies in the Kingdom of Thailand.However, its contractual obligations are no longer backed by the full faith andcredit of the Thai government.

The Company’s crude oiland condensate production from the Thailand Concession is currently sold on atanker load by tanker load basis. Prices that the Company receives for suchproduction are based on world benchmark prices, which are denominated indollars, and are typically paid in dollars. See “Business—InternationalOperations; Contractual Terms Governing the Thailand Concession and RelatedProduction” and “Business—Miscellaneous; Sales.”

*Recent AccountingPronouncements*

The Financial Accounting Standards Board (“FASB”) hasissued three new pronouncements relevant to the Company’s accounting. These areStatement of Financial Accounting Standards No. 123 (revised 2004) (“SFAS123R”), “Share-Based Payment”, Statement of Financial Accounting Standards No. 153(“SFAS 153”), “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29”and FASB Staff Position FAS 109-2 (“FSP FAS 109-2”), “Accounting and DisclosureGuidance for the Foreign Earnings Repatriation Provision Within the AmericanJobs Creation Act of 2004”.

*SFAS 123R.  *SFAS123R will require compensation costs related to share-based paymenttransactions to be recognized in the financial statements. With limitedexceptions, the amount of compensation cost will be measured based on thegrant-date fair value of the equity or liability instruments issued. Inaddition, liability awards will be remeasured each reporting period. Compensationcost will be recognized over the period that an employee provides service inexchange for the award. 

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Statement 123(R) replacesFASB Statement No. 123 (“SFAS 123”), “Accounting for Stock-BasedCompensation”, and supersedes APB Opinion No. 25, “Accounting for StockIssued to Employees”. SFAS 123R is effective as of the first interim orannual reporting period that begins after June 15, 2005. The Companycurrently follows the provisions of SFAS 123 and the adoption of SFAS 123R isnot expected to have a material effect on the Company’s financial statements.

*SFAS 153.  *SFAS153**was a result of an effort bythe FASB and the International Accounting Standards Board (“IASB”) to improvefinancial reporting by eliminating certain narrow differences between theirexisting accounting standards. One such difference was the exception from fairvalue measurement in APB Opinion No. 29, *Accountingfor Nonmonetary Transactions*, for nonmonetary exchanges of similarproductive assets. SFAS 153 replaces this exception with a general exceptionfrom fair value measurement for exchanges of nonmonetary assets that do nothave commercial substance. A nonmonetary exchange has commercial substance ifthe future cash flows of the entity are expected to change significantly as aresult of the exchange. SFAS 153 will be applied prospectively and is effectivefor nonmonetary asset exchanges occurring in fiscal periods beginning after June 15,2005. Earlier application is permitted for nonmonetary asset exchangesoccurring in fiscal periods beginning after the date of issuance of thisStatement. The adoption of SFAS 153 is not expected to have a material effecton the Company’s financial statements.

*FSP FAS109-2.  *In December 2004, the FASB staff issued FSPFAS 109-2 to provide accounting and disclosure guidance for the repatriationprovisions included in the Act. The Act introduced a special limited-timedividends received deduction on the repatriation of certain foreign earnings toa U.S. taxpayer. As a result, an issue has arisen as to whether an enterpriseshould be allowed additional time beyond the financial reporting period inwhich the Act was enacted to evaluate the effects of the Act on its plan forreinvestment or repatriation of foreign earnings for purposes of applyingStatement 109. The following are the key points relevant to the Company’sposition:

·       Anenterprise is allowed additional time beyond the financial reporting period ofenactment to evaluate the effect of the Act without undermining the entity’sassertion that repatriation of foreign earnings is not expected within theforeseeable future.

·       Anenterprise should recognize the income tax effect when it decides on a plan forreinvestment or repatriation of foreign earnings. This decision may occur instages, and each stage may occur at a different time. Also, before its plan forreinvestment or repatriation is finalized, an enterprise may decide on a rangeof amounts that it will repatriate. In this situation, the FSP requiresrecognition of the income tax effect of the lowest amount within the range.

·       Ifan enterprise has recognized a deferred tax liability for some, or all, of itsunremitted foreign earnings because it did not overcome the presumption ofrepatriation of foreign earnings, it should continue to presume repatriation ofthose earnings as well as current foreign earnings that are not expected to beindefinitely reinvested. The enterprise shall measure the income tax effects ofsuch repatriation without the effects of the repatriation provision until ithas decided on a plan for repatriation.

·       Anenterprise that has not yet completed its evaluation of the repatriationprovision should make certain disclosures. Additional disclosures are requiredin the period an enterprise completes its evaluation

The Company has adoptedthe disclosure requirements of FSP FAS 109-2 and is currently evaluating theeffects of the Act. The Company expects to be in a position to finalize itsassessment shortly after passage of technical corrections to the Act.

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

The Company is exposed tomarket risk, including adverse changes in commodity prices, interest rates andforeign currency exchange rates as discussed below.

**Commodity PriceRisk**

The Company produces,purchases and sells natural gas, crude oil, condensate and NGLs. As a result,the Company’s financial results can be significantly affected as these commodityprices fluctuate widely in response to changing market forces. In the past, theCompany has made limited use of a variety of derivative financial instrumentsonly for non-trading purposes as a hedging strategy to manage commodity pricesassociated with oil and gas sales and to reduce the impact of commodity pricefluctuations. See “Business—Competition and Market Conditions.”

**Interest Rate Risk**

Fromtime to time, the Company has entered into various financial instruments, suchas interest rate swaps, to manage the impact of changes in interest rates. Asof March 1, 2005, the Companyhas no open interest rate swap or interest rate lock agreements. Therefore, theCompany’s exposure to changes in interest rates primarily results from its short-termand long-term debt with both fixed and floating interest rates. The followingtable presents principal or notional amounts (stated in thousands) and relatedaverage interest rates by year of maturity for the Company’s debt obligationsand their indicated fair market value at December 31, 2004:
| ** **             | ** ** | **2005** | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **Thereafter** | ** ** | **Total** | ** ** | **Fair Value** | ** ** |
|------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|---------------------|------------|
| Long-Term Debt:        |       |     |       |     |       |     |       |     |       |     |       |           |       |      |       |                |       |
| Variable Rate          |       | $        | 0          |     | $          | 0        |       | $        | 0          |     | $          | 0              |       | $         | 555,000    |                | $          | 0 |   | $ | 555,000 |   | $ | 555,000 |   |
| Average Interest Rate  |       | —   |       | —   |       | —   |       | —   |       | 3.66     | %          | —         |       | 3.66      | %          | —              |       |
| Fixed Rate             |       | $        | 0          |     | $          | 0        |       | $        | 0          |     | $          | 0              |       | $         | 0          |                | $          | 200,000 |   | $ | 200,000 |   | $ | 216,500 |   |
| Average Interest  Rate |       | —   |       | —   |       | —   |       | —   |       | —   |       | 8.25           | %          | 8.25      | %          | —              |       |

 

**Foreign CurrencyExchange Rate Risk**

In addition to the U.S. dollar, the Company andcertain of its subsidiaries conduct their business in Thai Baht and HungarianForint and are therefore subject to foreign currency exchange rate risk on cashflows related to sales, expenses, financing and investing transactions. TheCompany conducts a substantial portion of its oil and gas production and salesin Southeast Asia. Southeast Asia in general, and the Kingdom of Thailand inparticular, have experienced severe economic difficulties in the past,including sharply reduced economic activity, illiquidity, highly volatileforeign currency exchange rates and unstable stock markets. See “Management’sDiscussion and Analysis of Financial Condition and Results ofOperations—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 natural 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 ofThailand are denominated in U.S. dollars, the U.S. dollar is the functionalcurrency for the Company’s operations in the Kingdom of Thailand. As of March 1, 2005, the Company isnot a party to any foreign currency exchange agreement.

Exposure from market ratefluctuations related to activities in Hungary, where the Company’s functionalcurrency is the U.S. dollar, is not material at this time.

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**Current HedgingActivity**

As of December 31, 2004, the Company held variousderivative instruments. During 2004, the Company entered into natural gas andcrude oil option agreements referred to as “collars.” Collars are designed toestablish floor and ceiling prices on anticipated future natural gas and crudeoil production. The Company has designated these contracts as cash flow hedgesdesigned to achieve a more predictable cash flow, as well as to reduce itsexposure to price volatility. While the use of these derivative instrumentslimits the downside risk of adverse price movements, they may also limit futurerevenues from favorable price movements. The use of derivatives also involves therisk that the counterparties to such instruments will be unable to meet thefinancial terms of such contracts. Currently, the Company does not expectlosses due to creditworthiness of its counterparties.

The gas hedging transactions are generally settledbased upon the average of the reporting settlement prices on the NYMEX for thelast 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 any particular collar transaction, thecounterparty is required to make a payment to the Company if the settlementprice for any settlement period is below the floor price for such transaction,and the Company is required to make a payment to the counterparty if thesettlement price for any settlement period is above the ceiling price of suchtransaction.

Theestimated fair value of these transactions is based upon various factors thatinclude closing exchange prices on the NYMEX, volatility and the time value ofoptions. Further details related to the Company’s hedging activities as of December 31,2004 are as follows:
| ** **                                                        | ** ** | ** ** | ** ** | **NYMEX**    | ** ** | ** **          | ** ** |
|-------------------------------------------------------------------|------------|------------|------------|--------------|------------|---------------------|------------|
| ** **                                                        | ** ** | ** ** | ** ** | **Contract** | ** ** | **Fair Value** | ** ** |
| ** **                                                        | ** ** | ** ** | ** ** | **Price**    | ** ** | **of**              | ** ** |
| **Contract Period and Type of Contract** | ** ** | ** ** | ** ** | **Volume**   | ** ** | **Floor**           | ** ** | **Ceiling** | ** ** | **Asset/(Liability)** | ** ** |
| **Natural Gas Contracts (MMBtu)(a)**                              |       |       |       |         |       |                |       |   |   |   |   |
| Collar Contracts:                                                 |       |       |       |         |       |                |       |   |   |   |   |
| January 2005 -  December 2005                           |       | 5,475      |       | $            | 5.50       |                | $          | 8.00 |   |   | $ | 214,810 |   |   |
| January 2005 -  December 2005                           |       | 1,825      |       | $            | 6.00       |                | $          | 9.30 |   |   | $ | 658,634 |   |   |
| January 2005 -  December 2005                           |       | 1,825      |       | $            | 6.00       |                | $          | 9.25 |   |   | $ | 652,362 |   |   |
| January 2005 -  December 2006                           |       | 3,650      |       | $            | 6.00       |                | $          | 9.25 |   |   | $ | 1,304,729 |   |   |
| January 2006 -  December 2006                           |       | 5,475      |       | $            | 5.00       |                | $          | 7.50 |   |   | $ | (2,116,689 | ) |   |
| January 2006 -  December 2006                           |       | 3,650      |       | $            | 5.50       |                | $          | 8.25 |   |   | $ | (184,107 | ) |   |
| January 2006 -  December 2006                           |       | 3,650      |       | $            | 5.75       |                | $          | 8.27 |   |   | $ | 182,666 |   |   |
| **Crude Oil Contracts (Barrels)**                                 |       |       |       |         |       |                |       |   |   |   |   |
| Collar Contracts:                                                 |       |       |       |         |       |                |       |   |   |   |   |
| January 2005 - December 2005                            |       | 1,825,000  |       | $            | 40.00      |                | $          | 62.50 |   |   | $ | 3,891,103 |   |   |
|                                                                   |            |            |            |              |            |                     |            |  |  |  |  |  |  |  |  |  |

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(a)           MMBtu means millionBritish Thermal Units.

In February 2005, the Company entered intoadditional crude oil collars to establish floor and ceiling prices onanticipated future crude oil production. The Company has designated thesecontracts as cash flow hedges. Further details related to this hedging activityis as follows:
| ** **                                                        | ** ** | ** ** | ** ** | **NYMEX  Contract  Price** | ** ** |
|-------------------------------------------------------------------|------------|------------|------------|----------------------------|------------|
| **Contract Period and Type of Contract** | ** ** | ** ** | ** ** | **Volume**                 | ** ** | **Floor** | ** ** | **Ceiling** | ** ** |
| **Crude Oil Contracts (Barrels)**                                 |       |       |       |                       |       |   |   |
| Collar Contracts:                                                 |       |       |       |                       |       |   |   |
| March 2005 -  December 2005                             |       | 1,530,000  |       | $                          | 40.00      |   | $ | 62.50 |   |
|                                                                   |            |            |            |                            |            |  |  |  |  |  |  |

 

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**ITEM 8.**   Financial Statements and SupplementaryData.

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM**

To the Stockholders and Board of Directors of PogoProducing Company:

We have completed anintegrated audit of Pogo Producing Company’s 2004 consolidated financialstatements and of its internal control over financial reporting as ofDecember 31, 2004 and audits of its 2003 and 2002 consolidated financialstatements in accordance with the standards of the Public Company Accounting OversightBoard (United States). Our opinions, based on our audits, are presented below.

*Consolidatedfinancial statements*

In our opinion, the accompanying consolidated balancesheets and the related consolidated statements of income, of stockholders’equity and of cash flows present fairly, in all material respects, thefinancial position of Pogo Producing Company and its subsidiaries atDecember 31, 2004 and 2003, and the results of their operations and theircash flows for each of the three years in the period ended December 31,2004 in conformity with accounting principles generally accepted in the UnitedStates of America. These financial statements are the responsibility of theCompany’s management. Our responsibility is to express an opinion on these financialstatements based on our audits. We conducted our audits of these statements inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform the audit toobtain reasonable assurance about whether the financial statements are free ofmaterial misstatement. An audit of financial statements includes examining, ona test basis, 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 audits provide a reasonable basis for ouropinion.

As discussed in Note 1 tothe consolidated financial statements, the Company changed its method ofaccounting for employee stock-based compensation effective January 1,2003. Additionally, as discussed in Note 11 to the consolidated financialstatements, the Company changed its method of accounting for asset retirementobligations effective January 1, 2003.

*Internal controlover financial reporting*

Also, in our opinion, management’s assessment,included in Management’s Report on Internal Control Over Financial Reportingappearing under Item 9A, that the Company maintained effective internal controlover financial reporting as of December 31, 2004 based on criteriaestablished in *Internal Control—Integrated Framework*issuedby the Committee of Sponsoring Organizations of the Treadway Commission (COSO),is fairly stated, in all material respects, based on those criteria.Furthermore, in our opinion, the Company maintained, in all material respects,effective internal control over financial reporting as of December 31,2004, based on criteria established in *Internal Control*—*Integrated Framework* issued by the COSO. The Company’smanagement is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting. Our responsibility is to express opinions onmanagement’s assessment and on the effectiveness of the Company’s internalcontrol over financial reporting based on our audit. We conducted our audit ofinternal control over financial reporting in accordance with the standards ofthe Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance aboutwhether effective internal control over financial reporting was maintained inall material respects. An audit of internal control over financial reportingincludes obtaining an understanding of internal control over financialreporting, evaluating management’s assessment, testing and evaluating thedesign and operating effectiveness of internal control, and performing suchother 

50

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procedures as we considernecessary in the circumstances. We believe that our audit provides a reasonablebasis for our opinions.

A company’s internal control over financial reportingis a process designed to provide reasonable assurance regarding the reliabilityof financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles. Acompany’s internal control over financial reporting includes those policies andprocedures that (i) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (ii) provide reasonableassurance that transactions are recorded as necessary to permit preparation offinancial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being madeonly in accordance with authorizations of management and directors of thecompany; and (iii) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements. Also, projections of any evaluation of effectiveness tofuture periods are subject to the risk that controls may become inadequatebecause of changes in conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.

PRICEWATERHOUSECOOPERS LLP

Houston,Texas

March 7, 2005

 

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**POGO PRODUCING COMPANY & SUBSIDIARIESCONSOLIDATED STATEMENTS OFINCOME**
| ** **                                                                                                                                     | ** ** | **Year Ended December 31,**   | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------|------------|
| ** **                                                                                                                                     | ** ** | **2004**                                     | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                                                                     | ** ** | **(Expressed in thousands,**       | ** ** |
| ** **                                                                                                                                     | ** ** | **except per share amounts)** | ** ** |
| **Revenues:**                                                                                                                                  |       |                                         |       |   |   |   |   |
| Oil and gas                                                                                                                                    |       | $                                            | 1,308,225  |   | $ | 1,159,544 |   | $ | 750,401 |   |
| Other                                                                                                                                          |       | 14,754                                       |       | 2,452 |   | 4,453 |   |
| Total                                                                                                                                          |       | 1,322,979                                    |       | 1,161,996 |   | 754,854 |   |
| **Operating Costs and Expenses:**                                                                                                              |       |                                         |       |   |   |   |   |
| Lease operating                                                                                                                                |       | 144,473                                      |       | 123,098 |   | 112,663 |   |
| General and  administrative                                                                                                                    |       | 69,775                                       |       | 61,291 |   | 49,490 |   |
| Exploration                                                                                                                                    |       | 23,063                                       |       | 7,547 |   | 4,783 |   |
| Dry hole and impairment                                                                                                                        |       | 106,417                                      |       | 35,102 |   | 26,999 |   |
| Depreciation, depletion  and amortization                                                                                                      |       | 365,089                                      |       | 325,820 |   | 287,809 |   |
| Production and other  taxes                                                                                                                    |       | 67,984                                       |       | 35,485 |   | 20,058 |   |
| Transportation and other                                                                                                                       |       | 21,699                                       |       | 25,924 |   | 12,879 |   |
| Total                                                                                                                                          |       | 798,500                                      |       | 614,267 |   | 514,681 |   |
| **Operating Income**                                                                                                                           |       | 524,479                                      |       | 547,729 |   | 240,173 |   |
| **Interest:**                                                                                                                                  |       |                                         |       |   |   |   |   |
| Charges                                                                                                                                        |       | (29,333                                      | )          | (46,360 | ) | (57,450 | ) |
| Income                                                                                                                                         |       | 2,526                                        |       | 1,852 |   | 1,760 |   |
| Capitalized                                                                                                                                    |       | 14,216                                       |       | 16,531 |   | 24,033 |   |
| **Loss on debt extinguishment**                                                                                                                |       | (13,759                                      | )          | (5,893 | ) | — |   |
| **Minority Interest—**Dividends  and costs associated with mandatorily redeemable convertible preferred securities  of a subsidiary trust |       | —                                       |       | — |   | (4,140 | ) |
| **Foreign Currency Transaction  Gain (Loss)**                                                                                                  |       | (1,726                                       | )          | 1,370 |   | 435 |   |
| **Income Before Taxes and  Cumulative Effect of Change in Accounting Principle**                                                               |       | 496,403                                      |       | 515,229 |   | 204,811 |   |
| **Income Tax Expense**                                                                                                                         |       | (234,649                                     | )          | (220,122 | ) | (97,780 | ) |
| **Income Before Cumulative Effect  of Change in Accounting Principle**                                                                         |       | 261,754                                      |       | 295,107 |   | 107,031 |   |
| **Cumulative Effect of Change in  Accounting Principle**                                                                                       |       | —                                       |       | (4,166 | ) | — |   |
| **Net Income**                                                                                                                                 |       | $                                            | 261,754    |   | $ | 290,941 |   | $ | 107,031 |   |
| **Earnings (Loss) per Common Share:**                                                                                                          |       |                                         |       |   |   |   |   |
| Basic                                                                                                                                          |       |                                         |       |   |   |   |   |
| Income before cumulative  effect of change in accounting principle                                                                             |       | $                                            | 4.10       |   | $ | 4.72 |   | $ | 1.85 |   |
| Cumulative effect of  change in accounting principle                                                                                           |       | —                                       |       | (0.07 | ) | — |   |
| Net income                                                                                                                                     |       | $                                            | 4.10       |   | $ | 4.65 |   | $ | 1.85 |   |
| Diluted                                                                                                                                        |       |                                         |       |   |   |   |   |
| Income before cumulative  effect of change in accounting principle                                                                             |       | $                                            | 4.06       |   | $ | 4.60 |   | $ | 1.77 |   |
| Cumulative effect of  change in accounting principle                                                                                           |       | —                                       |       | (0.06 | ) | — |   |
| Net income                                                                                                                                     |       | $                                            | 4.06       |   | $ | 4.54 |   | $ | 1.77 |   |
| **Dividends per Common Share**                                                                                                                 |       | $                                            | 0.2125     |   | $ | 0.20 |   | $ | 0.12 |   |

