**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON,D.C. 20549**

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**FORM 10-K**

| **x**      | ** ** | **ANNUAL  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE**     |
|------------|------------|-------------------------------------------------------------------------|
| ** ** | ** ** | **SECURITIES  EXCHANGE ACT OF 1934**                                    |
| ** ** | ** ** | **For the  fiscal year ended December 31, 2005**                   |
| ** ** | ** ** | **OR**                                                                  |
| **o**      | ** ** | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE** |
| ** ** | ** ** | **SECURITIES  EXCHANGE ACT OF 1934**                                    |

 

**For thetransition period from             to             **

**Commission file number:  1-7792**

**Pogo Producing Company**

(Exactname of registrant as specified in its charter)

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

 

**(713)297-5000**

(Registrant’stelephone number, including area code)

Securitiesregistered pursuant to Section 12(b) of the Act:

| **Title  of each class**                | ** ** | **Name of each exchange on which registered** |
|-----------------------------------------|------------|-----------------------------------------------|
| Common Stock, $1.00 par value per share |       | New York Stock Exchange                       |
|                                    |       | Pacific Exchange                              |
| Preferred Stock Purchase Rights         |       | New York Stock Exchange                       |

 

Securities registeredpursuant to Section 12(g) of the Act: ** None**

Indicateby check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405of the Securities Act. Yes x No o

Indicateby check mark if the registrant is not required to file reports pursuant to Section 13or Section 15(d) of the Exchange Act.      Yes o       No x

Indicateby check mark whether the registrant (1) has filed all reports required tobe filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject tosuch filing requirements for the past 90 days.      Yes x       No o

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, and willnot be contained, to the best of registrant’s knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K. x

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filer, or a non-accelerated filer. See definition of “acceleratedfiler and large accelerated filer” in Rule 12b-2 of the ExchangeAct.       Large accelerated filer x       Accelerated filer o       Non-accelerated filer o

Indicateby check mark whether the registrant is a shell company (as defined in Rule 12b-2of the Exchange Act). Yes o   No x

As of June 30, 2005, the aggregate market value ofthe registrant’s common stock held by non-affiliates of the registrant wasapproximately $3,200,000,000 based on the closing sale price as reported on theNew York Stock Exchange.

Indicate the number of shares outstanding of each ofthe issuer’s classes of common stock, as of the latest practicable date.

| **Class**                               | ** ** | **Outstanding at February 24, 2006** |
|-----------------------------------------|------------|--------------------------------------|
| Common Stock, $1.00 par value per share |       | 57,961,147 shares                    |

 

**DOCUMENTSINCORPORATED BY REFERENCE**

| Document                                                                                                                 | ** ** | ** **    | ** ** | Parts Into Which  Incorporated | ** ** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------|------------|---------------|------------|--------------------------------|------------|------------|
| Portions of the Registrant’s Proxy Statement for our  Annual Meeting of Stockholders to be held April 25, 2006 |       | Part III |

 

 

 

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**FORWARD LOOKING STATEMENTS**

The statementsincluded or incorporated by reference in this Annual Report on Form 10-Kfor the year ended December 31, 2005 (this “Annual Report”) include “forward-lookingstatements” within the meaning of Section 27A of the Securities Act of1933, as amended, and Section 21E of the Securities Exchange Act of 1934,as amended. All statements included or incorporated by reference herein, otherthan statements of historical fact, are forward-looking statements. In somecases, you can identify Pogo Producing Company’s (the “Company”)forward-looking statements by the words “anticipate,” “estimate,” “expect,” “objective,”“projection,” “forecast,” “goal,” and similar expressions. Such forward-lookingstatements include, without limitation, statements regarding expectedproduction volumes, drilling of wells and related expenditures and otherstatements herein and therein regarding the timing of future events regardingthe operations of the Company and its subsidiaries, and the statements underthe caption “Management’s Discussion and Analysis of Financial Condition andResults 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 factors set forth below, the riskfactors described under the caption “Risk Factors” and other factors set forthin 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 and integrate 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

·       covenantrestrictions in the Company’s debt agreements

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

**PART I**

**ITEM 1.**   *Business*.

The Company was incorporated in 1970 and is engaged inoil and gas exploration, development, acquisition and production activities onits properties primarily located in North America, both onshore and offshore,and in New Zealand. As of December 31, 2005, the Company ownedapproximately 3,885,000 gross leasehold acres in major oil and gas provinces inNorth America and approximately 1,044,000 gross acres in New Zealand. Over thelast several years, the Company has transitioned from a predominatelyoffshore-focused company to one with a majority of its reserves located in theonshore regions of North America. As of December 31, 2005, approximately86% of the Company’s reserves are located onshore.

The Company organizes its exploration and productionactivities principally into five operating regions, as well as a New VenturesGroup and an Unconventional Resources Group. The operating regions are itsCanadian Operations, 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; its Gulf of Mexico Region, which is responsible for the Company’soperations offshore Texas and Louisiana in the Gulf of Mexico; and the Asia andPacific Region, which has responsibility for the Company’s operations in NewZealand. The Company’s New Ventures Group is primarily responsible foridentifying new projects and opportunities for the Company outside the UnitedStates and the Unconventional Resources Group is responsible for identifyingnew unconventional resource opportunities in North America.

On August 17, 2005,the Company closed the sale of its Thailand properties for approximately $820million. On September 27, 2005, the Company completed the acquisition ofNorthrock Resources, Ltd. (“Northrock”) for approximately $1.7 billion. Northrock’sactivities are concentrated in Saskatchewan and Alberta with key explorationplays in Canada’s Northwest Territories, British Columbia and the AlbertaFoothills.

**Domestic Onshore Operations**

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 Texas Panhandle. TheCompany conducts its onshore operations in the United States directly andthrough its wholly-owned subsidiaries. Domestic onshore reserves as of December 31,2005, accounted for approximately 54% of the Company’s total proved reserves,with the Gulf Coast Region and the Western U.S. Region contributingapproximately 15% and 39%, respectively, of the Company’s total 

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provedreserves. During 2005, approximately 79% of the Company’s natural gasproduction and 38% of its oil and condensate production was from its domesticonshore properties, contributing approximately 60% of the Company’sconsolidated oil and gas revenues.

*Exploration andDevelopment*

The Company’s onshore capital and explorationexpenditures for 2005 were approximately $251,400,000 (excluding approximately$59,500,000 of net property acquisitions). Comparable expenditures for 2004 and2003 were approximately $196,500,000 (excluding approximately $489,600,000 ofnet property acquisitions) and $142,400,000 (excluding approximately $177,700,000of net property acquisitions), respectively. The increase in the Company’sonshore capital and exploration expenditures for 2005, compared to 2004,resulted primarily from expenditures related to increased exploratory anddevelopment drilling. The Company has currently budgeted approximately$430,000,000 for capital and exploration expenditures during 2006 in itsdomestic 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.

*WesternU.S. Region.*   The Company’s Western U.S. Regionhas actively explored in West Texas and New Mexico for more than 26 years and,during this period, has participated in the discovery or development of over 41oil and gas fields. In 2005, the Company participated in the drilling of 143wells in these areas (96% of which were successfully completed). The Companybelieves that during the past decade it has been one of the more activecompanies drilling for oil and natural gas in the Permian Basin of West Texasand southeastern New Mexico.

During 2006, the Company plans to drill approximatelysix exploratory wells and 104 development wells in various known fields andexploratory prospects located in southeast New Mexico, West Texas and the TexasPanhandle. Drilling objectives for these wells range in vertical depth from3,500 feet to 18,000 feet below the surface and target numerous formationsincluding, among others, the Brown Dolomite, Canyon, Delaware (Brushy Canyon),Spraberry, Bone Spring, Wolfcamp, Granite Wash, Strawn, Atoka and Morrowformations.

The Company also plans to continue an activedevelopment drilling program in the San Juan Basin, which is located innorthwest New Mexico. Nineteen wells are expected to be drilled in multipleprospects in this area during 2006. The primary targets are the Fruitland Coaland Mesaverde formations. Drilling depths are expected to range fromapproximately 1,500 feet to 6,500 feet.

The Company also continues to actively participate inthe exploration and development of the Madden Field in central Wyoming wherethe Company currently is credited with varying working interests that averageapproximately 14.5% across the unit area. Recent drilling activity in theMadden Deep Unit has focused on the Lower Fort Union formation (where productivezones have historically been found from approximately 5,500 feet to 11,000 feetbelow the surface). Also in progress is a Frontier exploratory test well with aprojected total depth of 20,585 feet.

An active Rocky Mountain drilling program of approximately64 wells is anticipated for 2006. In addition to the Company’s continuedparticipation in the development of the Madden Deep Unit, the Company alsoplans to initiate several exploratory tests elsewhere in Wyoming targeting theLower Fort Union and Lance formations at total depths ranging from 8,000 feetto 10,000 feet.

During 2005, the Company’s Western U.S. Regionacquired, in several transactions, proved producing properties located insoutheast New Mexico, West Texas and the Texas Panhandle to complement itsexisting asset base. The aggregate purchase price for these transactions wasapproximately $46 million.

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*GulfCoast Region.*   TheCompany’s Gulf Coast Region is actively exploring for, acquiring and developingoil and gas reserves, primarily in the coastal onshore areas of Louisiana andTexas. Other areas of activity include the East Texas Basin and the IllinoisBasin in southern Indiana. During 2005, the Gulf Coast Region participated indrilling 19 wells, 95% of which were successfully completed. For 2006, theCompany has budgeted to participate in 21 exploratory wells and 45 developmentwells.

The Company’s Gulf Coast Region was active during 2005drilling on its 65,000 gross acres of leasehold in South Texas’ Webb and ZapataCounties. The Company has been developing gas reserves primarily in its LosMogotes, Hundido and South Hundido Fields that produce from the Wilcox formation,found at depths ranging from 7,000 to 14,000 feet below the surface. At its LosMogotes Field, the Company drilled 10 wells in 2005. There were 49 locationsidentified to drill at Los Mogotes at the beginning of 2006 and 25 of those arecurrently budgeted to be drilled.  Currently, five wells are scheduled to bedrilled in South Hundido and Hundido Field in 2006. Elsewhere in South Texas,the Company operated and successfully completed an appraisal gas welloffsetting the 2004 South Rosita Prospect discovery well in Duval County, Texas.Additional development drilling is planned for this prospect during 2006. TheCompany also intends to actively explore various portions of the Vicksburg andWilcox trends of Texas during 2006.

In East Texas, the Company’s Gulf Coast Region isexploring the Woodbine and Austin Chalk Formations for new oil and gas reservesin Polk and Tyler Counties. The Company acquired 128 square miles of new,proprietary   3-D seismic data in2005 and interpretation of that data has yielded a number of exploratoryprospects which are 100% owned and operated by the Company. The Companycontrols approximately 80,000 acres in this area.

During 2005, the Company’s Gulf Coast Regionparticipated in drilling two Miocene exploratory wells in South Louisiana. For2006 in South Louisiana, the Company has agreed to participate in the drillingof three outside-operated exploratory wells. In addition, the Company willoperate four exploratory tests in this area in 2006. The Company also plans tooperate and begin to acquire 100-plus square miles of new 3-Dseismic in central South Louisiana.

InOctober 2005, the Company obtained a 50% working interest in anunconventional resource play in southwest Indiana that an industry partneroperates. Approximately 225,000 gross acres have been leased, seven horizontalNew Albany Shale gas wells have been drilled and gas from a production pilotcomprised of four of those wells is being produced and sold. Five exploratorywells and an additional 5 to 15 development wells are contemplated for 2006.

**Domestic Offshore Operations**

*Gulfof Mexico Region.*   Approximately14% of the Company’s proved reserves as of December 31, 2005 were locatedin the Gulf of Mexico. During 2005, approximately 14% of the Company’s naturalgas production and 50% of its oil and condensate production from the Company’sdomestic offshore properties contributed approximately 30% 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 Company’s domestic offshore capital andexploration expenditures for 2005 were $88,700,000. Comparable expenditures for2004 and 2003 were approximately $150,300,000 and $60,500,000, respectively.The decrease in the Company’s domestic offshore capital and explorationexpenditures for 2005, compared with 2004, resulted primarily from decreasedexpenditures for exploration and development wells and facilities construction.During 2005, the Company invested approximately $71,200,000 in exploration anddevelopment wells and $11,600,000 in facilities construction for its Gulf of 

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Mexico operations. TheCompany has currently budgeted approximately $91,000,000 for capital andexploration expenditures during 2006 in the Gulf of Mexico, of which$63,600,000 is budgeted for exploration and development wells and $23,300,000for facilities construction. The Company participated in drilling seven wellsduring 2005 in the Gulf of Mexico Region, two of which were consideredsuccessful. At December 31, 2005, the Company held varying interests in175 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 56 of the 88 offshore leases in which it had aninterest as of December 31, 2005.

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.

*Hurricanes Katrinaand Rita*

On August 29, 2005,after passing through the Gulf of Mexico, Hurricane Katrina made landfall nearNew Orleans, Louisiana and caused one of the worst natural disasters in U.S.history. On September 24, 2005, Hurricane Rita, one of the strongestmeasured hurricanes to have entered the Gulf of Mexico, made landfall betweenSabine Pass, Texas and Johnson’s Bayou, Louisiana. Due to the hurricanes,substantially all of the Company’s Gulf of Mexico production was shut-in andmost has been restored incrementally since then. As of February 1, 2006,approximately 4,000 Bbls of oil and 20 MMcf of natural gas of the Company’s netdaily production remain shut-in as a result of the storms. One of the platformsthe Company operates, located in Main Pass Block 123, sustained major damage,and significant damage to platforms, plants and pipelines operated by othersalso occurred, including facilities that are located in Viosca Knoll Block 823,Eugene Island Block 330, and South Marsh Island Block 128. The Company expectsremaining shut-in production to come back on-line by the end of the firstquarter of 2007. The Company maintains business interruption insurance on someof its blocks in the Gulf of Mexico. Coverage commenced 60 days after theblocks were shut in and continues for a period of one year thereafter, unlessthe production is fully restored earlier. There is no assurance that recoveriesunder the policy will be sufficient to cover the cash flow the Company wouldhave otherwise generated from the affected properties.

*Lease Acquisitions*

The Company hasparticipated, either on its own or with other companies, in bidding on andacquiring interests in federal and state leases offshore in the Gulf of Mexicosince 1970. As a result of such purchases and subsequent activities, as of December 31,2005, the Company owned interests in 76 federal leases and 12 state leasesoffshore Louisiana and Texas. Federal leases generally have primary terms offive, eight or ten years, depending on water depth, and state leases generallyhave terms of three or five years, depending on location, in each case subjectto extension by development and production operations.

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**International Operations**

The Company has conductedinternational exploration activities since the late 1970s in numerous oil andgas areas throughout the world. The Company currently holds acreage in Canadaand New Zealand. The Company’s explorationists continue to evaluate otherinternational opportunities that are consistent with its exploration strategyand expertise. For a discussion of certain risks associated with the Company’sinternational operations, see “Risk Factors—The Company’s foreign operationssubject it to additional risks,” “—The Company’s integration of Northrock maynot be successful” and “—The Company may not be able to obtain sufficientdrilling equipment and experienced personnel to conduct its operations.”

*Exploration andDevelopment*

The Company’s international capital and explorationexpenditures were approximately $162,000,000 (excluding approximately$2,526,000,000 of property acquisitions and approximately $71,095,000 of expendituresrelated to discontinued Thailand and Hungary operations) for 2005. Expendituresfor 2004 and 2003 were approximately $148,900,000 (approximately $5,700,000excluding Thailand and Hungary operations) and $138,000,000 (approximately$67,000 excluding Thailand and Hungary operations), respectively. The increasein the Company’s capital and exploration expenditures for 2005 resultedprimarily from expenditures for facilities costs and increased drillingactivity.

The Company has currentlybudgeted approximately $204,000,000 for capital and exploration expendituresduring 2006 in areas outside the United States, including approximately$200,000,000 in Canada.

**Canadian Operations**

The Company’s Canadian operations are conductedthrough Northrock, a wholly-owned subsidiary of the Company. Northrock isheadquartered in Calgary, Alberta, Canada, and has field offices in RockyMountain House, Alberta, Grande Prairie, Alberta and in Estevan, Saskatchewan. Northrockconducts its activities through joint ventures with other oil and gas companiesand operates its properties using field personnel and independent contractors.

Northrock’s principal producing properties are locatedin the Canadian provinces of Alberta, Saskatchewan and British Columbia. Inaddition, Northrock participates in an active exploration program in theNorthwest Territories.

Crude oil and natural gasreserves in Canada, as of December 31, 2005, accounted for approximately32% of the Company’s total proved reserves. During the fourth quarter of 2005,Northrock contributed approximately 27% of the Company’s natural gas productionand 41% of its oil and condensate production.

*Exploration andDevelopment*

Since the acquisition by the Company, Northrock hassignificantly expanded its existing exploration and development program,spending $78.1 million in the fourth quarter of 2005. During that time,Northrock drilled 43 wells, of which 39 wells were successfully completed. For2006, Northrock will initiate a very active exploration and development programand expects to spend approximately $200 million to drill 184 wells, including33 exploratory wells.

The exploration anddevelopment program in Canada will focus on various known fields in Alberta andSaskatchewan. In 2006, significant drilling activity is planned on recentexploration success in both southern Alberta and in southeast Saskatchewan. Inaddition to initiatives in Alberta and Saskatchewan, Northrock has an average32% interest in an exploration project in the Mackenzie Delta in the NorthwestTerritories near the route of the proposed Mackenzie Valley Gas Pipeline. Sincethe acquisition, 

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Northrockhas participated in drilling two wells in the Mackenzie Delta and is expectedto participate in the drilling of two additional wells in the first quarter of2006.

*Acquisitions*

Northrock also has an active acquisition programfocused on acquiring properties to complement existing initiatives or on newareas with anticipated significant development opportunities.

In the fourth quarter of2005, Northrock spent $41.5 million on corporate acquisitions and to acquireinterests in producing properties located primarily in southern Alberta and insouthwest Saskatchewan. For 2006, the Company anticipates that Northrock willcontinue to pursue incremental acquisition opportunities to supplement itsexploration and development program.

**Asia and Pacific Region**

*NewZealand.*   During2004, the Company was granted three petroleum exploration licenses overapproximately 1,044,000 acres in the offshore Northern Taranaki Basin. Theprimary exploration term of these licenses is for five years, subject toextension for up to an additional ten years, provided that at least half of theacreage under each license has been relinquished and the permit holder hassubstantially complied with the terms of its permits. The Company committed toacquire 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 seismicdata acquisition and 2-D seismic data reprocessing. The 3-D seismicdata acquired by the Company has been processed and is being analyzed with agoal of committing to drill multiple exploration wells in 2007, subject to rigavailability. The Company has a commitment to drill one well on each of thethree licenses by February 2008 or relinquish the license. Productionpermits of up to 40 years may be applied for if a commercial field isdiscovered.

*Vietnam.*   TheCompany, together with a joint venture partner, has been notified that it wasthe high bidder on Block 124, which covers approximately 1.48 million acresoffshore along the coast of Vietnam. As of year end, the Company wasnegotiating with PetroVietnam, the state oil company of Vietnam, for aProduction Sharing Contract covering Block 124.

*Thailandand Hungary Dispositions*

On August 17, 2005,the Company completed the sale of all of the issued and outstanding shares ofThaipo Limited, a Thailand company and a wholly-owned subsidiary of the Company(“Thaipo”), and all of the Company’s 46.34% interest in B8/32 Partners Limited,also a Thailand company (“B8/32 Partners”), for a total purchase price of $820million. The sale of the shares of Thaipo and the Company’s interests in B8/32Partners effected the disposition of all of the Company’s Thailand operations. TheCompany’s Thailand concession consisted of approximately 608,000 acres in thecentral portions of the Gulf of Thailand. The Company recognized an after taxgain of approximately $403 million on the sale of the Thailand assets for 2005.

On June 7, 2005, theCompany completed the sale of Pogo Hungary Ltd. (“Pogo Hungary”) forapproximately $9 million. The sale of Pogo Hungary resulted in the dispositionof the Company’s exploration license and related operations in Hungary. TheHungary license consisted of approximately 778,000 acres. The Companyrecognized an after tax gain of approximately $5 million on the sale of PogoHungary for 2005.

Both the Thailand and Hungary assets have been treatedas discontinued operations. For further discussion, please refer to “Management’sDiscussion and Analysis of Financial Condition and Results of Operations.”

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**Geographic and Other Information**

For financial information about geographic areas, seeNote 8—Geographic Segment Information in the Notes to Consolidated FinancialStatements, which is incorporated herein by reference. For a presentation ofthe Company’s revenues, net income and total assets for the years ended December 31,2005, 2004 and 2003, respectively, see “Financial Statements and SupplementaryData.”

The business ofexploration, development and production of crude oil and natural gas is capitalintensive. The Company has historically needed and will continue to needsubstantial amounts of cash to fund its capital expenditure and working capitalrequirements. For further discussion, see “Management’s Discussion and Analysisof Financial Condition and Results of Operations—Liquidity and CapitalResources” and “Risk Factors—The Company has substantial capital requirements.”

**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. The Company also owns an approximate 15% interest inthe Lost Cabin Gas Plant located in the Madden Field, which currently isprocessing in excess of 340 MMcf per day.

*Sales*

The marketing of all of the Company’s onshore and offshoreoil and gas production is subject to the availability of pipelines and othertransportation, processing and refining facilities, as well as the existence ofadequate markets. As a result, even if hydrocarbons are discovered incommercial 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.

Most of the Company’s domestic natural gas sales arecurrently made in the “spot market” for no more than one month at a time atthen-currently available prices or under longer-term contracts with prices thatare based on, and fluctuate with, spot market prices. Prices on the spot marketfluctuate with supply and demand. Domestic crude oil and condensate productionis also generally sold one month at a time at the price that is then-currentlyavailable or under longer-term contracts with prices that also fluctuate inrelationship to published market price.

Northrock, the Company’s wholly-owned Canadiansubsidiary, currently sells the majority of its oil production under contractswith a six-month term but with prices based on monthly market conditions. Theremainder of Northrock’s crude oil production is sold in the spot market for nomore than one month at a time at then currently available prices. The majorityof Northrock’s gas sales are month-to-month spot market sales at currentlyavailable prices. Approximately 60% of Northrock’s spot market, month-to-monthsales of natural gas are sold under firm delivery requirements for the month ofsales. The remaining approximate 40% of sales are sold under a best effortsbasis. The Company believes that this 60-40 mix affords it the necessaryflexibility in its production to meet all firm delivery requirements. A smallportion of Northrock’s gas sales are under longer-term contracts but withprices based on monthly market conditions and best efforts deliveryobligations.

Other than oil and natural gas forward sales contractsthat may exist from time to time, which are described below in “—Miscellaneous;Competition and Market Conditions,” and the natural gas contracts 

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discussed above, theCompany has no existing contracts that require the delivery of fixed quantitiesof oil or natural gas, other than on a best efforts basis.

In 2005, crude oil salesto Shell Trading Company constituted more than 10% of the Company’sconsolidated revenues.

*Competition andMarket Conditions*

The Company experiences competition from other oil andgas companies in all phases of its operations, as well as competition fromother energy-related industries. See “Risk Factors—The Company facessignificant competition and is smaller than many of its competitors.”  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 cashflow and profitability. Sustained periods of low prices could cause the Companyto shut-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 of Operations—Liquidityand Capital Resources; Credit Agreement.”

Because it is impossible to predict future oil and gasprice movements with any certainty, the Company from time to time enters intocontracts to hedge against future market price changes on a portion of itsproduction. While intended to limit the negative effect of price declines, someforms of hedging transactions could effectively limit the Company’sparticipation in price increases, which could be significant, for the coveredperiod. As of December 31, 2005, the Company was a party to certainnatural gas or crude oil option contracts (see “Quantitative and QualitativeDisclosures About Market Risk—Current Hedging Activity”). When the Company doesengage in certain types of hedging activities, it may satisfy its obligationswith its own production or by the purchase (or sale) of third-party production.The Company may also offset delivery obligations under these hedgingtransactions requiring physical delivery with equivalent agreements, therebyeffecting a purely cash transaction.

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**Exploration and Production Data**

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

The Companyowns interests in developed and undeveloped oil and gas acreage in variousparts of the world. These ownership interests generally take the form of “workinginterests” in oil and gas leases that have varying terms. The following tableshows the Company’s interest in developed and undeveloped oil and gas acreageunder lease as of December 31, 2005:

| ** **              | ** ** | **Developed Acreage(a)** | ** ** | **Undeveloped Acreage(b)** | ** ** |
|-------------------------|------------|-------------------------------|------------|---------------------------------|------------|
| ** **              | ** ** | **Gross**                     | ** ** | **Net**                         | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Domestic Onshore        |       |                          |       |                            |       |   |   |   |   |
| Louisiana               |       | 15,614                        |       | 4,629                           |       | 59,400 |   | 52,861 |   |
| New Mexico              |       | 81,816                        |       | 64,600                          |       | 86,156 |   | 65,334 |   |
| Texas                   |       | 236,072                       |       | 134,421                         |       | 213,767 |   | 132,578 |   |
| Indiana                 |       | 2,240                         |       | 1,120                           |       | 222,760 |   | 111,380 |   |
| Wyoming                 |       | 30,886                        |       | 3,894                           |       | 133,746 |   | 98,475 |   |
| Utah                    |       | —                        |       | —                          |       | 64,217 |   | 61,830 |   |
| Other                   |       | 15,959                        |       | 8,739                           |       | — |   | — |   |
| Total Domestic Onshore  |       | 382,587                       |       | 217,403                         |       | 780,046 |   | 522,458 |   |
| Domestic Offshore       |       |                          |       |                            |       |   |   |   |   |
| Louisiana               |       | 138,456                       |       | 59,412                          |       | 180,355 |   | 157,256 |   |
| Texas                   |       | 11,520                        |       | 5,286                           |       | 5,760 |   | 2,880 |   |
| Total Domestic Offshore |       | 149,976                       |       | 64,698                          |       | 186,115 |   | 160,136 |   |
| Total Domestic          |       | 532,563                       |       | 282,101                         |       | 966,161 |   | 682,594 |   |
| International           |       |                          |       |                            |       |   |   |   |   |
| Canada                  |       | 621,701                       |       | 292,383                         |       | 1,764,848 |   | 946,267 |   |
| New Zealand             |       | —                        |       | —                          |       | 1,043,806 |   | 1,043,806 |   |
| Total International     |       | 621,701                       |       | 292,383                         |       | 2,808,654 |   | 1,990,073 |   |
| Total Company           |       | 1,154,264                     |       | 574,484                         |       | 3,774,815 |   | 2,672,667 |   |

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(a)           “Developedacreage” consists of lease acres spaced or assignable to production on whichwells have been drilled or completed to a point that would permit theproduction of commercial quantities of oil or natural gas.

(b)          Approximately2% of the Company’s total onshore net undeveloped acreage is under leases thathave minimum terms expiring in 2006. Approximately 0.7% of the Company’s totaloffshore net undeveloped acreage have expiring terms in 2006.

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*Average Production (Lifting) Costs per Unit ofProduction*

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 received by the Companyfor such production, see “Selected Financial Data—Production (Sales) Data” and “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—Resultsof Operations; 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.

| ** **                                       | ** ** | **2005**   | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|--------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Average Production  (Lifting) Costs per Mcfe(a): | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Located in the United  States                    |       | $          | 1.45       |       | $          | 0.97       |       | $ | 0.68 |   |
| Located in Canada                                |       | $          | 1.47       |       | —     |       | —     |   |
| Total Company(b)                                 |       | $          | 1.45       |       | $          | 0.97       |       | $ | 0.68 |   |

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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.

(b)          TotalCompany average production costs exclude discontinued operations.

*Productive Wells and Drilling Activity*

The following table showsthe Company’s interest in productive oil and natural gas wells as of December 31,2005. For purposes of this table “productive wells” are defined as wellsproducing hydrocarbons and wells “capable of production” (i.e., natural gaswells waiting for pipeline connections or necessary governmental certificationto commence deliveries and oil wells waiting to be connected to currentlyinstalled production facilities). “Net wells” for purposes of this table aredefined to mean the sum of the Company’s working interest net of royalties andother burdens. This table does not include exploratory or development wellsthat have located commercial quantities of oil or natural gas but that are notcapable of commercial production without the installation of materialproduction facilities or that, for a variety of reasons, the Company does notcurrently believe will be placed on production.

| ** **            | ** ** | **Oil Wells(a)(b)** | ** ** | **Natural  Gas Wells(a)(b)** | ** ** | **Total** | ** ** |
|-----------------------|------------|--------------------------|------------|-----------------------------------|------------|-----------|------------|
| ** **            | ** ** | **Gross**                | ** ** | **Net**                           | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Domestic  Onshore** | ** ** | **1,512**                | ** ** | **910.0**                         | ** ** | **1,626** | ** ** | **917.7** | ** ** | **3,138** | ** ** | **1,827.7** | ** ** |
| Operated              | ** ** | 874                      | ** ** | 804.6                             | ** ** | 976       | ** ** | 801.2 | ** ** | 1,850 | ** ** | 1,605.8 | ** ** |
| Nonoperated           | ** ** | 638                      | ** ** | 105.4                             | ** ** | 650       | ** ** | 116.5 | ** ** | 1,288 | ** ** | 221.9 | ** ** |
| **Offshore**          | ** ** | **120**                  | ** ** | **58.0**                          | ** ** | **55**    | ** ** | **26.9** | ** ** | **175** | ** ** | **84.9** | ** ** |
| Operated              |       | 45                       |       | 38.5                              |       | 32        |       | 21.2 |   | 77 |   | 59.7 |   |
| Nonoperated           |       | 75                       |       | 19.5                              |       | 23        |       | 5.7 |   | 98 |   | 25.2 |   |
| **Canada**            | ** ** | **1,077**                | ** ** | **529.7**                         | ** ** | **670**   | ** ** | **322.4** | ** ** | **1,747** | ** ** | **852.1** | ** ** |
| Operated              |       | 325                      |       | 265.3                             |       | 281       |       | 229.4 |   | 606 |   | 494.7 |   |
| Nonoperated           |       | 752                      |       | 264.4                             |       | 389       |       | 93.0 |   | 1,141 |   | 357.4 |   |
| **Total**             | ** ** | **2,709**                | ** ** | **1,497.7**                       | ** ** | **2,351** | ** ** | **1,267.0** | ** ** | **5,060** | ** ** | **2,764.7** | ** ** |
| Operated              |       | 1,244                    |       | 1,108.4                           |       | 1,289     |       | 1,051.8 |   | 2,533 |   | 2,160.2 |   |
| Nonoperated           |       | 1,465                    |       | 389.3                             |       | 1,062     |       | 215.2 |   | 2,527 |   | 604.5 |   |

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(a)           Oneor more completions in the same bore hole are counted as one well. The data inthe above table includes 48 gross (31.3 net) oil wells and 143 gross (8.5 net)natural gas wells with multiple completions.

(b)          TheCompany was in the process of drilling a total of 48 gross (11 Canada, 37 U.S.)and 27.1 net (7.5 Canada, 19.6 U.S.) oil and natural gas wells as of December 31,2005.