 

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

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**POGO PRODUCING COMPANY & SUBSIDIARIESCONSOLIDATED BALANCE SHEETS**
| ** **                                                  | ** ** | **December 31,**                  | ** ** |
|-------------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                                  | ** ** | **2004**                               | ** ** | **2003** | ** ** |
| ** **                                                  | ** ** | **(Expressed in thousands)** | ** ** |
| **ASSETS**                                                  |       |                                   |       |   |   |
| **Current  Assets:**                                        |       |                                   |       |   |   |
| Cash and cash equivalents                                   |       | $                                      | 86,456     |   | $ | 104,474 |   |
| Current investments                                         |       | 135,000                                |       | 74,280 |   |
| Accounts receivable                                         |       | 140,988                                |       | 116,970 |   |
| Other receivables                                           |       | 37,229                                 |       | 39,497 |   |
| Federal income taxes receivable                             |       | 10,708                                 |       | — |   |
| Inventory—product                                      |       | 5,062                                  |       | 5,951 |   |
| Inventories—tubulars                                   |       | 17,850                                 |       | 7,735 |   |
| Price hedge contracts                                       |       | 6,722                                  |       | — |   |
| Other                                                       |       | 5,395                                  |       | 5,448 |   |
| Total current assets                                        |       | 445,410                                |       | 354,355 |   |
| **Property  and Equipment:**                                |       |                                   |       |   |   |
| Oil and gas, on  the basis of successful efforts accounting |       |                                   |       |   |   |
| Proved properties                                           |       | 4,931,264                              |       | 3,919,138 |   |
| Unevaluated properties                                      |       | 83,196                                 |       | 107,708 |   |
| Other, at cost                                              |       | 36,492                                 |       | 30,046 |   |
|                                                        |       | 5,050,952                              |       | 4,056,892 |   |
| Accumulated  depreciation, depletion, and amortization      |       |                                   |       |   |   |
| Oil and gas                                                 |       | (2,017,900                             | )          | (1,661,584 | ) |
| Other                                                       |       | (23,858                                | )          | (19,467 | ) |
|                                                        |       | (2,041,758                             | )          | (1,681,051 | ) |
| Property and equipment, net                                 |       | 3,009,194                              |       | 2,375,841 |   |
| **Other  Assets:**                                          |       |                                   |       |   |   |
| Deferred income tax                                         |       | —                                 |       | 2,416 |   |
| Foreign value added taxes receivable                        |       | 8,471                                  |       | 4,188 |   |
| Other                                                       |       | 18,034                                 |       | 21,851 |   |
|                                                        |       | 26,505                                 |       | 28,455 |   |
|                                                        |       | $                                      | 3,481,109  |   | $ | 2,758,651 |   |

 

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

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**POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Continued)**
| ** **                                                                                                      | ** ** | **December 31,**                  | ** ** |
|-----------------------------------------------------------------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                                                                                      | ** ** | **2004**                               | ** ** | **2003** | ** ** |
| ** **                                                                                                      | ** ** | **(Expressed in thousands)** | ** ** |
| **LIABILITIES  AND SHAREHOLDERS’ EQUITY**                                                                  |       |                                   |       |   |   |
| **Current  Liabilities:**                                                                                       |       |                                   |       |   |   |
| Accounts payable—operating activities                                                                      |       | $                                      | 72,228     |   | $ | 55,543 |   |
| Accounts payable—investing activities                                                                      |       | 128,075                                |       | 73,179 |   |
| Income taxes payable                                                                                            |       | 34,776                                 |       | 20,220 |   |
| Accrued interest payable                                                                                        |       | 4,550                                  |       | 9,950 |   |
| Accrued payroll and related benefits                                                                            |       | 3,609                                  |       | 3,242 |   |
| Deferred income tax                                                                                             |       | 4,919                                  |       | 5,324 |   |
| Other                                                                                                           |       | 31,862                                 |       | 16,126 |   |
| Total current liabilities                                                                                       |       | 280,019                                |       | 183,584 |   |
| **Long-Term Debt**                                                                                              |       | 755,000                                |       | 487,261 |   |
| **Deferred Income Tax**                                                                                         |       | 601,688                                |       | 546,709 |   |
| **Asset Retirement Obligation**                                                                                 |       | 95,140                                 |       | 70,790 |   |
| **Other Liabilities and Deferred Credits**                                                                      |       | 21,367                                 |       | 16,654 |   |
| Total liabilities                                                                                               |       | 1,753,214                              |       | 1,304,998 |   |
| **Commitments and Contingencies (Note 5)**                                                                      |       | —                                 |       | — |   |
| **Shareholders’  Equity:**                                                                                 |       |                                   |       |   |   |
| Preferred stock, $1 par; 4,000,000 shares authorized                                                            |       | —                                 |       | — |   |
| Common stock, $1 par; 200,000,000 shares authorized,  and 64,580,639 and 63,813,283 shares issued, respectively |       | 64,581                                 |       | 63,813 |   |
| Additional capital                                                                                              |       | 943,690                                |       | 914,492 |   |
| Retained earnings                                                                                               |       | 728,723                                |       | 480,576 |   |
| Accumulated other comprehensive income                                                                          |       | 2,565                                  |       | — |   |
| Deferred compensation                                                                                           |       | (9,954                                 | )          | (3,518 | ) |
| Treasury stock (55,359 shares), at cost                                                                         |       | (1,710                                 | )          | (1,710 | ) |
| Total shareholders’ equity                                                                                 |       | 1,727,895                              |       | 1,453,653 |   |
|                                                                                                            |       | $                                      | 3,481,109  |   | $ | 2,758,651 |   |

 

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

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**POGO PRODUCING COMPANY & SUBSIDIARIESCONSOLIDATED STATEMENTS OFCASH FLOWS**
| ** **                                                                        | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                        | ** ** | **2004**                                   | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                        | ** ** | **(Expressed in thousands)**     | ** ** |
| **Cash flows from operating activities:**                                         |       |                                       |       |   |   |   |   |
| Cash received from  customers                                                     |       | $                                          | 1,324,433  |   | $ | 1,180,901 |   | $ | 701,429 |   |
| Operating,  exploration and general and administrative expenses paid              |       | (311,534                                   | )          | (229,355 | ) | (199,104 | ) |
| Income taxes paid                                                                 |       | (240,553                                   | )          | (164,008 | ) | (19,287 | ) |
| Income taxes  received                                                            |       | 381                                        |       | — |   | 25,884 |   |
| Interest paid                                                                     |       | (30,043                                    | )          | (45,527 | ) | (55,526 | ) |
| Cash received  (paid) related to price hedge contracts                            |       | —                                     |       | (15,037 | ) | 14,931 |   |
| Value added taxes  (paid) received                                                |       | (4,283                                     | )          | 9,720 |   | (7,708 | ) |
| Other                                                                             |       | 314                                        |       | 7,865 |   | 5,860 |   |
| Net cash provided  by operating activities                                        |       | 738,715                                    |       | 744,559 |   | 466,479 |   |
| **Cash flows from investing activities:**                                         |       |                                       |       |   |   |   |   |
| Capital  expenditures                                                             |       | (442,475                                   | )          | (335,615 | ) | (368,466 | ) |
| Purchase of  properties                                                           |       | (189,597                                   | )          | (189,083 | ) | — |   |
| Acquisition of  corporations, net of $11,970 cash acquired                        |       | (270,452                                   | )          | — |   | — |   |
| Purchase of current investments                                                   |       | (269,107                                   | )          | (206,585 | ) | (67,951 | ) |
| Sale of current investments                                                       |       | 208,387                                    |       | 164,305 |   | 35,951 |   |
| Proceeds from the  sale of property and tubular stock                             |       | 1,518                                      |       | 521 |   | 4,215 |   |
| Net cash used in  investing activities                                            |       | (961,726                                   | )          | (566,457 | ) | (396,251 | ) |
| **Cash flows from financing activities:**                                         |       |                                       |       |   |   |   |   |
| Borrowings under  senior debt agreements                                          |       | 2,010,000                                  |       | 854,012 |   | 703,077 |   |
| Payments under  senior debt agreements                                            |       | (1,594,000                                 | )          | (875,000 | ) | (773,080 | ) |
| Redemption of debt                                                                |       | (157,782                                   | )          | (176,578 | ) | — |   |
| Proceeds from exercise  of stock options                                          |       | 12,013                                     |       | 33,370 |   | 20,154 |   |
| Payment of cash  dividends on common stock                                        |       | (13,607                                    | )          | (12,520 | ) | (6,895 | ) |
| Payment of senior  debt acquired through corporate purchase                       |       | (50,000                                    | )          | — |   | — |   |
| Payment of  preferred dividends of a subsidiary trust                             |       | —                                     |       | — |   | (4,850 | ) |
| Payment of  financing issue costs and other                                       |       | (3,820                                     | )          | (100 | ) | (329 | ) |
| Net cash (used in)  provided by financing activities                              |       | 202,804                                    |       | (176,816 | ) | (61,923 | ) |
| Effect of exchange  rate changes on cash                                          |       | 2,189                                      |       | 739 |   | (150 | ) |
| Net increase in  cash and cash equivalents                                        |       | (18,018                                    | )          | 2,025 |   | 8,155 |   |
| Cash and cash  equivalents at the beginning of the year                           |       | 104,474                                    |       | 102,449 |   | 94,294 |   |
| Cash and cash  equivalents at the end of the year                                 |       | $                                          | 86,456     |   | $ | 104,474 |   | $ | 102,449 |   |
| **Reconciliation of net income to net cash  provided by operating activities:**   |       |                                       |       |   |   |   |   |
| Net income                                                                        |       | $                                          | 261,754    |   | $ | 290,941 |   | $ | 107,031 |   |
| Adjustments to reconcile  net income to net cash provided by operating activities |       |                                       |       |   |   |   |   |
| Cumulative effect  of change in accounting principle                              |       | —                                     |       | 4,166 |   | — |   |
| Minority interest                                                                 |       | —                                     |       | — |   | 4,140 |   |
| (Gains) losses on  sales                                                          |       | 279                                        |       | (386 | ) | (3,034 | ) |
| Depreciation,  depletion and amortization                                         |       | 365,089                                    |       | 325,820 |   | 287,809 |   |
| Dry hole and  impairment                                                          |       | 106,417                                    |       | 35,102 |   | 26,999 |   |
| Interest  capitalized                                                             |       | (14,216                                    | )          | (16,531 | ) | (24,033 | ) |
| Price hedge  contracts                                                            |       | (657                                       | )          | 8,346 |   | 17,589 |   |
| Other                                                                             |       | 26,675                                     |       | 25,989 |   | 728 |   |
| Increase  (decrease) in deferred income taxes                                     |       | (9,377                                     | )          | 51,818 |   | 70,929 |   |
| Change in assets and  liabilities:                                                |       |                                       |       |   |   |   |   |
| Increase in accounts  receivable                                                  |       | (18,284                                    | )          | (14,990 | ) | (50,521 | ) |
| Increase in  federal income taxes receivable                                      |       | (10,637                                    | )          | — |   | — |   |
| (Increase)  decrease in inventory—product                                    |       | (247                                       | )          | (1,422 | ) | 173 |   |
| (Increase)  decrease in other current assets                                      |       | 73                                         |       | (623 | ) | (12,571 | ) |
| (Increase) decrease  in other assets                                              |       | (979                                       | )          | 11,502 |   | (6,784 | ) |
| Increase in  accounts payable                                                     |       | 12,289                                     |       | 14,606 |   | 6,170 |   |
| Increase in income  taxes payable                                                 |       | 14,653                                     |       | 4,347 |   | 33,610 |   |
| Decrease in  accrued interest payable                                             |       | (5,364                                     | )          | (1,133 | ) | (352 | ) |
| Increase in  accrued payroll and related benefits                                 |       | 369                                        |       | 234 |   | 343 |   |
| Increase in other  current liabilities                                            |       | 8,266                                      |       | 993 |   | 6,377 |   |
| Increase in  deferred credits                                                     |       | 2,612                                      |       | 5,780 |   | 1,876 |   |
| Net cash provided  by operating activities                                        |       | $                                          | 738,715    |   | $ | 744,559 |   | $ | 466,479 |   |

 

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

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**POGO PRODUCINGCOMPANY & SUBSIDIARIESCONSOLIDATED STATEMENTS OFSHAREHOLDERS’ EQUITY(Expressed in thousands)**
| ** **                                                         | ** ** | ** **   | ** ** | ** **     | ** ** | ** **               | ** ** | **Accumulated** | ** ** | ** **     | ** ** | ** **   | ** ** | ** **        | ** ** | ** **  | ** ** |
|--------------------------------------------------------------------|------------|--------------|------------|----------------|------------|--------------------------|------------|-----------------|------------|----------------|------------|--------------|------------|-------------------|------------|-------------|------------|
| ** **                                                         | ** ** | ** **   | ** ** | ** **     | ** ** | ** **               | ** ** | **Other**       | ** ** | **Deferred**   | ** ** | ** **   | ** ** | ** **        | ** ** | ** **  | ** ** |
| ** **                                                         | ** ** | ** **   | ** ** | ** **     | ** ** | ** **               | ** ** | **Compre-**     | ** ** | **Compen-**    | ** ** | ** **   | ** ** | ** **        | ** ** | **Compre-** | ** ** |
| ** **                                                         | ** ** | ** **   | ** ** | ** **     | ** ** | **Retained**             | ** ** | **hensive**     | ** ** | **sation**     | ** ** | ** **   | ** ** | **Share-**        | ** ** | **hensive** | ** ** |
| ** **                                                         | ** ** | **Common**   | ** ** | **Additional** | ** ** | ** Earnings ** | ** ** | **Income**      | ** ** | **Restricted** | ** ** | **Treasury** | ** ** | **holders’** | ** ** | **Income**  | ** ** |
| ** **                                                         | ** ** | **Stock(a)** | ** ** | **Capital**    | ** ** | **(Deficit)**            | ** ** | **(Loss)**      | ** ** | **Stock**      | ** ** | **Stock**    | ** ** | **Equity**        | ** ** | **(Loss)**  | ** ** |
| **Balance at December 31,  2001**                             |       |         | 53,691     |           |       |                     | $          | 659,227         |       |           |       | $            | 102,019    |              |       |        | $          | 10,272 |   |   |   | $ | — |   |   |   | $ | (324 | ) |   | $ | 824,885 |   |   |   |
| Net income                                                         |       |         | —     |           |       |                     | —     |            |       |           | 107,031    |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 107,031 |   | $ | 107,031 |   |
| Exercise of stock options                                          |       |         | 1,022      |           |       |                     | 23,460     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 24,482 |   |   |   |
| Shares issued as  compensation                                     |       |         | 39         |           |       |                     | 1,124      |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 1,163 |   |   |   |
| Conversion of Trust  Preferred Securities                          |       |         | 6,310      |           |       |                     | 138,715    |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 145,025 |   |   |   |
| Dividends ($0.12 per  common share)                                |       |         | —     |           |       |                     | —     |            |       |           | (6,895     | )            |       |              | —     |        |       |   | — |   |   |   | — |   |   | (6,895 | ) |   |   |
| Shares received in  satisfaction of note receivable                |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | (1,386 | ) |   | (1,386 | ) |   |   |
| Unrealized loss arising  during the year on  price hedge contracts |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | (14,155    | )           |       |   | — |   |   |   | — |   |   | (14,155 | ) |   |   |
| Reclassification  adjustment included in net income                |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | (2,366     | )           |       |   | — |   |   |   | — |   |   | (2,366 | ) |   |   |
| Net unrealized losses on price  hedge  contracts                   |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | — |   | (16,521 | ) |
| Comprehensive income                                               |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | — |   | $ | 90,510 |   |
| **Balance at December 31,  2002**                             |       |         | 61,062     |           |       |                     | $          | 822,526         |       |           |       | $            | 202,155    |              |       |        | $          | (6,249 | ) |   |   | $ | — |   |   |   | $ | (1,710 | ) |   | $ | 1,077,784 |   |   |   |
| Net income                                                         |       |         | —     |           |       |                     | —     |            |       |           | 290,941    |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 290,941 |   | $ | 290,941 |   |
| Stock option activity and  other                                   |       |         | 1,573      |           |       |                     | 43,915     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 45,488 |   |   |   |
| Shares issued as  compensation                                     |       |         | 170        |           |       |                     | 6,865      |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 7,035 |   |   |   |
| Conversion of 2006 Notes                                           |       |         | 1,008      |           |       |                     | 41,186     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 42,194 |   |   |   |
| Issuance of restricted  stock, less amortization of $412           |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | —     |        |       |   | (3,518 | ) |   |   | — |   |   | (3,518 | ) |   |   |
| Dividends ($0.20 per  common share)                                |       |         | —     |           |       |                     | —     |            |       |           | (12,520    | )            |       |              | —     |        |       |   | — |   |   |   | — |   |   | (12,520 | ) |   |   |
| Unrealized loss arising  during the year on  price hedge contracts |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | (8,624     | )           |       |   | — |   |   |   | — |   |   | (8,624 | ) |   |   |
| Reclassification  adjustment included in net income                |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | 14,873     |        |       |   | — |   |   |   | — |   |   | 14,873 |   |   |   |
| Net unrealized gains on  price hedge contracts                     |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | — |   | 6,249 |   |
| Comprehensive income                                               |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | — |   | $ | 297,190 |   |
| **Balance at December 31,  2003**                             |       |         | 63,813     |           |       |                     | $          | 914,492         |       |           |       | $            | 480,576    |              |       |        | $          | — |   |   |   | $ | (3,518 | ) |   |   | $ | (1,710 | ) |   | $ | 1,453,653 |   |   |   |
| Net income                                                         |       |         | —     |           |       |                     | —     |            |       |           | 261,754    |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 261,754 |   | $ | 261,754 |   |
| Stock option activity and  other                                   |       |         | 465        |           |       |                     | 16,818     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 17,283 |   |   |   |
| Shares issued as  compensation                                     |       |         | 303        |           |       |                     | 12,380     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | 12,683 |   |   |   |
| Issuance of restricted  stock, less amortization of $1,917         |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | —     |        |       |   | (6,436 | ) |   |   | — |   |   | (6,436 | ) |   |   |
| Dividends ($0.2125 per  common share)                              |       |         | —     |           |       |                     | —     |            |       |           | (13,607    | )            |       |              | —     |        |       |   | — |   |   |   | — |   |   | (13,607 | ) |   |   |
| Unrealized gain arising during the year on  price hedge contracts  |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | 2,992      |        |       |   | — |   |   |   | — |   |   | 2,992 |   |   |   |
| Net unrealized gains on  price hedge contracts                     |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | (427       | )           |       |   | — |   |   |   | — |   |   | (427 | ) | 2,565 |   |
| Comprehensive income                                               |       |         | —     |           |       |                     | —     |            |       |           | —     |         |       |              | —     |        |       |   | — |   |   |   | — |   |   | — |   | $ | 264,319 |   |
| **Balance  at December 31, 2004**                             |       |         | 64,581     |           |       |                     | $          | 943,690         |       |           |       | $            | 728,723    |              |       |        | $          | 2,565 |   |   |   | $ | (9,954 | ) |   |   | $ | (1,710 | ) |   | $ | 1,727,895 |   |   |   |

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(a)                 Reflects both dollar and share amounts at $1.00 parvalue.