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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 indicate 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.

| ** **             | ** ** | **2005**       | ** ** | **2004** | ** ** | **2003**       | ** ** |
|------------------------|------------|----------------|------------|----------|------------|----------------|------------|
| ** **             | ** ** | **Productive** | ** ** | **Dry**  | ** ** | **Productive** | ** ** | **Dry** | ** ** | **Productive** | ** ** | **Dry** | ** ** |
| **Gross  Wells:**      |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Onshore United States  |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory            |       |           | 10         |     |       | 3              |       |   | 1 |   |   | 5 |   |   | 9 |   |   |   | 3 |   |   |
| Development            |       |           | 204        |     |       | 12             |       |   | 248 |   |   | 9 |   |   | 169 |   |   |   | 9 |   |   |
| Offshore United States |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory            |       |           | 2          |     |       | 5              |       |   | 2 |   |   | 2 |   |   | 5 |   |   |   | 2 |   |   |
| Development            |       |           | —     |     |       | —         |       |   | 8 |   |   | — |   |   | 3 |   |   |   | — |   |   |
| Canada                 |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory            |       |           | 2          |     |       | 1              |       |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Development            |       |           | 37         |     |       | 3              |       |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Total                  |       |           | 255        |     |       | 24             |       |   | 259 |   |   | 16 |   |   | 186 |   |   |   | 14 |   |   |
| **Net  Wells:**        |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Onshore United States  |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory            |       |           | 7.7        |     |       | 2.2            |       |   | 0.6 |   |   | 3.8 |   |   | 5.9 |   |   |   | 2.0 |   |   |
| Development            |       |           | 70.2       |     |       | 5.1            |       |   | 122.4 |   |   | 4.6 |   |   | 75.9 |   |   |   | 3.5 |   |   |
| Offshore United States |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory            |       |           | 2.0        |     |       | 3.9            |       |   | 1.6 |   |   | 1.8 |   |   | 2.3 |   |   |   | 2.0 |   |   |
| Development            |       |           | —     |     |       | —         |       |   | 6.2 |   |   | — |   |   | 2.2 |   |   |   | — |   |   |
| Canada                 |       |           |       |     |       |           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Exploratory            |       |           | 1.5        |     |       | 1.0            |       |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Development            |       |           | 21.9       |     |       | 1.9            |       |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Total                  |       |           | 103.3      |     |       | 14.1           |       |   | 130.8 |   |   | 10.2 |   |   | 86.3 |   |   |   | 7.5 |   |   |

 

*Reserves*

Thefollowing table sets forth information as to the Company’s net proved andproved developed reserves as of December 31, 2005, 2004 and 2003, and thepresent value as of such dates (based on an annual discount rate of 10%) of theestimated future net revenues from the production and sale of those reserves (“PV-10”),as set forth in reports prepared by Ryder Scott Company L.P. (“Ryder Scott”)and reports prepared by the Company and reviewed by Ryder Scott Company—Canada(“Ryder Scott Canada”) and Miller and Lents, Ltd. (“Miller and Lents”), inaccordance with criteria prescribed by the Commission. The summary reports ofRyder Scott, Ryder Scott Canada, and Miller and Lents, independent petroleumengineering firms, on the Company’s reserves are set forth as exhibits to thisAnnual Report on Form 10-K and are incorporated herein by reference.The Ryder Scott report covers all of the Company’s reserves, except for theCompany’s Canadian areas, which are covered by the Ryder Scott Canada report,and certain domestic onshore areas on the Texas/Louisiana Gulf Coast and inWyoming, which are covered by the Miller and Lents report. Reservesattributable to the Company’s 

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operations in Thailand and Hungary, operations thatwere disposed of in 2005 and are accounted for in the Company’s financialstatements as discontinued operations, are excluded from the table below andseparately presented in the footnotes that follow the table.

| ** **                                                                          | ** ** | **As of December 31,** | ** ** |
|-------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                          | ** ** | **2005**                              | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Total Proved Reserves(a):**                                                       |       |                                  |       |   |   |   |   |
| Oil, condensate and  natural gas liquids (MBbls)                                    |       |                                  |       |   |   |   |   |
| Located in the United  States                                                       |       | 82,238                                |       | 83,866 |   | 77,553 |   |
| Located in Canada                                                                   |       | 61,803                                |       | — |   | — |   |
| Total Company                                                                       |       | 144,041                               |       | 83,866 |   | 77,553 |   |
| Natural Gas (MMcf)                                                                  |       |                                  |       |   |   |   |   |
| Located in the United  States                                                       |       | 891,298                               |       | 933,981 |   | 837,004 |   |
| Located in Canada                                                                   |       | 286,427                               |       | — |   | — |   |
| Total Company                                                                       |       | 1,177,725                             |       | 933,981 |   | 837,004 |   |
| Present value of  estimated future net revenues, before income taxes (in thousands) |       |                                  |       |   |   |   |   |
| Located in the United  States                                                       |       | $                                     | 4,666,472  |   | $ | 3,639,318 |   | $ | 2,928,663 |   |
| Located in Canada                                                                   |       | $                                     | 1,954,086  |   | — |   | — |   |
| Total Company                                                                       |       | $                                     | 6,620,558  |   | $ | 3,639,318 |   | $ | 2,928,663 |   |
| **Total Proved Developed  Reserves(b):**                                            |       |                                  |       |   |   |   |   |
| Oil, condensate and  natural gas liquids (MBbls)                                    |       |                                  |       |   |   |   |   |
| Located in the United  States                                                       |       | 63,161                                |       | 72,968 |   | 67,391 |   |
| Located in Canada                                                                   |       | 55,413                                |       | — |   | — |   |
| Total Company                                                                       |       | 118,574                               |       | 72,968 |   | 67,391 |   |
| Natural Gas (MMcf)                                                                  |       |                                  |       |   |   |   |   |
| Located in the United  States                                                       |       | 685,301                               |       | 769,753 |   | 702,836 |   |
| Located in Canada                                                                   |       | 220,704                               |       | — |   | — |   |
| Total Company                                                                       |       | 906,005                               |       | 769,753 |   | 702,836 |   |
| Present value of  estimated future net revenues, before income taxes (in thousands) |       |                                  |       |   |   |   |   |
| Located in the United  States                                                       |       | $                                     | 3,660,148  |   | $ | 3,122,860 |   | $ | 2,455,495 |   |
| Located in Canada                                                                   |       | $                                     | 1,653,299  |   | — |   | — |   |
| Total Company                                                                       |       | $                                     | 5,313,447  |   | $ | 3,122,860 |   | $ | 2,455,495 |   |

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(a)           Excludes provedreserves located in Thailand and Hungary, as well as the present value ofestimated future net revenues from such reserves. As of December 31, 2004and 2003, the Company’s proved reserves in Thailand consisted of 32,517 MBblsand 37,307 MBbls of oil, condensate and natural gas liquids, respectively, and145,689 MMcf and 165,188 MMcf of natural gas, respectively. As of December 31,2003, the Company’s proved reserves in Hungary consisted of 10,131 MMcf ofnatural gas. The Company had no proved reserves in      Hungary as of December 31, 2004 and no proved reserves inHungary of oil, condensate and natural gas liquids as of December 31,2003.

(b)          Excludes proveddeveloped reserves located in Thailand and Hungary, as well as the presentvalue of estimated future net revenues from such reserves. As of December 31,2004 and 2003, the Company’s proved developed reserves in Thailand consisted of19,607 MBbls and 19,878 MMBbls of oil, condensate and natural gas liquids,respectively, and 83,095 MMcf and 77,938 MMcf of natural gas, respectively.  The Company had no proved developed reservesin Hungary as of December 31, 2004 or December 31, 2003.

The following tablepresents a reconciliation of the PV-10 values set forth above for bothproved and proved developed reserves to the most directly comparable GAAPfinancial measure, which is the 

14

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standardizedmeasure of discounted future net cash flows. Management believes thatpresentation of PV-10 values is relevant and useful to the Company’sinvestors because it presents the discounted future net cash flows attributableto both the Company’s proved and proved developed reserves prior to taking intoaccount the effect of the non-property related expense of estimated futureincome taxes. Because many factors that are unique to individual companies mayimpact the amount of future income taxes to be paid, the use of a pre-taxmeasure such as PV-10 provides greater comparability for investors whenevaluating companies. Accordingly, investors may utilize the measure as a basisfor comparison of the relative size and value of the Company’s reserves toother companies. Management also uses the PV-10 measure when assessingthe potential return on investment related to the Company’s oil and gasproperties. PV-10 is not a measure of financial or operating performanceunder GAAP, nor should it be considered in isolation or as a substitute for thestandardized measure of discounted future net cash flows as defined under GAAP.For the Company’s presentation of the standardized measure of discounted futurenet cash flows, please see “Standardized Measure of Discounted Future Net CashFlows Related to Proved Oil and Gas Reserves—Unaudited” following the notes tothe consolidated financial statements in this report.

**PresentValue GAAP to Non-GAAP Reconciliation**

| ** **                                                                                            | ** ** | **As of December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                            | ** ** | **2005**                              | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                                            | ** ** | **(thousands)**                       | ** ** |
| Present value of  estimated future net revenues, before income taxes, of proved developed  reserves   |       | $                                     | 5,313,447  |   | $ | 3,122,860 |   | $ | 2,455,495 |   |
| Present value of  estimated future net revenues, before income taxes, of proved undeveloped  reserves |       | 1,307,111                             |       | 516,447 |   | 473,168 |   |
| Present value of  estimated future net revenues, before income taxes, of total proved reserves        |       | $                                     | 6,620,558  |   | $ | 3,639,307 |   | $ | 2,928,663 |   |
| Future income  taxes, net of discount at 10% per annum                                                |       | (2,057,713                            | )          | (1,080,607 | ) | (919,540 | ) |
| Standardized measure of  discounted future net cash flows related to proved oil and gas reserves      |       | $                                     | 4,562,845  |   | $ | 2,558,700 |   | $ | 2,009,123 |   |

 

15

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The PV-10 measure and the standardized measureof discounted future net cash flows do not purport to present the fair value ofthe Company’s natural gas and oil 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. Essentially all of the Company’s natural gas productionis currently sold on the spot market.

Natural gas liquids comprised approximately 14.3% ofthe Company’s total proved liquids reserves and approximately 13.4% of theCompany’s proved developed liquids reserves as of December 31, 2005. Allhydrocarbon liquid reserves are expressed in standard 42 gallon Bbls. All gasvolumes and gas sales are expressed in MMcf at the pressure and temperaturebases of the area where the gas reserves are located.

Theprices used by the Company to calculate the present value of estimated futurerevenues are determined on a well or field-by-field basis, as applicable, asdescribed above and were held constant over the productive life of thereserves. The initial weighted average prices used by Ryder Scott, and providedby the Company to Ryder Scott Canada and Miller and Lents were as follows:

| ** **                                        | ** ** | **As of December 31,** | ** ** |
|---------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                        | ** ** | **2005**                              | ** ** | **2004** | ** ** | **2003** | ** ** |
| Initial Weighted  Average Price (in Dollars):     |       |                                  |       |   |   |   |   |
| Oil, condensate and natural gas liquids (per Bbl) |       |                                  |       |   |   |   |   |
| Located in the United States                      |       | $                                     | 57.06      |   | $ | 40.82 |   | $ | 31.34 |   |
| Located in Canada(a)                              |       | $                                     | 42.86      |   | — |   | — |   |
| Natural Gas (per Mcf)                             |       |                                  |       |   |   |   |   |
| Located in the United States                      |       | $                                     | 8.15       |   | $ | 6.04 |   | $ | 5.70 |   |
| Located in Canada                                 |       | $                                     | 9.02       |   | — |   | — |   |

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(a)           The difference ininitial weighted prices presented for Canada and the United States areprimarily due to the medium gravity crude produced from the southwestSaskatchewan assets, which account for approximately 40% of the Canadian crudeoil and condensate production.

In computing future revenues from gas reserves attributableto the Company’s interests, prices in effect at December 31, 2005 wereused, including current market prices, contract prices and fixed anddeterminable price escalations where applicable. The gas prices that were usedmake no allowances for seasonal variations in gas prices that are likely tocause future yearly average gas prices to be different than December gasprices. For gas sold under contract, the contract gas price, including fixedand determinable escalations, exclusive of inflation adjustments, was useduntil the contract expires and then was adjusted to the current market pricefor the area and held at this adjusted price through to depletion of thereserves. In computing future revenues from liquids attributable to the Company’sinterests, prices in effect at December 31, 2005 were used and theseprices were held constant through to depletion of the properties. The futurenet revenues are adjusted to reflect the Company’s net revenue interest inthese reserves as well as any ad valorem and other severance taxes but do notinclude any provisions for corporate income taxes.

In calculating future net revenues, the operatingcosts for the leases and wells include only those costs directly applicable tothe leases or wells. When applicable, the operating costs include a portion ofgeneral and administrative costs allocated directly to the leases and wellsunder terms of operating agreements. Development costs are based onauthorization for expenditure for the proposed work or actual costs for similarprojects. The current operating and development costs were held constantthroughout the life of the properties. The estimated net cost of abandonmentafter salvage was considered for the properties. No deduction was made forindirect costs such as general and administrative and overhead expenses, loan 

16

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repayments, interestexpenses and exploration and development prepayments. Accumulated gasproduction 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 2005. 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, RyderScott Canada, and Miller and Lents. The accuracy of any reserve estimateis a function of the quality of available data and of engineering andgeological interpretation and judgment. Results of drilling, testing andproduction subsequent to the date of the estimate may justify revision of suchestimate, which may be material. Accordingly, reserve estimates are oftendifferent from the quantities of oil and gas that are ultimately recovered.

The Company isperiodically required to file estimates of its oil and gas reserve data withvarious U.S. governmental regulatory authorities and agencies, including theDepartment of Energy, the Federal Energy Regulatory Commission (“FERC”) and theFederal Trade Commission. 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, 2005, 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.

**Government Regulations**

*Domestic andForeign Tax*

The Company’s domestic andforeign operations are significantly affected by political developments andchanges in federal, provincial, state and local tax laws and regulations.

*American JobsCreation Act of 2004*

The American Jobs CreationAct of 2004 (the “Act”) created a temporary tax incentive for U. S.corporations to repatriate accumulated income earned abroad by providing an 85%dividend received deduction for certain dividends from controlled foreigncorporations. In 2005, the Company adopted a Domestic Reinvestment Plan thatqualifies for the temporary incentive, provided that repatriated funds areinvested pursuant to the plan. The Company repatriated $497 million (themaximum amount that qualified for the dividend received deduction under theAct) during September of 2005.

*EnvironmentalMatters*

The Company’s operations are subject to numerousforeign, federal, state and local environmental laws and regulations governingthe release and/or discharge of materials into the environment or otherwiserelating to environmental protection. Numerous governmental agencies issueregulations to implement and enforce these laws, for which compliance is oftencostly and difficult. The violation of these laws and 

17

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regulations may result inthe denial or revocation of permits, issuance of corrective action orders,assessment of administrative and civil penalties, and even criminalprosecution. The Company believes it is in substantial compliance withapplicable environmental laws and regulations. Further, the Company does notanticipate that compliance with existing environmental laws and regulationswill have a material effect on its financial condition or results ofoperations. However, there can be no assurance that substantial costs forcompliance will not be incurred in the future. Moreover, it is possible thatother developments, such as the adoption of stricter environmental laws,regulations, and enforcement policies, could result in additional costs orliabilities that the Company cannot currently quantify.

The Company generates wastes, including hazardouswastes, that are subject to the federal Resource Conservation and Recovery Act,or RCRA, and comparable state statutes or Canadian laws. The U.S. EnvironmentalProtection Agency (“the EPA”), and state agencies have limited the approvedmethods of disposal for some types of hazardous and nonhazardous wastes. Somewastes handled by the Company in its field service activities that currentlyare exempt from treatment as hazardous wastes may in the future be designatedas “hazardous wastes”‘ under RCRA or other applicable statutes. If this were tooccur, the Company would become subject to more rigorous and costly operatingand disposal requirements.

The federal Comprehensive Environmental Response,Compensation, and Liability Act, CERCLA or the “Superfund’’ law, and comparablestate statutes and Canadian laws impose liability, without regard to fault orlegality of the original conduct, on classes of persons that are considered tohave contributed to the release of a hazardous substance into the environment. UnderCERCLA, liable persons may be subject to joint and several liability for thecosts of cleaning up the hazardous substances that have been released into theenvironment and for damages to natural resources, and it is not uncommon forneighboring landowners and other third parties to file claims for personalinjury and property damage allegedly caused by the hazardous substancesreleased into the environment. The Company currently owns interests in oroperates numerous properties and facilities that for many years have been usedfor industrial activities, including oil and gas production operations.Hazardous substances, wastes, or hydrocarbons may have been released on orunder the properties owned or leased by the Company, or on or under otherlocations where such substances have been taken for disposal. In addition, someof these properties have been operated by third parties or by previous ownerswhose treatment and disposal or release of hazardous substances, wastes, orhydrocarbons, was not under the Company’s control. These properties and thesubstances disposed or released on them may be subject to CERCLA, RCRA andanalogous state laws. Under such laws, the Company could be required to removepreviously disposed substances and wastes (including substances disposed of orreleased by prior owners or operators), remediate contaminated property(including groundwater contamination, whether from prior owners or operators orother historic activities or spills), or perform remedial plugging or pitclosure operations to prevent future contamination. These laws and regulationsmay also expose the Company to liability for its acts that were in compliancewith applicable laws at the time the acts were performed. The Company maintainsinsurance against costs of clean-up operations, but is not fully insuredagainst all such risks. A serious incident of pollution may also result in theDepartment of the Interior requiring lessees under federal leases to suspend orcease operation in the affected area.

The Federal Water Pollution Control Act, also known asthe Clean Water Act, and analogous state laws and Canadian laws imposerestrictions and strict controls regarding the discharge of pollutants intostate waters or waters of the United States and Canada. The discharge ofpollutants into jurisdictional waters is prohibited unless the discharge ispermitted by the EPA or applicable state agencies. The Company has numerousapplications pending before the EPA for National Pollutant DischargeElimination System (“NPDES”) water discharge permits with respect to offshoredrilling and production operations.

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 

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spills in United Stateswaters. The OPA assigns liability to each responsible party for oil removalcosts and a variety of public and private damages. While liability limits applyin some circumstances, a party cannot take advantage of liability limits if thespill was caused by gross negligence or willful misconduct or resulted fromviolation of federal safety, construction or operating regulations. Fewdefenses exist to the liability imposed by the OPA. In addition, to the extentthe Company’s offshore lease operations affect state waters, the Company may besubject to additional state and local clean-up requirements or incur liabilityunder state and local laws. The OPA also imposes ongoing requirements onresponsible parties, including proof of financial responsibility to cover atleast some costs in a potential spill. The amount of financial responsibilitythat the Company must currently demonstrate for its offshore platforms is$70,000,000. The Company believes that it currently has established adequateproof of financial responsibility for its offshore facilities. However, theCompany cannot predict whether these financial responsibility requirementsunder the OPA amendments will result in the imposition of substantialadditional annual costs to the Company in the future or otherwise materially adverselyaffect the Company. The impact, however, should not be any more adverse to theCompany than it will be to other similarly situated or less capitalized ownersor operators in the Gulf of Mexico.

Some of the Company’s operations also result inemissions of regulated air pollutants. The federal Clean Air Act and analogousstate laws and Canadian laws require permits for facilities that have thepotential to emit substances into the atmosphere that could adversely affectenvironmental quality. Failure to comply with these requirements could resultin the imposition of substantial administrative, civil and even criminalpenalties.

The Company is also subject to the requirements of thefederal Occupational Safety and Health Act (“OSHA”) and comparable state statutesas well as Canadian provincial and local laws that regulate the protection ofthe health and safety of workers. In addition, the OSHA hazard communicationstandard requires that information be maintained about hazardous materials usedor produced in operations and that this information be provided to employees,state and local government authorities and the public.

Canada is a signatory to the United Nations FrameworkConvention on Climate Change and has ratified the Kyoto Protocol establishedthereunder to set legally binding targets to reduce nationwide emissions ofcarbon dioxide, methane, nitrous oxide and other so-called “greenhouse gases.”  Northrock’s exploration and productionfacilities and other operations and activities may emit greenhouse gases thatmay subject Northrock to legislation regulating emissions of greenhouse gases. TheGovernment of Canada has put forward a Climate Change Plan for Canada, whichsuggests further legislation will set greenhouse gases emission reductionrequirements for various industrial activities, including oil and gasexploration and production. Future federal legislation, together withprovincial emission reduction requirements such as those proposed in Alberta’sBill 37: Climate Change and Emissions Management, may require the reduction ofemissions or emissions intensity produced by a corporation’s operations andfacilities. Given the uncertainties regarding implementation of the KyotoProtocol and related climate change policies, the potential liability associatedwith future regulations is currently unknown. The Company can provide noassurances that the direct or indirect costs of such regulations will notmaterially adversely affect the business of Northrock.

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 2005, the Company incurred capitalexpenditures of approximately $1,297,000 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 $2,600,000 for expendituresinvolving environmental control 

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facilitiesduring 2006, including, among other things, anticipated site restoration costsand the installation of environmental 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 production,land tenure and other matters. The effect of these laws and regulations, aswell as other regulations that could be promulgated by the jurisdictions inwhich the Company has production, could be to limit the number of wells thatcould be drilled on the Company’s properties and to limit the allowableproduction from the successful wells completed on the Company’s properties,thereby limiting the Company’s revenues.

The Minerals Management Service (“MMS”) administersthe oil and gas leases held by the Company on federal onshore lands andoffshore tracts in the Outer Continental Shelf. The MMS holds a royaltyinterest in these federal leases on behalf of the federal government. While theroyalty interest percentage is fixed at the time that the lease is enteredinto, from time to time the MMS changes or reinterprets the applicableregulations governing its royalty interests, and such action can indirectlyaffect the actual royalty obligation that the Company is required to pay.However, the Company believes that the regulations generally do not impact theCompany to any greater extent than other similarly situated producers.

FERC regulates the rates, terms and conditionsapplicable to the transportation of natural gas by interstate pipelines and tothe storage of gas transported in interstate commerce. FERC generally requirescost-based rates, although under certain circumstances it approves market-basedrates and other alternative rate mechanisms. State agencies are generallyresponsible for regulating intrastate gas transportation and storage. Gatheringservices are exempt from FERC regulation except in certain circumstances wherethe services are provided in connection with interstate transportation. Stateagencies typically have authority to regulate rates for gathering servicesprovided within the respective states. To the extent FERC and the stateagencies allow higher rates for transportation, storage, or gathering, gasprices received by the Company for the sale of its gas production may beadversely impacted. However, the impact should not be substantially differenton the Company than it will be on other similar situated gas producers andsellers.

FERC also regulates the rates for interstate pipelinetransportation of crude oil, while state agencies regulate rates for intrastatecrude oil transportation. The transportation rates set by FERC and the stateagencies can affect the prices received by the Company for the sale of itscrude oil production. However, as in the case of gas transportation regulation,the impact of such rate regulation should not be substantially different on theCompany than it will be on other similarly situated crude oil producers andsellers.

The provincial governmentsin Canada each impose lessor royalties on Crown mineral leases, and these areset by regulation. For leases where the lessor is not the provincialgovernment, the royalty rate is negotiated between lessor and lessee.

**Employees**

As of December 31,2005, the Company and its subsidiaries had 421 full-time employees, including168 in its Calgary office. None of the Company’s employees are presentlyrepresented by a union for collective bargaining 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 

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www.pogoproducing.comas soon as reasonably practicable after the Company electronically files suchmaterial with, or furnishes it to, the Commission. Additionally, the Companymakes available free of charge on its Internet 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.Changes in or waivers to the Company’s Code of Business Conduct and Ethicsrequired to be disclosed by rules of the Commission or the New York StockExchange will be posted on the Company’s Internet website within five businessdays and maintained for at least twelve months.

**ITEM 1A.**   *Risk Factors*.

***Natural gas and oil prices fluctuate widely, and lowprices could have a material adverse impact on the Company’s business.***

The Company’s revenues, profitability and futuregrowth depend substantially on prevailing prices for natural gas and oil. Oiland natural gas market prices have historically been seasonal, cyclical andvolatile. The average prices that the Company has recently received for itsproduction are significantly higher than their historic average. A future dropin oil and natural gas prices could have a material adverse effect on theCompany’s cash flow and profitability. A sustained period of low prices couldhave a material adverse effect on the Company’s operations and financialcondition and could also result in a reduction in funds available under theCompany’s credit facility and associated prepayments. Lower prices may alsoreduce the amount of natural gas and oil that the Company can economicallyproduce.

Among the factorsthat can cause oil and natural gas price fluctuation are:

·       thelevel of consumer product demand;

·       weatherconditions;

·       domesticand foreign governmental regulations;

·       theprice and availability of alternative fuels;

·       politicalconditions in natural gas and oil producing regions;

·       thedomestic and foreign supply of natural gas and oil, including the decisions ofthe Organization of Petroleum Exporting Countries relating to export quotas andits ability to maintain oil price and production controls;

·       theprice of foreign imports; and

·       overall economicconditions.

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***The Company’s integration of Northrock may not besuccessful.***

The acquisition ofNorthrock in September, 2005 is the largest acquisition in the Company’shistory. The Company may not be able to realize anticipated economic, operationaland other benefits from the acquisition due to the following risks anddifficulties, among others:

·       Northrock’sproperties may not produce revenues, earnings or cash flow at anticipatedlevels;

·       theCompany may have exposure to unanticipated liabilities and costs as a result ofthe acquisition, some of which may materially exceed the Company’s estimates;

·       theCompany may lose key employees on whom management is substantially dependent inthe operation of Northrock’s assets;

·       theCompany may lose customers, suppliers, partners and agents of Northrock;

·       theCompany may experience material difficulties and additional costs in continuingto integrate Northrock’s operations, systems and personnel with those of theCompany.

Please see “—The Companywill continue to pursue acquisitions and dispositions,” below.

***The natural gas and oil business involves manyoperating risks that can cause substantial losses or hinder marketing efforts.***

Numerous risksaffect the Company’s drilling activities, including the risk of drillingnon-productive wells or dry holes. The cost of drilling, completing andoperating wells and of installing production facilities and pipelines is oftenuncertain. Also, the Company’s drilling operations could diminish or ceasebecause of any of the following:

·       titleproblems;

·       weatherconditions;

·       fires;

·       explosions;

·       blow-outsand surface cratering;

·       uncontrollableflows of underground natural gas, oil and formation water;

·       naturaldisasters;

·       pipeor cement failures;

·       casingcollapses;

·       embeddedoilfield drilling and service tools;

·       abnormallypressured formations;

·       environmentalhazards such as natural gas leaks, oil spills, pipeline ruptures and dischargesof toxic gases;

·       noncompliancewith governmental requirements; or

·       shortagesor delays in the delivery or availability of material, equipment or fabricationyards.

Offshore operations are also subject to a variety ofoperating risks related to the marine environment, such as capsizing,collisions and damage or loss from hurricanes or other adverse weatherconditions. These hazards may interrupt production and can cause substantiallosses to the Company due to injury or 

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loss of life, severedamage to facilities, or pollution or other environmental damage. As a result,the Company could incur substantial liabilities that could reduce or eliminatethe funds available for exploration, development or leasehold acquisitions. Informationregarding the impact of Hurricanes Katrina and Rita on the Company’soperations, please read “Business: Domestic Offshore Operations.”

Moreover, effectivemarketing of the Company’s natural gas production depends on a number offactors, such as the following:

·       existingmarket supply of and demand for natural gas;

·       theproximity of the Company’s reserves to pipelines;

·       theavailable capacity of such pipelines; and

·       governmentregulations.

The marketing of oil andnatural gas production similarly depends on the availability of pipelines andother transportation, processing and refining facilities, and the existence ofadequate markets. As a result, even if hydrocarbons are discovered incommercial quantities, a substantial period of time may elapse beforecommercial production commences. If pipeline facilities in an area areinsufficient, the Company may have to wait for the construction or expansion ofpipeline capacity before the Company can market production from that area.

***The Company may not be able to obtain sufficientdrilling equipment and experienced personnel to conduct its operations.***

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. The market for oilfield services is currently verycompetitive. This may lead to difficulty and delays in consistently obtainingservices and equipment from vendors, obtaining drilling rigs and otherequipment at favorable rates, and scheduling equipment fabrication at factoriesand fabrication yards. Obtaining drilling rigs for our New Zealand operationsis presently difficult. This, in turn, may lead to projects being delayed orexperiencing increased costs.

***The Company’s foreign operations subject it toadditional risks.***

The Company’sownership and operations in Canada, New Zealand, Vietnam and any other foreignareas where it does business are subject to the various risks inherent inforeign operations. These risks may include the following:

·       currencyrestrictions and exchange rate fluctuations;

·       risksof increases in taxes and governmental royalties and renegotiation of contractswith governmental entities; and

·       changesin laws and policies governing operations of foreign-based companies.

United States laws and policies on foreign trade,taxation and investment may also adversely affect the Company’s internationaloperations. In addition, if a dispute arises from foreign operations, foreigncourts may have exclusive jurisdiction over the dispute, or the Company may notbe able to subject foreign persons to the jurisdiction of United States courts.

Local laws and customs inmany countries differ significantly from those in the United States. In manyforeign countries, particularly in those with developing economies likeVietnam, it is common to engage in business practices that are prohibited byUnited States regulations applicable to the Company. The U.S. 

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ForeignCorrupt Practices Act prohibits corporations and individuals, including the Companyand its employees, from engaging in certain activities to obtain or retainbusiness or to influence a person working in an official capacity. Although theCompany has implemented policies and procedures designed to ensure compliancewith these laws, there can be no assurance that all of the Company’s employees,contractors and agents, including those based in or from countries wherepractices which violate such United States laws may be customary, will not takeactions in violation of the Company’s policies. Any such violation, even ifprohibited by the Company’s policies, could have a material adverse effect onthe Company’s business. In addition, the Company’s foreign competitors that arenot subject to the U.S. Foreign Corrupt Practices Act or similar laws may beable to secure business or other preferential treatment in such countries bymeans that such laws prohibit with respect to the Company.

***The Company cannot control the activities onproperties it does not operate; operators of those properties may act in waysthat are not in the Company’s best interests.***

Other companiesoperate a portion of the oil and natural gas properties in which the Companyhas an interest. As a result, the Company has limited influence over operationson some of those properties or their associated costs. The Company’s limitedinfluence on non-operated properties could result in the following:

·       theoperator may initiate exploration or development projects on a differentschedule than the Company prefers;

·       theoperator may propose to drill more wells or build more facilities on a projectthan the Company has funds for, which may mean that the Company cannotparticipate in those projects or share in revenues from those projects; and

·       ifthe operator refuses to initiate an exploration or development project, theCompany may not be able to pursue the project.

Any of these events couldsignificantly affect the Company’s anticipated exploration and developmentactivities and the economic value of those properties to the Company.

***Maintaining reserves and revenues in the futuredepends on successful exploration and development activities and/oracquisitions.***

The Company mustcontinually explore for and develop or acquire new oil and natural gas reservesto replace those produced and sold. The Company’s hydrocarbon reserves andrevenues will decline if the Company is not successful in its drilling,exploration or acquisition activities. Although the Company has historicallymaintained its reserves base primarily through successful exploration anddevelopment operations, its future efforts may not be similarly successful.

***The Company’s operations are subject to casualty risksagainst which it cannot fully insure.***

The Company’s operationsare subject to inherent casualty risks such as blowouts, fires, explosions,cratering, uncontrollable flows of oil, natural gas or well fluids, pollutionand other environmental risks, marine hazards and natural disasters. If anysuch event occurred, the Company could be subject to substantial financiallosses due to personal injury, property damage, environmental discharge, orsuspension of operations. The impact on the Company of one of these eventscould be significant. Although the Company purchases insurance at levels itbelieves to be customary for a company of its size in its industry, the Companyis not fully insured against all risks incident to its business. For somerisks, the Company may not obtain insurance if it believes the cost ofavailable insurance is excessive relative to the risks presented. For example,escalating costs for business interruption insurance may lead the Company toreduce or eliminate its business interruption coverage. In addition, pollutionand environmental risks 

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generallyare not fully insurable. If a significant accident or other event occurs and isnot fully covered by insurance, it could adversely affect the Company’soperations and financial condition. Moreover, there is no assurance thatrecoveries for insured events will be sufficient to cover cash flow that theCompany would have otherwise generated from affected properties.

***The Company has substantial capital requirements.***

The Companyrequires substantial capital to replace its reserves and generate sufficientcash flow to meet its financial obligations. If the Company cannot generatesufficient cash flow from operations or raise funds externally in the amountsand at the times needed, it may not be able to replace its reserves or meet itsfinancial obligations. The Company recently paid approximately $1.7 billion incash to acquire Northrock. The Company’s ongoing capital requirements consistprimarily of the following items:

·       fundingits 2006 capital and exploration budget of $725 million;

·       otherallocations for acquisition, development, production, exploration andabandonment of oil and natural   gasreserves;

·       futuredividends and stock repurchases.

The Company plansto finance anticipated ongoing expenses and capital requirements with fundsgenerated from the following resources:

·       availablecash and cash investments;

·       cashprovided by operating activities;

·       fundsavailable under the Company’s credit facility;

·       theCompany’s uncommitted bank line(s) of credit; and

·       capitalthe Company believes it can raise through opportunistic debt and equity offerings.

However, the Companyfinanced a substantial part of the Northrock acquisition utilizing cash on handand public debt issuance. In addition, the Company utilized borrowings underits credit facility related to the acquisition, thereby reducing the availabilityof those resources for other capital requirements. Moreover, the uncertaintiesand risks associated with future performance and revenues, as described inthese Risk Factors, will ultimately determine the Company’s liquidity andability to meet anticipated capital requirements.

***The Company will continue to pursue acquisitions anddispositions.***

The Company will continueto seek opportunities to generate value through business combinations,purchases and sales of assets. The Company examines potential transactions on aregular basis, depending on market conditions, available opportunities andother factors. In addition, the Company competes with other companies inpursuing acquisitions, many of which have greater financial and other resourcesto acquire attractive companies and properties. Dispositions of portions of theCompany’s existing business or properties would be intended to result in therealization of immediate value but would consequently result in lower cashflows over the longer term, unless the proceeds are reinvested in moreproductive assets. The successful acquisition of oil and gas propertiesrequires an assessment of several factors, including recoverable reserves,development and exploratory potential, projected future cash flows that are, inpart, based upon future oil and gas prices, current and projected operating,general and administrative and other costs, and contingent liabilitiesassociated with the properties or entities acquired, including potentialenvironmental and other liabilities. The accuracy of the Company’s assessmentof these factors is inherently uncertain, and the Company’s review andassessment of potential acquisitions will not reveal all existing or potentialproblems nor will it permit the Company to become sufficiently familiar withthe 

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propertiesor entities to fully assess their deficiencies and capabilities. Even whenproblems are identified, the other party may be unwilling or unable to provideeffective contractual protection against all or part of the problems. Furthermore,the Company may not be entitled to contractual indemnification for certainliabilities, or it may acquire the properties on an “as is, where is” basis. Fora discussion of additional risks associated with the Northrock acquisition, see“—The Company’s Acquisition of Northrock may not be successful,” above.

***The Company’s reserve data are estimates and shouldnot be unduly relied on.***

No one can measure underground accumulations of oiland natural gas in an exact way. Projecting future production rates and thetiming and amount of development expenditures is also an uncertain process.Accuracy of reserve estimates depends on the quality of available data and oneconomic, engineering and geological interpretation and judgment. As a result,reserve estimates often differ from the quantities of oil and natural gasultimately recovered. To estimate economically recoverable reserves, variousassumptions are made regarding future oil and natural gas prices, productionlevels and operating and development costs that may prove incorrect. Anysignificant variance from those assumptions could greatly affect estimates ofeconomically recoverable reserves and future net revenues.

It should not be assumedthat the present value of future net cash flows from the Company’s provenreserves is the current value of the estimated natural gas and oil reserves.Estimates of discounted future net cash flows from proven reserves are based onprices and costs on the date of the estimate. Actual future prices and costs maydiffer materially from those used in net present value estimates, and futurenet present value estimates using then-current prices and costs may besignificantly less than current estimates.

***The Company faces significant competition and issmaller than many of its competitors.***

The oil and gas industryis highly competitive. The Company competes with major and independent oil andnatural gas companies for property acquisitions and for the equipment and laborrequired to operate and develop properties. Many of the Company’s competitorshave substantially greater financial and other resources. As a result, thosecompetitors may be better able to withstand sustained periods of unsuccessfuldrilling. In addition, larger competitors may be able to absorb the burden ofany changes in applicable laws and regulations more easily than the Companycan, which would adversely affect the Company’s competitive position. Thesecompetitors may also be able to pay more for exploratory prospects andproductive oil and natural gas properties and may be able to define, evaluate,bid for and purchase a greater number of properties and prospects than theCompany can. The Company’s ability to explore for oil and natural gas prospectsand to acquire additional properties in the future will depend on its abilityto conduct operations and to evaluate and select suitable properties andtransactions in this highly competitive environment. Moreover, the oil andnatural gas industry itself competes with other industries in supplying the energyand fuel needs of industrial, commercial and other consumers. Increasedcompetition causing oversupply or depressed prices could greatly affect theCompany’s operational revenues.

***The Company’s competitors may use superior technology.***

The Company’s industry issubject to rapid and significant advancements in technology, including theintroduction of new products and services using new technologies. As theCompany’s competitors use or develop new technologies, the Company may beplaced at a competitive disadvantage, and competitive pressures may force theCompany to implement new technologies at a substantial cost. In addition, theCompany’s competitors may have greater financial, technical and personnelresources that allow them to enjoy technological advantages and may in thefuture allow them to implement new technologies before the Company can. TheCompany cannot be certain that it will be able to implement technologies on atimely basis or at a cost that is acceptable to it. One or more of the technologiesthat the Company 

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currentlyuses or that it may implement in the future may become obsolete, and theCompany may be adversely affected.

***The Company is subject to legal limitations that mayadversely affect the cost, manner or feasibility of doing business.***

The Company and itssubsidiaries are subject to extensive domestic and foreign laws and regulationson taxation, exploration and development, and environmental and safety mattersin countries where it owns or operates properties. These laws and regulationsare under continuing review for amendment or expansion, and the Company couldbe forced to expend significant resources to comply with new laws orregulations or changes to existing requirements. Many laws and regulationsrequire drilling permits and govern the spacing of wells, the prevention ofwaste, rates of production and other matters. These statutes and regulations,and any others that are passed by the jurisdictions where the Company hasproduction could limit the total number of wells drilled or the total allowableproduction from successful wells, which could limit revenues. Noncompliancewith these statutes or failure to establish exemptions from regulations couldalso result in substantial penalties, require the posting of substantial suretybonds, or in the suspension or termination of the Company’s operations.

***The Company is subject to various environmentalliabilities.***

The Company couldincur liability to governments or third parties for any unlawful discharge ofoil, natural gas or other pollutants into the air, soil or water, includingresponsibility for remedial costs. The Company’s onshore and offshoreoperations could potentially discharge oil or natural gas into the environmentin any of the following ways:

·       froma well, or drilling equipment at a drill site;

·       leakagefrom storage tanks, pipelines or other gathering and transportation facilities;

·       damageto oil or natural gas wells resulting from accidents during normal operations;and

·       blowouts,cratering or explosions.

Environmental dischargesmay move through soil to water supplies or adjoining properties, giving rise toadditional liabilities. Some laws and regulations could impose liability forfailure to notify the proper authorities of a discharge and other failures to complywith those laws. Environmental laws may also affect the Company’s costs toacquire properties. The Company does not believe that its environmental risksare materially different from those of comparable companies in the oil and gasindustry. However, there is no assurance that environmental laws will not, inthe future, result in decreased production, substantially increased operationalcosts or other adverse effects to the Company’s combined operations andfinancial condition. Pollution and similar environmental risks generally arenot fully insurable.

***Derivative instruments expose the Company to risks offinancial loss in a variety of circumstances.***

The Company usesderivative instruments in an effort to reduce its exposure to fluctuations inthe prices of oil and natural gas. The Company’s derivative instruments exposeit to risks of financial loss in a variety of circumstances, including when:

·       acounterparty to the Company’s derivative instruments is unable to satisfy itsobligations;

·       productionis delayed or less than expected; or

·       thereis an adverse change in the expected differential between the underlying pricein the derivative instrument and actual prices received for the Company’sproduction.

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Derivative instruments also may limit the Company’sability to realize increased revenue from increases in the prices for oil andnatural gas.

The Company follows theprovisions of Statement of Financial Accounting Standards No. 133, “Accountingfor Derivative Instruments and Hedging Activities,” which generally requiresthe Company to record each hedging transaction as an asset or liabilitymeasured at its fair value. Each quarter, the Company must record changes inthe fair value of its hedges, which could result in significant fluctuations innet income and stockholders’ equity from period to period.

***The Company is subject to restrictive debt covenants.***

Covenants in the creditfacility and the indentures governing the Company’s senior subordinated notesimpose significant operating and financial restrictions on it, including themaintenance of specified financial ratios. These restrictions may adverselyaffect the Company’s ability to finance its future operations and capitalneeds, to react to changes in its business or industry or to pursue availablebusiness opportunities. If certain events of default occurred under these debtinstruments, the Company’s outstanding indebtedness thereunder may beaccelerated, and its assets may not be sufficient to repay such indebtedness. Moreover,any new indebtedness that the Company incurs may impose similar or morerestrictive covenants on the Company.

**ITEM 1B.**   *UnresolvedStaff Comments*.

None.

**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 Regulations; Other Laws and Regulations.”

**ITEM4.**   *Submission of Matters to aVote of Security-Holders*.

No matters were submitted to a vote of the Company’ssecurity holders during the fourth quarter of the year ended December 31,2005.

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

Officersof the Company are appointed annually by the Company’s Board of Directors toserve for the ensuing year or until their successors have been elected orappointed. The officers of the Company that have been designated as “executiveofficers” for purposes of Item 401(b) of Regulation S-K and “officers” forpurposes of Section 16 of the Exchange Act, their age as of December 31,2005, and the year each was elected to his current position are as follows:
| Executive Officer       | ** ** | ** **                                                                | ** ** | **Executive Office** | ** ** | **Age** | ** ** | **Year  Elected** |
|-------------------------|------------|---------------------------------------------------------------------------|------------|----------------------|------------|---------|------------|-------------------|
| Paul G. Van Wagenen     |       | Chairman, President and Chief Executive Officer                           |       | 59                   |       | 1991    |
| Stephen R. Brunner      |       | Executive Vice President—Operations                                  |       | 47                   |       | 2002    |
| Jerry A. Cooper         |       | Executive Vice President and Regional  Manager—Western United States |       | 57                   |       | 2002    |
| John O. McCoy, Jr. |       | Executive Vice President and Chief Administrative  Officer                |       | 54                   |       | 2002    |
| David R. Beathard       |       | Senior Vice President—Engineering                                    |       | 47                   |       | 2002    |
| Michael J. Killelea     |       | Senior Vice President, General Counsel and Corporate  Secretary           |       | 43                   |       | 2005    |
| James P. Ulm, II   |       | Senior Vice President and Chief Financial Officer                         |       | 42                   |       | 2002    |
| Thomas E. Hart          |       | Vice President  and Chief Accounting Officer                              |       | 62                   |       | 1999    |

 

Mr. Van Wagenen, whojoined the Company in 1979, has served in his current position since 1991.Prior to assuming their present positions with the Company, the businessexperience of each of the other executive officers for at least the last fiveyears was as follows: Mr. Brunner, who joined the Company in 1994, servedas Vice President—Operations from 1997 - 2002; Mr. Cooper, who joinedthe Company in 1979, served as Senior Vice President and Western DivisionManager from 1998 - 2002; Mr. McCoy, who joined the Company in 1978,served as Senior Vice President from 1998 - 2002 and has served as ChiefAdministrative Officer since 1989; Mr. Beathard, who joined the Company in1982, served as Vice President—Engineering from 1997 - 2002; Mr. Killeleawho joined the Company in 2000, served as Vice President from 2001 - 2005,and has served as Corporate Secretary and General Counsel since 2004 and 2000,respectively; Mr. Ulm, who joined the Company in 1999, served as VicePresident from 1999 - 2002, and has served as Chief Financial Officersince 1999; and Mr. Hart, who joined the Company in 1977, has served asVice President and Chief Accounting Officer since 1999.

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**PART II**

**ITEM5.**   *Market for the Registrant’sCommon Equity and Related Stockholder Matters and Issuer Purchases of EquitySecurities*.

The following table showsthe range of low and high sales prices of the Company’s Common Stock (the “CommonStock”) on the New York Stock Exchange composite tape where the Common Stocktrades under the symbol PPP. The Common Stock is also listed on the PacificExchange under the same symbol.

| ** **  | ** ** | **Low** | ** ** | **High** | ** ** |
|-------------|------------|---------|------------|----------|------------|
| **2005**    |       |    |       |     |       |
| 1st Quarter |       | $       | 41.59      |     | $          | 53.30 |   |
| 2nd Quarter |       | $       | 43.38      |     | $          | 54.53 |   |
| 3rd Quarter |       | $       | 51.59      |     | $          | 59.69 |   |
| 4th Quarter |       | $       | 48.04      |     | $          | 59.52 |   |
| **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 1,2006, there were 2,006 holders of record of the Company’s Common Stock.

In 2004, the Company paidthree quarterly dividends of $0.05 per share on its Common Stock. On October 19,2004, the Company’s dividend was increased by 25% to $0.0625 per share on itsCommon Stock and it paid one quarterly dividend at that amount during 2004. In2005, the Company paid four quarterly dividends of $0.0625 per share on itsCommon Stock. On January 24, 2006, the Company’s quarterly dividend wasincreased by 20% to $0.075 per share on its Common Stock. The declaration andpayment of future dividends, and the amount of such dividends, will dependupon, among other things, the Company’s future earnings and financialcondition, liquidity and capital requirements, the general economic andregulatory climate and other factors deemed relevant by the Company’s Board ofDirectors.

The Company’s revolvingcredit facility (the “Facility”), under which the Company has borrowed funds,and the Indentures relating to the Company’s 8.250% Senior Subordinated Notesdue 2011 (the “2011 Notes”), 6.625% Senior Subordinated Notes due 2015 (the “2015Notes”) and 6.875% Senior Subordinated Notes due 2017 (the “2017 Notes”)contain covenants that may restrict the ability of the Company to pay futuredividends on the Company’s Common Stock. For further discussion of thecovenants, see “Note 4, Long Term Debt” to the Consolidated FinancialStatements in this report. The Company does not believe that any of theseagreements will restrict the Company’s ability to pay dividends on its CommonStock in the reasonably foreseeable future.

No equity securities ofthe Company not registered under the Securities Act of 1933 were sold by theCompany during the year ended December 31, 2005.

Thefollowing table sets forth certain information with respect to repurchases ofthe Company’s equity securities during the three months ended December 31,2005:

| **Period**            | ** ** | ** ** | ** ** | **Total Number  of Shares  Purchased(a)** | ** ** | **Average  Price Paid  per Share** | ** ** | **Maximum Dollar Value  of Shares that May  Yet Be Purchased  Under the Plan** | ** ** |
|-----------------------|------------|------------|------------|-----------------------------------------------------|------------|----------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------------------|------------|
| Oct 1 - 31  2005 |       |       | 1,245,000  |                                                |       |                                         | $          | 55.23                                                                                                                       |       |   |   | $ | 52,758,953 |   |   |
| Nov 1 - 30  2005 |       |       | 300,000    |                                                |       |                                         | $          | 49.28                                                                                                                       |       |   |   | $ | 37,963,821 |   |   |
| Dec 1 - 31  2005 |       |       | 455,000    |                                                |       |                                         | $          | 49.42                                                                                                                       |       |   |   | $ | 15,458,779 |   |   |
| Total                 |       |       | 2,000,000  |                                                |       |                                         |       |                                                                                                                        |       |   |   |   |   |

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(a)           Allof these shares were purchased under the plan announced on January 25,2005.

30

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

In thefollowing table, the Company’s financial, production and other data for 2005reflect the Company’s acquisition of Northrock Resources from and on September 27,2005. The Company’s results for all periods presented reflect its oil and gasexploration, development and production activities in the Kingdom of Thailandand Hungary as discontinued operations. The selected financial data should beread in conjunction with “Item 7—Management’s Discussion and Analysis ofFinancial Condition and Results of Operations” and the audited consolidatedfinancial statements and notes thereto included under “Item 8—FinancialStatements and Supplementary Data.”

| ** **                                                                                        | ** ** | **For the Year Ended December 31,**                                               | ** ** |
|---------------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                                        | ** ** | **2005**                                                                                                   | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                                                                                        | ** ** | **(Expressed in thousands, except per share and production data)** | ** ** |
| **Financial Data**                                                                                |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Revenues:                                                                                         |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Crude oil and condensate                                                                          |       | $                                                                                                          | 468,274    |   | $ | 417,093 |   | $ | 426,395 |   | $ | 281,990 |   | $ | 132,933 |   |
| Natural gas                                                                                       |       | 695,462                                                                                                    |       | 512,598 |   | 397,303 |   | 231,301 |   | 267,678 |   |
| Natural gas liquids                                                                               |       | 52,511                                                                                                     |       | 43,392 |   | 32,376 |   | 24,426 |   | 12,461 |   |
| Oil and gas revenues                                                                              |       | 1,216,247                                                                                                  |       | 973,083 |   | 856,074 |   | 537,717 |   | 413,072 |   |
| Other                                                                                             |       | 9,452                                                                                                      |       | 3,472 |   | 2,431 |   | 4,359 |   | 13,970 |   |
| Total                                                                                             |       | $                                                                                                          | 1,225,699  |   | $ | 976,555 |   | $ | 858,505 |   | $ | 542,076 |   | $ | 427,042 |   |
| Income from  continuing operations before cumulative effect of change in accounting  principle    |       | $                                                                                                          | 290,069    |   | $ | 249,035 |   | $ | 235,235 |   | $ | 68,647 |   | $ | 26,260 |   |
| Income from  discontinued operations, net of tax                                                  |       | 460,634                                                                                                    | (a)        | 12,719 |   | 59,872 |   | 38,384 |   | 61,694 |   |
| Cumulative effect  of change in accounting principle                                              |       | —                                                                                                     |       | — |   | (4,166 | )(b) | — |   | — |   |
| Net income                                                                                        |       | $                                                                                                          | 750,703    |   | $ | 261,754 |   | $ | 290,941 |   | $ | 107,031 |   | $ | 87,954 |   |
| Per share data:                                                                                   |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Basic  income from operations before cumulative effect of change in accounting  principle—   |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| From continuing operations                                                                        |       | $                                                                                                          | 4.80       |   | $ | 3.90 |   | $ | 3.76 |   | $ | 1.18 |   | $ | 0.51 |   |
| From discontinued operations                                                                      |       | 7.63                                                                                                       |       | 0.20 |   | 0.96 |   | 0.67 |   | 1.21 |   |
| Basic income from operations before cumulative effect  of change in accounting principle          |       | $                                                                                                          | 12.43      |   | $ | 4.10 |   | $ | 4.72 |   | $ | 1.85 |   | $ | 1.72 |   |
| Diluted  income from operations before cumulative effect of change in accounting  principle— |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| From continuing operations                                                                        |       | $                                                                                                          | 4.76       |   | $ | 3.87 |   | $ | 3.67 |   | $ | 1.16 |   | $ | 0.51 |   |
| From discontinued operations                                                                      |       | 7.56                                                                                                       |       | 0.19 |   | 0.93 |   | 0.61 |   | 1.11 |   |
| Diluted income from operations before cumulative  effect of change in accounting principle        |       | $                                                                                                          | 12.32      |   | $ | 4.06 |   | $ | 4.60 |   | $ | 1.77 |   | $ | 1.62 |   |
| Cash dividends on common stock                                                                    |       | $                                                                                                          | 0.2500     |   | $ | 0.2125 |   | $ | 0.20 |   | $ | 0.12 |   | $ | 0.12 |   |
| Price  range of common stock:                                                                     |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| High                                                                                              |       | $                                                                                                          | 59.69      |   | $ | 51.34 |   | $ | 49.50 |   | $ | 39.28 |   | $ | 34.50 |   |
| Low                                                                                               |       | $                                                                                                          | 41.59      |   | $ | 39.25 |   | $ | 34.29 |   | $ | 23.00 |   | $ | 20.45 |   |
| Basic weighted average number of common shares  outstanding                                  |       | 60,372                                                                                                     |       | 63,848 |   | 62,538 |   | 57,963 |   | 51,031 |   |
| Long-term debt at  year end                                                                       |       | $                                                                                                          | 1,643,452  |   | $ | 755,000 |   | $ | 487,261 |   | $ | 722,903 |   | $ | 792,561 |   |
| Minority interest  at year end                                                                    |       | $                                                                                                          | —     |   | $ | — |   | $ | — |   | $ | — |   | $ | 145,086 |   |
| Shareholders’  equity at year end                                                            |       | $                                                                                                          | 2,098,582  |   | $ | 1,727,895 |   | $ | 1,453,653 |   | $ | 1,077,784 |   | $ | 824,885 |   |
| Total assets at  year end                                                                         |       | $                                                                                                          | 5,675,748  |   | $ | 3,481,109 |   | $ | 2,758,651 |   | $ | 2,491,593 |   | $ | 2,423,979 |   |
| **Production (Sales) Data**                                                                       |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Net daily average  production and weighted average price:                                         |       |                                                                                                       |       |   |   |   |   |   |   |   |   |
| Natural gas (Mcf per day)                                                                         |       | 250,200                                                                                                    |       | 244,300 |   | 210,400 |   | 201,300 |   | 172,800 |   |
| Price (per Mcf)                                                                                   |       | $                                                                                                          | 7.62       |   | $ | 5.73 |   | $ | 5.17 |   | $ | 3.15 |   | $ | 4.25 |   |
| Crude oil and condensate (Bbl per day)                                                            |       | 25,734                                                                                                     |       | 29,530 |   | 40,173 |   | 30,971 |   | 14,804 |   |
| Price (per Bbl)                                                                                   |       | $                                                                                                          | 49.85      |   | $ | 38.59 |   | $ | 29.08 |   | $ | 24.95 |   | $ | 24.60 |   |
| Natural gas liquids (Bbl per day)                                                                 |       | 4,162                                                                                                      |       | 4,220 |   | 4,109 |   | 4,480 |   | 2,118 |   |
| Price (per Bbl)                                                                                   |       | $                                                                                                          | 34.56      |   | $ | 28.09 |   | $ | 21.59 |   | $ | 14.94 |   | $ | 16.12 |   |

 

31

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| ** **                                                 | ** ** | **For the Year Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2005**                                                     | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                                                 | ** ** | **(Expressed in thousands)**                       | ** ** |
| **Capital Expenditures (including  interest capitalized)** |       |                                                         |       |   |   |   |   |   |   |   |   |
| Oil and gas:                                               |       |                                                         |       |   |   |   |   |   |   |   |   |
| Domestic Onshore—                                     |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | $                                                            | 117,100    |   | $ | 29,000 |   | $ | 26,200 |   | $ | 14,500 |   | $ | 38,300 |   |
| Development                                                |       | 143,300                                                      |       | 159,500 |   | 118,000 |   | 117,200 |   | 113,600 |   |
| Purchase of reserves                                       |       | 46,000                                                       |       | 583,800 |   | 177,700 |   | — |   | 1,027,200 |   |
| Domestic  Offshore—                                   |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | 63,800                                                       |       | 54,300 |   | 28,100 |   | 33,600 |   | 18,000 |   |
| Development                                                |       | 20,900                                                       |       | 74,000 |   | 23,900 |   | 100,700 |   | 169,000 |   |
| Purchase of reserves                                       |       | —                                                       |       | 24,700 |   | — |   | — |   | 87,700 |   |
| Canada—                                               |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | 9,100                                                        |       | — |   | — |   | — |   | — |   |
| Development                                                |       | 55,800                                                       |       | — |   | — |   | — |   | — |   |
| Purchase of reserves                                       |       | 1,786,900                                                    |       | — |   | — |   | — |   | — |   |
| Purchase of unproved properties                            |       | 830,000                                                      |       | — |   | — |   | — |   | — |   |
| Other  international—                                 |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | —                                                       |       | 5,600 |   | 100 |   | — |   | 2,000 |   |
| Development                                                |       | 100                                                          |       | — |   | — |   | — |   | 1,200 |   |
| Total oil and gas                                          |       | 3,073,000                                                    |       | 930,900 |   | 374,000 |   | 266,000 |   | 1,457,000 |   |
| Other                                                      |       | 6,000                                                        |       | 6,200 |   | 2,500 |   | 3,300 |   | 4,800 |   |
| Total                                                      |       | $                                                            | 3,079,000  |   | $ | 937,100 |   | $ | 376,500 |   | $ | 269,300 |   | $ | 1,461,800 |   |

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(a)           Includes approximately$408 million of after-tax gain on the sale of the Company’s operation inHungary and Thailand.

(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 accountingstandard required a change in the accounting for asset retirement obligations. See“Management’s Discussion and Analysis of Financial Condition and Results ofOperations, Application of Critical Accounting Policies and Management’sEstimates, Future Development and Abandonment Costs” for further discussion ofthe provisions of SFAS 143.

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

Statements in the following discussion may beforward-looking and involve risks and uncertainties. The Company’s financialresults are most directly affected by changing prices for its production.Changing prices can influence not only current results of operations but thedetermination of the Company’s proved reserves and available sources offinancing, including the determination of the borrowing base under its bank creditfacility. The Company’s results depend not only on hydrocarbon pricesgenerally, but on its ability to market its production on favorable terms.  On a longer term basis, the Company’sfinancial condition and results of operations are affected by its ability toreplace reserves as they are produced through successful exploration,development and acquisition activities. The Company’s results could also beadversely affected by adverse regulatory developments and operational risksassociated with oil and gas operations. For further discussion of risks anduncertainties that may affect the Company’s results, see “Risk Factors” and thediscussion below.

The following discussionof the Company’s financial condition and results of operations reflects therecasting as discontinued operations of the Company’s Thailand and Hungaryoperations. See “Executive 

32

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Overview—ClosedSale of Thailand”. Except where noted, the following discussion relates to theCompany’s continuing activities only.

**Executive Overview**

The Company’s objective is to explore for, develop,acquire and produce oil and gas in select locations. In pursuit of thatobjective, the Company’s goal for each year is to add more oil and gas reservesthan it produces. The year 2005 marked the fourteenth consecutive year ofreserve 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 onshore Canada and alsoconducts exploration activities in offshore New Zealand. The Company also seeksto maintain a balanced mixture of the gas/oil ratio of its proven reservesbase. Over the last several years, the Company has transitioned from apredominately offshore focused company to a company with the majority of itsreserves located in the onshore regions of North America. As of December 31,2005, approximately 86% of the Company’s reserves are located onshore. As aresult of this transition, the Company has lengthened its reserves toproduction index to over 9.3 years.

At the end of 2005, proven reserves reached 2,042 Bcfeand production for the year averaged more than 71,500 BOE per day (429,000 Mcfeper day). Oil and gas pricing and production volumes are important componentsof an exploration and development company’s growth in net income and cash flow.In 2005, oil and gas pricing for the Company was strong, with the average priceincreasing 30% over 2004 on an equivalent barrel basis.

Oil and gas capital andexploration cash expenditures for 2005 were approximately $2.2 billion. Explorationand development operations were allocated approximately $437 million, andapproximately $1.8 billion was spent on selective acquisitions in the Company’score areas of operations. For 2005, in the Company’s continuing operations, 279wells were drilled with 255 successfully completed, a 91% success rate. During2005, approximately 762 Bcfe of proven reserves were added to the Company’sreserves ledger.

*Closed acquisitionof Northrock Resources*

On September 27, 2005, the Company completed theacquisition of Northrock Resources Ltd. for approximately $1.7 billion in cash.The purchase price of Northrock was funded using available cash on hand, thenet proceeds from the Company’s offering of $500 million aggregate principalamount of senior subordinated notes in September 2005 and additionalborrowings under the credit facility.

As of December 31,2005, Northrock owned 657 Bcfe of estimated proven reserves on approximately300,000 net acres, plus approximately 950,000 net acres of undevelopedleasehold. Northrock’s exploitation and development activities are concentratedin Saskatchewan and Alberta with key exploration plays in Canada’s NorthwestTerritories, British Columbia and the Alberta Foothills. The Company expects tohave an active drilling program in Canada in 2006, allocating approximately$200 million of capital to drill 184 wells. By allocating significant resourcesand capital, the Company anticipates growth in both reserves and productionfrom this important new area.

*Closed Sale ofThailand*

On August 17, 2005,the Company closed the sale of its wholly owned subsidiary Thaipo Ltd. and its46.34% interest in B8/32 Partners Ltd., effectively a sale of all of itsThailand operations, for a purchase 

33

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price of$820 million. The company recognized an after-tax gain from discontinuedoperations of approximately $403 million on the transaction.

*Hurricanes Katrinaand Rita*

On August 29, 2005,after passing through the Gulf of Mexico, Hurricane Katrina made landfall nearNew Orleans, Louisiana and caused one of the worst natural disasters in U.S.history. On September 24, 2005, Hurricane Rita, one of the strongestmeasured hurricanes to have entered the Gulf of Mexico, made landfall betweenSabine Pass, Texas and Johnson’s Bayou, Louisiana. Due to the hurricanes,substantially all of the Company’s Gulf of Mexico production was shut-in and,as of February 1, 2006, approximately 4,000 Bbls of oil and 20 MMcf ofnatural gas of the Company’s net daily production remain shut-in as a result ofthe storms. One of the platforms the Company operates, located in Main PassBlock 123, sustained major damage and significant damage to platforms andpipelines operated by others occurred, including facilities that are located inViosca Knoll Block 823, Eugene Island Block 330, and South Marsh Island Block128. The Company expects production to come back on-line by the end of thefirst quarter of 2007. Also, damage to processing plants and other onshore infrastructureowned and operated by others will likely continue to delay some of the shut-inproduction from coming back “on-line.” The Company maintains business interruption insurance on some of itsblocks in the Gulf.

*Senior SubordinatedNotes Issuances*

In March 2005, the Company issued and sold $300million aggregate principal amount of 6.625% Senior Subordinated Notes due 2015.Proceeds from the offering were used to reduce outstanding senior indebtednessunder the Company’s revolving credit facility.

In September 2005,the Company issued and sold $500 million aggregate principal amount of 6.875%Senior Subordinated Notes due 2017. Proceeds from the offering were used tofund a portion of the purchase price of the Northrock acquisition.

*Share Repurchases*

During 2005, the Companyannounced a share repurchase plan. The Company is authorized to expend up to amaximum of $375 million dollars to effect the repurchases. As of February 23,2006, 7.3 million shares of company stock have been repurchased for $360million, which represents approximately 11% of the Company’s outstanding sharesas of January 1, 2005.

*2005 Results*

Total revenue for 2005 was$1,225.6 million and net income from continuing operations totaled $290.1 million,or $4.80 per share. Cash flow from continuing operations totaled $700.8million. As of December 31, 2005, long-term debt was $1,646 million,increasing from December 31, 2004 by $891 million. The Company’s debtto total capitalization ratio, an indicator of a company’s financial strength,was 44% at December 31, 2005 and cash and cash equivalents decreased from$221 million at December 31, 2004 to approximately $58 million atDecember 31, 2005. The increase in debt and the decrease in cash are bothdue primarily to  the closing of theNorthrock acquisition.

*2006 Capital Budget*

The Company hasestablished a $725 million exploration and development budget (excludingproperty acquisitions). The Company expects to spend approximately $222 millionon exploration and $503 million on development activities. The capital budgetcalls for the drilling of approximately 451 wells during 2006, including wellsin the United States and Canada.

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*2006 ProductionOutlook Update*

The Company currentlyexpects its production volumes to average approximately 100,000 Boepd during2006. In addition, the Company currently expects its production volumes to exit2006 at approximately 112,500 Boepd. These estimates are subject to change, andactual results could differ materially, depending upon the amount of Gulf ofMexico production that remains shut-in, the timing of any such productioncoming back on-line, the availability of oilfield services, acquisitions,divestitures and many other factors that are beyond the Company’s control. Pleaseread “Forward-Looking Statements.”

*Exposure to Oil andGas Prices and Availability of Oilfield Services*

Oil and natural gas priceshave historically been seasonal, cyclical and volatile. Prices depend on manyfactors that the Company cannot control such as weather and economic, politicaland regulatory conditions. The average prices the Company is currentlyreceiving for production are higher than historical average prices. A futuredrop in oil and gas prices could have a serious adverse effect on cash flow andprofitability. Sustained periods of low prices could have a serious adverseeffect on the Company’s operations and financial condition. Additionally, thecost of drilling, completing and operating wells and installing facilities andpipelines is often uncertain and have each increased substantially during 2005.The market for oil field services is currently very competitive and shortagesor delays in delivery or availability of equipment or fabrication yards couldimpact the Company’s ability to conduct oil and gas drilling and completionoperations.