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

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**(1)   Summary of Significant Accounting Policies**

*Nature ofOperations—*

Pogo Producing Company wasincorporated in 1970. Pogo Producing Company and its subsidiaries (the “Company”)are engaged in oil and gas exploration, development, production and acquisitionactivities in the United States, both offshore in the Gulf of Mexico (primarilyin federal waters offshore Louisiana and Texas) and onshore principally in thestates of New Mexico, Texas, Louisiana and Wyoming. The Company also conductsexploration, development and production activities internationally in theKingdom of Thailand (offshore in the Gulf of Thailand), Hungary and explorationactivities in offshore New Zealand.

*Use of Estimates—*

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 andamortization of oil and gas properties and the impairment of oil and gas propertiesare determined using estimates of oil and gas reserves. There are numerousuncertainties in estimating the quantity of reserves and in projecting thefuture rates of production and timing of development expenditures. Oil and gasreserve engineering must be recognized as a subjective process of estimatingunderground accumulations of oil and gas that cannot be measured in an exactway. Provedreserves of crude oil, condensate, natural gas and natural gas liquids areestimated quantities that geological and engineering data demonstrate withreasonable certainty to be recoverable in the future from known reservoirsunder existing economic and operating conditions. Reservoirs are consideredproved if economic producibility is supported by either actual production orconclusive formation test. Proved reserves do not include, for example,hydrocarbons that may be recovered from undrilled prospects or the recovery ofwhich is otherwise subject to reasonable doubt because of uncertainty as togeology, reservoir characteristics or economic factors. Proved developedreserves are reserves that can be expected to be recovered through existingwells with existing equipment and operating methods or through the applicationof fluid injection or other improved recovery techniques confirmed by a pilotproject or operation of an installed program. Proved undeveloped oil and gasreserves are reserves that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditureis required for recompletion. Proved undeveloped reserves on undrilled acreageare limited to those drilling units offsetting productive units that arereasonably certain of production when drilled and other undrilled units whereit can be demonstrated with certainty that there is continuity of productionfrom the existing productive formation. TheSecurities and Exchange Commission provides a complete definition of proved reserves in Rule 4-10(a) ofRegulation S-X.

*Principles ofConsolidation—*

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

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

*RevenueRecognition—*

The Company follows the “sales”(takes or cash) method of accounting for oil and gas revenues. Under thismethod, the Company recognizes revenues on production as it is taken anddelivered to its purchasers. The volumes sold may be more or less than thevolumes the Company is entitled to based on its ownership interest in theproperty. These differences result in a condition known in the industry as aproduction imbalance. At December 31, 2004, the Company had takenapproximately 6,094MMcf of natural gas less than it was entitled to based on its interest incertain properties, and approximately 4,352 MMcf more than its entitlement onother properties, placing the Company in a net under-delivered position ofapproximately 1,742 MMcf of natural gas based onits working interest ownership in such properties. The Company’s crude oilimbalances are not significant. Such imbalances are reflected as adjustments toproved reserves and future cash flows in the unaudited supplementary oil andgas 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 revenueperiodically as economic quantities are accumulated. The product inventory at December 31,2004  consists of approximately399,416  barrels of crude oil andcondensate, net to the Company’s interest, and is carried at the Company’sestimated average cost of $12.67 per barrel. The product inventory at December 31,2003 consisted of approximately 495,452 barrels of crude oil and condensate,net to the Company’s interest, and is carried at its estimated average cost of$12.01 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.

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

*Oil and GasActivities and Depreciation, Depletion and Amortization—*

TheCompany follows the successful efforts method of accounting for its oil and gasactivities. Under the successful efforts method, lease acquisition costs andall development costs are capitalized. Proved oil and gas properties arereviewed annually or when circumstances suggest the need for such a review and,if required, the proved properties are written down to their estimated fairvalue. Unproved properties are reviewed quarterly to determine if there hasbeen impairment of the carrying value, with any such impairment charged toexpense in the period. Estimated fair value includes the estimated presentvalue of all reasonably expected future production, prices, and costs. Exploratorywell costs are capitalized until the results are determined. If proved reservesare not discovered, the exploratory well costs are expensed. The followingtable reflects the net changes in capitalized exploratory well costs pendingproved reserve determination during 2004, 2003 and 2002 (amounts expressed inthousands):
| ** **                                                                                     | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Balance at  January 1,                                                                    |       | $        | 18,784     |     | $          | 33,948   |       | $ | 31,968 |   |
| Additions to  capitalized exploratory well costs pending the determination of proved  reserves |       | 10,932   |       | 63       |       | 10,993   |       |
| Reclassifications  to proved oil and gas properties                                            |       | —   |       | (13,047  | )          | (9,013   | )          |
| Capitalized  exploratory well costs charged to expense                                         |       | (6,727   | )          | (2,180   | )          | —   |       |
| Balance at  December 31,                                                                  |       | $        | 22,989     |     | $          | 18,784   |       | $ | 33,948 |   |

 

Thefollowing table provides an aging of capitalized exploratory well costs basedon the date the drilling was completed and the number of wells for whichexploratory well costs have been capitalized for a period greater than one yearsince the completion of drilling (dollars expressed in thousands):
| ** **                                                                                         | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|----------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Capitalized  exploratory well costs that have been capitalized for a period of one year or  less   |       | $        | 10,932     |     | $          | 63       |       | $ | 10,993 |   |
| Capitalized  exploratory well costs that have been capitalized for a period greater than  one year |       | 12,057   |       | 18,721   |       | 22,955   |       |
| Balance at  December 31,                                                                      |       | $        | 22,989     |     | $          | 18,784   |       | $ | 33,948 |   |
| Number of  exploratory wells that have costs capitalized for a period greater than one  year       |       | 12       |       | 21       |       | 23       |       |

 

As of December 31, 2004, exploratory well coststhat have been capitalized for a period greater than one year since thecompletion of drilling include costs of $7.9 million and $3.8 million that havebeen capitalized since 2001 and 2000, respectively, related to two projects.

As of December 31, 2004, more than 91% of the capitalizedwell costs that have been capitalized for a period greater than one year relateto the Company’s Gulf of Thailand concession. It has been the Company’sexperience that the assignment of proved reserves in its Thailand Concession isoften delayed for more than one year due to the drilling of subsequentexploratory wells and the need for a production license grant from thegovernment of the Kingdom of Thailand. In regards to the costs capitalized at December 31,2004, the Company continues to actively pursue government approval foradditional production licenses on its Thailand concession, a process which hashistorically averaged approximately 3 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

years and has taken up tosix years. To the extent such licenses are not awarded or proved reserves cannotbe assigned, such costs will be charged to earnings in the period suchdetermination is made.

Interest costs related to financing major oil and gasprojects in progress are capitalized until the projects are evaluated or untilthe projects are substantially complete and ready for their intended use if theprojects are evaluated as successful. Other exploratory costs are expensed asincurred. The provision for depreciation, depletion and amortization is basedon the capitalized costs as determined above, and is computed on a cost centerby cost center basis using the units of production method, with leaseacquisition costs amortized over total proved reserves and other costsamortized over proved developed reserves. The Company generally creates costcenters on a field-by-field basis for oil and gas activities in the Gulf ofMexico and the Gulf of Thailand. Generally, the Company establishes costcenters on the basis of an oil or gas trend or play for its onshore oil and gasactivities. As described further below, the Company’s method of accounting forasset retirement obligations (i.e. future abandonment costs) changed effective January 1, 2003.

The Company has from time to time disposed of certainnon-core properties and other assets that it considers to be under performing,to have little or no remaining upside potential, or which face significantfuture expenditures that would result in an unacceptable rate of return. Referto the captions “Gains on sales” and “Proceeds from the sale of property andtubular 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.

*Income Taxes—*

Deferred income tax assetsand liabilities are recognized for temporary differences between the basis ofassets and liabilities for financial reporting and tax purposes. Changes in taxlegislation are included in the relevant computations in the period in whichsuch changes are effective. Deferred tax assets are reduced by a valuationallowance for the amount of any tax benefit when the Company believes it ismore likely than not that such benefits will not be realized. Note 3 containsinformation about the Company’s income taxes, including the components ofincome tax provision and the composition of deferred income tax assets andliabilities.

*Price RiskManagement—*

The Company from time to time enters into commodityprice hedging contracts with respect to its oil and gas production to achieve amore predictable cash flow, as well as reduce its exposure to price volatility.The Company follows the provisions of Statement of Financial Accounting Standards No. 133 “Accounting forDerivative Instruments and Hedging Activities” (“SFAS 133”). SFAS 133, asamended, established accounting and reporting standards requiring that everyderivative instrument (including certain derivative instruments embedded inother contracts) be recorded in the balance sheet as either an asset orliability measured at its fair value. The statement requires that changes inthe derivative’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 derivative instruments 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

used by the Company andthe historical volatility of oil and gas commodity prices, the Company expectsthat SFAS 133 could increase volatility in the Company’s earnings and othercomprehensive income for future periods during which derivative instruments areoutstanding.

SFAS 133 provides that theeffective portion of the gain or loss on a derivative instrument designated andqualifying 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.

*Accounting forStock-Based Compensation—*

The Company’s incentive plans authorize awards grantedwholly or partly in common stock (including rights or options which may beexercised for or settled in common stock) to key employees and non-employeedirectors (collectively, “Stock Awards”). Prior to January 1, 2003, theCompany accounted for Stock Awards using the intrinsic value recognitionprovisions of APB Opinion No. 25, “Accounting for Stock Issued toEmployees,” and related interpretations. Under this method, the Company recognizedno compensation expense for stock options granted when the exercise price ofthe options was equal to or greater than the quoted market price of the Company’scommon stock on the grant date. Effective January 1, 2003, the Companyadopted the fair value recognition provisions of SFAS No. 123, “Accountingfor Stock Based Compensation” (“SFAS 123”), and the prospective methodtransition provisions of SFAS No. 148, “Accounting for Stock BasedCompensation—Transition and Disclosure—an amendment of FAS No. 123”  (“SFAS148”), for all Stock Awards granted, modified or settled after January 1,2003. Compensation cost for stock options and other stock-based compensation isrecognized on a straight-line basis over the vesting period for the applicableStock Award. The Company granted Stock Awards covering 333,400 shares of commonstock with a fair market value of $13,491,000 during the year ended December 31,2004. The Company granted Stock Awards covering 547,000 shares of common stockwith a fair market value of $9,920,000 during the year ended December 31,2003.

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

Thefollowing table illustrates the effect on the Company’s net income and earningsper share if the fair value recognition provisions of SFAS 123 for employeestock-based compensation had been applied to all Stock Awards outstandingduring the years ended December 31, 2004, 2003 and 2002 (in thousands ofdollars, except per share amounts):
| ** **                                                                                                                               | ** ** | **Year Ended December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                                                               | ** ** | **2004**                              | ** ** | **2003** | ** ** | **2002** | ** ** |
| Net income, as  reported                                                                                                                 |       | $                                     | 261,754    |   | $ | 290,941 |   | $ | 107,031 |   |
| Add: Employee  stock-based compensation expense, net of related tax effects, included in net  income, as reported                        |       | 3,006                                 |       | 1,408 |   | 756 |   |
| Deduct: Total  employee stock-based compensation expense, determined under fair value method  for all awards, net of related tax effects |       | (6,759                                | )          | (7,017 | ) | (6,466 | ) |
| Net income, pro  forma                                                                                                                   |       | $                                     | 258,001    |   | $ | 285,332 |   | $ | 101,321 |   |
| Earnings per share:                                                                                                                      |       |                                  |       |   |   |   |   |
| Basic—as reported                                                                                                                   |       | $                                     | 4.10       |   | $ | 4.65 |   | $ | 1.85 |   |
| Basic—pro forma                                                                                                                     |       | $                                     | 4.04       |   | $ | 4.56 |   | $ | 1.75 |   |
| Diluted—as reported                                                                                                                 |       | $                                     | 4.06       |   | $ | 4.54 |   | $ | 1.77 |   |
| Diluted—pro forma                                                                                                                   |       | $                                     | 4.01       |   | $ | 4.45 |   | $ | 1.68 |   |

 

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 2004, 2003 and 2002,respectively: risk free interest rates of 3.00%, 2.30% and 4.20%, expectedvolatility of 25.7%, 28.4% and 33.9%, dividend yields of 0.48%,  0.61% and 0.51%, and an expected life of theoptions of three and a half, three and seven years.

*Consolidated Statements of Cash Flows—*

For the purpose of cashflows, the Company considers all highly liquid investments with a maturity dateof three months or less to be cash equivalents. Significant transactions mayoccur which do not directly affect cash balances and, as such, are not disclosedin the Consolidated Statements of Cash Flows. Certain such non-cashtransactions are disclosed in the Consolidated Statements of Shareholders’Equity relating to shares issued as compensation.

CurrentInvestments—

AtDecember 31, 2004 and 2003, the Company held $135.0 million and $74.3 million,respectively, of AAA ratedauction rate municipalbonds and variable rate municipal demand notes classified as available for sale securities. The Company’s investments in these securities arerecorded at cost, which approximates fair market value due to their variableinterest rates, which typically reset every 7 to 35 days, and, despite thelong-term nature of their stated contractual maturities, the Company has theability to quickly liquidate these securities. As a result, there were nocumulative gross unrealized holding gains (losses) or gross realized gains(losses) from these current investments. All income generated from thesecurrent investments was recorded as interest income.

Revisionin the Classification of Certain Securities—

In connection with the preparation of this report,the Company concluded that it was appropriate to classify our auction ratemunicipal bonds and variable rate municipal demand notes as currentinvestments. 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

Previously, such investments had been classified ascash and cash equivalents. Accordingly, the classification in 2003 has beenrevised to report $74.3 millionof these securities as current investments in a separate line item on theConsolidated Balance Sheet. Corresponding adjustments have also been made to the Consolidated Statement of Cash Flowsfor the periods ended December 31, 2003 and 2002 to reflect the gross purchasesand sales of these securities as investing activities rather than as cash and cash equivalents. Forthe fiscal years ended December 31, 2003 and 2002 net cash used in investingactivities related to these current investments of $42.3 million and $32.0 million, respectively, was previouslyincluded in cash and cash equivalents in the Consolidated Statement of CashFlows. This change in classification does not affect previously reported cashflows from operations or from financing activities, or the previously reported Consolidated Statements ofIncome for any period.

*Foreign Currency*—

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

*Prior YearReclassifications—*

Certain prior year amountshave been reclassified to conform with the current year presentation. Suchreclassifications had no effect on the Company’s operating income, net incomeor shareholders’ equity.

*Treasury Stock—*

On January 25, 2005,the Company announced a plan to repurchase, through open market or privatelynegotiated transactions, not less than $275 million nor more than $375million of its common stock.  Therepurchased shares will be accounted for as treasury stock. As of March 1, 2005, the Company had completed the purchase of 940,200 shares at a totalcost of $41.5 million.

*Recent AccountingPronouncements—*

The Financial Accounting Standards Board (“FASB”) hasissued three new pronouncements relevant to the Company’s accounting. These areStatement of Financial Accounting Standards No. 123 (revised 2004) (“SFAS123R”), “Share-Based Payment”, Statement of Financial Accounting Standards No. 153(“SFAS 153”), “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29”and FASB Staff Position FAS 109-2 (“FSP FAS 109-2”), “Accountingand Disclosure Guidance for the Foreign Earnings Repatriation Provision Withinthe American Jobs Creation Act of 2004”.

*SFAS 123R.  *SFAS123R will require compensation costs related to share-based paymenttransactions to be recognized in the financial statements. With limitedexceptions, the amount of compensation cost will be measured based on thegrant-date fair value of the equity orliability instruments issued. In addition, liability awards will be remeasuredeach reporting period. Compensation cost will be recognized over the periodthat an employee provides service in exchange for the award. Statement 123(R) replacesFASB Statement No. 123 (“SFAS 123”), “Accounting for Stock-Based Compensation”, and supersedes APB Opinion No. 25,“Accounting for Stock Issued to Employees”. SFAS 123R is  effective as of the first interim or annualreporting period that begins after June 15, 2005. 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

The Company currentlyfollows the provisions of SFAS 123 and the adoption of SFAS 123R is notexpected to have a material effect on the Company’s financial statements.

*SFAS 153.  *SFAS153**was a result of an effort bythe FASB and the International Accounting Standards Board (“IASB”) to improvefinancial reporting by eliminating certain narrow differences between theirexisting accounting standards. One such difference was the exception from fairvalue measurement in APB Opinion No. 29, *Accountingfor Nonmonetary Transactions*, for nonmonetary exchanges of similarproductive assets. SFAS 153 replaces this exception with a general exceptionfrom fair value measurement for exchanges of nonmonetary assets that do nothave commercial substance. A nonmonetary exchange has commercial substance ifthe future cash flows of the entity are expected to change significantly as aresult of the exchange. SFAS 153 will be applied prospectively and is effectivefor nonmonetary asset exchanges occurring in fiscal periods beginning after June 15,2005. Earlier application is permitted for nonmonetary asset exchangesoccurring in fiscal periods beginning after the date of issuance of thisStatement. The adoption of SFAS 153 is not expected to have a material effecton the Company’s financial statements.

*FSP FAS109-2.  *In December 2004, the FASB staffissued FSP FAS 109-2 to provide accounting and disclosure guidance forthe repatriation provisions included in the American Jobs Creation Act of 2004(the “Act”). The Act introduced a special limited-time dividends receiveddeduction on the repatriation of certain foreign earnings to a U.S. taxpayer.As a result, an issue has arisen as to whether an enterprise should be allowedadditional time beyond the financial reporting period in which the Act wasenacted to evaluate the effects of the Act on its plan for reinvestment orrepatriation of foreign earnings for purposes of applying Statement 109. Thefollowing are the key points relevant to the Company’s position:

·       Anenterprise is allowed additional time beyond the financial reporting period ofenactment to evaluate the effect of the Act without undermining the entity’sassertion that repatriation of foreign earnings is not expected within theforeseeable future.

·       Anenterprise should recognize the income tax effect when it decides on a plan forreinvestment or repatriation of foreign earnings. This decision may occur instages, and each stage may occur at a different time. Also, before its plan forreinvestment or repatriation is finalized, an enterprise may decide on a rangeof amounts that it will repatriate. In this situation, the FSP requiresrecognition of the income tax effect of the lowest amount within the range.

·       Ifan enterprise has recognized a deferred tax liability for some, or all, of itsunremitted foreign earnings because it did not overcome the presumption ofrepatriation of foreign earnings, it should continue to presume repatriation ofthose earnings as well as current foreign earnings that are not expected to beindefinitely reinvested. The enterprise shall measure the income tax effects ofsuch repatriation without the effects of the repatriation provision until ithas decided on a plan for  repatriation.

·       Anenterprise that has not yet completed its evaluation of the repatriationprovision should make certain disclosures. Additional disclosures are requiredin the period an enterprise completes its evaluation

The Company has adoptedthe disclosure requirements of FSP FAS 109-2 and is currently evaluatingthe effects of the Act. The Company expects to be in a position to finalize itsassessment shortly after passage of technical corrections to the Act.