**Results of Operations**

*Oil and GasRevenues*

TheCompany’s oil and gas revenues for 2005 were $1,216,247,000, an increase ofapproximately 25% from oil and gas revenues of $973,083,000 for 2004, whichwere an increase of approximately 14% from oil and gas revenues of $856,074,000for 2003. The following table reflects an analysis of variances in the Company’soil and gas revenues (expressed in thousands) between years:

| ** **                                                                | ** ** | **2005**             | ** ** | **2004**             | ** ** |
|---------------------------------------------------------------------------|------------|----------------------|------------|----------------------|------------|
| ** **                                                                | ** ** | **Compared to** | ** ** | **Compared to** | ** ** |
| ** **                                                                | ** ** | **2004**             | ** ** | **2003**             | ** ** |
| Increase  (decrease) in oil and gas revenues resulting from variances in: | ** ** |                 | ** ** | ** **           |       |   | ** ** | ** ** |   |
| **Natural gas—**                                                     | ** ** |                 | ** ** | ** **           |       |   | ** ** | ** ** |   |
| Price .                                                                   |       |                 | $          | 168,448              |       |   |   | $ | 43,010 |   |   |
| Production .                                                              |       |                 | 14,416     |                 |       |   | 72,285 |   |   |
|                                                                      |       |                 | 182,864    |                 |       |   | 115,295 |   |   |
| **Crude oil and condensate—**                                        |       |                 |       |                 |       |   |   |   |   |
| Price .                                                                   |       |                 | 121,758    |                 |       |   | 139,431 |   |   |
| Production .                                                              |       |                 | (70,577    | )                    |       |   | (148,733 | ) |   |
|                                                                      |       |                 | 51,181     |                 |       |   | (9,302 | ) |   |
| **Natural gas liquids (“NGL”)**                                 |       |                 | 9,119      |                 |       |   | 11,016 |   |   |
| Increase in oil  and gas revenues                                         |       |                 | $          | 243,164              |       |   |   | $ | 117,009 |   |   |

 

The increase in theCompany’s oil and gas revenues in 2005, compared to 2004, 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 2004,compared to 2003, is related to increases in both the average price that theCompany received for its hydrocarbon 

35

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productionvolumes and an increase in the Company’s natural gas production volumes,partially offset by a decrease in crude oil and condensate production volumes.The increase in oil and gas revenues for 2005, compared to 2004 and 2003 wasalso the result of an increase in the average price that the Company receivedfor its NGL production volumes from $21.59 and $28.09 in 2003 and 2004,respectively, to $34.56 in 2005.

| ** **                                                  | ** ** | ** ** | ** ** | ** ** | ** ** | **% Change** | ** ** | ** ** | ** ** | **% Change** | ** ** |
|-------------------------------------------------------------|------------|------------|------------|------------|------------|-------------------|------------|------------|------------|-------------------|------------|
| ** **                                                  | ** ** | ** ** | ** ** | ** ** | ** ** | **2004**          | ** ** | ** ** | ** ** | **2003**          | ** ** |
| ** **                                                  | ** ** | ** ** | ** ** | ** ** | ** ** | **to**            | ** ** | ** ** | ** ** | **to**            | ** ** |
| ** **                                                  | ** ** | **2005**   | ** ** | **2004**   | ** ** | **2005**          | ** ** | **2003**   | ** ** | **2004**          | ** ** |
| **Comparison  of Increases (Decreases) in:**                | ** ** | ** ** | ** ** | ** ** | ** ** |              | ** ** | ** ** |       | ** **        | ** ** |   | ** ** | ** ** |   |
| **Natural  Gas—**                                      | ** ** | ** ** | ** ** | ** ** | ** ** |              | ** ** | ** ** |       | ** **        | ** ** |   | ** ** | ** ** |   |
| Average prices                                              |       |       |       |       |       |              | ** ** | ** ** |       |              |       |   | ** ** | ** ** |   |
| United States(a)                                            | ** ** | **$**      | **7.46**   |       | $          | 5.73              | ** ** |       | **30**     | **%**             |       | $ | 5.17 | ** ** |   | **11** | **%** |   |
| Canada                                                      | ** ** | **$**      | **10.96**  |       | $          | —            | ** ** |       | **N/A**    | ** **        |       | $ | — | ** ** |   | **N/A** | ** ** |   |
| Company-wide average price                                  | ** ** | **$**      | **7.62**   |       | $          | 5.73              | ** ** |       | **33**     | **%**             |       | $ | 5.17 | ** ** |   | **11** | **%** |   |
| Average daily production volumes (MMcf per day):  |       |       | ** ** | ** ** | ** ** |              | ** ** | ** ** |       | ** **        | ** ** |   | ** ** | ** ** |   |
| United States                                               | ** ** | **231.6**  |       | 244.3      | ** ** |              | **(5**     | **)%**     |       | 210.4             | ** ** |   | **16** | **%** |   |
| Canada(c)                                                   | ** ** | **18.6**   |       | —     | ** ** |              | **N/A**    | ** ** |       | —            | ** ** |   | **N/A** | ** ** |   |
| Company-wide average daily  production                      | ** ** | **250.2**  |       | 244.3      | ** ** |              | **2**      | **%**      |       | 210.4             | ** ** |   | **16** | **%** |   |
| **Crude  Oil and Condensate—**                         |       |       | ** ** | ** ** | ** ** |              | ** ** | ** ** |       | ** **        | ** ** |   | ** ** | ** ** |   |
| Average prices                                              |       |       |       |       |       |              | ** ** | ** ** |       |              |       |   | ** ** | ** ** |   |
| United States(b)                                            | ** ** | **$**      | **50.90**  |       | $          | 38.59             | ** ** |       | **32**     | **%**             |       | $ | 29.08 | ** ** |   | **33** | **%** |   |
| Canada                                                      | ** ** | **$**      | **44.29**  |       | $          | —            | ** ** |       | **N/A**    | ** **        |       | $ | — | ** ** |   | **N/A** | ** ** |   |
| Company-wide average price                                  | ** ** | **$**      | **49.85**  |       | $          | 38.59             | ** ** |       | **29**     | **%**             |       | $ | 29.08 | ** ** |   | **33** | **%** |   |
| Average daily production volumes  (Bbls per day): |       |       | ** ** | ** ** | ** ** |              | ** ** | ** ** |       | ** **        | ** ** |   | ** ** | ** ** |   |
| United States                                               | ** ** | **22,337** |       | 29,530     | ** ** |              | **(24**    | **)%**     |       | 40,173            | ** ** |   | **(26** | **)%** |   |
| Canada(c)                                                   | ** ** | **3,397**  |       | —     | ** ** |              | **N/A**    | ** ** |       | —            | ** ** |   | **N/A** | ** ** |   |
| Company-wide average daily  production                      | ** ** | **25,734** |       | 29,530     | ** ** |              | **(13**    | **)%**     |       | 40,173            | ** ** |   | **(26** | **)%** |   |

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(a)           Average prices for theUnited States reflect the impact of the Company’s price hedging activity. Pricehedging activity reduced the average price per Mcf. of the Company’s UnitedStates natural gas production $0.11 and $0.17 during 2005 and 2003,respectively. The Company had no price hedging activity related to 2004production.

(b)          Average prices for theUnited States include the impact of the Company’s price hedging activity. Pricehedging activity reduced the average price per Bbl of the Company’s crude oiland condensate production $0.20 and $0.69 during 2005 and 2003, respectively. TheCompany had no price hedging activity related to 2004 production.  For average prices, sales volumes equate toactual production.

(c)           Northrock Resources wasacquired by the Company on September 27, 2005.

*NaturalGas Production.*   The increase in the Company’snatural gas production during 2005, compared to 2004, was primarily related tothe addition of production from acquisitions made during late 2005 and late2004, partially offset by shut-in offshore production caused by HurricanesIvan, Katrina and Rita and, to a lesser extent, natural production declines. 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 success of the Company’sexploration program 

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at its Los Mogotes Fieldin South Texas. These production gains were partially offset by shut-inproduction resulting from the infrastructure damage caused by Hurricane Ivan inthe final months of 2004 and natural production declines at other properties.

*CrudeOil and Condensate Production.**  *The decrease in the Company’s crudeoil and condensate production during 2005, compared to 2004, resulted primarilyfrom  the shut-in of Gulf of Mexicoplatforms due to the effects of Hurricanes Ivan, Katrina and Rita (includingMain Pass Block 61/62) during 2005 and, to a lesser extent, natural productiondeclines. This decrease was partially offset by the addition of production fromthe Northrock acquisition made on September 27, 2005. The decrease in theCompany’s crude oil and condensate production during 2004, compared to 2003,resulted primarily from shut-in production related to the infrastructure damagecaused by Hurricane Ivan in the final quarter of 2004 and natural productiondeclines at the Company’s Main Pass Blocks 61/62 Field in the Gulf of Mexico.

*NGL Production.**  *The Company’s oil and gas revenues,and its total liquid hydrocarbon production, reflect the production and sale bythe Company of NGL, which are liquid products that are extracted from naturalgas production. The increase in NGL revenues for 2005, compared with 2004,related to an increase in the average price that the Company received for itsNGL production to $34.56 in 2005 from $28.09 in 2004. The increase in NGLrevenues for 2004, compared with 2003, related to an increase in the averageprice that the Company received for its NGL production to $28.09 in 2004 from$21.59 in 2003 and, to a lesser extent, a slight increase in NGL productionvolumes.

*Other Revenues*

Other revenue is derivedfrom sources other than the current production of hydrocarbons. This revenueincludes, among other items, natural gas inventory sales, pipeline imbalancesettlements and revenue from salt water disposal activities. The increase inthe Company’s other revenues in 2005, compared to 2004 and 2003, is relatedprimarily to $5.6 million of natural gas inventory sales from the Company’sCanadian operations in 2005. No gas inventory sales were made in either 2004 or2003.

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*Costs and Expenses*

| ** **                                                        | ** ** | ** **                                                                  | ** **   | ** **  | ** ** | **% Change**          | ** ** | ** ** | ** ** | **% Change**          | ** ** |
|-------------------------------------------------------------------|------------|-----------------------------------------------------------------------------|--------------|-------------|------------|----------------------------|------------|------------|------------|----------------------------|------------|
| ** **                                                        | ** ** | **2005**                                                                    | ** **   | **2004**    | ** ** | **2004 to 2005** | ** ** | **2003**   | ** ** | **2003 to 2004** | ** ** |
| ** **                                                        | ** ** | **(expressed in thousands, except DD&A rate)** | ** **   |
| **Comparison of Increases (Decreases) in:**   | ** ** | ** **                                                                  | ** **   | ** **  |       |                       | ** ** | ** ** |       |                       | ** ** |   | ** ** | ** ** |   |
| **Lease Operating Expenses**                                      | ** ** | **$**                                                                       | **153,659**  | ** **  | **$**      | **100,506**                |       |       | **53**     | **%**                      |       | $ | 81,731 | ** ** |   | **23** | **%** |   |
| **General and Administrative Expenses**                           | ** ** | **$**                                                                       | **87,319**   | ** **  | **$**      | **62,506**                 |       |       | **40**     | **%**                      |       | $ | 54,068 | ** ** |   | **16** | **%** |   |
| **Exploration Expenses**                                          | ** ** | **$**                                                                       | **26,473**   | ** **  | **$**      | **21,739**                 |       |       | **22**     | **%**                      |       | $ | 6,899 | ** ** |   | **215** | **%** |   |
| **Dry Hole and Impairment  Expenses**                             | ** ** | **$**                                                                       | **87,170**   | ** **  | **$**      | **61,634**                 |       |       | **41**     | **%**                      |       | $ | 30,673 | ** ** |   | **101** | **%** |   |
| **Depreciation, Depletion and Amortization  (DD&A) Expenses** | ** ** | **$**                                                                       | **312,247**  | ** **  | **$**      | **251,876**                |       |       | **24**     | **%**                      |       | $ | 229,881 | ** ** |   | **10** | **%** |   |
| DD&A rate                                                     | ** ** | **$**                                                                       | **1.99**     | ** **  | **$**      | **1.54**                   |       |       | **29**     | **%**                      |       | $ | 1.32 | ** ** |   | **17** | **%** |   |
| Mcfe produced                                                     | ** ** | **156,782**                                                                 | ** **   | **163,528** |       |                       | **(4**     | **)%**     |       | 173,780                    | ** ** |   | **(6** | **)%** |   |
| **Production and Other Taxes**                                    | ** ** | **$**                                                                       | **59,527**   | ** **  | **$**      | **44,104**                 |       |       | **35**     | **%**                      |       | $ | 23,735 | ** ** |   | **86** | **%** |   |
| **Transportation and Other**                                      | ** ** | **$**                                                                       | **(9,079**   | **)**       | **$**      | **8,355**                  |       |       | **(209**   | **)%**                     |       | $ | 23,892 | ** ** |   | **(65** | **)%** |   |
| **Interest—**                                                | ** ** | ** **                                                                  |         | ** **  | ** ** |                       | ** ** | ** ** | ** ** | ** **                 | ** ** |   | ** ** | ** ** |   |
| Charges                                                           | ** ** | **$**                                                                       | **(68,654**  | **)**       | **$**      | **(29,333**                | **)**      |       | **134**    | **%**                      |       | $ | (46,360 | ) |   | **(37** | **)%** |   |
| Interest Income                                                   | ** ** | **$**                                                                       | **8,291**    | ** **  | **$**      | **522**                    |       |       | **1488**   | **%**                      |       | $ | 673 | ** ** |   | **(22** | **)%** |   |
| Capitalized Interest Expense                                      | ** ** | **$**                                                                       | **23,480**   | ** **  | **$**      | **14,216**                 |       |       | **65**     | **%**                      |       | $ | 16,531 | ** ** |   | **(14** | **)%** |   |
| **Commodity Derivative Expense**                                  | ** ** | **$**                                                                       | **(13,618**  | **)**       | **$**      | **—**                 |       |       | **N/M**    | ** **                 |       | $ | — | ** ** |   | **N/A** | ** ** |   |
| **Loss on debt extinguishment**                                   | ** ** | **$**                                                                       | **—**   | ** **  | **$**      | **(13,759**                | **)**      |       | **(100**   | **)%**                     |       | $ | (5,893 | ) |   | **133** | **%** |   |
| **Income  Tax Expense**                                           | ** ** | **$**                                                                       | **(167,884** | **)**       | **$**      | **(148,866**               | **)**      |       | **13**     | **%**                      |       | $ | (137,371 | ) |   | **8** | **%** |   |

 

*Lease OperatingExpenses*

The increase in lease operating expenses for 2005,compared to 2004, is related primarily to increased expenses incurred relatedto onshore properties acquired by the Company in the fourth quarter of 2004 andthroughout 2005, increased maintenance expenses on several of the Company’ssignificant offshore properties due to damage from Hurricanes Ivan, Katrina andRita (which were only partially offset by insurance recoveries), and also tohigher costs being charged by oilfield service companies in 2005. The Companycurrently expects lease operating expenses to increase in future periods withthe addition of Northrock related expenses for an entire reporting period. Theincrease in lease operating expenses for 2004, compared to 2003, is dueprimarily to increased expenses incurred on the properties acquired by theCompany during 2004 and the latter part of 2003, increased maintenance expenseson several of the Company’s significant offshore properties related to theeffects of Hurricane Ivan and also to increased expenses incurred as theCompany continues to expand production in the Los Mogotes field in South Texas.

On a per unit ofproduction basis, the Company’s total lease operating expenses were $0.47 perMcfe for 2003, $0.61 per Mcfe for 2004 and $0.98 per Mcfe for 2005. Theincreased unit costs in 2005 were primarily related to the increased expenseand the decreased production volumes discussed above.

*General andAdministrative Expenses*

The increase in generaland administrative expenses for 2005, compared with 2004, is primarily relatedto increases in the size of the Company’s workforce due to acquisitions,increased benefit expenses and normal increases in compensation. The Companycurrently expects general and administrative expenses to 

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increasein future periods with the addition of Northrock related expenses for an entirereporting period. The increase in general and administrative expenses for 2004,compared with 2003, is primarily related to increases in compensation andrelated benefit expense and to increased professional fees (due in part tocompliance with Sarbanes-Oxley legislation). On a per unit of production basis,the Company’s general and administrative expenses were $0.56 per Mcfe in 2005,$0.38per Mcfe in 2004 and $0.31 per Mcfe in 2003.

*ExplorationExpenses*

Exploration expensesconsist primarily of exploratory geological and geophysical costs that areexpensed as incurred and rental payments required under oil and gas leases tohold non-producing properties (“delay rentals”). The increase in explorationexpenses for 2005, compared to 2004, resulted primarily from increased seismicoperations in the Company’s New Zealand and Canadian operations, which werepartially offset by decreased 3-D seismic acquisition activities in theGulf of Mexico and decreased seismic operations in the Company’s Gulf Coastregion. The increase in exploration expenses for 2004, compared to 2003,resulted primarily from increased 3-D seismic acquisition activities inthe Gulf of Mexico and increased seismic operations in the Company’s Gulf Coastregion.

*Dry Hole andImpairment Expenses*

Dry hole and impairment expenses relate to costs ofunsuccessful exploratory wells drilled and impairment of oil and gasproperties. During 2005 the Company drilled 9 gross unsuccessful exploratorywells (7.1 net to the Company’s interest) for a total cost of approximately$67.1 million; in 2004 the Company drilled 7 unsuccessful exploratory wells(5.6 net to the Company’s interest) for a total cost of $40.2 million; and in2003 the Company drilled 5 unsuccessful exploratory wells (4.0 net to theCompany’s interest) for a total cost of $20.2 million.

Generally acceptedaccounting principles require that if the expected future cash flow of theCompany’s reserves on a proved property fall below the cost that is recorded onthe Company’s books, these costs must be impaired and written down to theproperty’s fair value. Depending on market conditions, including the prices foroil and natural gas, and the results of operations, a similar test may beconducted at any time to determine whether impairments are appropriate.Depending on the results of this test, an impairment could be required on someof the Company’s proved properties and this impairment could have a materialnegative non-cash impact on the Company’s earnings and balance sheet. Unprovedproperties are reviewed quarterly to determine if there has been impairment ofthe carrying value, with any such impairment charged to expense in the period. Theevaluation of unproved properties requires management’s judgment to estimatethe fair value of leasehold and exploratory costs related to drilling activityin a given area. Drilling activities in an area by other companies may alsoeffectively condemn unproved properties. As a result of its review of provedand unproved properties, the Company recognized impairments to oil and gasproperties of approximately $20.1 million during 2005, approximately $21.4 millionduring 2004 and $10.5 million during 2003.

*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 establishescost centers on the basis of an oil or gas trend or play for its onshore oiland gas activities. The Company generally creates cost centers on afield-by-field basis for oil and gas activities in the Gulf of Mexico.

The increase in the Company’s DD&A expense for2005, compared to 2004, resulted primarily from an increased DD&A ratecaused by a decrease in the percentage of the Company’s production coming fromfields that have DD&A rates that are lower than the Company’s recenthistorical composite DD&A rate (principally properties in the Gulf ofMexico which were shut-in due to hurricane downtime) and a 

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corresponding increase inthe percentage of the Company’s production coming from fields that haveDD&A rates that are higher than the Company’s recent historical compositerate (principally increased production from properties acquired by corporateacquisitions).

The increase in theCompany’s DD&A expense for 2004, compared to 2003, resulted primarily from adecrease in the percentage of the Company’s production coming from fields thathave DD&A rates that are lower than the Company’s recent historicalcomposite DD&A rate (principally properties in the Gulf of Mexico whichwere shut-in due to hurricane downtime) and a corresponding increase in thepercentage of the Company’s production coming from fields that have DD&Arates that are higher than the Company’s recent historical composite rate(principally increased production from onshore properties acquired byacquisition).

*Production andOther Taxes*

The increase in productionand other taxes for 2005, compared to 2004, and for 2004, compared to 2003, isprimarily related to increased severance taxes due to higher prices and higheronshore production volumes.

*Transportation andOther*

Transportationand other expense includes the Company’s cost to move its products to market(transportation costs), accretion expense related to Company asset retirementobligations under generally accepted accounting principles, natural gaspurchase costs, recognition of recoveries from business interruption insurance,write-down of tubular inventory values and various other operating expenses. Thefollowing table shows the significant items included in Transportation andother and the changes between periods (expressed in thousands):

| ** **                             | ** ** | **For the Year Ended December 31,** | ** ** |
|----------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                             | ** ** | **2005**                                                     | ** ** | **2004** | ** ** | **2003** | ** ** |
| Business  interruption insurance       |       | $                                                            | (40,743    | ) | $ | (11,133 | ) | $ | — |   |
| Transportation  costs                  |       | 14,568                                                       |       | 13,318 |   | 12,980 |   |
| Accretion expense                      |       | 7,995                                                        |       | 4,802 |   | 4,972 |   |
| Gas inventory  purchases               |       | 4,540                                                        |       | — |   | — |   |
| Write-down of  tubular inventory value |       | —                                                       |       | — |   | 1,450 |   |
| Other                                  |       | 4,561                                                        |       | 1,368 |   | 4,490 |   |
| Total                                  |       | $                                                            | (9,079     | ) | $ | 8,355 |   | $ | 23,892 |   |

 

The business interruptioninsurance relates to claims from the shut-in of a significant portion of theCompany’s Gulf of Mexico production during 2005 and  the fourth quarter of 2004 as a result of theinfrastructure damage caused by Hurricanes Ivan, Katrina and Rita. Accretionexpense increased in 2005 compared to 2004 due to increased estimates of futureliabilities due to rising service costs and the acquisition of Northrock in thethird quarter of 2005. Gas inventory purchases are related solely to theCompany’s Canadian operations and were therefore not present in 2004 and 2003.

*Interest*

*InterestCharges.**  *Theincrease in the Company’s interest charges for 2005, compared to 2004, resultedprimarily from an increase in the average amount of the Company’s outstandingdebt during 2005. The Company incurred approximately $690 million in additionaldebt in connection with the Northrock acquisition, which had a significantimpact on the Company’s 2005 interest expense. The decrease in the Company’sinterest charges for 2004, compared to 2003, resulted primarily from a decreasein the average amount of the Company’s outstanding debt during the first elevenmonths of the year and the repayment 

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of higher cost debt duringthe year, resulting in a lower weighted average cost of debt. The Companyincurred $317 million in additional debt during December 2004 primarilyrelated to acquisitions, but this did not have a significant impact on theCompany’s 2004 interest expense.

*InterestIncome.**  *Theincrease in the Company’s interest income for 2005, compared to 2004 and 2003resulted from an increase in the amount of cash and cash equivalentstemporarily invested. The cash and cash equivalents invested during 2005increased primarily due to the sales proceeds from the sale of the ThailandEntities. These proceeds were subsequently used to fund a portion of theNorthrock purchase.

*Capitalized Interest.**  *Interest costs related to financingmajor oil and gas projects in progress are required to be capitalized until theprojects are substantially complete and ready for their intended use ifprojects are evaluated as successful. The increase in capitalized interest for2005, compared to 2004, resulted from an increase in the average amount ofcapital expenditures subject to interest capitalization during 2005(approximately $358,000,000) compared to 2004 (approximately $210,000,000). Thedecrease in capitalized interest for 2004, compared to 2003, resulted from adecrease in the weighted average rate on borrowings incurred by the Company(discussed above under “Results of Operations—Interest Charges”) and applied tosuch capital expenditures to arrive at the total amount of capitalizedinterest, partially offset by an increase in the average amount of capitalexpenditures subject to interest capitalization during 2004 (approximately$210,000,000) compared to 2003 (approximately $192,000,000).

*CommodityDerivative Expense*

Commodity derivativeexpense for 2005 represents losses on derivative contracts that no longerqualify for hedge accounting treatment. Although all of the Company’s collarsare effective as economic hedges, the forecasted shut-in hydrocarbon productionfrom the Company’s Gulf of Mexico properties (resulting primarily fromhurricane activity during the third quarter of 2005) caused certain of the gasand crude oil collar contracts to lose their qualification for hedge accountingunder SFAS 133. The forecasted hydrocarbon production used to identify thosederivative contracts that qualify for hedge accounting is subject to changebased on the condition of third party infrastructure including pipelines,onshore facilities and many other factors. If hydrocarbon production isdeferred beyond the currently forecast schedule, additional contracts may losetheir qualification for hedge accounting and further adjustments may benecessary. No such expense was incurred during either 2004 or 2003, as all ofthe Company’s derivative contracts qualified for hedge accounting at that time.

*Loss on DebtExtinguishment*

*The loss on debt extinguishment for2004 is related to redemption premiums paid and/or unamortized debt issuancecosts which were expensed due to the redemption of the 2009 Notes and thereplacement of the Company’s previous bank credit facility with a new creditfacility. The loss on debt extinguishment for 2003 is related to redemptionpremiums paid and unamortized debt issuance costs which were expensed due tothe redemption of the 2006 Notes and 2007 Notes.*

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*Income Tax Expense*

Changes in the Company’sincome tax expense are a function of the Company’s consolidated effective taxrate, the Company’s pre-tax income and the jurisdiction in which the income isearned. The increase in the Company’s tax expense for 2005, compared to 2004,and for 2004, compared to 2003, resulted primarily from increased pre-taxincome in the later years. The Company’s consolidated effective tax rate for2005, 2004 and 2003 was 36.7%, 37.4%, and 36.9%, respectively. The Companycurrently expects its effective tax rate to decrease approximately 4 to 6percentage-points over the next two years, based on current earnings levels.This reduction is expected due to the favorable impact of cross-borderfinancing related to the acquisition of Northrock Resources,  reductions in the statutory federal incometax rates in Canada from approximately 26% to 22%, the phase-in of a deductionin Canada for Crown royalties, and the phase-in of the deduction for qualifieddomestic production activities in the United States.

*DiscontinuedOperations*

TheThailand Entities and Pogo Hungary are classified as discontinued operations inthe Company’s financial statements. The summarized financial results andfinancial position data of the discontinued operations were as follows (amountsexpressed in thousands):

**Operating Results Data**

| ** **                                                   | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                   | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Revenues                                                     |       | $                                          | 252,840    |   | $ | 335,291 |   | $ | 303,491 |   |
| Costs and  expenses                                          |       | (126,496                                   | )          | (237,097 | ) | (163,388 | ) |
| Other income                                                 |       | 4,962                                      |       | 308 |   | 2,520 |   |
| Income before  income taxes                                  |       | 131,306                                    |       | 98,502 |   | 142,623 |   |
| Income taxes                                                 |       | (78,456                                    | )          | (85,783 | ) | (82,751 | ) |
| Income before  gain from discontinued operations, net of tax |       | 52,850                                     |       | 12,719 |   | 59,872 |   |
| Gain on sale, net  of tax of $9,736                          |       | 407,784                                    |       | — |   | — |   |
| Income from discontinued  operations, net of tax             |       | $                                          | 460,634    |   | $ | 12,719 |   | $ | 59,872 |   |

 

The increase in incomefrom discontinued operations for 2005, compared to 2004, primarily relates togains recognized on the sale of the discontinued operations. The decrease inrevenues and expenses was primarily caused by the absence of Thailand revenuesand expenses after the sale date. The decrease in income from discontinuedoperations for 2004, compared to 2003, primarily relates to dry hole andimpairment costs incurred in Hungary and to increased Special RemunitoryBenefit (SRB) costs incurred in the Kingdom of Thailand, which were onlypartially offset by increased revenues in the Kingdom of Thailand.  The Company recognized no tax benefit for itscosts in Hungary, resulting in a high effective tax rate for each of theperiods presented.

*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 

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cumulativeaccretion, and also to increase the carrying amount of the associatedlong-lived asset and its accumulated depreciation.

**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 2005 was $845,537,000. This compares to cash flow from operatingactivities of $738,715,000 in 2004 and $744,559,000 in 2003. The resultingchanges are attributable to the reasons described under “Results of Operations”above. Cash flow from operating activities during 2005 was more than adequateto fund $564,614,000 in cash expenditures ($506,798,000 for continuingoperations and $57,816,000 for discontinued operations) for capital andexploration projects and property acquisitions, excluding corporate acquisitiontransactions. The approximately $1.7 billion Northrock transaction was fundedusing available cash on hand, proceeds from the sale of the Company’s ThailandEntities, the net proceeds from the Company’s offering of the 2017 Notes andadditional borrowings under the revolving credit facility. During 2005, theCompany issued $300,000,000 principal amount of 2015 Notes, $500,000,000principal amount 2017 Notes (see descriptions below) and borrowed cash of$91,000,000 (net of repayments) under its revolving credit facility. During2005, the Company also paid for the repurchase of $351,813,000 of its commonstock and paid $15,212,000 of common stock dividends. As of December 31,2005, the Company had cash and cash equivalents of $57,749,000 and long-termdebt obligations of $1,646,000,000 (excluding debt discount) with no repaymentobligations until 2009. The Company may determine to repurchase outstandingdebt in the future, including in market transactions, privately negotiatedtransactions or otherwise, depending on market conditions, liquidityrequirements, contractual restrictions and other factors.

Effective December 15,2005, the Company’s lenders redetermined the borrowing base under its revolvingcredit facility at $1,500,000,000. As of February 23, 2006, the Companyhad an outstanding balance of $585,000,000 under its facility. As such, theavailable borrowing capacity under the facility was $415,000,000.

*Purchase ofNorthrock Resources Ltd.*

On September 27,2005, the Company completed the acquisition of Northrock for approximately $1.7billion in cash. Pogo Canada, ULC, a Canadian company and wholly ownedsubsidiary of the Company, purchased all of the outstanding shares of Northrockpursuant to a share purchase agreement that was entered into on July 8,2005. As of December 31, 2005, Northrock owned 657 billion cubic feet ofgas equivalent (Bcfe) of estimated proven reserves on approximately 292,000 netacres, plus approximately 950,000 net acres of undeveloped leasehold. Northrock’sactivities are concentrated in Saskatchewan and Alberta with key explorationplays in Canada’s Northwest Territories, British Columbia and the AlbertaFoothills. The Company acquired Northrock primarily to strengthen its positionin North American exploration and development properties.

*2017 Notes*

On September 23,2005, the Company issued $500,000,000 principal amount of 2017 Notes. Theproceeds from the sale of the 2017 Notes were used to fund a portion of theNorthrock acquisition. The 

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2017Notes bear interest at a rate of 6.875%, payable semi-annually in arrears on April 1and October 1 of each year. The 2017 Notes are general unsecured seniorsubordinated obligations of the Company, and are subordinated in right ofpayment to the Company’s senior indebtedness, which includes the Company’sobligations under the revolving credit facility and LIBOR rate advances. TheCompany, at its option, may redeem the 2017 Notes in whole or in part, at anytime on or after October 1, 2010, at a redemption price of 103.4375% oftheir principal amount and decreasing percentages thereafter. The Company mayalso redeem a portion of the 2017 Notes prior to October 1, 2008 and someor all of the Notes prior to October 1, 2010, in each case by payingspecified premiums. The indenture governing the 2017 Notes also imposes certaincovenants 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 restrictedsubsidiaries; dividends and other payment restrictions affecting restrictedsubsidiaries; and merger, consolidations and the sale of assets.

*2015 Notes*

On March 29, 2005,the Company issued $300,000,000 principal amount of 2015 Notes at 99.101%. Theproceeds from the sale of the 2015 Notes were used to pay down obligationsunder the Company’s bank credit facility. The 2015 Notes bear interest at arate of 6.625%, payable semi-annually in arrears on March 15 and September 15of each year. The 2015 Notes are general unsecured senior subordinatedobligations of the Company, and are subordinated in right of payment to theCompany’s senior indebtedness, which includes the Company’s obligations underthe revolving credit facility and LIBOR advances. The Company, at its option,may redeem the 2015 Notes in whole or in part, at any time on or after March 15,2010, at a redemption price of 103.3125% of their principal amount anddecreasing percentages thereafter. The Company may also redeem a portion of the2015 Notes prior to March 15, 2008 and some or all of the Notes prior to March 15,2010, in each case by paying specified premiums. The indenture governing the2015 Notes also imposes certain covenants on the Company including covenantslimiting: incurrence of indebtedness including senior indebtedness; restrictedpayments; the issuance and sales of restricted subsidiary capital stock;transactions with affiliates; liens; disposition of proceeds of assets sales;non-guarantor restricted subsidiaries; dividends and other payment restrictionsaffecting restricted subsidiaries; and merger, consolidations and the sale ofassets.

*LIBOR Rate Advances*

Under separate PromissoryNote Agreements dated May 8, 2004 and September 13, 2004, two of theCompany’s lenders make available to the Company LIBOR rate advances on anuncommitted basis up to $50,000,000. Advances drawn under these agreements arereflected as long-term debt on the Company’s balance sheet because the Companycurrently has the ability and intent to reborrow such amounts under its CreditAgreement. The Company’s 2011 Notes, 2015 Notes and 2017 Notes may restrict allor a portion of the amounts that may be borrowed under the Promissory NoteAgreements as senior debt. The Promissory Note Agreements permit either partyto terminate the letter agreements at any time upon three-business days notice.As of February 23, 2006 there was $40,000,000 outstanding under theseagreements.

*Future Capital andOther Expenditure Requirements*

The Company’s capital andexploration budget for 2006, 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 $725,000,000. The Company has included 451 gross wells in its 2006 capitaland exploration budget, including wells to be drilled in the United States,Canada and New Zealand. As of February 23, 2006, the Company anticipatesthat its available cash and 

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cashinvestments, cash provided by operating activities and funds available underits revolving credit facility will be sufficient to fund the Company’s ongoingoperating, interest and general and administrative expenses, its authorizedcapital budget, and dividend payments at current levels for the foreseeablefuture. The declaration and amount of future dividends on the Company’s commonstock will depend upon, among other things, the Company’s future earnings andfinancial condition, liquidity and capital requirements, its ability to paydividends and other payments under covenants contained in its debt instruments,the general economic and regulatory climate and other factors deemed relevantby the Company’s Board of Directors.

*Stock Repurchase*

On January 25, 2005,the  Company announced a plan torepurchase, through open market or privately negotiated transactions, not lessthan $275 million nor more than $375 million of its common stock. As of February 23,2006, the Company had completed the purchase of 7,310,000 shares at a total cost of $359.5 million.

*Other MaterialLong-Term Commitments*

*Contractual Obligations.*   TheCompany’s material contractual obligations include long-term debt, operatingleases, and other contracts. Material contractual obligations for which theultimate settlement amounts are not fixed and determinable include derivativecontracts that are sensitive to future changes in commodity prices and otherfactors. See “Item 7A. Quantitative and Qualitative Disclosure about MarketRisk.”  A summary of the Company’s knowncontractual obligations as of December 31, 2005 are set forth on thefollowing table**:**

| ** **                       | ** ** | **Payments due by period (in millions)** | ** ** |
|----------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                       | ** ** | ** **                                                        | ** ** | **Less than** | ** ** | **1 - 3** | ** ** | **3 - 5** | ** ** | **More than** | ** ** |
| ** **                       | ** ** | **Total**                                                         | ** ** | **1 Year** | ** ** | **Years** | ** ** | **Years** | ** ** | **5 Years** | ** ** |
| Long Term Debt(a)                |       | $                                                                 | 2,302.7    |   |   | $ | 70.8 |   |   | $ | 141.5 |   | $ | 787.5 |   |   | $ | 1,302.9 |   |   |
| Operating Lease  Obligations(b)  |       | $                                                                 | 141.7      |   |   | $ | 16.8 |   |   | $ | 29.9 |   | $ | 24.0 |   |   | $ | 71.0 |   |   |
| Purchase  Obligations(c)         |       | $                                                                 | 23.4       |   |   | $ | 9.6 |   |   | $ | 2.6 |   | $ | 2.1 |   |   | $ | 9.1 |   |   |
| Asset Retirement  Obligations(d) |       | $                                                                 | 614.5      |   |   | $ | 4.7 |   |   | $ | 12.3 |   | $ | 5.7 |   |   | $ | 591.8 |   |   |
| Other Obligations(e)             |       | $                                                                 | 14.6       |   |   | $ | 14.6 |   |   | $ | 0.0 |   | $ | 0.0 |   |   | $ | 0.0 |   |   |
| Total                            |       | $                                                                 | 3,096.9    |   |   | $ | 116.5 |   |   | $ | 186.3 |   | $ | 819.3 |   |   | $ | 1,974.8 |   |   |

 

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(a)           Includes interest onfixed rate debt, but excludes variable rate interest expense on the Company’sbank credit facility.

(b)          Operating leasesprincipally include the Company’s office lease commitments, gas storage feecommitments and various other equipment rentals, including gas compressors. 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. See Note 5 to the Consolidated Financial Statements.

(c)           This represents i) theCompany’s share of the contractual commitments for drilling rigs that have aterm greater than six months or which cannot be terminated at the end of thewell that is currently being drilled and ii) firm transportation agreementsrepresenting “ship-or-pay” arrangements whereby the Company has committed toship certain volumes of gas for a fixed transportation fee (principally fromthe Madden Field in Wyoming). The Company entered into these arrangements toensure its access to gas markets and expects to produce sufficient volumes tosatisfy substantially all of its firm transportation obligations.

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(d)          This represents theCompany’s estimate of future asset retirement obligations on an undiscountedbasis. Because these costs typically extend many years into the future,estimating these future costs requires management to make estimates and judgmentsthat are subject to future revisions based upon numerous factors, including therate of inflation, changing technology and the political and regulatoryenvironment. See Note 14 to the Consolidated Financial Statements.

(e)           This represents theCompany’s estimate of retention bonus payments to  be made to those persons employed byNorthrock as of September 27, 2005, if those persons remain employees ofNorthrock on September 27, 2006.

*Commitmentsunder Joint Operating Agreements.**  *As is common in the oil and gasindustry, the Company operates in many instances through joint ventures underjoint operating agreements. Typically, the operator under a joint operatingagreement enters into contracts, such as drilling contracts, for the benefit ofall joint venture partners. Through the joint operating agreement, thenon-operators reimburse, and in some cases advance, the funds necessary to meetthe contractual obligations entered into by the operator. These obligations aretypically shared on a “working interest” basis. The joint operating agreementprovides remedies to the operator in the event that the non-operator does notsatisfy its share of the contractual obligations. Occasionally, the operator ispermitted by the joint operating agreement to enter into lease obligations andother contractual commitments that are then passed on to the non-operatingjoint interest owners as lease operating expenses, frequently without anyidentification as to the long-term nature of any commitments underlying suchexpenses. The contractual obligations set forth above represent the Company’sworking interest share of the contractual commitments that it has entered intoas operator and, to the extent that it is aware, the contractual commitmentsentered into by the operator of projects that the Company does not operate.

*SuretyBonds.**  *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 31,2005, 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 $8.8 million that are not included in thetable presented above. In connection with their administration of offshoreleases in the Gulf of Mexico, the MMS annually evaluates each lessee’s pluggingand abandonment liabilities. The MMS reviews this information and applies certainfinancial tests including, but not limited to, current asset and net worthtests. The MMS determines whether each lessee is financially capable of payingthe estimated costs of such plugging and abandonment liabilities. The Companymust annually provide the MMS with financial information. If the Company doesnot satisfy the MMS requirements, it could be required to post supplementalbonds. In the past, the Company has not been required to post supplementalbonds; however, there can be no assurance that the Company will satisfy thefinancial tests and remain on the list of MMS lessees exempt from thesupplemental bonding requirements. The Company cannot predict or quantify theamount of any such supplemental bonds or the annual premiums related thereto andtherefore has not included them in the prior table, but the amount could besubstantial.

*Guarantees and Letters ofCredit.**  *Asof February 23, 2006, approximately $2 million in letters of credit hadbeen issued on the Company’s behalf relating to its Canadian operations.

*Credit Agreementand Borrowing Base Determination*

*Credit Agreement.**  *The Company has a revolving creditfacility (the “Credit Agreement”) that provides for a $1.0 billion revolvingloan facility terminating on December 16, 2009. The amount that may beborrowed under the Credit Agreement may not exceed a borrowing base determinedat least semiannually using the administrative agent’s usual and customarycriteria for oil and gas reserve 

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valuation, adjustedfor incurrences of other indebtedness since the last redetermination of theborrowing base. As of February 23, 2006, the borrowing base was $1.5billion. The credit agreement provides that in specified circumstancesinvolving an increase in ratings assigned to Pogo’s debt, Pogo may elect forthe borrowing base limitation to no longer apply to restrict availableborrowings. The next redetermination of the borrowing base is expected to occurby May 1, 2006. A significant decline in the prices that the Company isexpected to receive for its future oil and gas production could have a materialnegative impact on the borrowing base under the Credit Agreement which, in turn,could have a material negative impact on the Company’s liquidity. If at aredetermination of the borrowing base, the lenders reduce the borrowing basebelow the amount then outstanding under the Credit Agreement and other seniordebt arrangements, the Company must repay the excess to the lenders in no morethan four substantially equal monthly installments, commencing not later than90 days after the Company is notified of the new borrowing base. The CreditAgreement includes procedures for additional financial institutions selected bythe Company to become lenders under the agreement, or for any existing lenderto increase its commitment in an amount approved by the Company and the lender,subject to a maximum of $250 million for all such increases in commitments ofnew or existing lenders. The Credit Agreement also permits short-termswing-line loans up to $10 million and the issuance of letters of credit up to$75 million, which in each case reduce the credit available for revolvingcredit borrowings.  As of February 23,2006, there was $585 million outstanding under the Credit Agreement.

**Applicationof Critical Accounting Policies and Management’s Estimates**

The discussion andanalysis of the Company’s financial condition and results of operations is basedupon the consolidated financial statements, which have been prepared inaccordance with accounting principles generally accepted in the United States.The preparation of these financial statements requires the Company to makeestimates and judgments that affect the reported amounts of assets,liabilities, revenues and expenses. The Company’s significant accountingpolicies are described in Note 1 to the consolidated financial statementsincluded in this Annual Report on Form 10-K. We have identified belowpolicies that are of particular importance to the portrayal of its financialposition and results of operations and which require the application ofsignificant judgment by management. The Company analyzes its estimates,including those related to oil and gas revenues, bad debts, oil and gasproperties, marketable securities, income taxes, derivatives, contingencies andlitigation, on a periodic basis and bases its estimates on historicalexperience and various other assumptions that management believes to bereasonable under the circumstances. Actual results may differ from theseestimates under different assumptions or conditions. The Company believes thefollowing critical accounting policies affect its more significant judgmentsand estimates used in the preparation of the Company’s financial statements:

*Successful EffortsMethod 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 

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requires both judgment andapplication of industry experience. Wells may be completed that are assumed tobe productive and actually deliver oil and gas in quantities insufficient to beeconomic, which may result in the abandonment of the wells at a later date. Onoccasion, wells are drilled which have targeted geologic structures that areboth 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 included in unproved properties requires management’s judgment toestimate the fair value of exploratory costs related to drilling activity in agiven area. Drilling activities in an area by other companies may alsoeffectively 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.

*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 2.75%, 1.05% and 3.66% of proved reservesduring the years ended December 31, 2005, 2004 and 2003, 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 at December 31, 2005 of 1% would result in anannual increase in DD&A expense of approximately $3.6 million.

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*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 2005, 2004 and 2003. Given thecomplexities associated with oil and gas reserve estimates and the history ofprice volatility in the oil and gas markets, events may arise that will requirethe Company to record an impairment of its oil and gas properties and there canbe no assurance that such impairments will not be required in the future northat 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 initiallyrepresented cash flow hedges of the price of future oil and natural gasproduction. Therefore, while fair values of such hedging instruments must beestimated at the end of each reporting period, the related changes in such fairvalues are not included in the Company’s consolidated results of operations, tothe extent they are expected to offset the future cash flows from oil andnatural gas production. Instead, the changes in fair value of hedginginstruments are recorded directly to shareholders’ equity until the hedged oilor natural gas quantities are produced and sold.

The estimation of fair values for the Company’shedging derivatives requires substantial judgment. The Company estimates thefair values of its derivatives on a monthly basis using an option-pricingmodel. To utilize the option-pricing model, the Company uses various factorsthat include closing exchange prices on the NYMEX, over-the-counter quotations,volatility and the time value of options. The estimated future prices are comparedto the prices fixed by the hedge agreements, and the resulting estimated futurecash inflows (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.

Derivative contracts thatdo not initially qualify for hedge accounting treatment or lose theirqualification for hedge accounting treatment (such as those contracts that lostthe qualification for hedge accounting treatment during 2005 due to curtailedproduction resulting from hurricane damage) are carried at their fair value onthe Company’s consolidated balance sheet. The Company recognizes all changes inthe fair value of these contracts in the Company’s consolidated results ofoperations in the period in which the change occurs in the caption “Commodityderivative expense.”

*BusinessCombinations/Acquisitions*

In 2005, the Company grew through the acquisition ofNorthrock Resources. This acquisition was 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. 

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Any excess of the purchaseprice over the fair values of the tangible and intangible net assets acquiredis recorded as goodwill. Goodwill and other intangibles with an indefiniteuseful life are assessed for impairment at least annually. The Company hasnever recorded any goodwill in connection with its businesscombinations/acquisitions. However, there can be no assurance that the Companywill 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 estimated fair value of bothproved and unproved properties, the Company prepares estimates of oil, naturalgas and NGL reserves. These estimates are based on work performed by theCompany’s engineers and outside petroleum reservoir consultants. The judgmentsassociated with the estimation of reserves are described earlier in thissection. The fair value of the estimated reserves acquired in a businesscombination is then calculated based on the Company’s estimates of future oil,natural gas and NGL prices. The Company’s estimates of future prices are based onits own analysis of pricing trends. These estimates are based on current dataobtained with regard to regional and worldwide supply and demand dynamics, suchas economic growth forecasts. They are also based on industry data regardingnatural gas storage availability, drilling rig activity, changes in deliverycapacity and trends in regional pricing differentials. Future price forecastsfrom independent third parties are also taken into account in arriving at theCompany’s own pricing estimates. The Company’s estimates of future prices areapplied to the estimated reserve quantities acquired to arrive at estimatedfuture net revenues. For estimated proved reserves, the future net revenues arethen discounted to derive a fair value for such reserves. The fair value ofproved reserves is then used to estimate the fair value of proved propertycosts acquired in a business combination. The Company also applies these samegeneral principles in arriving at the fair value of unproved reserves acquiredin a business combination. These unproved reserves are generally classified aseither probable or possible reserves. The fair value of probable and possiblereserves is then used to estimate the fair value of unproved property costsacquired in a business combination. Because of their very nature, probable andpossible 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.

*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, gathering systems, wellsand related structures and restoration costs of land and seabed. We developestimates of these costs for each of our properties based upon the type ofproduction structure, depth of water, reservoir characteristics, depth of thereservoir, market demand for equipment, currently available procedures andconsultations 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.

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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 $16 million (representingan increase of approximately 10% to the Company’s December 31, 2005 assetretirement obligation) to increase the Company’s DD&A rate by $0.01 perMcfe for the year ended December 31, 2005.

*Recognition ofInsurance Recoveries*

The Company recognizesestimated proceeds from insurance recoveries only when the amount of therecovery is determinable and when the Company believes that the proceeds areprobable of recovery. When the amount of the estimated recoveries has beendetermined and when the Company has concluded that the recovery is probable,the recoveries are recognized in the results of operations. Businessinterruption proceeds are recorded as a reduction of “Transportation and otherexpense” and property damage recoveries are recorded as a reduction of “Leaseoperating expense”.

*Pension and OtherPost-Retirement Benefits*

Accounting for pensionsand other post-retirement 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 its demographics andutilizes the work of actuaries to assist with the measurement of employee-relatedobligations. The assumptions used vary from year-to-year, which will affectfuture results of operations. Any differences among these assumptions and theresults actually experienced will also impact future results of operations. Ananalysis of the effect of a 1% change in health care cost trends onpost-retirement benefits is included in Note 10 to the Consolidated FinancialStatements.

*Income Taxes*

For financial reporting purposes, the Companygenerally provides for 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.

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.**  *Publicly held companies are askedto comment on the effects of inflation on their business. As of February 23,2006, annual inflation in terms of the decrease in the general purchasing powerof the dollar is running well below the general annual inflation ratesexperienced in the past. While the Company, like other companies, continues tobe affected by fluctuations in the purchasing power of the dollar due toinflation, such effect is not considered significant as of February 23,2006.

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**ITEM 7A.   *Quantitative andQualitative 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 Price Risk**

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

**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 February    , 2006, the Company has no open interestrate swap or interest rate lock agreements. Therefore, the Company’s exposureto changes in interest rates primarily results from its short-term andlong-term debt with both fixed and floating interest rates. The following tablepresents 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, 2005:

| ** **                   | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **Thereafter** | ** ** | **Total** | ** ** | **Fair Value** | ** ** |
|------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|---------------------|------------|
| Long-Term Debt:              |       |     |       |     |       |     |       |     |       |     |       |           |       |      |       |                |       |   |   |   |   |   |   |   |   |   |   |
| Variable Rate                |       |     | $          | 0        |       |     |       | $        | 0          |     |       |           | $          | 0         |       |                | $          | 646,000 |   |   | $ | 0 |   |   | $ | 0 |   | $ | 646,000 |   |   | $ | 646,000 |   |   |
| Average Interest Rate   |       |     | —     |     |       |     | —     |     |       |     | —     |           |       | 5.82      | %          |                | —     |   |   | — |   | 5.82 | % |   | — |   |   |
| Fixed Rate                   |       |     | $          | 0        |       |     |       | $        | 0          |     |       |           | $          | 0         |       |                | $          | 0 |   |   | $ | 0 |   |   | $ | 1,000,000 |   | $ | 1,000,000 |   |   | $ | 985,250 |   |   |
| Average Interest  Rate  |       |     | —     |     |       |     | —     |     |       |     | —     |           |       | —    |       |                | —     |   |   | 7.08 | % | 7.08 | % |   | — |   |   |

 

**Foreign Currency Exchange Rate Risk**

In addition to the U.S.dollar, the Company and certain of its subsidiaries conduct a substantialportion of their business in Canadian dollars and are therefore subject toforeign currency exchange rate risk on cash flows related to sales, expenses,financing and investing transactions conducted in Canada.  As of February 23, 2006, the Company isnot a party to any foreign currency exchange agreement.

**Current Hedging Activity**

As of December 31, 2005, the Company held variousderivative instruments. The Company has entered into natural gas and crude oiloption agreements referred to as “collars”. Collars are designed to establishfloor and ceiling prices on anticipated future natural gas and crude oilproduction. The Company has designated a significant portion of these contractsas cash flow hedges designed to achieve a more predictable cash flow, as wellas to reduce its exposure to price volatility. While the use of thesederivative instruments limits the downside risk of adverse price movements,they may also limit future revenues from favorable price movements. The use ofderivatives also involves the risk that the counterparties to such instrumentswill be unable to meet the financial terms of such contracts. Currently, theCompany does not expect losses due to creditworthiness of its counterparties.

The gas derivative 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 derivativetransactions 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 

52

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particular collartransaction, the counterparty is required to make a payment to the Company ifthe settlement price for any settlement period is below the floor price forsuch transaction, and the Company is required to make a payment to thecounterparty if the settlement price for any settlement period is above theceiling price of such transaction.

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 31,2005 are as follows:

| **Contract Period and**            | ** ** | ** ** | ** ** | **NYMEX  Contract  Price** | ** ** | **Fair Value  of** | ** ** |
|----------------------------------------------|------------|------------|------------|----------------------------|------------|-------------------------|------------|
| **Type of Contract**               | ** ** | **Volume** | ** ** | **Floor**                  | ** ** | **Ceiling**             | ** ** | **Liability** | ** ** |
| **Natural  Gas Contracts (MMBtu)(a)**        |       |       |       |                       |       |                    |       |   |   |
| Collar Contracts:                            |       |       |       |                       |       |                    |       |   |   |
| January 2006 - December 2006  |       | 5,475      |       | $                          | 5.00       |                    | $          | 7.50 |   | $ | (18,527,528 | ) |
| January 2006 - December 2006  |       | 1,825      |       | $                          | 5.50       |                    | $          | 8.25 |   | $ | (5,106,509 | ) |
| January 2006 - December 2006  |       | 3,650      |       | $                          | 5.75       |                    | $          | 8.27 |   | $ | (10,053,301 | ) |
| January 2006 - December 2006  |       | 10,950     |       | $                          | 6.00       |                    | $          | 13.50 |   | $ | (4,942,274 | ) |
| January 2006 - December 2006  |       | 1,825      |       | $                          | 6.00       |                    | $          | 13.55 |   | $ | (809,200 | ) |
| January 2006 - December 2006  |       | 3,650      |       | $                          | 6.00       |                    | $          | 13.60 |   | $ | (1,589,865 | ) |
| January 2006 - December 2006  |       | 10,950     |       | $                          | 6.00       |                    | $          | 14.00 |   | $ | (4,134,399 | ) |
| January 2007 - December 2007  |       | 5,475      |       | $                          | 6.00       |                    | $          | 12.00 |   | $ | (5,536,823 | ) |
| January 2007 - December 2007  |       | 9,125      |       | $                          | 6.00       |                    | $          | 12.15 |   | $ | (8,878,679 | ) |
| January 2007 - December 2007  |       | 3,650      |       | $                          | 6.00       |                    | $          | 12.20 |   | $ | (3,505,893 | ) |
| January 2007 - December 2007  |       | 9,125      |       | $                          | 6.00       |                    | $          | 12.50 |   | $ | (8,106,668 | ) |
| ** **                                   |       |       |       |                       |       |                    |       |   |   |
| **Crude  Oil Contracts (Barrels)**           |       |       |       |                       |       |                    |       |   |   |
| Collar Contracts:                            |       |       |       |                       |       |                    |       |   |   |
| January 2006 - December 2006  |       | 1,460,000  |       | $                          | 50.00      |                    | $          | 78.00 |   | $ | (976,728 | ) |
| January 2006 - December 2006  |       | 365,000    |       | $                          | 50.00      |                    | $          | 79.00 |   | $ | (195,932 | ) |
| January 2006 - December 2006  |       | 1,460,000  |       | $                          | 50.00      |                    | $          | 81.00 |   | $ | (439,482 | ) |
| January 2006 - December 2006  |       | 365,000    |       | $                          | 50.00      |                    | $          | 81.04 |   | $ | (108,279 | ) |
| January 2006 - December 2006  |       | 1,825,000  |       | $                          | 50.00      |                    | $          | 82.00 |   | $ | (357,749 | ) |
| January 2007 - December 2007  |       | 1,460,000  |       | $                          | 50.00      |                    | $          | 75.00 |   | $ | (3,463,645 | ) |
| January 2007 - December 2007  |       | 365,000    |       | $                          | 50.00      |                    | $          | 75.25 |   | $ | (842,944 | ) |
| January 2007 -  December 2007 |       | 3,650,000  |       | $                          | 50.00      |                    | $          | 77.50 |   | $ | (6,439,226 | ) |

----

(a)           MMBtu means millionBritish Thermal Units.

53

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Althoughall of the Company’s collars are effective as economic hedges, the forecastedshut-in hydrocarbon production from the Company’s Gulf of Mexico properties(resulting primarily from hurricane activity during the third quarter of 2005)caused certain of the gas and crude oil collar contracts to lose theirqualification for hedge accounting under SFAS 133. As a result, the Companyreclassified $18.7 million of previously deferred losses from accumulated othercomprehensive income to “Commodity derivative expense” in the income statementduring the third quarter of 2005. Additionally, the Company now recognizes allfuture changes in the fair value of these collar contracts in the consolidatedstatement of income for the period in which the change occurs under the caption“Commodity derivative expense.’’  As of December 31,2005, the Company had the following collar contracts that no longer qualify forhedge accounting:

| **Contract Period and**            | ** ** | ** ** | ** ** | **NYMEX  Contract  Price** | ** ** | **Fair Value  of** | ** ** |
|----------------------------------------------|------------|------------|------------|----------------------------|------------|-------------------------|------------|
| **Type of Contract**               | ** ** | **Volume** | ** ** | **Floor**                  | ** ** | **Ceiling**             | ** ** | **Liability** | ** ** |
| **Natural  Gas Contracts (MMBtu)**           |       |       |       |                       |       |                    |       |   |   |   |   |   |   |
| Collar Contracts:                            |       |       |       |                       |       |                    |       |   |   |   |   |   |   |
| January 2006 -  November 2006 |       |       | 1,825      |                       |       | $                       | 5.50       |   |   | $ | 8.25 |   |   | $ | (5,034,443 | ) |
|                                              |            |            |            |                            |            |                         |            |  |  |  |  |  |  |  |  |  |

 

**ITEM 8.   *Financial Statements andSupplementary Data***.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM

To the Stockholders and Board of Directors of PogoProducing Company:

We have completedintegrated audits of Pogo Producing Company’s 2005 and 2004 consolidatedfinancial statements and of its internal control over financial reporting as ofDecember 31, 2005, and an audit of its 2003 consolidated financialstatements in accordance with the standards of the Public Company AccountingOversight Board (United States). Our opinions, based on our audits, arepresented below.

*Consolidated financial 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 at December 31,2005 and 2004, and the results of their operations and their cash flows foreach of the three years in the period ended December 31, 2005 inconformity with accounting principles generally accepted in the United Statesof America. These financial statements are the responsibility of the Company’smanagement. 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 statement presentation.We believe that our audits provide a reasonable basis for our opinion.

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 14 to the consolidated financial statements,the Company changed its method of accounting for asset retirement obligations effectiveJanuary 1, 2003.

54

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*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, 2005 based on criteriaestablished in *Internal Control—Integrated Framework*issued by 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, effectiveinternal control over financial reporting as of December 31, 2005, basedon criteria established in *Internal Control—IntegratedFramework* issued by the COSO. The Company’s management isresponsible for maintaining effective internal control over financial reportingand for its assessment of the effectiveness of internal control over financialreporting. Our responsibility is to express opinions on management’s assessmentand on the effectiveness of the Company’s internal control over financialreporting based on our audit. We conducted our audit of internal control overfinancial reporting in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whethereffective internal control over financial reporting was maintained in allmaterial 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 procedures as we consider necessary in the circumstances. We believe thatour audit provides a reasonable basis 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. A company’sinternal 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 the company;and (iii) provide reasonable assurance regarding prevention or timelydetection of unauthorized acquisition, use, or disposition of the company’sassets that could have a material effect on the financial statements.

Because of its inherent limitations, internal controlover financial reporting may not prevent or detect misstatements. Also,projections of any evaluation of effectiveness to future periods are subject tothe risk that controls may become inadequate because of changes in conditions,or that the degree of compliance with the policies or procedures maydeteriorate.

As described in Management’s Report on InternalControl Over Financial Reporting, management has excluded the Company’sCanadian division from it assessment of internal control over financialreporting as of December 31, 2005 because the division was formed with theacquisition of Northrock Resources Ltd. in a purchase business combinationduring 2005. We have also excluded the Canadian division from our audit ofinternal control over financial reporting. The Canadian division is awholly-owned subsidiary of the Company whose total assets and total revenuesrepresent 49% and 11%, respectively, of the related consolidated financial statementamounts as of and for the year ended December 31, 2005.

PRICEWATERHOUSECOOPERS LLP

Houston, TexasMarch 2, 2006

55

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**POGOPRODUCING COMPANY & SUBSIDIARIESCONSOLIDATED STATEMENTS OF INCOME**

| ** **                                                                                                   | ** ** | **Year Ended December 31,**                                       | ** ** |
|--------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| ** **                                                                                                   | ** ** | **2005**                                                                         | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                                                   | ** ** | **(Expressed in thousands,  except per share amounts)** | ** ** |
| **Revenues:**                                                                                                |       |                                                                             |       |   |   |   |   |
| Oil and gas                                                                                                  |       | $                                                                                | 1,216,247  |   | $ | 973,083 |   | $ | 856,074 |   |
| Other                                                                                                        |       | 9,452                                                                            |       | 3,472 |   | 2,431 |   |
| Total                                                                                                        |       | 1,225,699                                                                        |       | 976,555 |   | 858,505 |   |
| **Operating  Costs and Expenses:**                                                                           |       |                                                                             |       |   |   |   |   |
| Lease operating                                                                                              |       | 153,659                                                                          |       | 100,506 |   | 81,731 |   |
| General and administrative                                                                                   |       | 87,319                                                                           |       | 62,056 |   | 54,068 |   |
| Exploration                                                                                                  |       | 26,473                                                                           |       | 21,739 |   | 6,899 |   |
| Dry hole and impairment                                                                                      |       | 87,170                                                                           |       | 61,634 |   | 30,673 |   |
| Depreciation, depletion and amortization                                                                     |       | 312,247                                                                          |       | 251,876 |   | 229,881 |   |
| Production and other taxes                                                                                   |       | 59,527                                                                           |       | 44,104 |   | 23,735 |   |
| Transportation and other                                                                                     |       | (9,079                                                                           | )          | 8,355 |   | 23,892 |   |
| Total                                                                                                        |       | 717,316                                                                          |       | 550,270 |   | 450,879 |   |
| **Operating  Income**                                                                                        |       | 508,383                                                                          |       | 426,285 |   | 407,626 |   |
| **Interest:**                                                                                                |       |                                                                             |       |   |   |   |   |
| Charges                                                                                                      |       | (68,654                                                                          | )          | (29,333 | ) | (46,360 | ) |
| Income                                                                                                       |       | 8,291                                                                            |       | 522 |   | 673 |   |
| Capitalized                                                                                                  |       | 23,480                                                                           |       | 14,216 |   | 16,531 |   |
| **Commodity  Derivative Expense**                                                                            |       | (13,618                                                                          | )          | — |   | — |   |
| **Loss on  debt extinguishment**                                                                             |       | —                                                                           |       | (13,759 | ) | (5,893 | ) |
| **Foreign  Currency Transaction Gain (Loss)**                                                                |       | 71                                                                               |       | (30 | ) | 29 |   |
| **Income  From Continuing Operations Before Taxes and Cumulative Effect of Change in  Accounting Principle** |       | 457,953                                                                          |       | 397,901 |   | 372,606 |   |
| **Income  Tax Expense**                                                                                      |       | (167,884                                                                         | )          | (148,866 | ) | (137,371 | ) |
| **Income  From Continuing Operations Before Cumulative Effect of Change in Accounting  Principle**           |       | 290,069                                                                          |       | 249,035 |   | 235,235 |   |
| **Income  from Discontinued Operations, net of tax**                                                         |       | 460,634                                                                          |       | 12,719 |   | 59,872 |   |
| **Cumulative  Effect of Change in Accounting Principle**                                                     |       | —                                                                           |       | — |   | (4,166 | ) |
| **Net  Income**                                                                                              |       | $                                                                                | 750,703    |   | $ | 261,754 |   | $ | 290,941 |   |
| **Earnings  (Loss) per Common Share:**                                                                       |       |                                                                             |       |   |   |   |   |
| Basic                                                                                                        |       |                                                                             |       |   |   |   |   |
| Income from continuing operations before cumulative  effect of change in accounting principle                |       | $                                                                                | 4.80       |   | $ | 3.90 |   | $ | 3.76 |   |
| Income from discontinued operations                                                                          |       | 7.63                                                                             |       | 0.20 |   | 0.96 |   |
| Cumulative effect of change in accounting principle                                                          |       | —                                                                           |       | — |   | (0.07 | ) |
| Net income                                                                                                   |       | $                                                                                | 12.43      |   | $ | 4.10 |   | $ | 4.65 |   |
| Diluted                                                                                                      |       |                                                                             |       |   |   |   |   |
| Income from continuing operations before cumulative  effect of change in accounting principle                |       | $                                                                                | 4.76       |   | $ | 3.87 |   | $ | 3.67 |   |
| Income from discontinued operations                                                                          |       | 7.56                                                                             |       | 0.19 |   | 0.93 |   |
| Cumulative effect of change in accounting principle                                                          |       | —                                                                           |       | — |   | (0.06 | ) |
| Net income                                                                                                   |       | $                                                                                | 12.32      |   | $ | 4.06 |   | $ | 4.54 |   |
| **Dividends per Common Share**                                                                               |       | $                                                                                | 0.25       |   | $ | 0.2125 |   | $ | 0.20 |   |

 

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

56

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**POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED BALANCE SHEETS**

| ** **                                                  | ** ** | **December 31,**                  | ** ** |
|-------------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                                  | ** ** | **2005**                               | ** ** | **2004** | ** ** |
| ** **                                                  | ** ** | **(Expressed in thousands)** | ** ** |
| **ASSETS**                                                  |       |                                   |       |   |   |
| **Current  Assets:**                                        |       |                                   |       |   |   |
| Cash and cash equivalents                                   |       | $                                      | 57,749     |   | $ | 86,456 |   |
| Accounts receivable                                         |       | 198,792                                |       | 120,466 |   |
| Other receivables                                           |       | 19,957                                 |       | 20,875 |   |
| Federal income taxes receivable                             |       | 21,661                                 |       | 10,708 |   |
| Deferred income tax                                         |       | 12,165                                 |       | — |   |
| Inventories—product                                    |       | 13,220                                 |       | — |   |
| Inventories—tubulars                                   |       | 19,057                                 |       | 9,112 |   |
| Price hedge contracts                                       |       | —                                 |       | 6,722 |   |
| Other                                                       |       | 4,220                                  |       | 3,987 |   |
| Assets of discontinued operations                           |       | —                                 |       | 187,084 |   |
| Total current assets                                        |       | 346,821                                |       | 445,410 |   |
| **Property  and Equipment:**                                |       |                                   |       |   |   |
| Oil and gas, on  the basis of successful efforts accounting |       |                                   |       |   |   |
| Proved properties                                           |       | 6,254,516                              |       | 4,003,332 |   |
| Unproved properties                                         |       | 872,164                                |       | 76,890 |   |
| Other, at cost                                              |       | 40,531                                 |       | 28,656 |   |
|                                                        |       | 7,167,211                              |       | 4,108,878 |   |
| Accumulated  depreciation, depletion, and amortization      |       |                                   |       |   |   |
| Oil and gas                                                 |       | (1,858,275                             | )          | (1,551,502 | ) |
| Other                                                       |       | (24,551                                | )          | (19,194 | ) |
|                                                        |       | (1,882,826                             | )          | (1,570,696 | ) |
| Property and equipment, net                                 |       | 5,284,385                              |       | 2,538,182 |   |
| **Other  Assets:**                                          |       |                                   |       |   |   |
| Other                                                       |       | 44,542                                 |       | 17,420 |   |
| Assets of discontinued operations                           |       | —                                 |       | 480,097 |   |
|                                                        |       | 44,542                                 |       | 497,517 |   |
|                                                        |       | $                                      | 5,675,748  |   | $ | 3,481,109 |   |

 