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

**(2)   Earningsper Share**

Earningsper common share (basic earnings per share) are based on the weighted averagenumber of shares of common stock outstanding during the periods. Earnings percommon share and potential common share (diluted earnings per share) considerthe effect of dilutive securities as set out below in thousands, except pershare amounts.
| ** **                                                                                                                                                                                               | ** ** | **For the Year Ended December 31, 2004** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                                                                                                                                                               | ** ** | **  Income(a)  **                                  | ** ** | ** Shares ** | ** ** | ** Per Share ** | ** ** |
| **Basic  earnings per share**                                                                                                                                                                            |       |                                                                   | $          | 261,754 |   |   | 63,848 |   |   | $ | 4.10 |   |   |
| 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              |       |                                                                   | —     |   |   | 545 |   |   |   |   |   |
| **Diluted  earnings per share**                                                                                                                                                                          |       |                                                                   | $          | 261,754 |   |   | 64,393 |   |   | $ | 4.06 |   |   |
| 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 |       |                                                                   | $          | — |   |   | 25 |   |   | $ | 49.02 |   |   |

 
| ** **                                                                                                                                                                                               | ** ** | **For the Year Ended December 31, 2003** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                                                                                                                                                               | ** ** | **  Income(a)  **                                  | ** ** | ** Shares ** | ** ** | ** Per Share ** | ** ** |
| **Basic  earnings per share**                                                                                                                                                                            |       |                                                                   | $          | 295,107 |   |   | 62,538 |   |   | $ | 4.72 |   |   |
| Effect of potential  dilutive securities:                                                                                                                                                                |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Shares assumed issued from the exercise of options  to purchase common shares, net of treasury shares assumed purchased from  the proceeds, at the average market price for the period                   |       |                                                                   | —     |   |   | 683 |   |   |   |   |   |
| Interest expense incurred, net of taxes, and shares  issued related to  the assumed conversion at $42.185 per share of the 2006 Notes (redeemed  July 7, 2003)                                      |       |                                                                   | 2,106      |   |   | 1,391 |   |   |   |   |   |
| **Diluted  earnings per share**                                                                                                                                                                          |       |                                                                   | $          | 297,213 |   |   | 64,612 |   |   | $ | 4.60 |   |   |
| Antidilutive  securities:                                                                                                                                                                                |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Shares assumed  not issued from options to purchase common shares as the exercise prices are  above the average market price for the period or the effect of the assumed  exercise would be antidilutive |       |                                                                   | $          | — |   |   | 467 |   |   | $ | 41.87 |   |   |

----

(a)           Representsincome before cumulative effect of change in accounting principle.

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

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

 

**(3)   IncomeTaxes**

Thecomponents of income before income taxes and cumulative effect of change inaccounting principle for each of the three years in the period ended December 31,2004, are as follows (expressed in thousands): 
| ** **                                                                          | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| United States                                                                       |       | $        | 396,068    |     | $          | 364,097  |       | $ | 101,349 |   |
| Foreign                                                                             |       | 100,335  |       | 151,132  |       | 103,462  |       |
| Income before  income taxes and cumulative effect of change in accounting principle |       | $        | 496,403    |     | $          | 515,229  |       | $ | 204,811 |   |

 

Thecomponents of income tax expense (benefit) for each of the three years in theperiod ended December 31, 2004, are as follows (expressed in thousands):
| ** **         | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|--------------------|------------|----------|------------|----------|------------|----------|------------|
| Current            |       |     |       |     |       |     |       |
| United States      |       | $        | 147,759    |     | $          | 116,813  |       | $ | 15,497 |   |
| Foreign            |       | 96,262   |       | 51,491   |       | 11,351   |       |
| Deferred           |       |     |       |     |       |     |       |
| United States      |       | 3,896    |       | 26,375   |       | 32,451   |       |
| Foreign            |       | (13,268  | )          | 25,443   |       | 38,481   |       |
| Income tax expense |       | $        | 234,649    |     | $          | 220,122  |       | $ | 97,780 |   |

 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

Totalincome tax expense for each of the three years in the period ended December 31,2004, differs from the amounts computed by applying the statutory federalincome tax rate to income before taxes as follows (expressed as percent ofpretax income):
| ** **                                           | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Federal statutory  income tax rate                   |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| Increases resulting from:                            |       |     |       |     |       |     |       |
| Foreign income taxed at different rates              |       | 6.4      |       | 4.6      |       | 7.8      |       |
| Recognition of valuation allowance on foreign losses |       | 2.2      |       | —   |       | —   |       |
| U.S. taxes on repatriation of foreign earnings.      |       | 1.1      |       | 1.9      |       | 2.3      |       |
| State income taxes, net of federal benefits          |       | 1.2      |       | 0.7      |       | 0.5      |       |
| Other                                                |       | 1.4      |       | 0.5      |       | 2.2      |       |
|                                                 |       | 47.3     | %          | 42.7     | %          | 47.8     | %          |

 

Theprincipal components of the Company’s deferred income tax assets andliabilities at December 31, 2004 and 2003 (expressed in thousands) are asfollows: 
| ** **                                                                  | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                  | ** ** | **2004**              | ** ** | **2003** | ** ** |
| Deferred tax  assets:                                                       |       |                  |       |   |   |
| Foreign deferred tax assets and net operating loss  carry forwards          |       | $                     | 12,143     |   | $ | 2,795 |   |
| Valuation allowance of deferred tax assets and  foreign net operating loss  |       | (12,143               | )          | (379 | ) |
| Other                                                                       |       | 16,252                |       | 9,938 |   |
|                                                                        |       | 16,252                |       | 12,354 |   |
| Deferred tax  liabilities:                                                  |       |                  |       |   |   |
| Book basis in excess of tax basis for oil and gas  properties and equipment |       | (613,664              | )          | (553,967 | ) |
| Other                                                                       |       | (9,195                | )          | (8,004 | ) |
|                                                                        |       | (622,859              | )          | (561,971 | ) |
| Net deferred tax  liability                                                 |       | $                     | (606,607   | ) | $ | (549,617 | ) |

 

Book basis in excess of tax basis for oil and gasproperties and equipment primarily results from differing methodologies forrecording property costs and depreciation, depletion and amortization underUnited States generally accepted accounting principles and income taxreporting. In addition, the Company recorded a deferred tax liability resultingfrom book and tax basis differences of the acquired corporations during 2004.

During 2003, the Company utilized its remainingThailand net operating loss carryforwards to offset current year income taxes. Asof December 31, 2004 the Company had $20,595,000 in net operating losscarryforwards available to offset future income tax in Hungary. Such netoperating loss carryforwards do not expire. In addition, there are additionalloss carryforwards of $44,606,000 that may be available pending approval of theHungarian tax authorities

Where the Company’s present intention is to reinvestthe unremitted earnings in its foreign operations, the Company does not providefor U.S. income taxes on unremitted earnings of foreign 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

subsidiaries. Unremittedearnings of foreign subsidiaries for which U.S. income taxes have not beenprovided are approximately $122,328,000 at December 31, 2004. It is notpracticable to determine the amount of U.S. income taxes that would be payableupon remittance of the assets that represent those earnings.

On October 22, 2004, thePresident signed the American Jobs Creation Act of 2004 (the “Act”). The Actcreates a temporary incentive for U.S. corporations to repatriate accumulatedincome earned abroad by providing an 85% dividend received deduction forcertain dividends from controlled foreign corporations. The deduction issubject to a number of limitations and, as of March 1,2005, uncertainty remains as to how to interpret numerous provisions of theAct. As a result, the Company is not yet in a position to decide whether, andto what extent, it might repatriate foreign earnings that have not yet beenremitted to the U.S. If certain technical corrections to the Act are passed,the Company may consider repatriating an amount up to $195,669,000 of the cashand current investments held byinternational subsidiaries as of December 31, 2004, with an associated taxliability of approximately $10.2 million (assuming 15% of such cash is subjectto tax at the U.S. statutory rate).

**(4)   Long-TermDebt**

Long-term debt at December 31,2004 and 2003, consists of the following (dollars expressed in thousands): 
| ** **                                                                                                              | ** ** | **December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                              | ** ** | **2004**              | ** ** | **2003** | ** ** |
| Senior debt—                                                                                                       |       |                  |       |   |   |
| Bank revolving  credit agreement:                                                                                       |       |                  |       |   |   |
| LIBOR based loans, borrowings at December 31,  2004 and 2003 at interest rates of 3.665% and 2.3125%, respectively |       | $                     | 515,000    |   | $ | 135,000 |   |
| LIBOR Rate Advances, borrowings at December 31,  2004 at an interest rate of 3.5275%                               |       | 40,000                |       | — |   |
| Swing line money market loans, borrowings at  December 31, 2003 at an interest rate of 2.375%.                     |       | —                |       | 4,000 |   |
| Total senior debt                                                                                                       |       | 555,000               |       | 139,000 |   |
| Subordinated debt—                                                                                                 |       |                  |       |   |   |
| 103¤8% Senior  subordinated notes, due 2009                                                                        |       | —                |       | 150,000 |   |
| 81¤4% Senior  subordinated notes, due 2011                                                                         |       | 200,000               |       | 200,000 |   |
| Total  subordinated debt                                                                                                |       | 200,000               |       | 350,000 |   |
| Unamortized  discount on 2009 Notes                                                                                     |       | —                |       | (1,739 | ) |
| Long-term debt                                                                                                          |       | $                     | 755,000    |   | $ | 487,261 |   |

 

On December 16, 2004, the Company entered into a newcredit agreement (the “Credit Facility”) , replacing its then existing creditagreement dated as of March 8, 2001, as amended. The Credit Facility is withvarious financial institutions and provides for revolving credit borrowings upto a maximum principal amount of $750,000,000 at any one time outstanding, withborrowings not to exceed a borrowing base determined at least semiannuallyusing the administrative agent’s usual and customary criteria for oil and gasreserve valuation, adjusted for incurrences of other indebtedness since thelast redetermination of the borrowing base. As of December 31, 2004, theborrowing base was $900,000,000. The Credit Facility 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

provides that in specifiedcircumstances involving an increase in ratings assigned to the Company’s debt,the Company may elect for the borrowing base limitation to no longer apply torestrict available borrowings. The Credit Facility also includes procedures foradditional financial institutions selected by the Company to become lendersunder the agreement, or for any existing lender to increase its commitment inan amount approved by the Company and the lender, subject to a maximum of$250,000,000 for all such increases in commitments of new or existing lenders.Additionally, the Credit Facility permits short-term swing-line loans up to$10,000,000 and the issuance of letters of credit up to $75,000,000, which ineach case reduce the credit available for revolving credit borrowings. Alloutstanding amounts owed under the Credit Facility become due and payable nolater than the final maturity date of December 16, 2009, and are subject to accelerationupon the occurrence of events of default which the Company considers usual andcustomary for an agreement of this type, including failure to make paymentsunder the credit agreement, non-performance of covenants and obligationscontinuing beyond any applicable grace period, default in the payment of otherindebtedness in excess in principal amount of $25,000,000 or a defaultaccelerating or permitting the acceleration of any such indebtedness, or theoccurrence of a “change in control” of the Company, including the acquisitionof beneficial ownership of in excess of 50% of its capital stock. If at anytime the outstanding credit extended under the agreement exceeds the applicableborrowing base, the deficiency is required to be amortized in four monthlyinstallments commencing 90 days after the deficiency arises, and until thedeficiency is eliminated, increases in some applicable interest rate marginsapply.

Borrowings under the Credit Facility bear interest, atthe Company’s election, at a prime rate or Eurodollar rate, plus in each casean applicable margin. In addition, a commitment fee is payable on the unusedportion of each lender’s commitment. The applicable interest rate margin variesfrom 0% to 0.25% in the case of borrowings based on the prime rate and from1.00% to 2.00% in the case of borrowings based on the Eurodollar rate,depending on the utilization level in relation to the borrowing base and, inthe case of Eurodollar borrowings, ratings assigned to the Company’s debt.

The Credit Facility contains various covenants,including among others restrictions on liens, restrictions on incurring otherindebtedness if a default under the credit agreement exists or would result orif a borrowing base deficiency would result, restrictions on dividends andother restricted payments if a default under the credit agreement exists orwould result, restrictions on mergers, restrictions on investments, andrestrictions on hedging activity of a speculative nature or with counterpartieshaving credit ratings below specified levels. Financial covenants include acovenant not to permit the Company’s ratio of consolidated debt to consolidatedtotal capitalization (determined without reduction for any non-cash writedowns after the date of the credit agreement) to exceed 60% at any time, and not to permit the Company’sconsolidated ratio of EBITDAX to Fixed Charges (as those terms are defined inthe credit agreement) for the four most recent fiscal quarters to be less than or equal to 2.5 to 1.0 at the endof any quarter.

The Company gave notice on March 18, 2004 of itsintent to redeem all $150,000,000 of its 103¤8% SeniorSubordinated Notes due 2009 (the “2009 Notes”) at 105.188% of their face amount.On April 19, 2004, the Company paid $157,782,000 (excluding accruedinterest) in cash to holders of the 2009 Notes. The cash redemption payment wasfunded through borrowings under the Company’s existing bank credit facility. TheCompany recorded a pre-tax expense on the redemption of the 2009 Notes of$10,893,000 in “Loss on debt extinguishment” during the year ended December 31,2004.

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

On April 10, 2001,the Company issued $200,000,000 principal amount of 2011 Notes. The 2011 Notesbear interest at a rate of  81¤4%,payable semi-annually in arrears on April 15 and October 15 of eachyear. The 2011 Notes are general 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. The Company, at its option, may redeem the 2011 Notes in wholeor in part, at any time on or after April 15, 2006, at a redemption priceof 104.125% of their principal value and decreasing percentages thereafter. Theindenturegoverning the 2011 Notes also imposescertain covenants on the Company including covenants limiting: incurrence ofindebtedness including senior indebtedness; restricted payments; the issuanceand sales of restricted subsidiary capital stock; transactions with affiliates;liens; disposition of proceeds of assets sales; non-guarantor restricted subsidiaries;dividends and other payment restrictions affecting restricted subsidiaries; andmerger, consolidations and the sale of assets.

**(5)   Commitments andContingencies**

The Company has commitments for operating leases(primarily for office space) in Houston, Midland, Fort Worth, Bangkok,Budapest, for an FPSO and FSO in the Gulf of Thailand, and for other equipment(including gas compressors). Rental expense for office space was $3,096,000 in2004, $2,942,000 in 2003, and $2,821,000 in 2002. Expenses for the FPSO leasewere approximately $10,600,000 in each of the years 2004, 2003 and 2002.Expenses for the FSO were approximately $4,000,000 in each of the years 2004,2003 and 2002. Rental expense for other equipment was $5,497,000 in 2004,$4,241,000 in 2003 and $2,022,000 in 2002.

Future minimum leasepayments related to the Company’s operating leases at December 31, 2004are approximately $23,500,000 in 2005; $23,500,000 in 2006; $20,200,000 in2007; $16,800,000 in 2008; $9,900,000 in 2009 and $47,100,000 thereafter. Whererented equipment such as compressors is considered essential to the operationof the lease, the Company has assumed that such equipment will be leased forthe estimated productive life of the reserves, even if the contract terminatesprior to such date.

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

**(6)   GeographicInformation**

TheCompany’s reportable geographic information is identified below. The accountingpolicies of the geographic regions are the same as those described in thesummary of significant accounting policies (Note 1). The Company evaluatesperformance based on operating income (loss). Financial information bygeographic region is presented below: 
| ** **                                                | ** ** | **2004**                               | ** ** | **2003** | ** ** | **2002**  | ** ** |
|-----------------------------------------------------------|------------|----------------------------------------|------------|----------|------------|-----------|------------|
| ** **                                                | ** ** | **(Expressed in thousands)** | ** ** |
| **Long-Lived Assets:**                                    |       |                                   |       |     |       |      |       |
| As of  December 31,                                  |       |                                   |       |     |       |      |       |
| United States                                             |       | $                                      | 2,576,120  |     | $          | 1,943,564 |       | $ | 1,780,431 |   |
| Kingdom of Thailand                                       |       | 433,032                                |       | 420,856  |       | 378,260   |       |
| Other                                                     |       | 42                                     |       | 11,421   |       | 358       |       |
| Total                                                     |       | $                                      | 3,009,194  |     | $          | 2,375,841 |       | $ | 2,159,049 |   |
| **Capital Expenditures:**(including interest capitalized) |       |                                   |       |     |       |      |       |
| For the year  ended December 31,                     |       |                                   |       |     |       |      |       |
| United States                                             |       | $                                      | 931,444    |     | $          | 376,430   |       | $ | 269,250 |   |
| Kingdom of Thailand                                       |       | 122,748                                |       | 132,409  |       | 112,440   |       |
| Other                                                     |       | 32,033                                 |       | 11,485   |       | —    |       |
| Total                                                     |       | $                                      | 1,086,225  |     | $          | 520,324   |       | $ | 381,690 |   |
| **Revenues:**                                             |       |                                   |       |     |       |      |       |
| For the year  ended December 31,                     |       |                                   |       |     |       |      |       |
| United States                                             |       | $                                      | 987,688    |     | $          | 858,505   |       | $ | 542,014 |   |
| Kingdom of Thailand                                       |       | 335,237                                |       | 303,470  |       | 212,763   |       |
| Other                                                     |       | 54                                     |       | 21       |       | 77        |       |
| Total                                                     |       | $                                      | 1,322,979  |     | $          | 1,161,996 |       | $ | 754,854 |   |
| **Depreciation, depletion, and  amortization expense:**   |       |                                   |       |     |       |      |       |
| For the year  ended December 31,                     |       |                                   |       |     |       |      |       |
| United States                                             |       | $                                      | 258,467    |     | $          | 237,853   |       | $ | 221,646 |   |
| Kingdom of Thailand                                       |       | 106,556                                |       | 87,906   |       | 66,099    |       |
| Other                                                     |       | 66                                     |       | 61       |       | 64        |       |
| Total                                                     |       | $                                      | 365,089    |     | $          | 325,820   |       | $ | 287,809 |   |
| **Operating income (loss):**                              |       |                                   |       |     |       |      |       |
| For the year  ended December 31,                     |       |                                   |       |     |       |      |       |
| United States                                             |       | $                                      | 424,790    |     | $          | 399,678   |       | $ | 138,934 |   |
| Kingdom of Thailand                                       |       | 147,953                                |       | 151,830  |       | 103,021   |       |
| Other                                                     |       | (48,264                                | )          | (3,779   | )          | (1,782    | )          |
| Total                                                     |       | $                                      | 524,479    |     | $          | 547,729   |       | $ | 240,173 |   |

 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

**(7)   Sales to MajorCustomers**

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, saleshave been presented for all three years for those customers who have exceeded10% of revenues in any given year (expressed in thousands):
| ** **                              | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|-----------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Shell Trading  Company                  |       | $        | 147,076    |     | $          | 161,451  |       | $ | 103,714 |   |
| Pacific Petroleum and  Trading Co. Ltd. |       | 135,160  |       | 30,018   |       | —   |       |
|                                         |            |          |            |          |            |          |            |  |  |  |

 

**(8)**   Credit Risk

Substantially all of the Company’s accounts receivableat December 31, 2004 and 2003, result from oil and gas sales and jointinterest billings to other companies in the energy industry. This concentrationof customers and joint interest owners may impact the Company’s overall creditrisk, either positively or negatively, in that these entities may be similarlyaffected by industry-wide changes in economic or other conditions. Suchreceivables are generally not collateralized.  As of December 31, 2004 and 2003, theCompany had provided reserves for receivables from specifically identifiedreceivables from customers and joint interest owners that are considereddoubtful of collection of $3,882,000 and $3,810,000, respectively.

A substantial portion of the Company’s oil and gasoperations are conducted in Southeast Asia, and a substantial portion of itsnatural gas and liquids hydrocarbon production are sold there. Southeast Asiain general, and the Kingdom of Thailand in particular, experienced severeeconomic difficulties in 1997 and 1998 which were characterized by sharplyreduced economic activity, illiquidity, highly volatile foreign currencyexchange rates and unstable stock markets. Since that time, the economicsituation in the Kingdom of Thailand has generally stabilized and begun toimprove. However, as with most emerging market economies, the Thai economyremains particularly sensitive to worldwide economic trends and to the effectof the recent tsunami disaster in the Kingdom. The economic health of the Thaieconomy and its effect on the volatility of the Thai Baht against the U.S.dollar will continue to have a material impact on the Company’s operations inthe Kingdom of Thailand, as well as the prices that the company receives forits 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 are diversified between cash and short-terminvestments.

**(9)**   Employee Benefit Plans

The Company has a tax-advantaged savings plan in whichall U.S. salaried employees may participate. Under such plan, a participatingemployee may allocate up to 30% of their salary, up to a maximum allowed bylaw, and the Company will then match the employee’s contribution on a dollarfor dollar basis up to the lesser of 6% of the employee’s salary or $13,000 in2004. Funds contributed by the employee and the matching funds contributed bythe Company are held in trust by a bank trustee in six separate funds. Amountscontributed and earnings and accretions thereon may be used to purchase sharesof the Company’s common stock, invest in a money market fund or invest in fourstock, bond, or blended stock 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

and bond mutual fundsaccording to instructions from the employee. The Company contributed $1,360,000to the savings plan in 2004, $1,233,000 in 2003, and $1,068,000 in 2002.

The Company has adopted a trusteed retirement plan forits U.S. salaried employees. The benefits are based on years of service and theemployee’s average compensation for five consecutive years within the final tenyears of service which produce the highest average compensation. The Companymakes annual contributions to the plan in the amount of retirement plan costaccrued or the maximum amount that can be deducted for federal income taxpurposes. The Company does not expect to make a contribution to the plan in2005. The plan’s investment strategy and goals are to ensure, over thelong-term life of the retirement plan, an adequate pool of sufficiently liquidassets to support the benefit obligations to participants, retirees andbeneficiaries. Investment objectives are long-term in nature covering typicalmarket cycles of three to five years.

Although the Company has no obligation to do so, theCompany currently provides full medical benefits to its retired U.S. employeesand dependents. For current employees, the Company assumes all or a portion ofpost-retirement medical and term life insurance costs based on the employee’sage and length of service with the Company. The post-retirement medical planhas no assets and is currently funded by the Company on a pay-as-you-go basis. Theexpected Company contributions to the post-retirement medical plan during 2005are approximately $554,000.

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

The following table setsforth the plans’ status (in thousands of dollars) as of December 31, 2004and 2003. The Company uses a December 31 measurement date for its plans.
| ** **                                     | ** ** | **Retirement Plan** | ** ** | **Post-Retirement  Medical Plan** | ** ** |
|------------------------------------------------|------------|--------------------------|------------|----------------------------------------|------------|
| ** **                                     | ** ** | **2004**                 | ** ** | **2003**                               | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Change in benefit obligation**               |       |                     |       |                                   |       |   |   |   |   |
| Benefit obligation at beginning of year        |       | $                        | 29,519     |                                   | $          | 24,297 |   | $ | 17,145 |   | $ | 15,067 |   |
| Service cost                                   |       | 2,631                    |       | 2,248                                  |       | 1,385 |   | 1,102 |   |
| Interest cost                                  |       | 1,751                    |       | 1,546                                  |       | 1,044 |   | 915 |   |
| Benefits paid                                  |       | (1,302                   | )          | (340                                   | )          | (356 | ) | (338 | ) |
| Actuarial loss                                 |       | 4,259                    |       | 1,768                                  |       | 1,984 |   | 399 |   |
| Benefit obligation at end of year              |       | $                        | 36,858     |                                   | $          | 29,519 |   | $ | 21,202 |   | $ | 17,145 |   |
| **Change in plan assets**                      |       |                     |       |                                   |       |   |   |   |   |
| Fair value of plan assets at beginning of year |       | $                        | 32,236     |                                   | $          | 26,625 |   | $ | — |   | $ | — |   |
| Actual return on plan assets                   |       | 1,729                    |       | 6,234                                  |       | — |   | — |   |
| Employer contributions                         |       | —                   |       | —                                 |       | 356 |   | 338 |   |
| Benefits paid                                  |       | (1,302                   | )          | (340                                   | )          | (356 | ) | (338 | ) |
| Administrative expenses                        |       | (364                     | )          | (283                                   | )          | — |   | — |   |
| Fair value of plan assets at end of year       |       | $                        | 32,299     |                                   | $          | 32,236 |   | $ | — |   | $ | — |   |
| **Reconciliation of funded status**            |       |                     |       |                                   |       |   |   |   |   |
| Funded status                                  |       | $                        | (4,559     | )                                      | $          | 2,717 |   | $ | (21,202 | ) | $ | (17,145 | ) |
| Unrecognized actuarial loss                    |       | 13,849                   |       | 9,037                                  |       | 5,086 |   | 3,292 |   |
| Unrecognized transition (asset) or obligation  |       | —                   |       | —                                 |       | 303 |   | 608 |   |
| Unrecognized prior service cost                |       | 625                      |       | 671                                    |       | — |   | — |   |
| Prepaid (accrued) benefit cost at year-end     |       | $                        | 9,915      |                                   | $          | 12,425 |   | $ | (15,813 | ) | $ | (13,245 | ) |
| **Components  of net periodic benefit cost**   |       |                     |       |                                   |       |   |   |   |   |
| Service cost                                   |       | $                        | 2,631      |                                   | $          | 2,248 |   | $ | 1,385 |   | $ | 1,102 |   |
| Interest cost                                  |       | 1,750                    |       | 1,546                                  |       | 1,044 |   | 915 |   |
| Expected return on plan assets                 |       | (2,639                   | )          | (2,176                                 | )          | — |   | — |   |
| Amortization of prior service cost             |       | 46                       |       | 43                                     |       | — |   | — |   |
| Amortization of transition (asset) obligation  |       | —                   |       | —                                 |       | 305 |   | 305 |   |
| Amortization of net loss                       |       | 722                      |       | 1,040                                  |       | 190 |   | 64 |   |
|                                           |       | $                        | 2,510      |                                   | $          | 2,701 |   | $ | 2,924 |   | $ | 2,386 |   |
| **Accumulated benefit obligation**             |       | $                        | 28,248     |                                   | $          | 23,591 |   |   |   |   |   |

                                                

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

*Plan Assumptions*
| ** **                                             | ** ** | **Retirement Plan** | ** ** | **Post-Retirement  Medical Plan** | ** ** |
|--------------------------------------------------------|------------|--------------------------|------------|----------------------------------------|------------|
| ** **                                             | ** ** | **2004**                 | ** ** | **2003**                               | ** ** | **2002** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| **Plan assumptions to determine  benefit obligations** |       |                     |       |                                   |       |   |   |   |   |   |   |   |   |
| Discount rate                                          |       | 5.75                     | %          | 6.00                                   | %          | 6.50 | % | 5.75 | % | 6.00 | % | 6.50 | % |
| Rate of compensation increase                          |       | 5.50                     | %          | 4.75                                   | %          | 4.75 | % | — |   | — |   | — |   |
| **Plan  assumptions to determine net cost**            |       |                     |       |                                   |       |   |   |   |   |   |   |   |   |
| Discount rate                                          |       | 6.00                     | %          | 6.50                                   | %          | 7.25 | % | 6.00 | % | 6.50 | % | 7.25 | % |
| Expected long-term rate of return on plan assets       |       | 8.50                     | %          | 8.50                                   | %          | 9.50 | % | — |   | — |   | — |   |
| Rate of compensation increase                          |       | 4.75                     | %          | 4.75                                   | %          | 4.75 | % | — |   | — |   | — |   |

 

To develop the expected long-term rate of return onplan assets assumption, the Company considered the current level of expectedreturns on risk free investments (primarily government bonds), the historicallevel of the risk premium associated with the other asset classes in which theportfolio is invested and the expectations for future returns of each assetclass. The expected return for each asset class was then weighted based on thetarget asset allocation to develop the expected long-term rate of return onplan assets assumption for the portfolio. This resulted in the selection of the8.50% assumption for 2004.

Expected benefit payments for the retirement planfor the next ten years are as follows (amounts expressed in thousands):
| **Year Ending  December 31,** | ** ** | ** ** | ** ** | **Expected   Benefit Payment** | ** ** |
|-----------------------------------------|------------|------------|------------|------------------------------------------|------------|
| 2005                                    |       |       | $          | 2,905                                    |       |   |
| 2006                                    |       |       | 3,435      |                                     |       |
| 2007                                    |       |       | 2,761      |                                     |       |
| 2008                                    |       |       | 3,442      |                                     |       |
| 2009                                    |       |       | 3,375      |                                     |       |
| Next 5 years                            |       |       | 19,667     |                                     |       |

 

 

Thefollowing table provides the target and actual asset allocations in theretirement plan:
| ** **              | ** ** | ** ** | ** ** | **Actual as of December 31,** | ** ** |
|-------------------------|------------|------------|------------|---------------------------------------------------|------------|
| **Asset Category** | ** ** | ** ** | ** ** | **Target**                                        | ** ** | **2004** | ** ** | **2003** | ** ** |
| Equity securities       |       |       | 100        | %                                                 |       |   | 99 | % |   |   | 100 | % |   |
| Debt securities         |       |       | 0          | %                                                 |       |   | 0 | % |   |   | 0 | % |   |
| Real estate             |       |       | 0          | %                                                 |       |   | 0 | % |   |   | 0 | % |   |
| Other                   |       |       | 0          | %                                                 |       |   | 1 | % |   |   | 0 | % |   |
| Total                   |       |       | 100        | %                                                 |       |   | 100 | % |   |   | 100 | % |   |
|                         |            |            |            |                                                   |            |  |  |  |  |  |  |  |  |  |  |

 

For measurement purposes related to the Company’spost-retirement medical plan, a 11% annual rate of increase in the per capitacost of covered health care benefits was assumed for 2005. The rate is assumed 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

todecrease gradually to 5% for 2012 and remain at that level thereafter. Thiscompares to the amounts used for 2004 measurement purposes, where a 12% annualrate of increase in the per capita cost of covered health care benefits wasassumed, decreasing gradually to 5% for 2012 and remaining level thereafter.

Assumedhealth care cost trends have a significant effect on the amount reported forthe health care plan. A one-percentage-point change in assumed health care costtrend rates would have the following effects (in thousands):
| ** **                                                        | ** ** | **One Percentage Point**                           | ** ** |
|-------------------------------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                                                        | ** ** | **    Increase    ** | ** ** | **    Decrease    ** | ** ** |
| Effect on total  of service and interest cost components for 2004 |       |                                                         | $          | 472 |   |   |   | $ | (376 | ) |   |
| Effect on year-end 2004  postretirement benefit obligation        |       |                                                         | $          | 3,539 |   |   |   | $ | (2,868 | ) |   |

 

In December 2003, theMedicare Prescription Drug Improvement and Modernization Act of 2003 (the Act)was signed into law. The Act introduced a prescription drug benefit underMedicare (Medicare Part D), as well as a nontaxable federal subsidy tosponsors of retiree health care benefit plans that provide a benefit that is atleast actuarially equivalent to Medicare Part D. In May 2004, theFASB issued Staff Position No. 106-2, “Accounting and DisclosureRequirements Related to the Medicare Prescription Drug Improvement andModernization Act of 2003” (FSP No. 106-2), which addresses theaccounting and disclosure requirements associated with the effects of the Act.

The Company has elected not to reflect changes in theAct in its 2004 financial statements since the Company has concluded that theeffects of the Act are not a significant event that calls for remeasurementunder FAS 106.

**(10)   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 Companymay be made as grants of stock options, stock appreciation rights, stockawards, cash awards, performance awards or any combination thereof(collectively, “Awards”). Employee Awards generally become exercisable in threeinstallments. The number of shares available for future issuance was 3,975,757,2,297,657 and 2,911,565 as of December 31, 2004, 2003 and 2002,respectively. Stock options granted during and after 2003 expire 5 years fromthe date of grant, if not exercised. Stock options granted prior to 2003, ifnot exercised, expire 10 years from the date of grant.

*Restricted Stock*

TheCompany granted the following shares of restricted stock during the indicatedperiods:
| **Year Ended  December 31,** | ** ** | ** ** | ** ** | **Number  of  Awards** | ** ** | **Weighted  Average  Grant Date  Fair Value** | ** ** |
|----------------------------------------|------------|------------|------------|------------------------|------------|---------------------------------------------------------|------------|
| 2004                                   |       | 303,400    |       | $                      | 13,164,429 |                                                    |
| 2003                                   |       | 144,000    |       | $                      | 6,045,840  |                                                    |
| 2002                                   |       | 40,065     |       | $                      | 1,192,935  |                                                    |

 

The number of unvestedshares of restricted stock was 403,900, 157,019 and 38,621 as of December 31,2004, 2003 and 2002, respectively.

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

*Stock Options*

Asummary of the status of the Company’s stock option activity as of December 31,2004, 2003 and 2002, and changes during the years ended on those dates ispresented below:
| ** **                                                  | ** ** | **Number of  Awards** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
|-------------------------------------------------------------|------------|----------------------------|------------|----------------------------------------|------------|
| Outstanding, December 31,  2001                        |       | 3,852,580                  |       |                                   | $          | 22.01 |   |   |
| Granted in 2002                                             |       | 960,900                    |       |                                   | $          | 29.84 |   |   |
| Exercised in 2002                                           |       | (1,022,034                 | )          |                                   | $          | 19.72 |   |   |
| Canceled in 2002                                            |       | (44,000                    | )          |                                   | $          | 23.49 |   |   |
| Outstanding,  December 31, 2002                        |       | 3,747,446                  |       |                                   | $          | 24.62 |   |   |
| Exercisable,  December 31, 2002                        |       | 1,992,883                  |       |                                   | $          | 22.41 |   |   |
| Weighted-average fair value of options granted  during 2002 |       |                       |       |                                   | $          | 12.43 |   |   |
| Outstanding, December 31, 2002                         |       | 3,747,446                  |       |                                   | $          | 24.54 |   |   |
| Granted in 2003                                             |       | 403,000                    |       |                                   | $          | 42.02 |   |   |
| Exercised in 2003                                           |       | (1,553,573                 | )          |                                   | $          | 21.48 |   |   |
| Canceled in 2003                                            |       | (14,100                    | )          |                                   | $          | 17.14 |   |   |
| Outstanding,  December 31, 2003                        |       | 2,582,773                  |       |                                   | $          | 29.16 |   |   |
| Exercisable,  December 31, 2003                        |       | 1,258,999                  |       |                                   | $          | 25.75 |   |   |
| Weighted-average fair value of options granted  during 2003 |       |                       |       |                                   | $          | 9.61 |   |   |
| Outstanding, December 31, 2003                         |       | 2,582,773                  |       |                                   | $          | 29.16 |   |   |
| Granted in 2004                                             |       | 30,000                     |       |                                   | $          | 48.50 |   |   |
| Exercised in 2004                                           |       | (452,437                   | )          |                                   | $          | 26.55 |   |   |
| Canceled in 2004                                            |       | (15,000                    | )          |                                   | $          | 26.98 |   |   |
| Outstanding,  December 31, 2004                        |       | 2,145,336                  |       |                                   | $          | 30.00 |   |   |
| Exercisable,  December 31, 2004                        |       | 1,553,567                  |       |                                   | $          | 27.66 |   |   |
| Weighted-average  fair value of options granted during 2004 |       |                       |       |                                   | $          | 10.88 |   |   |

 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

Thefollowing table summarizes information about stock options outstanding at December 31,2004
| ** **                                | ** ** | **Options Outstanding** | ** ** | **Options Exercisable** | ** ** |
|-------------------------------------------|------------|------------------------------|------------|------------------------------|------------|
| **Range of Option Prices** | ** ** | ** **                   | ** ** | **Number  Outstanding**      | ** ** | **Weighted  Average  Remaining  Contractual  Life  (days)** | ** ** | **Weighted  Average  Exercise  Price** | ** ** | **Number  Exercisable** | ** ** | **Weighted  Average  Exercise  Price** | ** ** |
| $17.91 to $19.56                          |       | 50,800                       |       |                         | 1,578      |   |   |   | $ | 18.35 |   |   | 50,800 |   |   | $ | 18.35 |   |   |
| $20.31 to $24.77                          |       | 772,702                      |       |                         | 2,178      |   |   |   | $ | 23.33 |   |   | 772,702 |   |   | $ | 23.33 |   |   |
| $25.38 to $29.78                          |       | 766,834                      |       |                         | 2,701      |   |   |   | $ | 29.60 |   |   | 478,467 |   |   | $ | 29.50 |   |   |
| $31.18 to $33.94                          |       | 54,000                       |       |                         | 2,163      |   |   |   | $ | 32.03 |   |   | 40,665 |   |   | $ | 32.24 |   |   |
| $36.00                                    |       | 35,000                       |       |                         | 519        |   |   |   | $ | 36.00 |   |   | 35,000 |   |   | $ | 36.00 |   |   |
| $40.63 to $43.46                          |       | 436,000                      |       |                         | 1,252      |   |   |   | $ | 41.87 |   |   | 175,933 |   |   | $ | 41.65 |   |   |
| $45.89 to $49.48                          |       | 30,000                       |       |                         | 1,590      |   |   |   | $ | 48.50 |   |   | — |   |   | — |   |   |
| Total                                     |       | 2,145,336                    |       |                         | 2,127      |   |   |   | $ | 30.00 |   |   | 1,553,567 |   |   | $ | 27.66 |   |   |
|                                           |            |                              |            |                              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**(11)   Change in Accounting Principle**

The Company adopted Statement of Financial AccountingStandard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS143”), as of January 1, 2003. SFAS 143 requires the Company to record thefair value of a liability for an asset retirement obligation (“ARO”) in theperiod in which it is incurred. Upon adoption of SFAS 143, the Company wasrequired to recognize a liability for the present value of all legalobligations associated with the retirement of tangible long-lived assets and anasset retirement cost (“ARC”) was capitalized as part of the carrying value ofthe associated asset. Upon initial application of SFAS 143, a cumulative effectof a change in accounting principle was also required in order to recognize aliability for any existing AROs adjusted for cumulative accretion, an increaseto the carrying amount of the associated long-lived asset and accumulateddepreciation on the capitalized cost. Subsequent to initial measurement,liabilities are required to be accreted to their present value each period andcapitalized costs are depreciated over the estimated useful life of the relatedassets. This periodic accretion expense is recorded as “Transportation andother” in the consolidated statement of income. Upon settlement of theliability, the Company will settle the obligation against its recorded amountand will record any resulting gain or loss.

Activityrelated to the Company’s ARO during the years ended December 31, 2004 and2003 is as follows (in thousands):
| ** **                              | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------|------------|--------------------------------------------|------------|
| ** **                              | ** ** | **2004**                                   | ** ** | **2003** | ** ** |
| Initial ARO as of  January 1,      |       | $                                          | 70,790     |   | $ | 63,643 |   |
| Liabilities  incurred during period     |       | 22,224                                     | (a)        | 3,001 |   |
| Liabilities  settled during period      |       | (3,856                                     | )          | (691 | ) |
| Accretion expense                       |       | 5,982                                      |       | 4,837 |   |
| Balance of ARO as of  December 31, |       | $                                          | 95,140     |   | $ | 70,790 |   |

----

(a)    $14.1million of this amount relates to acquisitions during 2004.

78

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

For the years ended December 31, 2004 and 2003,the Company recognized depreciation expense related to its ARC of $3,017,000and $3,850,000, respectively. As a result of the adoption of SFAS 143 on January 1,2003, the Company recorded a $56,769,000 increase in the net capitalized costof its oil and gas properties and recognized an after-tax charge of $4,166,000for the cumulative effect of the change in accounting principle (net of relatedincome tax benefit of $2,707,000).