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,**                  | ** ** |
|-----------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------|------------|
| ** **                                                                                                            | ** ** | **2005**                               | ** ** | **2004** | ** ** |
| ** **                                                                                                            | ** ** | **(Expressed in thousands)** | ** ** |
| **LIABILITIES  AND SHAREHOLDERS’ EQUITY**                                                                        |       |                                   |       |   |   |
| **Current  Liabilities:**                                                                                             |       |                                   |       |   |   |
| Accounts payable—operating activities                                                                            |       | $                                      | 167,323    |   | $ | 62,156 |   |
| Accounts payable—investing activities                                                                            |       | 137,137                                |       | 86,582 |   |
| Income taxes payable                                                                                                  |       | 2,034                                  |       | 131 |   |
| Accrued interest payable                                                                                              |       | 20,225                                 |       | 4,550 |   |
| Accrued payroll and related benefits                                                                                  |       | 3,717                                  |       | 3,566 |   |
| Price hedge contracts                                                                                                 |       | 52,245                                 |       | — |   |
| Deferred income tax                                                                                                   |       | —                                 |       | 4,919 |   |
| Other                                                                                                                 |       | 12,480                                 |       | 8,187 |   |
| Liabilities of discontinued operations                                                                                |       | —                                 |       | 109,928 |   |
| Total current liabilities                                                                                             |       | 395,161                                |       | 280,019 |   |
| **Long-Term Debt**                                                                                                    |       | 1,643,452                              |       | 755,000 |   |
| **Deferred Income Tax**                                                                                               |       | 1,316,895                              |       | 536,823 |   |
| **Asset Retirement Obligation**                                                                                       |       | 149,374                                |       | 74,046 |   |
| **Other Liabilities and Deferred Credits**                                                                            |       | 72,284                                 |       | 21,367 |   |
| **Liabilities of Discontinued Operations**                                                                            |       | —                                 |       | 85,959 |   |
| Total liabilities                                                                                                     |       | 3,577,166                              |       | 1,753,214 |   |
| **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 65,275,106  and 64,580,639 shares issued, respectively |       | 65,275                                 |       | 64,581 |   |
| Additional capital                                                                                                    |       | 977,885                                |       | 943,690 |   |
| Retained earnings                                                                                                     |       | 1,464,214                              |       | 728,723 |   |
| Accumulated other comprehensive income (loss)                                                                         |       | (30,019                                | )          | 2,565 |   |
| Deferred compensation                                                                                                 |       | (17,522                                | )          | (9,954 | ) |
| Treasury stock (7,365,359 and 55,359 shares,  respectively), at cost                                                  |       | (361,251                               | )          | (1,710 | ) |
| Total shareholders’ equity                                                                                       |       | 2,098,582                              |       | 1,727,895 |   |
|                                                                                                                  |       | $                                      | 5,675,748  |   | $ | 3,481,109 |   |

 

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

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**POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS**

| ** **                                                                           | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                           | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                           | ** ** | **(Expressed in thousands)**     | ** ** |
| **Cash flows from operating  activities:**                                           |       |                                       |       |   |   |   |   |
| Cash received from customers                                                         |       | $                                          | 1,238,472  |   | $ | 978,541 |   | $ | 876,016 |   |
| Operating, exploration and general and administrative  expenses paid            |       | (332,041                                   | )          | (243,276 | ) | (178,653 | ) |
| Income taxes paid                                                                    |       | (197,833                                   | )          | (159,559 | ) | (121,923 | ) |
| Income taxes received                                                                |       | 166                                        |       | 381 |   | — |   |
| Interest paid                                                                        |       | (51,322                                    | )          | (30,043 | ) | (45,527 | ) |
| Cash paid related to price hedge contracts                                           |       | (11,354                                    | )          | — |   | (15,037 | ) |
| Business interruption insurance proceeds                                             |       | 47,077                                     |       | — |   | — |   |
| Other                                                                                |       | 7,636                                      |       | (1,752 | ) | 7,773 |   |
| Net cash provided by continuing operating activities                                 |       | 700,801                                    |       | 544,292 |   | 522,649 |   |
| Net cash provided by discontinued operating  activities                              |       | 144,736                                    |       | 194,423 |   | 221,910 |   |
| Net cash provided by operating activities                                            |       | 845,537                                    |       | 738,715 |   | 744,559 |   |
| **Cash flows from investing  activities:**                                           |       |                                       |       |   |   |   |   |
| Capital expenditures                                                                 |       | (374,960                                   | )          | (285,885 | ) | (191,379 | ) |
| Purchase of properties                                                               |       | (131,838                                   | )          | (189,597 | ) | (189,083 | ) |
| Acquisition of corporations, net of $32,870 and  $11,970 cash acquired, respectively |       | (1,704,590                                 | )          | (270,452 | ) | — |   |
| Proceeds from the sale of corporations, net of  $51,529 cash on hand                 |       | 763,618                                    |       |   |   |   |   |
| Purchase of current investments                                                      |       | (16,750                                    | )          | (15,000 | ) | — |   |
| Sale of current investments                                                          |       | 122,250                                    |       | 15,000 |   | — |   |
| Other                                                                                |       | 9,831                                      |       | 1,522 |   | 521 |   |
| Net cash used in continuing investing activities                                     |       | (1,332,439                                 | )          | (744,412 | ) | (379,941 | ) |
| Net cash used in discontinued investing activities                                   |       | (57,816                                    | )          | (217,314 | ) | (186,516 | ) |
| Net cash used in investing activities                                                |       | (1,390,255                                 | )          | (961,726 | ) | (566,457 | ) |
| **Cash flows from financing  activities:**                                           |       |                                       |       |   |   |   |   |
| Borrowings under senior debt agreements                                              |       | 3,865,000                                  |       | 2,010,000 |   | 854,012 |   |
| Payments under senior debt agreements                                                |       | (3,774,000                                 | )          | (1,594,000 | ) | (875,000 | ) |
| Proceeds from issuance of new financing                                              |       | 797,303                                    |       | — |   | — |   |
| Purchase of Company stock                                                            |       | (351,813                                   | )          | — |   | — |   |
| Payments (to) from discontinued operations                                           |       | 138,287                                    |       | (24,955 | ) | 32,464 |   |
| Redemption of debt                                                                   |       | —                                     |       | (157,782 | ) | (176,578 | ) |
| Proceeds from exercise of stock options                                              |       | 11,169                                     |       | 12,013 |   | 33,370 |   |
| Payment of cash dividends on common stock                                            |       | (15,212                                    | )          | (13,607 | ) | (12,520 | ) |
| Payment of senior debt acquired through corporate  purchase                          |       | —                                     |       | (50,000 | ) | — |   |
| Payment of financing issue costs and other                                           |       | (14,806                                    | )          | (3,820 | ) | (100 | ) |
| Net cash (used in) provided by continuing financing  activities                      |       | 655,928                                    |       | 177,849 |   | (144,352 | ) |
| Net cash (used in) provided by discontinued financing  activities                    |       | (139,630                                   | )          | 24,955 |   | (32,464 | ) |
| Net cash (used in) provided by financing activities                                  |       | 516,298                                    |       | 202,804 |   | (176,816 | ) |
| Effect of exchange rate changes on cash from  discontinued operations                |       | (287                                       | )          | 2,189 |   | 739 |   |
| Net increase in cash and cash equivalents                                            |       | (28,707                                    | )          | (18,018 | ) | 2,025 |   |
| Cash and cash equivalents from continuing operations,  beginning of the year         |       | 33,488                                     |       | 55,759 |   | 57,403 |   |
| Cash and cash equivalents from discontinued  operations, beginning of the year       |       | 52,968                                     |       | 48,715 |   | 45,046 |   |
| Cash and cash  equivalents at the end of the year                                    |       | $                                          | 57,749     |   | $ | 86,456 |   | $ | 104,474 |   |

 

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

59

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**POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)**

 

| ** **                                                                        | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                        | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                        | ** ** | **(Expressed in thousands)**     | ** ** |
| **Reconciliation of net income to  net cash provided by operating activities:**   |       |                                       |       |   |   |   |   |
| Net income                                                                        |       | $                                          | 750,703    |   | $ | 261,754 |   | $ | 290,941 |   |
| Adjustments  to reconcile net income to net cash provided by operating activities |       |                                       |       |   |   |   |   |
| Income from discontinued operations, net of tax                                   |       | (460,634                                   | )          | (12,719 | ) | (59,872 | ) |
| Cumulative effect of change in accounting principle                               |       | —                                     |       | — |   | 4,166 |   |
| (Gains) losses on sales                                                           |       | (72                                        | )          | 275 |   | (386 | ) |
| Depreciation, depletion and amortization                                          |       | 312,247                                    |       | 251,876 |   | 229,881 |   |
| Dry hole and impairment                                                           |       | 87,170                                     |       | 61,634 |   | 30,673 |   |
| Interest capitalized                                                              |       | (23,480                                    | )          | (14,216 | ) | (16,531 | ) |
| Price hedge contracts                                                             |       | 1,314                                      |       | (657 | ) | 8,346 |   |
| Other                                                                             |       | 15,433                                     |       | 23,375 |   | 14,732 |   |
| Deferred income taxes                                                             |       | 9,110                                      |       | 3,070 |   | 26,800 |   |
| Change  in assets and liabilities:                                                |       |                                       |       |   |   |   |   |
| Increase in accounts receivable                                                   |       | (9,949                                     | )          | (26,716 | ) | (16,091 | ) |
| Increase in federal income taxes receivable                                       |       | (43,199                                    | )          | (12,735 | ) | (4,743 | ) |
| Increase in inventory—product                                                |       | (12,101                                    | )          | — |   | — |   |
| Decrease in other assets                                                          |       | 2,314                                      |       | 3,505 |   | 4,568 |   |
| Increase in accounts payable                                                      |       | 54,337                                     |       | 12,683 |   | 13,467 |   |
| Increase (decrease) in income taxes payable                                       |       | 1,900                                      |       | (652 | ) | (6,607 | ) |
| Increase (decrease) in accrued interest payable                                   |       | 15,675                                     |       | (5,400 | ) | (1,146 | ) |
| Increase in accrued payroll and related benefits                                  |       | 151                                        |       | 333 |   | 226 |   |
| Increase (decrease) in other current liabilities                                  |       | (2,661                                     | )          | (3,713 | ) | 982 |   |
| Increase in deferred credits                                                      |       | 2,543                                      |       | 2,595 |   | 3,243 |   |
| Net cash provided by continuing operating activities                              |       | 700,801                                    |       | 544,292 |   | 522,649 |   |
| Net cash provided by discontinued operating  activities                           |       | 144,736                                    |       | 194,423 |   | 221,910 |   |
| Net cash provided  by operating activities                                        |       | $                                          | 845,537    |   | $ | 738,715 |   | $ | 744,559 |   |

 

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

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**POGOPRODUCING COMPANY & SUBSIDIARIESCONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY(Expressed in thousands)**

| ** **                                                        | ** ** | ** **   | ** ** | ** **     | ** ** | ** **   | ** ** | **Accumulated** | ** ** | ** **     | ** ** | ** **   | ** ** | ** **        | ** ** | ** **  | ** ** |
|-------------------------------------------------------------------|------------|--------------|------------|----------------|------------|--------------|------------|-----------------|------------|----------------|------------|--------------|------------|-------------------|------------|-------------|------------|
| ** **                                                        | ** ** | ** **   | ** ** | ** **     | ** ** | ** **   | ** ** | **Other**       | ** ** | **Deferred**   | ** ** | ** **   | ** ** | ** **        | ** ** | ** **  | ** ** |
| ** **                                                        | ** ** | ** **   | ** ** | ** **     | ** ** | ** **   | ** ** | **Compre-**     | ** ** | **Compen-**    | ** ** | ** **   | ** ** | ** **        | ** ** | **Compre-** | ** ** |
| ** **                                                        | ** ** | ** **   | ** ** | ** **     | ** ** | ** **   | ** ** | **hensive**     | ** ** | **sation**     | ** ** | ** **   | ** ** | **Share-**        | ** ** | **hensive** | ** ** |
| ** **                                                        | ** ** | **Common**   | ** ** | **Additional** | ** ** | **Retained** | ** ** | **Income**      | ** ** | **Restricted** | ** ** | **Treasury** | ** ** | **holders’** | ** ** | **Income**  | ** ** |
| ** **                                                        | ** ** | **Stock(a)** | ** ** | **Capital**    | ** ** | **earnings** | ** ** | **(Loss)**      | ** ** | **Stock**      | ** ** | **Stock**    | ** ** | **Equity**        | ** ** | **(Loss)**  | ** ** |
| **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 |   |   |   |   |   |
| Reclassification  adjustment included in net income               |       |         | —     |           |       |         | —     |            |       | —         |       |         | —     |              |       |        | —     |   |   | — |   | — |   |   |   |   |   |
| 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 |   |   |   |   |   |
| Net income                                                        |       |         | —     |           |       |         | —     |            |       | 750,703        |       |         | —     |              |       |        | —     |   |   | — |   | 750,703 |   |   | $ | 750,703 |   |   |
| Stock option  activity and other                             |       |         | 363        |           |       |         | 15,928     |            |       | —         |       |         | —     |              |       |        | —     |   |   | — |   | 16,291 |   |   |   |   |   |
| Shares issued as  compensation                                    |       |         | 331        |           |       |         | 18,267     |            |       | —         |       |         | —     |              |       |        | —     |   |   | — |   | 18,598 |   |   |   |   |   |
| Issuance of  restricted stock, less amortization of $4,585        |       |         | —     |           |       |         | —     |            |       | —         |       |         | —     |              |       |        | (7,568     | ) |   | — |   | (7,568 | ) |   |   |   |   |
| Dividends ($0.25  per common share)                               |       |         | —     |           |       |         | —     |            |       | (15,212        | )          |         | —     |              |       |        | —     |   |   | — |   | (15,212 | ) |   |   |   |   |
| Share repurchase                                                  |       |         | —     |           |       |         | —     |            |       | —         |       |         | —     |              |       |        | —     |   |   | (359,541 | ) | (359,541 | ) |   |   |   |   |
| Unrealized loss  arising during the year on price hedge contracts |       |         | —     |           |       |         | —     |            |       | —         |       |         | (72,189    | )                 |       |        | —     |   |   | — |   | (72,189 | ) |   |   |   |   |
| Reclassification  adjustment included in net income               |       |         | —     |           |       |         | —     |            |       | —         |       |         | 16,672     |              |       |        | —     |   |   | — |   | 16,672 |   |   |   |   |   |
| Net unrealized  gains on price hedge contracts                    |       |         | —     |           |       |         | —     |            |       | —         |       |         | —     |              |       |        | —     |   |   | — |   | — |   |   | (55,517 | ) |   |
| Foreign currency  translation adjustment                          |       |         | —     |           |       |         | —     |            |       | —         |       |         | 22,933     |              |       |        | —     |   |   | — |   | 22,933 |   |   | 22,933 |   |   |
| Comprehensive  income                                             |       |         | —     |           |       |         | —     |            |       | —         |       |         | —     |              |       |        | —     |   |   | — |   | — |   |   | $ | 718,119 |   |   |
| **Balance  at December 31, 2005**                       |       |         | 65,275     |           |       |         | $          | 977,885         |       |           | $          | 1,464,214    |       |              | $          | (30,019     | )          |   |   | $ | (17,522 | ) |   | $ | (361,251 | ) | $ | 2,098,582 |   |   |   |   |   |

----

(a)           Reflects both dollarand share amounts at $1.00 par value.

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

61

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

**(1) Summaryof Significant Accounting Policies**

*Nature ofOperations—*

Pogo Producing Company was incorporated in 1970. PogoProducing Company and its subsidiaries (the “Company”) are engaged in oil andgas exploration, development, production and acquisition activities in NorthAmerica, both onshore principally in Canada and the states of New Mexico,Texas, Louisiana, Wyoming and Indiana, and offshore in the Gulf of Mexico(primarily in federal waters offshore Louisiana and Texas). The Company alsoconducts exploration activities in offshore New Zealand.

The Company’s results forall periods presented reflect its oil and gas exploration, development andproduction activities in the Kingdom of Thailand and Hungary as discontinuedoperations. Except where noted, the discussions in the following notes relateto the Company’s continuing activities only.

*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, the impairment of oil and gasproperties, and the Company’s allocation of purchase price to acquiredproperties are all determined using estimates of oil and gas reserves. Thereare numerous uncertainties in estimating the quantity of reserves and inprojecting the future rates of production and timing of developmentexpenditures. Oil and gas reserve engineering must be recognized as asubjective process of estimating underground accumulations of oil and gas thatcannot be measured in an exact way. Proved reserves of crude oil, condensate, natural gas and naturalgas liquids are estimated quantities that geological and engineering datademonstrate with reasonable certainty to be recoverable in the future fromknown reservoirs under existing economic and operating conditions. Reservoirsare considered proved if economic producibility is supported by either actualproduction or conclusive formation test. Proved reserves do not include, forexample, hydrocarbons that may be recovered from undrilled prospects or therecovery of which is otherwise subject to reasonable doubt because ofuncertainty as to geology, reservoir characteristics or economic factors.Proved developed reserves are reserves that can be expected to be recoveredthrough existing wells with existing equipment and operating methods or throughthe application of fluid injection or other improved recovery techniquesconfirmed by a pilot project or operation of an installed program. Provedundeveloped oil and gas reserves are reserves that are expected to be recoveredfrom new wells on undrilled acreage, or from existing wells where a relativelymajor expenditure is required for recompletion. Proved undeveloped reserves onundrilled acreage are limited to those drilling units offsetting productiveunits that are reasonably certain of production when drilled and otherundrilled units where it can be demonstrated with certainty that there iscontinuity of production from the existing productive formation. The Securities and Exchange Commissionprovides 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 subsidiaries,after elimination of all significant intercompany transactions. Majority ownedsubsidiaries are fully consolidated. The Company’s operating and working interestsin oil and gas joint ventures are pro rata consolidated.

62

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

*Revenue Recognition—*

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. The Company’s crude oil and natural gas imbalances arenot significant. Such imbalances are reflected as adjustments to provedreserves and future cash flows in the unaudited supplementary oil and gas dataincluded herein.

*Inventory—Product—*

The Company maintainsnatural gas and crude oil and condensate inventories in storage facilities andpipelines in Canada. These inventories are stated at the lower of average costor market value. The product inventory at December 31, 2005 consisted ofapproximately 1,892,276 Mcf of natural gas valued at its estimated average costof $8.25 per Mcf and 77,462 barrels of crude oil and condensate at itsestimated average cost of $22.63 per barrel. Natural gas inventory used as storage facilitycushion gas to maintain operation pressures is carried as a long-term asset.

*Inventories—Tubulars—*

Tubular inventoriesconsist primarily of tubular pipe and general equipment used in the Company’soperations and are stated at the lower of average cost or market value.

*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. Estimated fair value includes the estimated present value of all reasonablyexpected future production, prices, and costs. Unproved properties are reviewedquarterly to determine if there has been impairment of the carrying value, withany such impairment charged to expense in the period. The evaluation ofunproved properties requires management’s judgment to estimate the fair valueof leasehold and exploratory costs related to drilling activity in a given area.Drilling activities in an area by other companies may also effectively condemnunproved properties. Exploratory well costs are capitalized until the resultsare determined. If proved reserves are not discovered, the exploratory wellcosts are expensed. The following table reflects the net changes in capitalizedexploratory well costs pending proved reserve determination during 2005, 2004and 2003 (amounts expressed in thousands):

| ** **                                                                                    | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Balance at  January 1,                                                                   |       | $        | 11,806     |     | $          | 976      |       | $ | 11,080 |   |
| Additions to capitalized  exploratory well costs pending the determination of proved reserves |       | 7,098    |       | 10,830   |       | 39       |       |
| Reclassifications to  proved oil and gas properties                                           |       | (6,748   | )          | —   |       | (10,143  | )          |
| Capitalized exploratory  well costs charged to expense                                        |       | (5,057   | )          | —   |       | —   |       |
| Balance at December 31,                                                                  |       | $        | 7,099      |     | $          | 11,806   |       | $ | 976 |   |

 

As of December 31, 2005, the Company has noexploratory well costs that have been capitalized for a period greater than oneyear since the completion of drilling.

63

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

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. Generally, the Company establishescost centers on the basis of an oil or gas trend or play for its onshore oiland gas activities. The Company generally creates cost centers on afield-by-field basis for oil and gas activities in the Gulf of Mexico. Asdescribed further below, the Company’s method of accounting for assetretirement 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) losses on sales” in the Consolidated Statements ofCash 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 used by the Company,the historical volatility of oil and gas commodity prices and the recentproduction disruptions resulting from hurricanes, the Company expects that SFAS133 could increase volatility in the Company’s earnings and other comprehensiveincome for future periods during which derivative instruments are outstanding.

64

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

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. To the extent the forecasted transaction in a designated andqualifying hedge relationship is no longer probable of occurring, gains andlosses previously deferred in other comprehensive income are immediatelyreclassified to earnings under the caption “Commodity derivative expense.’’  For those derivative instruments that do notqualify as a cash flow hedge instrument, the Company recognizes all futurechanges in the fair value of these instruments in the consolidated statement ofincome for the period in which the change occurs under the caption “Commodityderivative expense.’’

*InsuranceRecoveries—*

The Company recognizesestimated proceeds from insurance recoveries only when the amount of therecovery is determinable and when the Company believes that the proceeds areprobable of recovery. When the amount of the estimated recoveries has beendetermined and when the Company has concluded that the recovery is probable,the recoveries are recognized in the results of operations. Businessinterruption proceeds are recorded as a reduction of “Transportation and otherexpense” and property damage recoveries are recorded as a reduction of “Leaseoperating expense”. During the years ended December 31, 2005 and 2004 theCompany recognized $40,743,000 and $11,133,000, respectively of businessinterruption insurance recoveries related to deferred production resulting fromHurricanes Ivan, Katrina and Rita.

*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 December 31,2005, the Company had completed the purchase of 7,310,000 shares at a totalcost of $359.5 million.

*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. Awards to employees of the Company may be made as grants of stockoptions, stock appreciation rights, stock awards, cash awards, performanceawards or any combination thereof (collectively, “Stock Awards”). Effective January 1,2003, the Company adopted the fair value recognition provisions of SFAS No. 123,“Accounting for Stock Based Compensation” (“SFAS 123”), and the prospectivemethod transition provisions of SFAS No. 148, “Accounting for Stock BasedCompensation—Transition and Disclosure—an amendment of FAS No. 123”  (“SFAS 148”), for all Stock Awards granted,modified or settled after January 1, 2003. On January 1, 2006, theCompany will adopt the provisions of SFAS No. 123 (revised 2004) (“SFAS123R”), “Share-Based Payment”, which replaces the provisions of SFAS 123. Theadoption of SFAS 123R is not expected to have a material effect on the Company’sfinancial statements.

Compensation cost for restricted stock, stock optionsand other stock-based compensation is recognized on a straight-line basis overthe vesting period for the applicable Stock Award. The Company granted StockAwards covering 351,800 shares of common stock with a  fair market value of $19,528,000 

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

duringthe year ended December 31, 2005. The Company granted Stock Awardscovering 333,400 shares of common stock with a fair market value of $13,491,000during the year ended December 31, 2004.

Thefollowing table illustrates the effect on the Company’s net income and earningsper share (including the results of discontinued operations) if the fair valuerecognition provisions of SFAS 123 for employee stock-based compensation hadbeen applied to all Stock Awards outstanding during the years ended December 31,2005, 2004 and 2003 (in thousands of dollars, except per share amounts):

| ** **                                                                                                                               | ** ** | **Year Ended December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                                               | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Net income, as reported                                                                                                                  |       | $                                          | 750,703    |   | $ | 261,754 |   | $ | 290,941 |   |
| Add: Employee  stock-based compensation expense, net of related tax effects, included in net income, as reported               |       | 5,389                                      |       | 3,006 |   | 1,408 |   |
| Deduct: Total employee  stock-based compensation expense, determined under fair value method for all  awards, net of related tax effects |       | (6,802                                     | )          | (6,759 | ) | (7,017 | ) |
| Net income, pro forma                                                                                                                    |       | $                                          | 749,290    |   | $ | 258,001 |   | $ | 285,332 |   |
| Earnings per share:                                                                                                                      |       |                                       |       |   |   |   |   |
| Basic—as reported                                                                                                                   |       | $                                          | 12.43      |   | $ | 4.10 |   | $ | 4.65 |   |
| Basic—pro forma                                                                                                                     |       | $                                          | 12.41      |   | $ | 4.04 |   | $ | 4.56 |   |
| Diluted—as reported                                                                                                                 |       | $                                          | 12.32      |   | $ | 4.06 |   | $ | 4.54 |   |
| Diluted—pro forma                                                                                                                   |       | $                                          | 12.30      |   | $ | 4.01 |   | $ | 4.45 |   |

 

The fair value ofrestricted stock grants was estimated based on the average of the high and lowshare price on the date of grant. The fair value of  stock option grants was estimated on the dateof grant using the Black-Scholes option pricing model with the followingweighted-average assumptions used in 2004 and 2003, respectively: risk freeinterest rates of 3.00% and 2.30%, expected volatility of 25.7% and 28.4%,dividend yields of 0.48% and 0.61%, and an expected life of the options ofthree and a half and three years.  Nostock options were granted in 2005.

*ConsolidatedStatements 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 notdisclosed in the Consolidated Statements of Cash Flows. Significant non-cashtransactions are disclosed in the Consolidated Statements of Shareholders’Equity relating to shares issued as compensation and in Note 14 relatingto asset retirement costs.

*Foreign Currency—*

The Canadian dollar is the functional currency for theCompany’s Canadian operations. Accordingly, foreign exchange translationadjustments resulting from translating the Northrock financial statements fromCanadian dollars to U.S. dollars are included as a separate component of othercomprehensive income in shareholders’ equity on the consolidated balance sheet.Gains or losses incurred on currency transactions in other than Canadiandollars are included in the consolidated statements of income for the period inwhich the transactions occur.

The U.S. dollar is thefunctional currency for all areas of operations of the Company other thanCanada. Accordingly, monetary assets and liabilities and items of income andexpense denominated in a foreign currency are remeasured to U.S. dollars at therate of exchange in effect at the end of each month 

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

or theaverage for the month, and the resulting gains or losses on foreign currencytransactions are included in the consolidated statements of income for theperiod.

*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.

**(2) Earnings per Share**

Earningsper common share (basic earnings per share) are based on the weighted averagenumber of shares of common stock outstanding during the periods indicated.Earnings per common share and potential common share (diluted earnings pershare) consider the effect of dilutive securities as set out below inthousands, except per share amounts.

| ** **                                                                                                                                                                                                         | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| **Income (numerator):**                                                                                                                                                                                            |       |     |       |     |       |     |       |
| Income from continuing  operations                                                                                                                                                                                 |       | $        | 290,069    |     | $          | 249,035  |       | $ | 235,235 |   |
| Income from discontinued  operations, net of tax                                                                                                                                                                   |       | 460,634  |       | 12,719   |       | 59,872   |       |
| Income before cumulative  effect of change in accounting principle                                                                                                                                            |       | 750,703  |       | 261,754  |       | 295,107  |       |
| Cumulative effect of  change in accounting principle                                                                                                                                                               |       | —   |       | —   |       | (4,166   | )          |
| Net income—basic                                                                                                                                                                                              |       | 750,703  |       | 261,754  |       | 290,941  |       |
| Interest expense  incurred, net of taxes, and shares issued related to the assumed conversion  at $42.185 per share of the 2006 Notes                                                                              |       | —   |       | —   |       | 2,106    |       |
| Net income—diluted                                                                                                                                                                                            |       | $        | 750,703    |     | $          | 261,754  |       | $ | 293,047 |   |
| **Weighted average shares  (denominator):**                                                                                                                                                                        |       |     |       |     |       |     |       |
| Weighted average  shares—basic                                                                                                                                                                                |       | 60,372   |       | 63,848   |       | 62,538   |       |
| Shares assumed issued  from the exercise of options to purchase common shares and restriced stock,  net of treasury shares assumed purchased from the proceeds, at the average  market price for the period        |       | 552      |       | 545      |       | 683      |       |
| Dilution effect of 2006  Notes                                                                                                                                                                                     |       | —   |       | —   |       | 1,391    |       |
| Weighted average  shares—diluted                                                                                                                                                                              |       | 60,924   |       | 64,393   |       | 64,612   |       |
| **Earnings per share:**                                                                                                                                                                                            |       |     |       |     |       |     |       |
| Basic:                                                                                                                                                                                                             |       |     |       |     |       |     |       |
| Income from continuing  operations                                                                                                                                                                                 |       | $        | 4.80       |     | $          | 3.90     |       | $ | 3.76 |   |
| Income from discontinued  operations                                                                                                                                                                               |       | 7.63     |       | 0.20     |       | 0.96     |       |
| Cumulative effect of  change in accounting principle                                                                                                                                                               |       | —   |       | —   |       | (0.07    | )          |
| Basic earnings per share                                                                                                                                                                                           |       | $        | 12.43      |     | $          | 4.10     |       | $ | 4.65 |   |
| Diluted:                                                                                                                                                                                                           |       |     |       |     |       |     |       |
| Income from continuing  operations                                                                                                                                                                                 |       | $        | 4.76       |     | $          | 3.87     |       | $ | 3.67 |   |
| Income from discontinued  operations                                                                                                                                                                               |       | 7.56     |       | 0.19     |       | 0.93     |       |
| Cumulative effect of  change in accounting principle                                                                                                                                                               |       | —   |       | —   |       | (0.06    | )          |
| Diluted earnings per  share                                                                                                                                                                                        |       | $        | 12.32      |     | $          | 4.06     |       | $ | 4.54 |   |
| **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       |       | 467      |       |
| Average price                                                                                                                                                                                                      |       | $        | —     |     | $          | 49.02    |       | $ | 41.87 |   |

 

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

**(3)**          IncomeTaxes

Thecomponents of income from continuing operations before income taxes andcumulative effect of change in accounting principle for each of the three yearsin the period ended December 31, 2005, are as follows (expressed inthousands):

| ** **                                                                                                      | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|-----------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| United States                                                                                                   |       | $        | 417,655    |     | $          | 403,845  |       | $ | 373,267 |   |
| Foreign                                                                                                         |       | 40,298   |       | (5,944   | )          | (661     | )          |
| Income from  continuing operations before income taxes and cumulative effect of change in  accounting principle |       | $        | 457,953    |     | $          | 397,901  |       | $ | 372,606 |   |

 

The componentsof income tax expense (benefit) for each of the three years in the period endedDecember 31, 2005, are as follows (expressed in thousands):

| ** **          | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|---------------------|------------|----------|------------|----------|------------|----------|------------|
| Current             |       |     |       |     |       |     |       |
| United States       |       | $        | 156,882    |     | $          | 145,730  |       | $ | 110,572 |   |
| Foreign             |       | 1,908    |       | 60       |       | 397      |       |
| Deferred            |       |     |       |     |       |     |       |
| United States       |       | (6,141   | )          | 3,076    |       | 26,402   |       |
| Foreign             |       | 15,235   |       | —   |       | —   |       |
| Income tax  expense |       | $        | 167,884    |     | $          | 148,866  |       | $ | 137,371 |   |

 

Totalincome tax expense for each of the three years in the period ended December 31,2005, differs from the amounts computed by applying the statutory federalincome tax rate to income before taxes as follows (expressed as percent ofpretax income):

| ** **                                  | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Federal statutory  income tax rate          |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| Increases  resulting from:                  |       |     |       |     |       |     |       |
| State income taxes, net of federal benefits |       | 1.6      |       | 1.5      |       | 1.0      |       |
| Other                                       |       | 0.1      |       | 0.9      |       | 0.9      |       |
|                                        |       | 36.7     | %          | 37.4     | %          | 36.9     | %          |

 

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

Theprincipal components of the Company’s deferred income tax assets andliabilities at December 31, 2005 and 2004 (expressed in thousands) are as follows:

| ** **                                                                     | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                     | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Deferred tax assets:                                                           |       |                  |       |   |   |
| Foreign deferred tax assets and net operating loss  carry forwards             |       | $                     | 6,347      |   | $ | 3,049 |   |
| Valuation allowance of deferred tax assets and foreign net operating loss |       | (6,347                | )          | (3,049 | ) |
| Tax basis in excess of book basis for price hedge  contracts                   |       | 35,203                |       | — |   |
| Tax basis in excess of book basis for deferred  compensation and benefit plans |       | 20,004                |       | 12,691 |   |
| Net operating loss carryforwards                                               |       | 2,386                 |       | — |   |
| Other                                                                          |       | 4,278                 |       | 3,561 |   |
|                                                                           |       | 61,871                |       | 16,252 |   |
| Deferred tax  liabilities:                                                     |       |                  |       |   |   |
| Book basis in excess of tax basis for oil and gas  properties and equipment    |       | (1,360,860            | )          | (548,799 | ) |
| Other                                                                          |       | (5,741                | )          | (9,195 | ) |
|                                                                           |       | (1,366,601            | )          | (557,994 | ) |
| Net deferred tax  liability                                                    |       | $                     | (1,304,730 | ) | $ | (541,742 | ) |

 

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 acquired corporations during 2004 and2005.