HadSFAS 143 been applied retroactively during the year ended December 31,2002, the Company’s net income and earnings per share would have been asfollows (expressed in thousands, except per share amounts):
| ** **          | ** ** | **Year Ended  December 31, 2002** | ** ** |
|---------------------|------------|--------------------------------------------------|------------|
| ** **          | ** ** | **As Reported**                             | ** ** | **Pro forma** | ** ** |
| Net Income          |       |                                             | $          | 107,031 |   |   | $ | 106,662 |   |
| Earnings per share: |       |                                             |       |   |   |   |   |
| Basic               |       |                                             | $          | 1.85 |   |   | $ | 1.84 |   |
| Diluted             |       |                                             | $          | 1.77 |   |   | $ | 1.76 |   |

 

**(12)   Minority Interest**

Pogo Trust I, a subsidiary of the Company, called forredemption of its 61¤2%Cumulative Quarterly Income Convertible Preferred Securities due 2029 (the “TrustPreferred Securities”) on June 3, 2002. Prior to their redemption, holdersof 2,997,196 of the 3,000,000 outstanding Trust Preferred Securities convertedtheir Trust Preferred Securities, representing $149,850,000 face value of TrustPreferred Securities, into 6,309,972 shares of the Company’s common stock. Inconnection with the redemption, Pogo Trust I paid a total of $147,000 to formerholders of the Trust Preferred Securities. Subsequent to June 3, 2002,there were no Trust Preferred Securities outstanding.

The amount recorded under “MinorityInterests—Dividends and costs associated with mandatorily redeemable 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.

**(13)   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.

*Cash and Cash Equivalents*

Fair value is carryingvalue.

*Current Investments*

Fair value is carryingvalue due to short term holding period.

*Receivables and Payables*

Fair value isapproximately carrying value.

79

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

*Derivative Financial Instruments*

Fair value is carryingvalue.

*Debt and Other*
| **Instrument**                     | ** ** | ** **                                                                                                               | ** ** | **Basis of Fair Value Estimate** |
|------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|
| Bank revolving credit agreement(s) |       | Fair value is carrying value as of December 31,  2004 and 2003 based on the market value interest rates.            |
| LIBOR Rate Advances                |       | Fair value is carrying  value as of December 31, 2004 based on the market value interest rates.                     |
| 2009 Notes                         |       | Fair value is 106% of  carrying value as of December 31, 2003 based on quoted market value.                         |
| 2011 Notes                         |       | Fair value is 108.1% and  110.6% of carrying value as of December 31, 2004 and 2003, based on  quoted market value. |

 

Thecarrying value and estimated fair value of the Company’s financial instrumentsat December 31, 2004 and 2003 (in thousands of dollars) are as follows:
| ** **                            | ** ** | **2004**     | ** ** | **2003**  | ** ** |
|---------------------------------------|------------|--------------|------------|-----------|------------|
| ** **                            | ** ** | **Carrying** | ** ** | **Fair**  | ** ** | **Carrying** | ** ** | **Fair** | ** ** |
| ** **                            | ** ** | **Value**    | ** ** | **Value** | ** ** | **Value** | ** ** | **Value** | ** ** |
| Cash and cash equivalents             |       | $            | 86,456     |      | $          | 86,456 |   | $ | 104,474 |   | $ | 104,474 |   |
| Current  investments                  |       | $            | 135,000    |      | $          | 135,000 |   | $ | 74,280 |   | $ | 74,280 |   |
| Receivables                           |       | $            | 178,217    |      | $          | 178,217 |   | $ | 156,467 |   | $ | 156,467 |   |
| Payables                              |       | $            | (235,079   | )         | $          | (235,079 | ) | $ | (148,942 | ) | $ | (148,942 | ) |
| Debt:                                 |       |         |       |      |       |   |   |   |   |
| Bank revolving credit agreement loans |       | $            | (515,000   | )         | $          | (515,000 | ) | $ | (139,000 | ) | $ | (139,000 | ) |
| LIBOR Rate Advances                   |       | $            | (40,000    | )         | $          | (40,000 | ) | $ | — |   | $ | — |   |
| 2009 Notes                            |       | $            | —     |      | $          | — |   | $ | (148,261 | ) | $ | (159,000 | ) |
| 2011 Notes                            |       | $            | (200,000   | )         | $          | (216,250 | ) | $ | (200,000 | ) | $ | (221,250 | ) |

 

The Company occasionallyenters into hedging contracts to minimize the impact of oil and gas pricefluctuations. See Note 14 for a further discussion of these contracts.

**(14)   Hedging Activities**

During the year ended December 31, 2004, theCompany did not recognize any gains or losses from its hedging activitiesrelated to 2004 production. The Company did recognize a pre-tax gain of$657,000 due to ineffectiveness on hedge contracts during the year ended 2004. TheCompany recognized a pre-tax loss of $22,822,000 ($14,873,000 after taxes) forthe year ended December 31, 2003 and a pre-tax gain of $3,640,000($2,367,000 after tax) for the year ended December 31, 2002 from its pricehedge contracts, which are included in oil and gas revenues. Net unrealizedgains on derivative instruments of $2,565,000, net of deferred taxes of$1,381,000, have been reflected as a component of other comprehensive incomefor the year ended December 31, 2004. Based on the fair market value ofthe hedge contracts as of December 31, 2004, the Company would reclassifyadditional pre-tax losses of approximately $6,722,000 

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

(approximately $4,369,000after taxes) from accumulated other comprehensive loss (shareholders’ equity)to net income during the next twelve months.

As of December 31, 2004, the Company held variousderivative instruments. During 2004, the Company entered into natural gas andcrude oil option agreements referred to as “collars.” Collars are designed toestablish floor and ceiling prices on anticipated future natural gas and crudeoil production. The Company has designated these contracts as cash flow hedgesdesigned to achieve a more predictable cash flow, as well as to reduce itsexposure to price volatility. While the use of these derivative instrumentslimits the downside risk of adverse price movements, they may also limit futurerevenues from favorable price movements. The use of derivatives also involvesthe risk that the counterparties to such instruments will be unable to meet thefinancial terms of such contracts. Currently, the Company does not expectlosses due to creditworthiness of its counterparties.

The gas hedging transactions are generally settledbased upon the average of the reporting settlement prices on the NYMEX for thelast 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 any particular collar transaction, thecounterparty is required to make a payment to the Company if the settlementprice for any settlement period is below the floor price for such transaction,and the Company is required to make a payment to the counterparty if thesettlement price for any settlement period is above the ceiling price of suchtransaction.

Theestimated fair value of these transactions is based upon various factors thatinclude closing exchange prices on the NYMEX, volatility and the time value ofoptions. Further details related to the Company’s hedging activities as of December 31,2004 are as follows:
| ** **                                                              | ** ** | ** ** | ** ** | **NYMEX  Contract  Price** | ** ** | **Fair Value  of** | ** ** |
|-------------------------------------------------------------------------|------------|------------|------------|----------------------------|------------|-------------------------|------------|
| **Contract Period and Type of  Contract** | ** ** | ** ** | ** ** | **Volume**                 | ** ** | **Floor**               | ** ** | **Ceiling** | ** ** | **Asset/(Liability)** | ** ** |
| **Natural  Gas Contracts (MMBtu)(a)**                                   |       |       |       |                       |       |                    |       |   |   |   |   |
| Collar Contracts:                                                       |       |       |       |                       |       |                    |       |   |   |   |   |
| January 2005 - December 2005                                  |       | 5,475      |       | $                          | 5.50       |                    | $          | 8.00 |   |   | $ | 214,810 |   |   |
| January 2005 - December 2005                                  |       | 1,825      |       | $                          | 6.00       |                    | $          | 9.30 |   |   | $ | 658,634 |   |   |
| January 2005 - December 2005                                  |       | 1,825      |       | $                          | 6.00       |                    | $          | 9.25 |   |   | $ | 652,362 |   |   |
| January 2005 - December 2006                                  |       | 3,650      |       | $                          | 6.00       |                    | $          | 9.25 |   |   | $ | 1,304,729 |   |   |
| January 2006 - December 2006                                  |       | 5,475      |       | $                          | 5.00       |                    | $          | 7.50 |   |   | $ | (2,116,689 | ) |   |
| January 2006 - December 2006                                  |       | 3,650      |       | $                          | 5.50       |                    | $          | 8.25 |   |   | $ | (184,107 | ) |   |
| January 2006 - December 2006                                  |       | 3,650      |       | $                          | 5.75       |                    | $          | 8.27 |   |   | $ | 182,666 |   |   |
| **Crude Oil Contracts (Barrels)**                                       |       |       |       |                       |       |                    |       |   |   |   |   |
| Collar Contracts:                                                       |       |       |       |                       |       |                    |       |   |   |   |   |
| January 2005  - December 2005                                 |       | 1,825,000  |       | $                          | 40.00      |                    | $          | 62.50 |   |   | $ | 3,891,103 |   |   |
|                                                                         |            |            |            |                            |            |                         |            |  |  |  |  |  |  |  |  |  |

----

(a)           MMBtumeans million British Thermal Units.

81

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

In February 2005,the Company entered into additional crude oil collars to establish floor andceiling prices on anticipated future crude oil production. The Company hasdesignated these contracts as cash flow hedges. Further details related to thishedging activity is as follows:
| ** **                                                        | ** ** | ** ** | ** ** | **NYMEX  Contract  Price** | ** ** |
|-------------------------------------------------------------------|------------|------------|------------|----------------------------|------------|
| **Contract Period and Type of Contract** | ** ** | ** ** | ** ** | **Volume**                 | ** ** | **Floor** | ** ** | **Ceiling** | ** ** |
| **Crude Oil Contracts (Barrels)**                                 |       |       |       |                       |       |   |   |
| Collar Contracts:                                                 |       |       |       |                       |       |   |   |
| March 2005 -  December 2005                             |       | 1,530,000  |       | $                          | 40.00      |   | $ | 62.50 |   |
|                                                                   |            |            |            |                            |            |  |  |  |  |  |  |

 

**(15)   Acquisitions**

In December 2004, the Company completed theacquisition of two privately held corporations for approximately $282.5 millionin cash and a deferred payment of $26.4 million to be made in 2005 to theformer owner of one of the corporations. The corporations have subsequentlybeen named Pogo Producing (San Juan) Company and Pogo Producing (TexasPanhandle) Company (the “corporations”). The transactions included propertieslocated primarily in the San Juan basin of New Mexico and the Texas Panhandle.The Company acquired the corporations primarily to strengthen its position indomestic natural gas properties. The corporations had an estimated 133 billioncubic feet of gas equivalent proven reserves (Bcfe) as of the dates ofacquisition. The Company recorded the estimated fair values of the assetsacquired and the liabilities assumed at the closing date of the transactions,which primarily consisted of oil and gas properties of $423.7 million, longterm debt of $50.1 million and deferred tax liabilities of $67.4 million. Nogoodwill was recorded for the transactions.

In 2004, the Company alsocompleted six other producing property acquisitions for cash considerationtotaling approximately $186 million. These acquisitions added approximately 119Bcfe to the Company’s proved reserves.

82

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**POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)**

*Pro Forma Information*

Thefollowing summary presents unaudited pro forma consolidated results ofoperations as if the acquisitions had occurred as of January 1, 2002. Thepro forma results are for illustrative purposes only and include adjustments inaddition to the pre-acquisition historical results of the corporations, 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 not necessarilyindicative of the operating results that would have occurred had theacquisitions been consummated at that date, nor are they necessarily indicativeof future operating results.
| ** **                                                         | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                         | ** ** | **2004**                              | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                         | ** ** | **(Unaudited)**                       | ** ** |
| **Pro Forma:**                                                     | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues                                                           |       | $                                     | 1,385,056  |   | $ | 1,203,236 |   | $ | 789,382 |   |
| Income before  cumulative effect of change in accounting principle |       | 271,853                               |       | 298,959 |   | 106,499 |   |
| Net income                                                         |       | 271,853                               |       | 294,830 |   | 106,499 |   |
| Earnings per share:                                                |       |                                  |       |   |   |   |   |
| Basic—                                                        |       |                                  |       |   |   |   |   |
| Income before cumulative effect of change in  accounting principle |       | $                                     | 4.26       |   | $ | 4.78 |   | $ | 1.84 |   |
| Net income                                                         |       | $                                     | 4.26       |   | $ | 4.66 |   | $ | 1.84 |   |
| Diluted—                                                      |       |                                  |       |   |   |   |   |
| Income before cumulative effect of change in  accounting principle |       | $                                     | 4.22       |   | $ | 4.71 |   | $ | 1.76 |   |
| Net income                                                         |       | $                                     | 4.22       |   | $ | 4.59 |   | $ | 1.76 |   |

 

 

83

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**POGO PRODUCING COMPANY & SUBSIDIARIES UNAUDITED SUPPLEMENTARY FINANCIAL DATA**

**Oil and GasProducing Activities**

Theresults of operations from oil and gas producing activities exclude non-oil andgas revenues, general and administrative expenses, other non oil and gasproducing expenses, interest charges, interest income and interest capitalized.Income tax (expense) or benefit was determined by applying the statutory ratesto pretax operating results with adjustments for permanent differences.
| ** **                                         | ** ** | **Total**                              | ** ** | **United** | ** ** | **Kingdom of** | ** ** | **Other**         | ** ** |
|----------------------------------------------------|------------|----------------------------------------|------------|------------|------------|---------------------|------------|-------------------|------------|
| ** **                                         | ** ** | **Company**                            | ** ** | **States** | ** ** | **Thailand**        | ** ** | **International** | ** ** |
| ** **                                         | ** ** | **(Expressed in thousands)** | ** ** |
| ** **                                         | ** ** | **2004**                               | ** ** |
| Revenues                                           |       | $                                      | 1,308,225  |       | $          | 973,083             |       | $                 | 335,142    |   |   | $ | — |   |   |
| Lease operating expense                            |       | (144,444                               | )          | (100,506   | )          | (43,938             | )          |              | —     |   |   |
| Exploration expense                                |       | (23,063                                | )          | (21,557    | )          | (197                | )          |              | (1,309     | )(a) |   |
| Dry hole and impairment  expense                   |       | (106,417                               | )          | (57,443    | )          | (5,594              | )          |              | (43,380    | )(a) |   |
| Depreciation, depletion  and amortization  expense |       | (360,569                               | )          | (255,022   | )          | (105,547            | )          |              | —     |   |   |
| Production and other  taxes                        |       | (67,984                                | )          | (44,104    | )          | (23,880             | )          |              | —     |   |   |
| Transportation and  accretion                      |       | (21,651                                | )          | (19,487    | )          | (2,164              | )          |              | —     |   |   |
| Pretax operating results                           |       | 584,097                                |       | 474,964    |       | 153,822             |       |              | (44,689    | ) |   |
| Income tax (expense)  benefit                      |       | (264,503                               | )          | (178,416   | )          | (83,663             | )          |              | (2,424     | ) |   |
| Operating results                                  |       | $                                      | 319,594    |       | $          | 296,548             |       | $                 | 70,159     |   |   | $ | (47,113 | ) |   |

 
| ** **                                        | ** ** | **2003** | ** ** |
|---------------------------------------------------|------------|----------|------------|
| Revenues                                          |       | $        | 1,159,544  |   | $ | 856,074 |   | $ | 303,470 |   |   | $ | — |   |   |
| Lease operating expense                           |       | (123,098 | )          | (81,731 | ) | (41,367 | ) |   | — |   |   |
| Exploration expense                               |       | (7,547   | )          | (6,899 | ) | (644 | ) |   | (4 | )(a) |   |
| Dry hole and impairment  expense                  |       | (35,102  | )          | (31,600 | ) | (3,231 | ) |   | (271 | )(a) |   |
| Depreciation, depletion  and amortization expense |       | (321,572 | )          | (234,579 | ) | (86,993 | ) |   | — |   |   |
| Production and other  taxes                       |       | (35,485  | )          | (23,735 | ) | (11,750 | ) |   | — |   |   |
| Transportation and  accretion                     |       | (17,952  | )          | (16,949 | ) | (1,003 | ) |   | — |   |   |
| Pretax operating results                          |       | 618,788  |       | 460,581 |   | 158,482 |   |   | (275 | ) |   |
| Income tax (expense)  benefit                     |       | (256,198 | )          | (176,957 | ) | (79,241 | ) |   | — |   |   |
| Operating results                                 |       | $        | 362,590    |   | $ | 283,624 |   | $ | 79,241 |   |   | $ | (275 | ) |   |

 
| ** **                                        | ** ** | **2002** | ** ** |
|---------------------------------------------------|------------|----------|------------|
| Revenues                                          |       | $        | 750,401    |   | $ | 537,717 |   | $ | 212,684 |   |   | $ | — |   |   |
| Lease operating expense                           |       | (112,663 | )          | (74,416 | ) | (38,247 | ) |   | — |   |   |
| Exploration expense                               |       | (4,783   | )          | (4,161 | ) | (544 | ) |   | (78 | )(a) |   |
| Dry hole and impairment  expense                  |       | (26,999  | )          | (26,999 | ) | — |   |   | — |   |   |
| Depreciation, depletion  and amortization expense |       | (283,865 | )          | (218,636 | ) | (65,229 | ) |   | — |   |   |
| Production and other  taxes                       |       | (20,058  | )          | (20,058 | ) | — |   |   | — |   |   |
| Transportation                                    |       | (10,194  | )          | (10,194 | ) | — |   |   | — |   |   |
| Pretax operating results                          |       | 291,839  |       | 183,253 |   | 108,664 |   |   | (78 | ) |   |
| Income tax (expense)  benefit                     |       | (128,498 | )          | (65,545 | ) | (62,967 | ) |   | 14 |   |   |
| Operating results                                 |       | $        | 163,341    |   | $ | 117,708 |   | $ | 45,697 |   |   | $ | (64 | ) |   |

----

(a)    Includedin Other International for 2004, 2003 and 2002 are costs associated withactivities related primarily to Hungary with the exception of $5,551 of dryhole and impairment cost related to the Danish North Sea in 2004, $182 ofexploration expense in 2004 related to New Zealand, and $271 of dry hole andimpairment expense in 2003 related to the Company’s British North Sea blockthat was relinquished in 2003.