As of December 31, 2005, the Company had foreignnet operating loss (NOL) carryforwards of approximately $20 million thatmay be used in future years to offset foreign taxable income. The majority ofthese NOL carryforwards have no expiration date, however their utilization maybe subject to limitations due to enacted tax legislation within the applicableforeign jurisdiction and their realization is dependent upon generatingsufficient taxable income within the applicable foreign jurisdiction. The $6.3 millionvaluation allowance at December 31, 2005 was related to explorationexpenses the Company incurred in its foreign operations. During 2005, theCompany recorded an additional valuation allowance of $3.3 million, primarilyrelated to exploration expenses in New Zealand.

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 subsidiaries.Unremitted earnings of foreign subsidiaries for which U.S. income taxes havenot been provided are approximately $29,117,000 at December 31, 2005. Itis not practicable to determine the amount of U.S. income taxes that would bepayable upon remittance of the assets that represent those earnings.

On October 22, 2004,the President signed the American Jobs Creation Act of 2004 (the “Act”). TheAct provides a deduction for income from qualified domestic productionactivities, which will be phased in from 2005 through 2010. The Act alsocreated a temporary incentive for U.S. corporations to repatriate accumulatedincome earned abroad by providing an 85 percent dividends received deductionfor certain dividends from controlled foreign corporations. The Company adopteda Domestic Reinvestment Plan 

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

thatqualifies for the temporary incentive. Based on that decision, the Companyrepatriated  $497 million inextraordinary dividends, as defined in the Act, during the third quarter of2005. The Company also repatriated an additional $315 million that did notqualify for the temporary incentive. As a result of the repatriation of $812million, the Company recorded a U.S. tax expense of $24.1 million during 2005.

**(4)**          Long-TermDebt

Long-termdebt at December 31, 2005 and 2004, consists of the following (dollarsexpressed in thousands):

| ** **                                                                                                                      | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                      | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Senior debt—                                                                                                               |       |                  |       |   |   |
| Bank revolving  credit facility:                                                                                                |       |                  |       |   |   |
| LIBOR based loans, borrowings at December 31,  2005 and 2004 at  interest rates of 5.837% and 3.665%, respectively    |       | $                     | 606,000    |   | $ | 515,000 |   |
| LIBOR Rate Advances, borrowings at December 31,  2005 and 2004 at  interest rates of 5.618% and 3.5275%, respectively |       | 40,000                |       | 40,000 |   |
| Total senior debt                                                                                                               |       | 646,000               |       | 555,000 |   |
| Subordinated debt—                                                                                                         |       |                  |       |   |   |
| 8.25% Senior subordinated notes, due 2011                                                                                       |       | 200,000               |       | 200,000 |   |
| 6.625% Senior subordinated notes, due 2015                                                                                      |       | 300,000               |       |   |   |
| 6.875% Senior subordinated notes, due 2017                                                                                      |       | 500,000               |       | — |   |
| Total  subordinated debt                                                                                                        |       | 1,000,000             |       | 200,000 |   |
| Unamortized  discount on 2015 Notes                                                                                             |       | (2,548                | )          | — |   |
| Long-term debt                                                                                                                  |       | $                     | 1,643,452  |   | $ | 755,000 |   |

 

On December 16, 2004, the Company entered into anew credit agreement (the “Credit Facility”) , replacing its then existingcredit agreement dated as of March 8, 2001, as amended. The CreditFacility is with various financial institutions and provides for revolvingcredit borrowings up to a maximum principal amount of $1,000,000,000 at any onetime outstanding, with borrowings not to exceed a borrowing base determined atleast semiannually using the administrative agent’s usual and customarycriteria for oil and gas reserve valuation, adjusted for incurrences of otherindebtedness since the last redetermination of the borrowing base.  As of December 31, 2005, the borrowingbase was $1,500,000,000. The Credit Facility 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.  All outstanding amounts owed under the CreditFacility become due and payable no later than the final maturity date of December 16,2009, and are subject to acceleration upon the occurrence of events of default which the Company considersusual and customary for an agreement of this type, including failure to makepayments under the credit agreement, non-performance of covenants andobligations continuing beyond any applicable grace period, 

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

defaultin the payment of other indebtedness in excess in principal amount of$25,000,000 or a default accelerating or permitting the acceleration of anysuch indebtedness, or the occurrence of a “change in control” of the Company,including the acquisition of beneficial ownership of in excess of 50% of itscapital stock. If at any time the outstanding credit extended under theagreement exceeds the applicable borrowing base, the deficiency is required tobe amortized in four monthly installments commencing 90 days after thedeficiency arises, and until the deficiency is eliminated, increases in someapplicable interest rate margins apply.

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, in thecase 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 write downsafter 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 Facility) for the four most recent fiscal quarters to be less thanor equal to 2.5 to 1.0 at the end of any quarter.

On September 23, 2005, the Company issued$500,000,000 principal amount of 2017 Notes. The proceeds from the sale of the2017 Notes were used to fund a portion of the Northrock acquisition. The 2017Notes bear interest at a rate of 6.875%, payable semi-annually in arrears on April 1and October 1 of each year. The 2017 Notes are general unsecured seniorsubordinated obligations of the Company, and are subordinated in right ofpayment to the Company’s senior indebtedness, which includes the Company’sobligations under the bank revolving credit agreement and LIBOR rate advances. TheCompany, at its option, may redeem the 2017 Notes in whole or in part, at anytime on or after October 1, 2010, at a redemption price of 103.4375% oftheir principal amount and decreasing percentages thereafter. The Company mayalso redeem a portion of the 2017 Notes prior to October 1, 2008 and someor all of the Notes prior to October 1, 2010, in each case by payingspecified premiums. The indenture governing the 2017 Notes also imposes certaincovenants 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 restrictedsubsidiaries; dividends and other payment restrictions affecting restrictedsubsidiaries; and merger, consolidations and the sale of assets.

On March 29, 2005, the Company issued$300,000,000 principal amount of 2015 Notes at 99.101%. The proceeds from thesale of the 2015 Notes were used to pay down obligations under the Company’sbank credit facility. The 2015 Notes bear interest at a rate of 6.625%, payablesemi-annually in arrears on March 15 and September 15 of each year.The 2015 Notes are general unsecured senior subordinated 

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

obligations of theCompany, and are subordinated in right of payment to the Company’s seniorindebtedness, which includes the Company’s obligations under the bank revolvingcredit agreement and LIBOR rate advances. The Company, at its option, mayredeem the 2015 Notes in whole or in part, at any time on or after March 15,2010, at a redemption price of 103.3125% of their principal amount anddecreasing percentages thereafter. The Company may also redeem a portion of the2015 Notes prior to March 15, 2008 and some or all of the Notes prior to March 15,2010, in each case by paying specified premiums. The indenture governing the2015 Notes also imposes certain covenants on the Company including covenantslimiting: incurrence of indebtedness including senior indebtedness; restrictedpayments; the issuance and sales of restricted subsidiary capital stock;transactions with affiliates; liens; disposition of proceeds of asset sales;non-guarantor restricted subsidiaries; dividends and other payment restrictionsaffecting restricted subsidiaries; and merger, consolidations and the sale ofassets.

On April 10, 2001, the Company issued$200,000,000 principal amount of 2011 Notes. The 2011 Notes bear interest at arate of  8.25%, payable semi-annually inarrears on April 15 and October 15 of each year. The 2011 Notes aregeneral unsecured senior subordinated obligations of the Company, aresubordinated in right of payment to the Company’s senior indebtedness, whichcurrently includes the Company’s obligations under the Credit Facility. TheCompany, at its option, may redeem the 2011 Notes in whole or in part, at anytime on or after April 15, 2006, at a redemption price of 104.125% oftheir principal amount and decreasing percentages thereafter. The indenturegoverning the 2011 Notes also imposes certain covenants on the Companyincluding covenants limiting: incurrence of indebtedness including seniorindebtedness; restricted payments; the issuance and sales of restrictedsubsidiary capital stock; transactions with affiliates; liens; disposition ofproceeds of asset sales; non-guarantor restricted subsidiaries; dividends andother payment restrictions affecting restricted subsidiaries; and merger,consolidations and the sale of assets.

The Company gave notice onMarch 18, 2004 of its intent to redeem all $150,000,000 of its 10.375%Senior Subordinated Notes due 2009 (the “2009 Notes”) at 105.188% of their faceamount. On April 19, 2004, the Company paid $157,782,000 (excludingaccrued interest) in cash to holders of the 2009 Notes. The cash redemptionpayment was funded through borrowings under the Company’s existing bank creditfacility. The Company recorded a pre-tax expense on the redemption of the 2009Notes of $10,893,000 in “Loss on debt extinguishment” during the year ended December 31,2004.

**(5)**          Commitmentsand Contingencies

The Company hascommitments for operating leases (primarily for office space) in Houston,Calgary, Midland, Laredo, and for other equipment (including gas compressors). Rentalexpense for office space was $3,305,000 in 2005, $2,859,000 in 2004, and$2,739,000 in 2003. Rental expense for other equipment was $6,782,000 in 2005,$5,497,000 in 2004 and $4,241,000 in 2003.

Future minimum lease payments related to the Company’soperating leases at December 31, 2005 are approximately $16,729,000 in2006; $16,302,000 in 2007; $13,630,000 in 2008; $12,997,000 in 2009;$11,047,000 in 2010 and $70,952,000 thereafter. Where rented equipment such ascompressors is considered essential to the operation of the lease, the Companyhas assumed that such equipment will be leased for the estimated productivelife of the reserves, even if the contract terminates prior to such date.

The Company has in place aretention incentive plan that covers only those employees who were employed byNorthrock on September 27, 2005 (the date of acquisition).  If the covered employees are still employedby Northrock on September 27, 2006, they will receive an incentive planpayment. The Company estimates that the total liability related to theretention incentive plan will be approximately $14.6 million.

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

**(6)**          Salesto Major Customers

TheCompany is an oil and gas exploration and production company that generallysells its oil and gas to numerous customers on a month-to-month basis. Forpurposes of comparison, sales have been presented for all three years for thecustomer who has exceeded 10% of revenues in any given year (expressed inthousands):

| ** **             | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------|------------|----------|------------|----------|------------|----------|------------|
| Shell Trading  Company |       | $        | 117,456    |     | $          | 147,076  |       | $ | 161,451 |   |
|                        |            |          |            |          |            |          |            |  |  |  |

 

**(7)**          CreditRisk

Substantially all of theCompany’s accounts receivable at December 31, 2005 and 2004, result fromoil and gas sales and joint interest billings to other companies in the energyindustry. This concentration of customers and joint interest owners may impactthe Company’s overall credit risk, either positively or negatively, in thatthese entities may be similarly affected by industry-wide changes in economicor other conditions. Such receivables are generally not collateralized TheCompany provides reserves for specifically identified receivables fromcustomers and joint interest owners that, in the opinion of management, areconsidered doubtful. As of December 31, 2005 and 2004, the Company’sallowances for doubtful accounts were not material.

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

**(8)**          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: 

| ** **                                              | ** ** | **2005**                               | ** ** | **2004** | ** ** | **2003**  | ** ** |
|---------------------------------------------------------|------------|----------------------------------------|------------|----------|------------|-----------|------------|
| ** **                                              | ** ** | **(Expressed in thousands)** | ** ** |
| **Long-Lived Assets:**                                  |       |                                   |       |     |       |      |       |
| As of  December 31,                                |       |                                   |       |     |       |      |       |
| United States                                           |       | $                                      | 2,624,663  |     | $          | 2,538,182 |       | $ | 1,904,676 |   |
| Canada                                                  |       | 2,659,722                              |       | —   |       | —    |       |
| Other                                                   |       | —                                 |       | —   |       | 67        |       |
| Total                                                   |       | $                                      | 5,284,385  |     | $          | 2,538,182 |       | $ | 1,904,743 |   |
| **Capital Expenditures:**                               |       |                                   |       |     |       |      |       |
| (including interest  capitalized)                       |       |                                   |       |     |       |      |       |
| For the year  ended December 31,                   |       |                                   |       |     |       |      |       |
| United States                                           |       | $                                      | 397,192    |     | $          | 931,444   |       | $ | 376,430 |   |
| Canada                                                  |       | 2,681,855                              |       | —   |       | —    |       |
| Other                                                   |       | —                                 |       | 5,656    |       | 70        |       |
| Total                                                   |       | $                                      | 3,079,047  |     | $          | 937,100   |       | $ | 376,500 |   |
| **Revenues:**                                           |       |                                   |       |     |       |      |       |
| For the year  ended December 31,                   |       |                                   |       |     |       |      |       |
| United States                                           |       | $                                      | 1,085,712  |     | $          | 976,555   |       | $ | 858,505 |   |
| Canada                                                  |       | 139,636                                |       | —   |       | —    |       |
| Other                                                   |       | 351                                    |       | —   |       | —    |       |
| Total                                                   |       | $                                      | 1,225,699  |     | $          | 976,555   |       | $ | 858,505 |   |
| **Depreciation, depletion, and  amortization expense:** |       |                                   |       |     |       |      |       |
| For the year  ended December 31,                   |       |                                   |       |     |       |      |       |
| United States                                           |       | $                                      | 261,324    |     | $          | 251,876   |       | $ | 229,881 |   |
| Canada                                                  |       | 50,923                                 |       | —   |       | —    |       |
| Other                                                   |       | —                                 |       | —   |       | —    |       |
| Total                                                   |       | $                                      | 312,247    |     | $          | 251,876   |       | $ | 229,881 |   |
| **Operating income (loss):**                            |       |                                   |       |     |       |      |       |
| For the year  ended December 31,                   |       |                                   |       |     |       |      |       |
| United States                                           |       | $                                      | 474,138    |     | $          | 432,741   |       | $ | 408,830 |   |
| Canada                                                  |       | 43,876                                 |       | —   |       | —    |       |
| Other                                                   |       | (9,631                                 | )          | (6,456   | )          | (1,204    | )          |
| Total                                                   |       | $                                      | 508,383    |     | $          | 426,285   |       | $ | 407,626 |   |

 

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

**(9) DiscontinuedOperations**

Under SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, the Companyclassifies assets to be disposed of as held for sale or, if appropriate,discontinued operations when they have received appropriate approvals by theCompany’s management or Board of Directors and when they meet other criteria. Asof December 31, 2005, the Company had completed the sale of the assetsdiscussed below.

*Thaipo Ltd. andB8/32 Partners Ltd.—*

On August 17, 2005,the Company completed the sale of its wholly owned subsidiary Thaipo Ltd. andits 46.34% interest in B8/32 Partners Ltd. (collectively referred to as the “ThailandEntities”) for a purchase price of $820 million. The Company recognized anafter tax gain of approximately $403 million on the sale of the ThailandEntities.

*Pogo Hungary Ltd.—*

On June 7, 2005, the Company completed the saleof its wholly owned subsidiary Pogo Hungary, Ltd. (“Pogo Hungary”) for apurchase price of $9 million. The Company recognized an after tax gain ofapproximately $5 million on the sale of Pogo Hungary.

TheThailand Entities and Pogo Hungary are classified as discontinued operations inthe Company’s financial statements for all periods presented. The summarizedfinancial results and financial position data of the discontinued operationswere as follows (amounts expressed in thousands): 

**Operating Results Data**

| ** **                                                   | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                   | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Revenues                                                     |       | $                                          | 252,840    |   | $ | 335,291 |   | $ | 303,491 |   |
| Costs and  expenses                                          |       | (126,496                                   | )          | (237,097 | ) | (163,388 | ) |
| Other income                                                 |       | 4,962                                      |       | 308 |   | 2,520 |   |
| Income before  income taxes                                  |       | 131,306                                    |       | 98,502 |   | 142,623 |   |
| Income taxes                                                 |       | (78,456                                    | )          | (85,783 | ) | (82,751 | ) |
| Income before  gain from discontinued operations, net of tax |       | 52,850                                     |       | 12,719 |   | 59,872 |   |
| Gain on sale, net  of tax of $9,736                          |       | 407,784                                    |       | — |   | — |   |
| Income from discontinued  operations, net of tax             |       | $                                          | 460,634    |   | $ | 12,719 |   | $ | 59,872 |   |

 

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

**Financial PositionData**

| ** **                                  | ** ** | **December 31,** | ** ** |
|---------------------------------------------|------------|-----------------------|------------|
| ** **                                  | ** ** | **2004**              | ** ** |
| **Assets of Discontinued  Operations**      |       |                  |       |   |   |
| Current Investments                         |       |                  | $          | 135,000 |   |   |
| Accounts receivable                         |       |                  | 36,876     |   |   |
| Inventories                                 |       |                  | 13,800     |   |   |
| Other current assets                        |       |                  | 1,408      |   |   |
| Total current assets                        |       |                  | 187,084    |   |   |
| Property, plant and equipments, net         |       |                  | 471,012    |   |   |
| Other long-term assets                      |       |                  | 9,085      |   |   |
| Total assets                                |       |                  | $          | 667,181 |   |   |
| **Liabilities  of Discontinued Operations** |       |                  |       |   |   |
| Accounts payable                            |       |                  | $          | 51,565 |   |   |
| Income taxes payable                        |       |                  | 34,645     |   |   |
| Other current liabilities                   |       |                  | 23,718     |   |   |
| Total current liabilities                   |       |                  | 109,928    |   |   |
| Deferred income tax                         |       |                  | 64,865     |   |   |
| Asset retirement obligation                 |       |                  | 21,094     |   |   |
| Total liabilities                           |       |                  | $          | 195,887 |   |   |

 

**(10) Employee BenefitPlans**

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 by law,and the Company will then match the employee’s contribution on a dollar fordollar basis up to the lesser of 6% of the employee’s salary or $14,000 in2005. 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 and bond mutual funds according to instructionsfrom the employee. The Company contributed $1,524,000 to the savings plan in2005, $1,360,000 in 2004, and $1,233,000 in 2003.

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. During 2005, the Company contributed $4.5 million to the plan. TheCompany does not expect to make a contribution to the plan in 2006. The plan’sinvestment strategy and goals are to ensure, over the long-term life of theretirement plan, an adequate pool of sufficiently liquid assets to support thebenefit obligations to participants, retirees and beneficiaries. Investmentobjectives are long-term in nature covering typical market cycles of three tofive 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 

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

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 2006are approximately $552,000.

Thefollowing two tables set forth the plans’ status (in thousands of dollars) asof and for the years ended December 31 of the applicable year. The Companyuses a December 31 measurement date for its plans.

| ** **                                     | ** ** | ** **               | ** ** | ** **            | ** ** | **Post-Retirement** | ** ** |
|------------------------------------------------|------------|--------------------------|------------|-----------------------|------------|---------------------|------------|
| ** **                                     | ** ** | **Retirement Plan** | ** ** | **Medical Plan** | ** ** |
| ** **                                     | ** ** | **2005**                 | ** ** | **2004**              | ** ** | **2005**            | ** ** | **2004** | ** ** |
| **Change in benefit obligation**               |       |                     |       |                  |       |                |       |   |   |
| Benefit obligation at beginning of year        |       | $                        | 36,858     |                  | $          | 29,519              |       | $ | 21,202 |   | $ | 17,145 |   |
| Service cost                                   |       | 3,394                    |       | 2,631                 |       | 1,371               |       | 1,385 |   |
| Interest cost                                  |       | 2,069                    |       | 1,751                 |       | 1,038               |       | 1,044 |   |
| Benefits paid                                  |       | (2,370                   | )          | (1,302                | )          | (422                | )          | (356 | ) |
| Actuarial loss                                 |       | 6,615                    |       | 4,259                 |       | (1,259              | )          | 1,984 |   |
| Benefit obligation at end of year              |       | $                        | 46,566     |                  | $          | 36,858              |       | $ | 21,930 |   | $ | 21,202 |   |
| **Change in plan assets**                      |       |                     |       |                  |       |                |       |   |   |
| Fair value of plan assets at beginning of year |       | $                        | 32,299     |                  | $          | 32,236              |       | $ | — |   | $ | — |   |
| Actual return on plan assets                   |       | 1,566                    |       | 1,729                 |       | —              |       | — |   |
| Employer contributions                         |       | 4,500                    |       | —                |       | 422                 |       | 356 |   |
| Benefits paid                                  |       | (2,370                   | )          | (1,302                | )          | (422                | )          | (356 | ) |
| Administrative expenses                        |       | (314                     | )          | (364                  | )          | —              |       | — |   |
| Fair value of plan assets at end of year       |       | $                        | 35,681     |                  | $          | 32,299              |       | $ | — |   | $ | — |   |
| **Reconciliation of funded status**            |       |                     |       |                  |       |                |       |   |   |
| Funded status                                  |       | $                        | (10,885    | )                     | $          | (4,559              | )          | $ | (21,930 | ) | $ | (21,202 | ) |
| Unrecognized actuarial loss                    |       | 20,606                   |       | 13,849                |       | 3,795               |       | 5,086 |   |
| Unrecognized transition (asset) or obligation  |       | —                   |       | —                |       | —              |       | 303 |   |
| Unrecognized prior service cost                |       | 539                      |       | 625                   |       | —              |       | — |   |
| Prepaid (accrued) benefit cost at year-end     |       | $                        | 10,260     |                  | $          | 9,915               |       | $ | (18,135 | ) | $ | (15,813 | ) |
| **Accumulated benefit obligation**             |       | $                        | 35,646     |                  | $          | 28,248              |       |   |   |   |   |

 

| ** **                                          | ** ** | ** **               | ** ** | ** **            | ** ** | ** ** | ** ** | **Post-Retirement** | ** ** |
|-----------------------------------------------------|------------|--------------------------|------------|-----------------------|------------|------------|------------|---------------------|------------|
| ** **                                          | ** ** | **Retirement Plan** | ** ** | **Medical Plan** | ** ** |
| ** **                                          | ** ** | **2005**                 | ** ** | **2004**              | ** ** | **2003**   | ** ** | **2005**            | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Components of net periodic  benefit cost**        |       |                     |       |                  |       |       |       |                |       |   |   |   |   |
| Service cost                                        |       | $                        | 3,393      |                  | $          | 2,631      |       | $                   | 2,248      |   | $ | 1,371 |   | $ | 1,385 |   | $ | 1,102 |   |
| Interest cost                                       |       | 2,069                    |       | 1,750                 |       | 1,546      |       | 1,038               |       | 1,044 |   | 915 |   |
| Expected return on plan assets                      |       | (2,591                   | )          | (2,639                | )          | (2,176     | )          | —              |       | — |   | — |   |
| Amortization of prior service cost                  |       | 86                       |       | 46                    |       | 43         |       | —              |       | — |   | — |   |
| Amortization of transition (asset) obligation  |       | —                   |       | —                |       | —     |       | 303                 |       | 305 |   | 305 |   |
| Amortization of net loss                            |       | 1,197                    |       | 722                   |       | 1,040      |       | 32                  |       | 190 |   | 64 |   |
|                                                |       | $                        | 4,154      |                  | $          | 2,510      |       | $                   | 2,701      |   | $ | 2,744 |   | $ | 2,924 |   | $ | 2,386 |   |

 

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

*Plan Assumptions*

| ** **                                             | ** ** | ** **               | ** ** | ** **            | ** ** | ** ** | ** ** | **Post-Retirement** | ** ** |
|--------------------------------------------------------|------------|--------------------------|------------|-----------------------|------------|------------|------------|---------------------|------------|
| ** **                                             | ** ** | **Retirement Plan** | ** ** | **Medical Plan** | ** ** |
| ** **                                             | ** ** | **2005**                 | ** ** | **2004**              | ** ** | **2003**   | ** ** | **2005**            | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Plan assumptions to determine  benefit obligations** |       |                     |       |                  |       |       |       |                |       |   |   |   |   |
| Discount rate                                          |       | 5.50                     | %          | 5.75                  | %          | 6.00       | %          | 5.50                | %          | 5.75 | % | 6.00 | % |
| Rate of compensation increase                          |       | 5.50                     | %          | 5.50                  | %          | 4.75       | %          | —              |       | — |   | — |   |
| **Plan  assumptions to determine net cost**            |       |                     |       |                  |       |       |       |                |       |   |   |   |   |
| Discount rate                                          |       | 5.75                     | %          | 6.00                  | %          | 6.50       | %          | 5.75                | %          | 6.00 | % | 6.50 | % |
| Expected long-term rate of return on plan assets       |       | 8.50                     | %          | 8.50                  | %          | 8.50       | %          | —              |       | — |   | — |   |
| Rate of  compensation increase                         |       | 5.50                     | %          | 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 2005.

The Company determines the discount rate used tomeasure plan liabilities as of the December 31 measurement date for theretirement plan. The discount rate reflects the current rate at which theassociated liabilities could be effectively settled at the end of the year. Indetermining this rate, the Company reviews rates of return on fixed-incomeinvestments of similar duration to the liabilities in the plan that receivehigh, investment grade ratings by recognized ratings agencies. Using thismethodology, the Company determined a discount rate of 5.50% to be appropriateas of December 31, 2005, which is a reduction of 0.25 percentage pointsfrom the rate used as of December 31, 2004.

Expectedbenefit payments for the retirement plan for the next ten years are as follows(expressed in thousands):

| **Year Ending**  | ** ** | **Expected** | ** ** |
|-----------------------|------------|--------------|------------|
| **December 31,** | ** ** | ** **   | ** ** | **Benefit Payment** | ** ** |
| 2006                  |       |         | $          | 4,153,874 |   |   |
| 2007                  |       |         | 3,025,019  |   |   |
| 2008                  |       |         | 4,210,836  |   |   |
| 2009                  |       |         | 4,194,414  |   |   |
| 2010                  |       |         | 4,056,835  |   |   |
| Next 5 Years          |       |         | 27,289,415 |   |   |
|                       |            |              |            |  |  |  |  |  |

 

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

Thefollowing table provides the target and actual asset allocations in theretirement plan:

| ** **              | ** ** | **Actual as of December 31,** | ** ** |
|-------------------------|------------|---------------------------------------------------|------------|
| **Asset Category** | ** ** | ** **                                        | ** ** | **Target** | ** ** | **2005** | ** ** | **2004** | ** ** |
| Equity securities       |       |                                              | 100        | % |   |   | 87 | % |   |   | 99 | % |   |
| Debt securities         |       |                                              | 0          | % |   |   | 0 | % |   |   | 0 | % |   |
| Real estate             |       |                                              | 0          | % |   |   | 0 | % |   |   | 0 | % |   |
| Other                   |       |                                              | 0          | % |   |   | 13 | % |   |   | 1 | % |   |
| Total                   |       |                                              | 100        | % |   |   | 100 | % |   |   | 100 | % |   |
|                         |            |                                                   |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

For measurement purposes related to the Company’spost-retirement medical plan, a 10% annual rate of increase in the per capitacost of covered health care benefits was assumed for 2005. The rate is assumedto decrease gradually to 5% for 2012 and remain at that level thereafter. Thiscompares to the amounts used for 2004 measurement purposes, where a 11% 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 2005 |       |                               | $          | 503 |   |   | $ | (397 | ) |
| Effect on year-end 2005  postretirement benefit obligation        |       |                               | $          | 4,058 |   |   | $ | (3,251 | ) |

 

In December 2003, the Medicare Prescription DrugImprovement and Modernization Act of 2003 (the Act) was signed into law. TheAct introduced a prescription drug benefit under Medicare (Medicare Part D),as well as a nontaxable federal subsidy to sponsors of retiree health carebenefit plans that provide a benefit that is at least actuarially equivalent toMedicare Part D. In May 2004, the FASB issued Staff Position No. 106-2,“Accounting and Disclosure Requirements Related to the Medicare PrescriptionDrug Improvement and Modernization Act of 2003” (FSP No. 106-2),which addresses the accounting and disclosure requirements associated with theeffects of the Act.

The Company has electednot to reflect changes in the Act in its 2005 financial statements since theCompany has concluded that the effects of the Act are not a significant eventthat calls for remeasurement under FAS 106.

**(11) Stock-BasedCompensation Plans**

The Company’s incentiveplans authorize awards granted wholly or partly in common stock (includingrights or options which may be exercised for or settled in common stock) to keyemployees and non-employee directors. Awards to employees of the Company may bemade as grants of stock options, stock appreciation rights, stock awards, cashawards, performance awards or any combination thereof (collectively, “Awards”).Employee Awards generally become exercisable in three installments. The numberof shares of Company common stock available for future issuance was 3,637,057,3,975,757and 2,297,657 as of December 31, 2005, 2004 and 2003,respectively. Stock options granted during and after 

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

2003expire 5 years from the date of grant, if not exercised. Stock options grantedprior to 2003, if not exercised, expire 10 years from the date of grant.

*Restricted Stock*

TheCompany granted the following shares of restricted stock during the indicatedperiods:

| ** **            | ** ** | ** ** | ** ** | **Weighted**        | ** ** |
|-----------------------|------------|------------|------------|---------------------|------------|
| ** **            | ** ** | **Number** | ** ** | **Average**         | ** ** |
| **Year Ended**   | ** ** | **of**     | ** ** | **Grant Date** | ** ** |
| **December 31,** | ** ** | ** ** | ** ** | **Awards**          | ** ** | **Fair Value** | ** ** |
| 2005                  |       | 351,800    |       | $                   | 19,528,106 |   |
| 2004                  |       | 303,400    |       | $                   | 13,164,429 |   |
| 2003                  |       | 144,000    |       | $                   | 6,045,840  |   |
|                       |            |            |            |                     |            |  |  |  |

 

The number of unvestedshares of restricted stock was 630,600, 403,900 and 157,019 as of December 31,2005, 2004 and 2003, respectively.

*Restricted StockUnits*

On November 1, 2005 the Company awarded 135,000Restricted Stock Units (the “Units”) to certain employees of Northrock. TheUnits vest ratably over a three year period. Vested Units are payable in cashin an amount equal to the fair market value of the Company’s common stock forthe five-day trading period ending on the vesting date. The Company recognizescompensation expense and a liability based on the average fair market value ofCompany common stock for the last five trading days of the period. For the yearended December 31, 2005, the Company recognized compensation expense of$370,440 related to the Units.

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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 31,2005, 2004 and 2003, and changes during the years ended on those dates ispresented below:

| ** **                                                  | ** ** | ** **         | ** ** | **Weighted** | ** ** |
|-------------------------------------------------------------|------------|--------------------|------------|--------------|------------|
| ** **                                                  | ** ** | ** **         | ** ** | **Average**  | ** ** |
| ** **                                                  | ** ** | **Number of** | ** ** | **Exercise** | ** ** |
| ** **                                                  | ** ** | **Awards**         | ** ** | **Price**    | ** ** |
| 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 |   |   |
| Outstanding, December 31, 2004                         |       | 2,145,336          |       |         | $          | 30.00 |   |   |
| Exercised in 2005                                           |       | (352,767           | )          |         | $          | 31.66 |   |   |
| Canceled in 2005                                            |       | (10,333            | )          |         | $          | 26.09 |   |   |
| Outstanding,  December 31, 2005                        |       | 1,782,236          |       |         | $          | 29.69 |   |   |
| Exercisable,  December 31, 2005                        |       | 1,635,901          |       |         | $          | 28.51 |   |   |
| Weighted-average  fair value of options granted during 2005 |       |               |       |         | N/A        |   |   |

 

The following table summarizes information about stockoptions outstanding at December 31, 2005

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

 

| ** **             | ** ** | **Options Outstanding** | ** ** | **Options Exercisable** | ** ** |
|------------------------|------------|------------------------------|------------|------------------------------|------------|
| ** **             | ** ** | ** **                   | ** ** | **Weighted**                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **             | ** ** | ** **                   | ** ** | **Average**                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **             | ** ** | ** **                   | ** ** | **Remaining**                | ** ** | **Weighted** | ** ** | ** ** | ** ** | **Weighted** | ** ** |
| ** **             | ** ** | ** **                   | ** ** | **Contractual**              | ** ** | **Average** | ** ** | ** ** | ** ** | **Average** | ** ** |
| **Range of**      | ** ** | **Number**                   | ** ** | **Life**                     | ** ** | **Exercise** | ** ** | **Number** | ** ** | **Exercise** | ** ** |
| **Option Prices** | ** ** | ** **                   | ** ** | **Outstanding**              | ** ** | **(days)** | ** ** | **Price** | ** ** | **Exercisable** | ** ** | **Price** | ** ** |
| $17.91 to $19.56       |       |                         | 47,500     |                         |       |   | 1,200 |   |   |   | $ | 18.30 |   |   | 47,500 |   |   | $ | 18.30 |   |   |
| $20.31 to $24.77       |       |                         | 655,101    |                         |       |   | 1,884 |   |   |   | $ | 23.27 |   |   | 655,101 |   |   | $ | 23.27 |   |   |
| $25.38 to $29.78       |       |                         | 638,500    |                         |       |   | 2,335 |   |   |   | $ | 29.59 |   |   | 638,500 |   |   | $ | 29.59 |   |   |
| $31.18 to $33.94       |       |                         | 54,000     |                         |       |   | 1,798 |   |   |   | $ | 32.03 |   |   | 54,000 |   |   | $ | 32.03 |   |   |
| $36.00                 |       |                         | 30,000     |                         |       |   | 154 |   |   |   | $ | 36.00 |   |   | 30,000 |   |   | $ | 36.00 |   |   |
| $40.63 to $43.46       |       |                         | 332,134    |                         |       |   | 2,419 |   |   |   | $ | 41.83 |   |   | 205,800 |   |   | $ | 41.71 |   |   |
| $45.89 to $49.48       |       |                         | 25,001     |                         |       |   | 3,049 |   |   |   | $ | 48.58 |   |   | 5,000 |   |   | $ | 48.93 |   |   |
| Total                  |       |                         | 1,782,236  |                         |       |   | 2,112 |   |   |   | $ | 29.69 |   |   | 1,635,901 |   |   | $ | 28.51 |   |   |
|                        |            |                              |            |                              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**(12) Commodity Derivativesand Hedging Activities**

During the year ended December 31, 2005, theCompany recognized $11,323,000 of pre-tax losses related to settled contractsin its oil and gas revenues from its price hedge contracts. The Company alsorecognized a pre-tax loss of $1,314,000 due to ineffectiveness on these hedge contractsduring the year ended December 31, 2005. During the year ended December 31,2004, the Company did not recognize any gains or losses from its hedgingactivities related to 2004 production. The Company did recognize a pre-tax gainof $657,000 due to ineffectiveness on hedge contracts during the year ended2004. The Company recognized a pre-tax loss of $22,822,000 ($14,873,000 aftertaxes) for the year ended December 31, 2003 from its price hedgecontracts, which are included in oil and gas revenues. Net unrealized losses onderivative instruments of $52,952,000, net of deferred taxes of $30,437,000,have been reflected as a component of other comprehensive income for the yearended December 31, 2005. Based on the fair market value of the hedgecontracts as of December 31, 2005, the Company would reclassify additionalpre-tax losses of approximately $46,805,000 (approximately $29,721,000 aftertaxes) from accumulated other comprehensive loss (shareholders’ equity) to netincome during the next twelve months.