84

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**POGO PRODUCING COMPANY & SUBSIDIARIES UNAUDITED SUPPLEMENTARY FINANCIAL DATA—(Continued)**

Thefollowing table sets forth the Company’s costs incurred (expressed inthousands) for oil and gas producing activities during the years indicated.
| ** **                                                | ** ** | **Total**   | ** ** | **United** | ** ** | **Kingdom of** | ** ** | **Other**            | ** ** |
|-----------------------------------------------------------|------------|-------------|------------|------------|------------|---------------------|------------|----------------------|------------|
| ** **                                                | ** ** | **Company** | ** ** | **States** | ** ** | **Thailand**        | ** ** | **International(a)** | ** ** |
| Costs incurred  (capitalized unless otherwise indicated): |       |        |       |       |       |                |       |                 |       |   |   |   |   |
| **2004:**                                                 |       |        |       |       |       |                |       |                 |       |   |   |   |   |
| Property acquisition                                      |       |        |       |       |       |                |       |                 |       |   |   |   |   |
| Proved                                                    |       | $           | 608,496    |       | $          | 608,496             |       |                 | $          | — |   |   |   | $ | — |   |   |
| Unproved                                                  |       | 26,707      |       | 26,707     |       |                | —     |                 |       |   | — |   |   |
| Exploration                                               |       |        |       |       |       |                |       |                 |       |   |   |   |   |
| Capitalized                                               |       | 89,673      |       | 56,533     |       |                | 2,018      |                 |       |   | 31,122 |   |   |
| Expensed                                                  |       | 23,063      |       | 21,553     |       |                | 379        |                 |       |   | 1,131 |   |   |
| Development                                               |       | 340,967     |       | 226,804    |       |                | 113,252    |                 |       |   | 911 |   |   |
| Asset retirement  cost                                    |       | 19,603      |       | 15,569     |       |                | 4,034      |                 |       |   | — |   |   |
| Interest                                                  |       | 14,216      |       | 6,738      |       |                | 6,960      |                 |       |   | 518 |   |   |
| Total oil and gas  costs incurred                         |       | $           | 1,122,725  |       | $          | 962,400             |       |                 | $          | 126,643 |   |   |   | $ | 33,682 |   |   |
| Provision for  depreciation, depletion and amortization   |       | $           | 360,569    |       | $          | 255,022             |       |                 | $          | 105,547 |   |   |   | $ | — |   |   |
| **2003:**                                                 |       |        |       |       |       |                |       |                 |       |   |   |   |   |
| Property acquisition                                      |       |        |       |       |       |                |       |                 |       |   |   |   |   |
| Proved                                                    |       | $           | 177,680    |       | $          | 177,680             |       |                 | $          | — |   |   |   | $ | — |   |   |
| Unproved                                                  |       | 15,540      |       | 12,065     |       |                | 3,475      |                 |       |   | — |   |   |
| Exploration                                               |       |        |       |       |       |                |       |                 |       |   |   |   |   |
| Capitalized                                               |       | 59,714      |       | 42,248     |       |                | 6,155      |                 |       |   | 11,311 |   |   |
| Expensed                                                  |       | 7,547       |       | 6,899      |       |                | 644        |                 |       |   | 4 |   |   |
| Development                                               |       | 248,348     |       | 131,732    |       |                | 116,616    |                 |       |   | — |   |   |
| Asset retirement  cost(b)                                 |       | 59,142      |       | 49,706     |       |                | 9,436      |                 |       |   | — |   |   |
| Interest                                                  |       | 16,531      |       | 10,194     |       |                | 6,163      |                 |       |   | 174 |   |   |
| Total oil and gas  costs incurred                         |       | $           | 584,502    |       | $          | 430,524             |       |                 | $          | 142,489 |   |   |   | $ | 11,489 |   |   |
| Provision for  depreciation, depletion and amortization   |       | $           | 321,572    |       | $          | 234,579             |       |                 | $          | 86,993 |   |   |   | $ | — |   |   |
| **2002:**                                                 |       |        |       |       |       |                |       |                 |       |   |   |   |   |
| Property acquisition                                      |       |        |       |       |       |                |       |                 |       |   |   |   |   |
| Proved                                                    |       | $           | —     |       | $          | —              |       |                 | $          | — |   |   |   | $ | — |   |   |
| Unproved                                                  |       | 8,030       |       | 8,030      |       |                | —     |                 |       |   | — |   |   |
| Exploration                                               |       |        |       |       |       |                |       |                 |       |   |   |   |   |
| Capitalized                                               |       | 43,165      |       | 40,028     |       |                | 3,137      |                 |       |   | — |   |   |
| Expensed                                                  |       | 4,783       |       | 4,161      |       |                | 544        |                 |       |   | 78 |   |   |
| Development                                               |       | 303,197     |       | 205,035    |       |                | 98,162     |                 |       |   | — |   |   |
| Interest                                                  |       | 24,033      |       | 12,892     |       |                | 11,141     |                 |       |   | — |   |   |
| Total oil and gas  costs incurred                         |       | $           | 383,208    |       | $          | 270,146             |       |                 | $          | 112,984 |   |   |   | $ | 78 |   |   |
| Provision for  depreciation, depletion and amortization   |       | $           | 283,865    |       | $          | 218,636             |       |                 | $          | 65,229 |   |   |   | $ | — |   |   |

----

(a)    Included in Other International for 2004 are costsassociated with Hungary, the Danish North Sea and New Zealand. Included for theyears 2003 and 2002 are costs associated with initial activities related almostentirely to Hungary.

(b)    Includes $56,769 of cumulative asset retirement costrecorded to adopt the provisions of SFAS 143 on January 1,2003. Of thesecosts $47,893 has been reflected as activity in the United States and $8,876has been reflected as activity in the Kingdom of Thailand.

85

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**POGO PRODUCING COMPANY & SUBSIDIARIES UNAUDITED SUPPLEMENTARY FINANCIAL DATA—(Continued)**

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, offshore in the Kingdom of Thailand and in Hungary is based onreports prepared by Ryder Scott Company, L.P. and Miller & Lents, Ltd.The definitions and assumptions that serve as the basis for the discussionsunder the caption “Item 1, Business—Exploration and Production Data—Reserves”should be referred to in connection with the following information.

**Estimates of Proved Reserves**

**Oil,Condensate and Natural Gas Liquids (Bbls.)**
| ** **                                    | ** ** | **Total**   | ** ** | **United**  | ** ** | **Kingdom of** | ** ** | **Other**         | ** ** |
|-----------------------------------------------|------------|-------------|------------|-------------|------------|---------------------|------------|-------------------|------------|
| ** **                                    | ** ** | **Company** | ** ** | **States**  | ** ** | **Thailand**        | ** ** | **International** | ** ** |
| Proved Reserves  as of December 31, 2001 |       | 119,279,395 |       | 79,978,695  |       | 39,300,700          |       |              | —     |   |   |
| Revisions of previous estimates               |       | 9,563,087   |       | 9,290,517   |       | 272,570             |       |              | —     |   |   |
| Extensions, discoveries and other additions   |       | 8,460,885   |       | 3,965,585   |       | 4,495,300           |       |              | —     |   |   |
| Sale of properties                            |       | (202,785    | )          | (202,785    | )          | —              |       |              | —     |   |   |
| Estimated 2002 production                     |       | (18,921,750 | )          | (12,939,750 | )          | (5,982,000          | )          |              | —     |   |   |
| Proved Reserves  as of December 31, 2002 |       | 118,178,832 |       | 80,092,262  |       | 38,086,570          |       |              | —     |   |   |
| Revisions of previous estimates               |       | 9,964,506   |       | 6,338,668   |       | 3,625,838           |       |              | —     |   |   |
| Extensions, discoveries and other additions   |       | 6,305,471   |       | 2,982,400   |       | 3,312,627           |       |              | 10,444     |   |   |
| Purchase of properties                        |       | 4,301,200   |       | 4,301,200   |       | —              |       |              | —     |   |   |
| Estimated 2003 production                     |       | (23,880,000 | )          | (16,162,000 | )          | (7,718,000          | )          |              | —     |   |   |
| Proved Reserves  as of December 31, 2003 |       | 114,870,009 |       | 77,552,530  |       | 37,307,035          |       |              | 10,444     |   |   |
| Revisions of previous estimates               |       | 4,281,792   |       | 5,012,763   |       | (720,527            | )          |              | (10,444    | ) |   |
| Extensions, discoveries and other additions   |       | 4,197,673   |       | 1,727,761   |       | 2,469,912           |       |              | —     |   |   |
| Purchase of properties                        |       | 13,775,000  |       | 13,775,000  |       | —              |       |              | —     |   |   |
| Sale of properties                            |       | (1,832,000  | )          | (1,832,000  | )          | —              |       |              | —     |   |   |
| Estimated 2004 production                     |       | (18,910,000 | )          | (12,370,000 | )          | (6,540,000          | )          |              | —     |   |   |
| Proved Reserves  as of December 31, 2004 |       | 116,382,474 |       | 83,866,054  |       | 32,516,420          |       |              | —     |   |   |
| Proved Developed Reserves as of:              |       |        |       |        |       |                |       |              |       |   |   |
| December 31, 2001                        |       | 79,777,300  |       | 59,383,200  |       | 20,394,100          |       |              | —     |   |   |
| December 31, 2002                        |       | 97,873,000  |       | 74,041,149  |       | 23,831,851          |       |              | —     |   |   |
| December 31, 2003                        |       | 87,269,277  |       | 67,391,031  |       | 19,878,246          |       |              | —     |   |   |
| December 31,  2004                       |       | 92,574,224  |       | 72,968,008  |       | 19,606,216          |       |              | —     |   |   |

 

86

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**POGO PRODUCING COMPANY & SUBSIDIARIES UNAUDITED SUPPLEMENTARY FINANCIAL DATA—(Continued)**

**Estimates of Proved Reserves**

**Natural Gas (MMcf)**
| ** **                                    | ** ** | **Total**   | ** ** | **United** | ** ** | **Kingdom of** | ** ** | **Other**         | ** ** |
|-----------------------------------------------|------------|-------------|------------|------------|------------|---------------------|------------|-------------------|------------|
| ** **                                    | ** ** | **Company** | ** ** | **States** | ** ** | **Thailand**        | ** ** | **International** | ** ** |
| Proved Reserves  as of December 31, 2001 |       | 818,792     |       | 670,567    |       |                | 148,225    |              |       |   | — |   |   |
| Revisions of previous estimates               |       | 66,796      |       | 38,237     |       |                | 28,559     |              |       |   | — |   |   |
| Extensions, discoveries and other additions   |       | 89,774      |       | 78,575     |       |                | 11,199     |              |       |   | — |   |   |
| Estimated 2002 production                     |       | (101,852    | )          | (73,473    | )          |                | (28,379    | )                 |       |   | — |   |   |
| Proved Reserves  as of December 31, 2002 |       | 873,510     |       | 713,906    |       |                | 159,604    |              |       |   | — |   |   |
| Revisions of previous estimates               |       | 22,408      |       | 5,686      |       |                | 16,722     |              |       |   | — |   |   |
| Extensions, discoveries and other additions   |       | 95,664      |       | 65,095     |       |                | 20,438     |              |       |   | 10,131 |   |   |
| Purchase of properties                        |       | 129,119     |       | 129,119    |       |                | —     |              |       |   | — |   |   |
| Estimated 2003 production                     |       | (108,378    | )          | (76,802    | )          |                | (31,576    | )                 |       |   | — |   |   |
| Proved Reserves  as of December 31, 2003 |       | 1,012,323   |       | 837,004    |       |                | 165,188    |              |       |   | 10,131 |   |   |
| Revisions of previous estimates               |       | (20,854     | )          | (16,357    | )          |                | 5,634      |              |       |   | (10,131 | ) |   |
| Extensions, discoveries and other additions   |       | 37,648      |       | 33,610     |       |                | 4,038      |              |       |   | — |   |   |
| Purchase of properties                        |       | 172,022     |       | 172,022    |       |                | —     |              |       |   | — |   |   |
| Sale of properties                            |       | (2,888      | )          | (2,888     | )          |                | —     |              |       |   | — |   |   |
| Estimated 2004 production                     |       | (118,581    | )          | (89,410    | )          |                | (29,171    | )                 |       |   | — |   |   |
| Proved Reserves  as of December 31, 2004 |       | 1,079,670   |       | 933,981    |       |                | 145,689    |              |       |   | — |   |   |
| Proved Developed Reserves as of:              |       |        |       |       |       |                |       |              |       |   |   |   |   |
| December 31, 2001                        |       | 602,345     |       | 532,348    |       |                | 69,997     |              |       |   | — |   |   |
| December 31, 2002                        |       | 687,556     |       | 600,255    |       |                | 87,301     |              |       |   | — |   |   |
| December 31, 2003                        |       | 780,774     |       | 702,836    |       |                | 77,938     |              |       |   | — |   |   |
| December 31,  2004                       |       | 852,848     |       | 769,753    |       |                | 83,095     |              |       |   | — |   |   |

 

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**POGO PRODUCING COMPANY & SUBSIDIARIES**

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

The standardizedmeasure of discounted future net cash flows from the production of provedreserves is developed 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 measure of discounted future net cashflows does not purport to present the fair value of the Company’s oil and gasreserves. An estimate of fair value would also take into account, among otherthings, the recovery of reserves in excess of proved reserves, anticipatedfuture changes in prices and costs, a discount factor more representative ofthe time value of money and the risks inherent in reserve estimates.

Thefollowing are the principal sources of change in the standardized measure ofdiscounted future net cash flows. All amounts are related to changes inreserves located in the United States, the Kingdom of Thailand and Hungary, asnoted.
| ** **                                                                            | ** ** | **Year Ended December 31, 2004** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                                            | ** ** | **Total**                                            | ** ** | **United** | ** ** | **Kingdom of** | ** ** | ** ** | ** ** |
| ** **                                                                            | ** ** | **Company**                                          | ** ** | **States** | ** ** | **Thailand** | ** ** | **Hungary** | ** ** |
| ** **                                                                            | ** ** | **(Expressed in thousands)**               | ** ** |
| Beginning balance                                                                     |       | $                                                    | 2,450,030  |   | $ | 2,009,123 |   | $ | 424,439 |   | $ | 16,468 |   |
| Revisions to  prior years’ proved reserves:                                      |       |                                                 |       |   |   |   |   |   |   |
| Net changes in prices and production costs                                            |       | 868,070                                              |       | 631,060 |   | 237,010 |   | — |   |
| Net changes due to revisions in quantity estimates                                    |       | 25,232                                               |       | 39,661 |   | 3,739 |   | (18,168 | ) |
| Net changes in estimates of future development costs                                  |       | (161,666                                             | )          | (154,659 | ) | (7,007 | ) | — |   |
| Accretion of discount                                                                 |       | 369,000                                              |       | 292,866 |   | 74,482 |   | 1,652 |   |
| Changes in production rate and other                                                  |       | (43,414                                              | )          | (51,192 | ) | 7,778 |   | — |   |
| Total revisions                                                                       |       | 1,057,222                                            |       | 757,736 |   | 316,002 |   | (16,516 | ) |
| New field  discoveries and extensions, net of future production and development costs |       | 212,963                                              |       | 126,167 |   | 86,796 |   | — |   |
| Purchases of  properties                                                              |       | 596,173                                              |       | 596,173 |   | — |   | — |   |
| Sales of  properties                                                                  |       | (58,570                                              | )          | (58,570 | ) | — |   | — |   |
| Sales of oil and  gas produced, net of production costs                               |       | (1,074,146                                           | )          | (808,986 | ) | (265,160 | ) | — |   |
| Previously  estimated development costs incurred                                      |       | 148,290                                              |       | 98,135 |   | 50,155 |   | — |   |
| Net change in  income taxes                                                           |       | (236,395                                             | )          | (161,067 | ) | (75,376 | ) | 48 |   |
| Net change in standardized measure of discounted  future net cash flows               |       | 645,537                                              |       | 549,588 |   | 112,417 |   | (16,468 | ) |
| Ending balance                                                                        |       | $                                                    | 3,095,567  |   | $ | 2,558,711 |   | $ | 536,856 |   | $ | — |   |

 

88

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**POGO PRODUCING COMPANY & SUBSIDIARIES**

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

 
| ** **                                                                            | ** ** | **Year Ended December 31, 2003** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                                            | ** ** | **Total**                                            | ** ** | **United** | ** ** | **Kingdom of** | ** ** | ** ** | ** ** |
| ** **                                                                            | ** ** | **Company**                                          | ** ** | **States** | ** ** | **Thailand** | ** ** | **Hungary** | ** ** |
| ** **                                                                            | ** ** | **(Expressed in thousands)**               | ** ** |
| Beginning balance                                                                     |       | $                                                    | 2,055,215  |   | $ | 1,714,788 |   | $ | 340,427 |   | $ | — |   |
| Revisions to prior  years’ proved reserves:                                      |       |                                                 |       |   |   |   |   |   |   |
| Net changes in prices and production costs                                            |       | 619,394                                              |       | 434,060 |   | 185,334 |   | — |   |
| Net changes due to revisions in quantity estimates                                    |       | 200,593                                              |       | 113,329 |   | 87,264 |   | — |   |
| Net changes in estimates of future development costs                                  |       | (70,226                                              | )          | (21,781 | ) | (48,445 | ) | — |   |
| Accretion of discount                                                                 |       | 309,836                                              |       | 249,556 |   | 60,280 |   | — |   |
| Changes in production rate and other                                                  |       | (194,267                                             | )          | (182,172 | ) | (12,095 | ) | — |   |
| Total revisions                                                                       |       | 865,330                                              |       | 592,992 |   | 272,338 |   | — |   |
| New field  discoveries and extensions, net of future production and development costs |       | 320,188                                              |       | 241,946 |   | 61,726 |   | 16,516 |   |
| Purchases of properties                                                               |       | 289,484                                              |       | 289,484 |   | — |   | — |   |
| Sales of oil and  gas produced, net of production costs                               |       | (987,981                                             | )          | (737,628 | ) | (250,353 | ) | — |   |
| Previously  estimated development costs incurred                                      |       | 104,624                                              |       | 46,311 |   | 58,313 |   | — |   |
| Net change in income  taxes                                                           |       | (196,830                                             | )          | (138,770 | ) | (58,012 | ) | (48 | ) |
| Net change in standardized measure of discounted  future net cash flows               |       | 394,815                                              |       | 294,335 |   | 84,012 |   | 16,468 |   |
| Ending balance                                                                        |       | $                                                    | 2,450,030  |   | $ | 2,009,123 |   | $ | 424,439 |   | $ | 16,468 |   |

 
| ** **                                                                            | ** ** | **Year Ended December 31, 2002** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                                            | ** ** | **Total**                                            | ** ** | **United** | ** ** | **Kingdom of** | ** ** |
| ** **                                                                            | ** ** | **Company**                                          | ** ** | **States** | ** ** | **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                                  |       | (103,916                                             | )          | (56,659 | ) | (47,257 | ) |
| Accretion of discount                                                                 |       | 154,066                                              |       | 113,035 |   | 41,031 |   |
| Changes in production rate and other                                                  |       | 16,577                                               |       | 60,325 |   | (43,748 | ) |
| Total revisions                                                                       |       | 1,608,211                                            |       | 1,416,233 |   | 191,978 |   |
| 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                                      |       | 224,980                                              |       | 165,374 |   | 59,606 |   |
| 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 |   |

 

89

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**POGO PRODUCING COMPANY & SUBSIDIARIES**

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

 
| ** **                                                                                             | ** ** | **Total**                              | ** ** | **United** | ** ** | **Kingdom of** | ** ** | ** **  | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|----------------------------------------|------------|------------|------------|---------------------|------------|-------------|------------|
| ** **                                                                                             | ** ** | **Company**                            | ** ** | **States** | ** ** | **Thailand**        | ** ** | **Hungary** | ** ** |
| ** **                                                                                             | ** ** | **(Expressed in thousands)** | ** ** |
| ** **                                                                                             | ** ** | **2004**                               | ** ** |
| Future gross  revenues                                                                                 |       | $                                      | 10,574,504 |       | $          | 8,850,237           |       | $           | 1,724,267  |   | $ | — |   |
| Future production costs:                                                                               |       |                                   |       |       |       |                |       |        |       |
| Lease operating expense                                                                                |       | (2,529,480                             | )          | (2,123,530 | )          | (405,950            | )          | —      |       |
| Future  development and abandonment costs                                                              |       | (580,701                               | )          | (437,117   | )          | (143,584            | )          | —      |       |
| Future net cash  flows before income taxes                                                             |       | 7,464,323                              |       | 6,289,590  |       | 1,174,733           |       | —      |       |
| Discount at 10%  per annum                                                                             |       | (2,892,390                             | )          | (2,650,272 | )          | (242,118            | )          | —      |       |
| Discounted future  net cash flows before income taxes                                             |       | 4,571,933                              |       | 3,639,318  |       | 932,615             |       | —      |       |
| Future income taxes,  net of discount at 10% per annum                                                 |       | (1,476,366                             | )          | (1,080,607 | )          | (395,759            | )          | —      |       |
| Standardized  measure of discounted future net cash flows related to proved oil and  gas reserves |       | $                                      | 3,095,567  |       | $          | 2,558,711           |       | $           | 536,856    |   | $ | — |   |

 
| ** **                                                                                             | ** ** | **2003**   | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|------------|------------|
| Future gross  revenues                                                                                 |       | $          | 8,507,228  |   | $ | 6,912,547 |   | $ | 1,545,580 |   | $ | 49,101 |   |
| Future production costs:                                                                               |       |       |       |   |   |   |   |   |   |
| Lease operating expense                                                                                |       | (1,811,584 | )          | (1,417,118 | ) | (385,058 | ) | (9,408 | ) |
| Future  development and abandonment costs                                                              |       | (520,159   | )          | (324,813 | ) | (181,396 | ) | (13,950 | ) |
| Future net cash  flows before income taxes                                                             |       | 6,175,485  |       | 5,170,616 |   | 979,126 |   | 25,743 |   |
| Discount at 10%  per annum                                                                             |       | (2,485,484 | )          | (2,241,953 | ) | (234,304 | ) | (9,227 | ) |
| Discounted future  net cash flows before income taxes                                             |       | 3,690,001  |       | 2,928,663 |   | 744,822 |   | 16,516 |   |
| Future income  taxes, net of discount at 10% per annum                                                 |       | (1,239,971 | )          | (919,540 | ) | (320,383 | ) | (48 | ) |
| Standardized  measure of discounted future net cash flows related to proved oil and  gas reserves |       | $          | 2,450,030  |   | $ | 2,009,123 |   | $ | 424,439 |   | $ | 16,468 |   |

 
| ** **                                                                                       | ** ** | **2002**   | ** ** |
|--------------------------------------------------------------------------------------------------|------------|------------|------------|
| Future gross revenues                                                                            |       | $          | 7,078,353  |   | $ | 5,486,454 |   | $ | 1,591,899 |   | $ | — |   |
| Future production costs:                                                                         |       |       |       |   |   |   |   |   |   |
| Lease operating expense                                                                          |       | (1,819,485 | )          | (1,150,305 | ) | (669,180 | ) | — |   |
| Future  development and abandonment costs                                                        |       | (406,101   | )          | (267,578 | ) | (138,523 | ) | — |   |
| Future net cash  flows before income taxes                                                       |       | 4,852,767  |       | 4,068,571 |   | 784,196 |   | — |   |
| Discount at 10%  per annum                                                                       |       | (1,754,411 | )          | (1,573,013 | ) | (181,398 | ) | — |   |
| Discounted future  net cash flows before income taxes                                       |       | 3,098,356  |       | 2,495,558 |   | 602,798 |   | — |   |
| Future income  taxes, net of discount at 10% per annum                                           |       | (1,043,141 | )          | (780,770 | ) | (262,371 | ) | — |   |
| Standardized measure of  discounted future net cash flows related to proved oil and gas reserves |       | $          | 2,055,215  |   | $ | 1,714,788 |   | $ | 340,427 |   | $ | — |   |

 

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**POGO PRODUCING COMPANY & SUBSIDIARIES**

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

**Quarterly Results—Unaudited**

Summariesof the Company’s results of operations by quarter for the years 2004 and 2003are as follows: 
| ** **             | ** ** | **Quarter Ended**                                                               | ** ** |
|------------------------|------------|--------------------------------------------------------------------------------------|------------|
| ** **             | ** ** | **Mar. 31**                                                                     | ** ** | **June 30** | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** |
| ** **             | ** ** | **(Expressed in thousands, except per share amounts)** | ** ** |
| **2004**               |       |                                                                                 |       |   |   |   |   |   |   |
| Revenues               |       | $                                                                                    | 307,882    |   | $ | 326,893 |   | $ | 364,197 |   | $ | 324,007 |   |
| Gross profit(a)        |       | $                                                                                    | 150,911    |   | $ | 152,403 |   | $ | 173,775 |   | $ | 117,165 |   |
| Net income             |       | $                                                                                    | 71,640     |   | $ | 65,189 |   | $ | 86,612 |   | $ | 38,313 |   |
| Earnings per share(b): |       |                                                                                 |       |   |   |   |   |   |   |
| Basic                  |       | $                                                                                    | 1.13       |   | $ | 1.02 |   | $ | 1.36 |   | $ | 0.60 |   |
| Diluted                |       | $                                                                                    | 1.12       |   | $ | 1.01 |   | $ | 1.35 |   | $ | 0.59 |   |
| **2003**               |       |                                                                                 |       |   |   |   |   |   |   |
| Revenues               |       | $                                                                                    | 312,673    |   | $ | 297,146 |   | $ | 279,332 |   | $ | 272,845 |   |
| Gross profit(a)        |       | $                                                                                    | 181,206    |   | $ | 158,970 |   | $ | 148,682 |   | $ | 120,162 |   |
| Net income             |       | $                                                                                    | 88,477     |   | $ | 79,719 |   | $ | 67,660 |   | $ | 55,085 |   |
| Earnings per share(b): |       |                                                                                 |       |   |   |   |   |   |   |
| Basic                  |       | $                                                                                    | 1.45       |   | $ | 1.29 |   | $ | 1.07 |   | $ | 0.87 |   |
| Diluted                |       | $                                                                                    | 1.37       |   | $ | 1.24 |   | $ | 1.06 |   | $ | 0.86 |   |

----

(a)           Represents revenuesless lease operating, production and other taxes, transportation and other,exploration, dry hole, and impairment, and depreciation, depletion andamortization expenses.

(b)          Thesum of the individual quarterly earnings (loss) per share may not agree withyear-to-date earnings (loss) per share as each quarterly computation is basedon the income or loss for that quarter and the weighted average number ofcommon shares outstanding during that period.

**ITEM9.   *Changes in and Disagreements With Accountants onAccounting and Financial Disclosure*.**

None.

**ITEM 9A.   *Controls and Procedures***

**Evaluationof Disclosure Controls and Procedures**

The Company has established disclosure controls andprocedures to ensure that material information relating to the Company,including its consolidated subsidiaries, is made known to the officers whocertify the Company’s financial reports and to other members of seniormanagement and the Board of Directors.

Based on their evaluationas of December 31, 2004, the Company’s Chairman, President and ChiefExecutive Officer and its Senior Vice President and Chief Financial Officerhave concluded that the Company’s disclosure controls and procedures (asdefined in Rules 13a-15(e) and 15d-15(e) under theSecurities Exchange Act of 1934) are effective to ensure that the informationrequired to be disclosed by the Company in the reports that it files or submitsunder the Securities Exchange Act of 1934 is recorded, processed, summarizedand reported within the time periods specified in SEC rules and forms.

91

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**POGO PRODUCING COMPANY & SUBSIDIARIES**

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

**Management’sReport on Internal Control Over Financial Reporting**

The Company’s managementis responsible for establishing and maintaining adequate internal control overfinancial reporting, as such term is defined in Exchange Act Rules 13a-15(f).Under the supervision and with the participation of the Company’s management,including the Chairman, President and Chief Executive Officer and its SeniorVice President and Chief Financial Officer, the Company conducted an evaluationof the effectiveness of its internal control over financial reporting based onthe framework in *Internal Control—IntegratedFramework*issued by the Committee of Sponsoring Organizations of theTreadway Commission. Based on the Company’s evaluation under the framework in *Internal Control—Integrated Framework,*theCompany’s management concluded that its internal control over financialreporting was effective as of December 31, 2004. The Company’s managementsassessment of the effectiveness of our internal control over financialreporting as of December 31, 2004 has been audited byPricewaterhouseCoopers LLP, an independent registered public accounting firm,as stated in their report which is included herein.

**Changes in Internal Controls**

There were no changes inthe Company’s internal control over financial reporting that occurred duringthe most recent fiscal quarter that have materially affected, or are reasonablylikely to materially affect the Company’s internal control over financialreporting.

**ITEM 9B.   *Other Information***

There is no information required to be disclosed onForm 8-K for the quarter ended December 31, 2004 that has not been previouslyreported.

92

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**PART III**

**ITEM10.   *Directors and Executive Officers of the Registrant.***

The information responsiveto Items 401, 405 and 406 of Regulation S-K in the Company’s definitive ProxyStatement for its annual meeting to be held on April 26, 2005, to be filedwithin 120 days of December 31, 2004 pursuant to Regulation 14A under theSecurities Exchange Act of 1934, as amended (the Company’s “2005 ProxyStatement”), is incorporated herein by reference. See also Item S-K 401(b) appearingin Part I of this Form 10-K.

**ITEM 11.**   *Executive Compensation.*

The information responsiveto Item 402 of Regulation S-K in the Company’s 2005 Proxy Statement isincorporated herein by reference. The portion of the incorporated materialconsisting of the Compensation Committee Report on Executive Compensation andthe Performance Graph is not be considered “filed” with the Commission.

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

The information responsiveto Items 201(d) and 403 of Regulation S-K in the Company’s 2005 ProxyStatement is incorporated herein by reference.

**ITEM 13.**   *Certain Relationships and Related Transactions.*

The information responsiveto Item 404 of Regulation S-K in the Company’s 2005 Proxy Statement isincorporated herein by reference.

**ITEM 14.**   *Principal Accountant Fees and Services.*

The information responsiveto Item 9(e) of Schedule 14A in the Company’s 2005 Proxy Statement isincorporated herein by reference.

**PART IV**

**ITEM 15.**   *Exhibitsand Financial Statement Schedules.*

(a)           DocumentsFiled as Part of this Form 10-K
|        | ** **                                               | **Page**   |
|--------|----------------------------------------------------------|------------|
| **1.** | **Financial Statements and Supplementary Data:**         | ** ** |
|   | Report  of Independent Registered Public Accounting Firm | 50         |
|   | Consolidated  statements of income                       | 52         |
|   | Consolidated  balance sheets                             | 53         |
|   | Consolidated  statements of cash flows                   | 55         |
|   | Consolidated  statements of shareholders’ equity    | 56         |
|   | Notes to  consolidated financial statements              | 57         |
|   | Unaudited  supplementary financial data                  | 84         |

 

93

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**2.****                FinancialStatement Schedules:**

All FinancialStatement Schedules have been omitted because they are not required, are notapplicable or the information required has been included elsewhere herein.

**3.****                                          Exhibits:**
| *3.1   |   | Restated Certificate of Incorporation of Pogo  Producing Company, as filed on April 28, 2004 (Exhibit 3.1,  Quarterly Report on Form 10-Q for the quarter ended March 31, 2004,  File No. 1-7796).                                                                                                                                                                                                                                                                                                                                                                                            |
|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *3.2   |   | 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 December 16, 2004  among Pogo Producing Company, as the Borrower, certain commercial lending  institutions, as the Lenders, Bank of Montreal, acting through its Chicago,  Illinois branch, as the Administrative Agent for the Lenders, Bank of  America, N.A., Toronto Dominion (Texas) LLC and BNP Paribas, as  Co-Syndication Agents, Wachovia Bank, National Association, as Documentation  Agent, and Citibank, N.A. and the Bank of Nova Scotia, as Managing Agents  (Exhibit 4.1, Current Report on Form 8-K filed December 22,  2004, File No. 1-7792). |
| *4.2   |   | 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).                                                                                                                                                                                                                                                                                                                                                         |
| *4.3   |   | 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).                                                                                                                                                                                                                                                                                                                                                                           |
| *4.4   |   | Amendment to Rights Agreement dated as of  April 26, 2004 between Pogo Producing Company and Computershare Investor  Services, L.L.C., as successor Rights Agent (Exhibit 99.2, Current  Report on Form 8-K filed April 29, 2004, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                           |
|   |   | Other instruments defining the rights of holders of  long-term debt of Pogo Producing Company and its subsidiaries are not being  filed because the total amount of securities authorized by such instruments  does not exceed 10% of the total assets of Pogo Producing Company and its subsidiaries  on a consolidated basis as of December 31, 2003. Pogo Producing Company  hereby agrees to furnish to the Commission a copy of any such debt instrument  upon request.                                                                                                                                      |

 

**ExecutiveCompensation Plans and Arrangements (comprising Exhibits 10.1 through 10.33,inclusive)**
| *10.1 |   | 1989 Incentive and Nonqualified Stock Option Plan of  Pogo Producing Company, as amended and restated effective January 25,  1994 (Exhibit 99, Definitive Proxy Statement on Schedule 14A, filed  March 22, 1994, File No. 1-7792).                           |
|-------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *10.2 |   | Form of Stock Option Agreement under 1989  Incentive and Nonqualified Stock Option Plan, as amended and restated  effective January 22, 1991 (Exhibit 10(d)(1), Annual Report on  Form 10-K for the year ended December 31, 1991, File No. 0-5468). |

94

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| *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   |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and Paul G. Van Wagenen, dated  February 1, 2005.                                                                                                                                          |
| 10.9   |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and Stephen R. Brunner, dated February 1, 2005.                                                                                                                                            |
| 10.10  |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and Jerry A. Cooper, dated  February 1, 2005.                                                                                                                                              |
| 10.11  |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and John O. McCoy, Jr., dated  February 1, 2005.                                                                                                                                      |
| 10.12  |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and David R. Beathard, dated February 1, 2005.                                                                                                                                             |
| 10.13  |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and Radford P. Laney, dated  February 1, 2005.                                                                                                                                             |
| 10.14  |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and J. Don McGregor, dated February 1, 2005.                                                                                                                                               |
| 10.15  |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and Gerald A. Morton, dated February 1, 2005.                                                                                                                                              |
| 10.16  |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and James P. Ulm, II, dated February 1, 2005.                                                                                                                                         |
| 10.17  |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and Barry W. Acomb, dated  February 1, 2005.                                                                                                                                               |
| 10.18  |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and Bruce E. Archinal, dated February 1, 2005.                                                                                                                                             |
| 10.19  |   | Amended and Restated Executive Employment Agreement  by and between Pogo Producing Company and Michael J. Killelea, dated  February 1, 2005.                                                                                                                                          |
| *10.32 |   | Form of Restricted Stock Award Agreement Under  Incentive Plans (Exhibit 10.1, Quarterly Report on Form 10-Q for  the quarter ended June 30, 2003, File No. 1-7792).                                                                                              |
| *10.33 |   | Form of Directors Phantom Stock Agreement  (Exhibit 10.2, Quarterly Report on Form 10-Q for the quarter ended  June 30, 2003, File No. 1-7792).                                                                                                                   |
| *10.34 |   | Amended and Restated Bareboat Charter Agreement by  and between Tantawan Services, L.L.C. and Tantawan Production B.V., dated February 9,  1996 (Exhibit 10.26,  Annual Report on Form 10-K for the year ended December 31, 1999,  File No. 001-7792).       |

95

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| *10.35 |   | Bareboat Charter Agreement by and between Thaipo  Limited, Thai Romo Limited, Palang Sophon Limited, B8/32 Partners Limited and  Watertight Shipping B.V. dated as of August 24, 1998  (Exhibit 10.27, Annual Report on Form 10-K for the year ended  December 31, 1999, File No. 001-7792).                                                                                 |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *10.36 |   | Gas Sales Agreement dated November 7, 1995,  among The Petroleum Authority of Thailand, Thaipo, Limited, Thai Romo Ltd.  and The Sophonpanich Co., Ltd. (Exhibit 10(k), Quarterly Report on  Form 10-Q for the quarter ended June 30, 1996, File  No. 001-7792).                                                                                                             |
| *10.37 |   | The First Amendment to  the Gas Sales Agreement dated November 12, 1997, among The Petroleum  Authority of Thailand, B8/32 Partners Limited, Thaipo, Limited, Thai Romo  Limited and Palang Sophon Limited (Exhibit 10(g)(ii), Annual Report on  Form 10-K for the year ended December 31, 1998, File  No. 001-7792).                                                        |
| *10.38 |   | The Second Amendment to the Gas Sales Agreement  dated effective as of October 1, 2001, among The Petroleum Authority of  Thailand, Chevron Offshore (Thailand) Limited, Thaipo Limited, Palang Sophon  Limited and B8/32 Partners Limited (Exhibit 10.23, Annual Report on  Form 10-K for the year ended December 31, 2002, File  No. 1-7792).                              |
| *10.39 |   | The Third Amendment to the Gas Sales Agreement dated  November 7, 1995 between PTT Public Company Limited and Chevron Offshore  (Thailand) Limited, Thaipo Limited, Palang Sophon Limited and B8/32 Partners  Limited, dated effective as of October 1, 2001 (Exhibit 10.1,  Quarterly Report on Form 10-Q for the quarter ended September 30,  2003, File No. 1-7792). |
| 21     |   | List of Subsidiaries of Pogo Producing Company                                                                                                                                                                                                                                                                                                                                                        |
| 23.1   |   | Consent of PricewaterhouseCoopers LLP                                                                                                                                                                                                                                                                                                                                                                 |
| 23.2   |   | Consent of Ryder Scott Company, L.P.                                                                                                                                                                                                                                                                                                                                                                  |
| 23.3   |   | Consent of Miller and Lents, Ltd.                                                                                                                                                                                                                                                                                                                                                                     |
| 24     |   | Powers of Attorney from each director of Pogo  Producing Company whose signature is affixed to this Form 10-K for year  ended December 31, 2004.                                                                                                                                                                                                                                            |
| 31.1   |   | Certification of Chief Executive Officer, pursuant  to Rule 13a-14(a) under the Securities Exchange Act.                                                                                                                                                                                                                                                                                    |
| 31.2   |   | Certification of Chief Financial Officer, pursuant  to Rule 13a-14(a) under the Securities Exchange Act.                                                                                                                                                                                                                                                                                    |
| 32.1   |   | Certification of Chief Executive Officer, pursuant  to 18 U.S.C. Section 1350.                                                                                                                                                                                                                                                                                                                   |
| 32.2   |   | Certification of Chief Financial Officer, pursuant  to 18 U.S.C. Section 1350                                                                                                                                                                                                                                                                                                                    |
| 99.1   |   | Summary Report of Ryder Scott Company, L.P. for the year ended December 31, 2004.                                                                                                                                                                                                                                                                                                                     |
| 99.2   |   | Summary Report of Miller and Lents, Ltd. for the year ended December 31, 2004.                                                                                                                                                                                                                                                                                                                        |
| *99.3  |   | Summary Report of Ryder  Scott Company, L.P. for the year ended December 31, 2003 (Exhibit 99.1,  Annual Report on Form 10-K for the year ended December 31, 2003).                                                                                                                                                                                                                                   |
| *99.4  |   | Summary Report of Miller  and Lents, Ltd. for the year ended December 31, 2003    (Exhibit 99.2,  Annual Report on Form 10-K for the year ended December 31, 2003).                                                                                                                                                                                                                              |
| 99.5   |   | Summary Report of Ryder  Scott Company, L.P. for the year ended December 31, 2002.                                                                                                                                                                                                                                                                                                                    |
| 99.6   |   | Summary Report of Miller  and Lents, Ltd. for the year ended December 31, 2002.                                                                                                                                                                                                                                                                                                                       |

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*                    Asteriskindicates exhibits incorporated by reference as shown.

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the Registrant has duly caused this report to be signed on itsbehalf 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:   March 7,  2005 |                   |   |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the Registrant and inthe capacities indicated on March 2, 2005.
|                                                     | **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/ THOMAS A. FRY, III                         |           |                                     |
| **Thomas A. Fry, III**                         |           | Director                                 |
| /s/ GERRIT W. GONG                                  |           |                                     |
| **Gerrit W. Gong**                                  |           | Director                                 |
| /s/ CARROLL W. SUGGS                                |           |                                     |
| **Carroll W. Suggs**                                |           | Director                                 |
| /s/ STEPHEN A. WELLS                                |           |                                     |
| **Stephen A. Wells**                                |           | Director                                 |
| /s/ THOMAS E. HART                                  |           |                                     |
| **Thomas E. Hart**                                  | * *       | * *                                 |
| *Attorney-in-Fact*                                  | * *       | * *                                 |

 

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