As of December 31, 2005, the Company held variousderivative instruments. During 2004 and 2005, the Company entered into naturalgas and crude oil option agreements referred to as “collars.”  Collars are designed to establish floor andceiling prices on anticipated future natural gas and crude oil production. TheCompany has designated these contracts as cash flow hedges designed to achievea more predictable cash flow, as well as to reduce its exposure to pricevolatility. While the use of these derivative instruments limits the downsiderisk of adverse price movements, they may also limit future revenues fromfavorable price movements. The use of derivatives also involves the risk thatthe counterparties to such instruments will be unable to meet the financialterms of such contracts. Currently, the Company does not expect losses due tocreditworthiness 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 

82

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

payment to the counterpartyif the settlement price for any settlement period is above the ceiling price ofsuch transaction.

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 31,2005 are as follows:

| ** **                             | ** ** | ** ** | ** ** | **NYMEX**    | ** ** | ** **          | ** ** |
|----------------------------------------|------------|------------|------------|--------------|------------|---------------------|------------|
| ** **                             | ** ** | ** ** | ** ** | **Contract** | ** ** | **Fair Value** | ** ** |
| **Contract Period and**      | ** ** | ** ** | ** ** | **Price**    | ** ** | **of**              | ** ** |
| **Type of Contract**         | ** ** | ** ** | ** ** | **Volume**   | ** ** | **Floor**           | ** ** | **Ceiling** | ** ** | **Liability** | ** ** |
| **Natural Gas Contracts (MMBtu)  (a)** |       |       |       |         |       |                |       |   |   |
| Collar Contracts:                      |       |       |       |         |       |                |       |   |   |
| January 2006 - December 2006 |       | 5,475      |       | $            | 5.00       |                | $          | 7.50 |   | $ | (18,527,528 | ) |
| January 2006 - December 2006 |       | 1,825      |       | $            | 5.50       |                | $          | 8.25 |   | $ | (5,106,509 | ) |
| January 2006 - December 2006 |       | 3,650      |       | $            | 5.75       |                | $          | 8.27 |   | $ | (10,053,301 | ) |
| January 2006 - December 2006 |       | 10,950     |       | $            | 6.00       |                | $          | 13.50 |   | $ | (4,942,274 | ) |
| January 2006 - December 2006 |       | 1,825      |       | $            | 6.00       |                | $          | 13.55 |   | $ | (809,200 | ) |
| January 2006 - December 2006 |       | 3,650      |       | $            | 6.00       |                | $          | 13.60 |   | $ | (1,589,865 | ) |
| January 2006 - December 2006 |       | 10,950     |       | $            | 6.00       |                | $          | 14.00 |   | $ | (4,134,399 | ) |
| January 2007 - December 2007 |       | 5,475      |       | $            | 6.00       |                | $          | 12.00 |   | $ | (5,536,823 | ) |
| January 2007 - December 2007 |       | 9,125      |       | $            | 6.00       |                | $          | 12.15 |   | $ | (8,878,679 | ) |
| January 2007 - December 2007 |       | 3,650      |       | $            | 6.00       |                | $          | 12.20 |   | $ | (3,505,893 | ) |
| January 2007 - December 2007 |       | 9,125      |       | $            | 6.00       |                | $          | 12.50 |   | $ | (8,106,668 | ) |
| **Crude  Oil Contracts (Barrels)**     |       |       |       |         |       |                |       |   |   |
| Collar Contracts:                      |       |       |       |         |       |                |       |   |   |
| January 2006 - December 2006 |       | 1,460,000  |       | $            | 50.00      |                | $          | 78.00 |   | $ | (976,728 | ) |
| January 2006 - December 2006 |       | 365,000    |       | $            | 50.00      |                | $          | 79.00 |   | $ | (195,932 | ) |
| January 2006 - December 2006 |       | 1,460,000  |       | $            | 50.00      |                | $          | 81.00 |   | $ | (439,482 | ) |
| January 2006 - December 2006 |       | 365,000    |       | $            | 50.00      |                | $          | 81.04 |   | $ | (108,279 | ) |
| January 2006 - December 2006 |       | 1,825,000  |       | $            | 50.00      |                | $          | 82.00 |   | $ | (357,749 | ) |
| January 2007 - December 2007 |       | 1,460,000  |       | $            | 50.00      |                | $          | 75.00 |   | $ | (3,463,645 | ) |
| January 2007 - December 2007 |       | 365,000    |       | $            | 50.00      |                | $          | 75.25 |   | $ | (842,944 | ) |
| January 2007 - December 2007 |       | 3,650,000  |       | $            | 50.00      |                | $          | 77.50 |   | $ | (6,439,226 | ) |
|                                        |            |            |            |              |            |                     |            |  |  |  |  |  |  |  |

----

(a)           MMBtu means millionBritish Thermal Units.

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

Althoughall of the Company’s collars are effective as economic hedges, the forecastedshut-in hydrocarbon production from the Company’s Gulf of Mexico properties(resulting primarily from hurricane activity during the third quarter of 2005)caused certain of the gas and crude oil collar contracts to lose theirqualification for hedge accounting under SFAS 133. As a result, the Companyreclassified $18.7 million of previously deferred losses from accumulated othercomprehensive income to “Commodity derivative expense” in the income statementduring the third quarter of 2005. Additionally, the Company now recognizes allfuture changes in the fair value of these collar contracts in the consolidatedstatement of income for the period in which the change occurs under the caption“Commodity derivative expense.’’  As of December 31,2005, the Company had the following collar contracts that no longer qualify forhedge accounting: 

| ** **                              | ** ** | ** ** | ** ** | **NYMEX**    | ** ** | ** **          | ** ** |
|-----------------------------------------|------------|------------|------------|--------------|------------|---------------------|------------|
| ** **                              | ** ** | ** ** | ** ** | **Contract** | ** ** | **Fair Value** | ** ** |
| **Contract Period and**       | ** ** | ** ** | ** ** | **Price**    | ** ** | **of**              | ** ** |
| **Type of Contract**          | ** ** | ** ** | ** ** | **Volume**   | ** ** | **Floor**           | ** ** | **Ceiling** | ** ** | **Liability** | ** ** |
| **Natural Gas Contracts (MMBtu)**       |       |       |       |         |       |                |       |   |   |   |   |   |   |
| Collar Contracts:                       |       |       |       |         |       |                |       |   |   |   |   |   |   |
| January 2006  - November 2006 |       |       | 1,825      |         |       | $                   | 5.50       |   |   | $ | 8.25 |   |   | $ | (5,034,443 | ) |
|                                         |            |            |            |              |            |                     |            |  |  |  |  |  |  |  |  |  |  |  |

 

**(13) Acquisitions**

On September 27,2005, the Company completed the acquisition of Northrock for approximately $1.7billion in cash. The Company purchased all of the outstanding shares ofNorthrock pursuant to a share purchase agreement that was entered into on July 8,2005. As of September 27, 2005, Northrock owned approximately 292,000 netproducing acres, plus approximately 950,000 net acres of undeveloped leasehold.Northrock’s activities are concentrated in Saskatchewan and Alberta with keyexploration plays in Canada’s Northwest Territories, British Columbia and theAlberta Foothills. The Company acquired Northrock primarily to strengthen itsposition in North American exploration and development properties. Thefollowing is a calculation and allocation of purchase price to the acquired assetsand liabilities based on their relative fair values:  

| CALCULATION OF PURCHASE  PRICE (IN THOUSANDS)  |   |    |      |
|------------------------------------------------|--------|---------|-----------|
| Cash paid, including transaction costs         |   | $       | 1,737,464 |   |
| Plus fair market  value of liabilites assumed: |   |    |      |
| Other liabilites                               |   | 97,123  |      |
| Asset retirement obligation                    |   | 38,810  |      |
| Deferred income taxes                          |   | 771,558 |      |
| Total purchase  price for assets acquired      |   | $       | 2,644,955 |   |
| ALLOCATION OF  PURCHASE PRICE (IN THOUSANDS)   |   |    |      |
| Proved oil and gas properties                  |   | $       | 1,715,777 |   |
| Unproved oil and gas properties                |   | 809,860 |      |
| Other assets                                   |   | 119,318 |      |
| Total                                          |   | $       | 2,644,955 |   |

 

84

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

The purchase price allocation noted above is subjectto change based on the Company’s final analysis of the oil and gas propertiesand tax attributes it has acquired, which is expected to be completed in the firstquarter of 2006.

In addition to the Northrock acquisition, during 2005the Company also completed two corporate acquisitions in Canada for cashconsideration totaling approximately $32.9 million and six other producingproperty acquisitions for cash consideration totaling approximately $51million.The Company recorded the estimated fair value of assets and liabilities on thetwo corporate transactions which consisted primarily of $50 million of oil andgas properties and deferred tax liabilities of $15.8 million. No goodwill wasrecorded for these transactions.

In December 2004, the Company completed theacquisition of  two privately heldcorporations for approximately $282.5 million in cash and a deferred payment of$26.4 million made in 2005 to the former owner of one of the corporations. Thecorporations have subsequently been named Pogo Producing (San Juan) Company andPogo Producing (Texas Panhandle) Company (the “corporations”). The transactionsincluded properties located primarily in the San Juan basin of New Mexico andthe Texas  Panhandle. The Companyacquired the corporations primarily to strengthen its position in domesticnatural gas properties. The Company recorded the estimated fair values of theassets acquired and the liabilities assumed at the closing date of thetransactions, which primarily consisted of oil and gas properties of$423.7 million, long term debt of $50.1 million and deferred taxliabilities of $67.4 million. No goodwill was recorded for thetransactions.

In 2004, the Company alsocompleted six other producing property acquisitions for cash considerationtotaling approximately $186 million.

85

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

*Pro FormaInformation*

Thefollowing summary presents unaudited pro forma consolidated results ofoperations for the three years ended December 31, 2005 for the Company’scontinuing operations as if the acquisitions of Northrock and the corporationshad each****occurred as of January 1,2003. The pro forma results are for illustrative purposes only and includeadjustments in addition to the pre-acquisition historical results of Northrockand the corporations, such as increased depreciation, depletion andamortization expense resulting from the allocation of fair value to oil and gasproperties acquired, increased interest expense on acquisition debt and therelated tax effects of these adjustments. The unaudited pro forma information(presented in thousands of dollars, except per share amounts) is notnecessarily indicative of the operating results that would have occurred hadthe acquisitions been consummated at that date, nor are they necessarilyindicative of future operating results.

| ** **                                                         | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                         | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                         | ** ** | **(Unaudited)**                            | ** ** |
| **Pro Forma:**                                                     |       |                                       |       |   |   |   |   |
| Revenues                                                           |       | $                                          | 1,531,066  |   | $ | 1,380,893 |   | $ | 1,203,580 |   |
| Income before  cumulative effect of change in accounting principle |       | 330,487                                    |       | 266,063 |   | 248,173 |   |
| Net income                                                         |       | 330,487                                    |       | 266,063 |   | 247,806 |   |
| Earnings per share:                                                |       |                                       |       |   |   |   |   |
| Basic—                                                        |       |                                       |       |   |   |   |   |
| Income before cumulative effect of change in  accounting principle |       | $                                          | 5.47       |   | $ | 4.17 |   | $ | 3.97 |   |
| Net income                                                         |       | $                                          | 5.47       |   | $ | 4.17 |   | $ | 3.96 |   |
| Diluted—                                                      |       |                                       |       |   |   |   |   |
| Income before cumulative effect of change in  accounting principle |       | $                                          | 5.42       |   | $ | 4.13 |   | $ | 3.87 |   |
| Net income                                                         |       | $                                          | 5.42       |   | $ | 4.13 |   | $ | 3.87 |   |

 

**(14) 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.

86

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

Activity related to the Company’s ARO during the years  ended December 31, 2005 and 2004 is as follows (in thousands):

| ** **                                            | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                            | ** ** | **2005**                                   | ** ** | **2004** | ** ** |
| Initial ARO as of  January 1,                    |       | $                                          | 74,046     |   | $ | 58,509 |   |
| Liabilities incurred  during period                   |       | 41,872                                     | (a)        | 15,569 | (a) |
| Liabilities settled  during period                    |       | (7,145                                     | )          | (3,595 | ) |
| Revisions to previous  estimate                       |       | 39,672                                     | (b)        | (1,239 | ) |
| Accretion expense                                     |       | 7,884                                      |       | 4,802 |   |
| Balance of ARO as of  December 31,               |       | $                                          | 156,329    |   | $ | 74,046 |   |
| Less: Current portion of  ARO as of December 31, |       | (6,955                                     | )          | — |   |
| Long term portion of ARO  as of December 31,     |       | $                                          | 149,374    |   | $ | 74,046 |   |

----

(a)           $39.1 million and $14.1million of this amount relates to acquistions during 2005 and 2004,respectively.

(b)          Related primarily toincreased estimated future service costs based on substantial inflation in thepricing environment during 2005.

For the years ended December 31,2005, 2004, and 2003, the Company recognized depreciation expense related toits ARC of $4,529,000, $984,000 and $2,867,000, respectively. The Companyrecognized $3,989,000 of accretion expense in the year ended December 31,2003. As a result of the adoption of SFAS 143 on January 1, 2003, theCompany recorded a $47,893,000 increase in the net capitalized cost of its oiland gas properties and recognized an after-tax charge of $4,166,000 for thecumulative effect of the change in accounting principle (net of related incometax benefit of $2,707,000).  Thisafter-tax charge includes the effect on the Company’s discontinued operations.

**(15) Fair Value ofFinancial 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 CashEquivalents*

Fair value is carryingvalue.

*Receivables andPayables*

Fair value isapproximately carrying value.

87

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

*DerivativeFinancial Instruments*

Fair value is carrying value.

*Debt and Other*

| Instrument                          | ** ** | **Basis of Fair Value Estimate**                                                                                   |
|-------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------|
| Bank revolving credit  agreement(s) |       | Fair value is carrying value as of December 31,  2005 and 2004 based on the market value interest rates.      |
| LIBOR Rate Advances                 |       | Fair value is carrying value as of December 31, 2005  and 2004 based on the market value interest rates.           |
| 2011 Notes                          |       | Fair value is 104.1% and 108.1% of carrying value as  of December 31, 2005 and 2004, based on quoted market value. |
| 2015 Notes                          |       | Fair value is 97.1% of carrying value as of  December 31, 2005, based on quoted market value.                 |
| 2017 Notes                          |       | Fair value is 97.1% of carrying value as of  December 31, 2005, based on quoted market value.                 |

 

The carrying valueand estimated fair value of the Company’s financial instruments atDecember 31, 2005 and 2004 (in thousands of dollars) are as follows:

| ** **                            | ** ** | **2005**            | ** ** | **2004**        | ** ** |
|---------------------------------------|------------|---------------------|------------|-----------------|------------|
| ** **                            | ** ** | **Carrying  Value** | ** ** | **Fair  Value** | ** ** | **Carrying  Value** | ** ** | **Fair  Value** | ** ** |
| Cash and cash  equivalents            |       | $                   | 57,749     |            | $          | 57,749 |   | $ | 86,456 |   | $ | 86,456 |   |
| Receivables                           |       | $                   | 218,749    |            | $          | 218,749 |   | $ | 141,341 |   | $ | 141,341 |   |
| Payables                              |       | $                   | (304,460   | )               | $          | (304,460 | ) | $ | (148,738 | ) | $ | (148,738 | ) |
| Debt:                                 |       |                |       |            |       |   |   |   |   |
| Bank revolving credit agreement loans |       | $                   | (606,000   | )               | $          | (606,000 | ) | $ | (515,000 | ) | $ | (515,000 | ) |
| LIBOR Rate Advances                   |       | $                   | (40,000    | )               | $          | (40,000 | ) | $ | (40,000 | ) | $ | (40,000 | ) |
| 2011 Notes                            |       | $                   | (200,000   | )               | $          | (208,250 | ) | $ | (200,000 | ) | $ | (216,250 | ) |
| 2015 Notes                            |       | $                   | (297,452   | )               | $          | (291,375 | ) | $ | — |   | $ | — |   |
| 2017 Notes                            |       | $                   | (500,000   | )               | $          | (485,625 | ) | $ | — |   | $ | — |   |

 

The Company occasionallyenters into hedging contracts to minimize the impact of oil and gas pricefluctuations. See Note 12 for a further discussion of these contracts.

88

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

**Oiland Gas Producing Activities**

Theresults of operations from oil and gas producing activities (expressed inthousands) exclude non-oil and gas revenues, corporate general andadministrative expenses, other non oil and gas producing expenses, interest charges,interest income and interest capitalized. Income tax (expense) or benefit wasdetermined by applying the statutory rates to pre-tax operating results withadjustments for permanent differences.  Except as noted, all of the Company’s oil andgas producing activities were conducted in the United States during 2004 and2003

| ** **                                        | ** ** | **2005**           | ** ** |
|---------------------------------------------------|------------|--------------------|------------|
| ** **                                        | ** ** | **Total  Company** | ** ** | **United  States** | ** ** | **Canada** | ** ** | **Other  International** | ** ** |
| Revenues                                          |       | $                  | 1,216,247  |   | $ | 1,082,065 |   | $ | 134,182 |   |   | $ | — |   |   |
| Lease operating  expense                          |       | (153,659           | )          | (135,969 | ) | (17,690 | ) |   | — |   |   |
| Exploration  expense                              |       | (26,473            | )          | (14,047 | ) | (3,397 | ) |   | (9,029 | )(a) |   |
| Dry hole and  impairment expense                  |       | (87,170            | )          | (82,217 | ) | (4,953 | ) |   | — |   |   |
| Depreciation,  depletion and amortization expense |       | (307,109           | )          | (256,579 | ) | (50,530 | ) |   | — |   |   |
| Production and  other taxes                       |       | (59,527            | )          | (56,783 | ) | (2,744 | ) |   | — |   |   |
| Transportation  and accretion                     |       | (27,124            | )          | (24,983 | ) | (2,141 | ) |   | — |   |   |
| Pretax operating  results                         |       | 555,185            |       | 511,487 |   | 52,727 |   |   | (9,029 | ) |   |
| Income tax  (expense) benefit                     |       | (200,508           | )          | (182,361 | ) | (18,147 | ) |   | — |   |   |
| Operating results                                 |       | $                  | 354,677    |   | $ | 329,126 |   | $ | 34,580 |   |   | $ | (9,029 | ) |   |

 

| ** **                                        | ** ** | **2004** | ** ** | **2003** | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------------------------------|------------|----------|------------|----------|------------|------------|------------|------------|------------|
| Revenues                                          |       | $        | 973,083    |     | $          | 856,074    |       |       |       |   |   |   |   |
| Lease operating  expense                          |       | (100,506 | )          | (81,731  | )          |       |       |       |       |   |   |
| Exploration  expense                              |       | (21,739  | )          | (6,899   | )          |       |       |       |       |   |   |
| Dry hole and  impairment expense                  |       | (61,634  | )(b)       | (30,673  | )          |       |       |       |       |   |   |
| Depreciation,  depletion and amortization expense |       | (248,431 | )          | (226,607 | )          |       |       |       |       |   |   |
| Production and  other taxes                       |       | (44,104  | )          | (23,735  | )          |       |       |       |       |   |   |
| Transportation  and accretion                     |       | (19,488  | )          | (16,949  | )          |       |       |       |       |   |   |
| Pretax operating  results                         |       | 477,181  |       | 469,480  |       |       |       |       |       |   |   |
| Income tax  (expense) benefit                     |       | (175,576 | )          | (170,750 | )          |       |       |       |       |   |   |
| Operating results                                 |       | $        | 301,605    |     | $          | 298,730    |       |       |       |   |   |   |   |

----

(a)           Related to New Zealand.

(b)          Included is $5,551related to the Danish North  Sea.

89

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

Thefollowing table sets forth the Company’s costs incurred (expressed inthousands) for oil and gas producing activities, including capitalizedinterest, during the years indicated. 

| ** **                                                | ** ** | **2005**           | ** ** |
|-----------------------------------------------------------|------------|--------------------|------------|
| ** **                                                | ** ** | **Total  Company** | ** ** | **United  States** | ** ** | **Canada** | ** ** | **Other  International** | ** ** |
| Costs incurred (capitalized  unless otherwise indicated): |       |               |       |   |   |   |   |   |   |   |   |
| Property  acquisition                                     |       |               |       |   |   |   |   |   |   |   |   |
| Proved                                                    |       | $                  | 1,832,897  |   | $ | 45,981 |   | $ | 1,786,916 |   |   | $ | — |   |   |
| Unproved                                                  |       | 880,859            |       | 50,843 |   | 830,016 |   |   | — |   |   |
| Exploration                                               |       |               |       |   |   |   |   |   |   |   |   |
| Capitalized                                               |       | 139,206            |       | 130,079 |   | 9,127 |   |   | — |   |   |
| Expensed                                                  |       | 26,473             |       | 14,013 |   | 3,397 |   |   | 9,063 |   |   |
| Development                                               |       | 220,119            |       | 164,194 |   | 55,796 |   |   | 129 |   |   |
| Asset retirement cost                                     |       | 53,183             |       | 3,256 |   | 49,927 |   |   | — |   |   |
| Total oil and gas costs incurred                          |       | $                  | 3,152,737  |   | $ | 408,366 |   | $ | 2,735,179 |   |   | $ | 9,192 |   |   |
| Provision for depreciation, depletion and amortization    |       | $                  | 307,109    |   | $ | 256,579 |   | $ | 50,530 |   |   | $ | — |   |   |

 

| ** **                                              | ** ** | **2004** | ** ** | **2003** | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------------------------------------|------------|----------|------------|----------|------------|------------|------------|------------|------------|
| Property  acquisition                                   |       |     |       |     |       |       |       |       |       |   |   |
| Proved                                                  |       | $        | 612,975    |     | $          | 182,660    |       |       |       |   |   |   |   |
| Unproved                                                |       | 26,904   |       | 12,403   |       |       |       |       |       |   |   |
| Exploration                                             |       |     |       |     |       |       |       |       |       |   |   |
| Capitalized                                             |       | 62,500   | (a)        | 43,499   |       |       |       |       |       |   |   |
| Expensed                                                |       | 21,739   |       | 6,832    |       |       |       |       |       |   |   |
| Development                                             |       | 228,473  |       | 135,424  |       |       |       |       |       |   |   |
| Asset retirement cost                                   |       | 14,330   |       | 49,706   | (b)        |       |       |       |       |   |   |
| Total oil and gas costs incurred                        |       | $        | 966,921    |     | $          | 430,524    |       |       |       |   |   |   |   |
| Provision for  depreciation, depletion and amortization |       | $        | 248,431    |     | $          | 226,607    |       |       |       |   |   |   |   |

----

(a)           Includes $5,551 ofcosts related to the Danish North Sea.

(b)          Includes $47,893 ofcumulative asset retirement cost recorded to adopt the provisions of SFAS 143on January 1, 2003.

90

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

The following informationregarding estimates of the Company’s proved oil and gas reserves, which arelocated onshore in the United States and Canada and offshore in United Stateswaters of the Gulf of Mexico is based on reports prepared by Ryder ScottCompany, L.P. and reports prepared by the Company and reviewed by Ryder ScottCompany—Canada and Miller & Lents, Ltd. The definitions andassumptions that serve as the basis for the discussions under the caption “Item1, Business—Exploration and Production Data—Reserves” should be referred to inconnection with the following information.

**Estimatesof Proved Reserves**

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

| ** **                                    | ** ** | **Total  Company** | ** ** | **United  States** | ** ** | **Canada** | ** ** |
|-----------------------------------------------|------------|--------------------|------------|--------------------|------------|------------|------------|
| Proved Reserves  as of December 31, 2002 |       | 80,092,262         |       | 80,092,262         |       | —     |       |
| Revisions of previous estimates               |       | 6,338,668          |       | 6,338,668          |       | —     |       |
| Extensions, discoveries and other additions   |       | 2,982,400          |       | 2,982,400          |       | —     |       |
| Purchase of properties                        |       | 4,301,200          |       | 4,301,200          |       | —     |       |
| Estimated 2003 production                     |       | (16,162,000        | )          | (16,162,000        | )          | —     |       |
| Proved Reserves  as of December 31, 2003 |       | 77,552,530         |       | 77,552,530         |       | —     |       |
| Revisions of previous estimates               |       | 5,012,763          |       | 5,012,763          |       | —     |       |
| Extensions, discoveries and other additions   |       | 1,727,761          |       | 1,727,761          |       | —     |       |
| Purchase of properties                        |       | 13,775,000         |       | 13,775,000         |       | —     |       |
| Sale of properties                            |       | (1,832,000         | )          | (1,832,000         | )          | —     |       |
| Estimated 2004 production                     |       | (12,370,000        | )          | (12,370,000        | )          | —     |       |
| Proved Reserves  as of December 31, 2004 |       | 83,866,054         |       | 83,866,054         |       | —     |       |
| Revisions of previous estimates               |       | 5,513,972          |       | 5,537,272          |       | (23,300    | )          |
| Extensions, discoveries and other additions   |       | 4,884,697          |       | 1,801,097          |       | 3,083,600  |       |
| Purchase of properties                        |       | 60,688,379         |       | 588,379            |       | 60,100,000 |       |
| Estimated 2005 production                     |       | (10,912,237        | )          | (9,554,925         | )          | (1,357,312 | )          |
| Proved Reserves  as of December 31, 2005 |       | 144,040,865        |       | 82,237,877         |       | 61,802,988 |       |
| Proved Developed  Reserves as of:             |       |               |       |               |       |       |       |
| December 31, 2002                        |       | 74,041,149         |       | 74,041,149         |       | —     |       |
| December 31, 2003                        |       | 67,391,031         |       | 67,391,031         |       | —     |       |
| December 31, 2004                        |       | 72,968,008         |       | 72,968,008         |       | —     |       |
| December 31,  2005                       |       | 118,573,719        |       | 63,160,705         |       | 55,413,014 |       |

 

91

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

**Estimatesof Proved Reserves**

**Natural Gas (MMcf)**

| ** **                                    | ** ** | **Total  Company** | ** ** | **United  States** | ** ** | **Canada** | ** ** |
|-----------------------------------------------|------------|--------------------|------------|--------------------|------------|------------|------------|
| Proved Reserves  as of December 31, 2002 |       | 713,906            |       | 713,906            |       | —     |       |
| Revisions of previous estimates               |       | 5,686              |       | 5,686              |       | —     |       |
| Extensions, discoveries and other additions   |       | 65,095             |       | 65,095             |       | —     |       |
| Purchase of properties                        |       | 129,119            |       | 129,119            |       | —     |       |
| Estimated 2003 production                     |       | (76,802            | )          | (76,802            | )          | —     |       |
| Proved Reserves  as of December 31, 2003 |       | 837,004            |       | 837,004            |       | —     |       |
| Revisions of previous estimates               |       | (16,357            | )          | (16,357            | )          | —     |       |
| Extensions, discoveries and other additions   |       | 33,610             |       | 33,610             |       | —     |       |
| Purchase of properties                        |       | 172,022            |       | 172,022            |       | —     |       |
| Sale of properties                            |       | (2,888             | )          | (2,888             | )          | —     |       |
| Estimated 2004 production                     |       | (89,410            | )          | (89,410            | )          | —     |       |
| Proved Reserves  as of December 31, 2004 |       | 933,981            |       | 933,981            |       | —     |       |
| Revisions of previous estimates               |       | 7,234              |       | 6,280              |       | 954        |       |
| Extensions, discoveries and other additions   |       | 61,709             |       | 29,063             |       | 32,646     |       |
| Purchase of properties                        |       | 266,110            |       | 6,500              |       | 259,610    |       |
| Estimated 2005 production                     |       | (91,309            | )          | (84,526            | )          | (6,783     | )          |
| Proved Reserves  as of December 31, 2005 |       | 1,177,725          |       | 891,298            |       | 286,427    |       |
| Proved Developed  Reserves as of:             |       |               |       |               |       |       |       |
| December 31, 2002                        |       | 600,255            |       | 600,255            |       | —     |       |
| December 31, 2003                        |       | 702,836            |       | 702,836            |       | —     |       |
| December 31, 2004                        |       | 769,753            |       | 769,753            |       | —     |       |
| December 31,  2005                       |       | 906,005            |       | 685,301            |       | 220,704    |       |

 

92

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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.                Estimates are madeof quantities of proved reserves and the future periods in which they areexpected to be produced based on year-end economic conditions.

2.                The estimatedfuture gross revenues from proved reserves are priced on the basis of year-endmarket prices, except in those instances where fixed and determinable naturalgas price escalations are covered by contracts.

3.                The future grossrevenue streams are reduced by estimated future costs to develop and to producethe proved reserves, as well as certain abandonment costs based on year-endcost estimates, and the estimated effect of future income taxes. These costestimates are subject to some uncertainty.

4.                The cash flows arediscounted at 10% per annum.

Thestandardized measure of discounted future net cash flows does not purport topresent the fair value of the Company’s oil and gas reserves. An estimate offair value would also take into account, among other things, the recovery ofreserves in excess of proved reserves, anticipated future changes in prices andcosts, a discount factor more representative of the time value of money and therisks inherent in reserve estimates.

| ** **                                                                                             | ** ** | **Year Ended December 31, 2005** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                                                             | ** ** | **Total Company**                               | ** ** | **United States** | ** ** | **Canada** | ** ** |
| Future gross  revenues                                                                                 |       |                                                 | $          | 16,504,944 |   |   | $ | 11,670,396 |   | $ | 4,834,548 |   |
| Future production  costs                                                                               |       |                                                 | (3,754,999 | ) |   | (2,585,215 | ) | (1,169,784 | ) |
| Future  development and abandonment costs                                                              |       |                                                 | (914,104   | ) |   | (709,555 | ) | (204,549 | ) |
| Future net cash  flows before income taxes                                                             |       |                                                 | 11,835,841 |   |   | 8,375,626 |   | 3,460,215 |   |
| Discount at 10%  per annum                                                                             |       |                                                 | (5,215,283 | ) |   | (3,709,154 | ) | (1,506,129 | ) |
| Discounted future  net cash flows before income taxes                                                  |       |                                                 | 6,620,558  |   |   | 4,666,472 |   | 1,954,086 |   |
| Future income  taxes, net of discount at 10% per annum                                                 |       |                                                 | (2,057,713 | ) |   | (1,445,038 | ) | (612,675 | ) |
| Standardized measure of  discounted future net cash  flows related to proved oil and gas reserves |       |                                                 | $          | 4,562,845 |   |   | $ | 3,221,434 |   | $ | 1,341,411 |   |

 

| ** **                                                                                      | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                      | ** ** | **2004**                                   | ** ** | **2003** | ** ** |
| Future gross  revenues                                                                          |       | $                                          | 8,850,237  |   | $ | 6,912,547 |   |
| Future production  costs                                                                        |       | (2,123,530                                 | )          | (1,417,118 | ) |
| Future  development and abandonment costs                                                       |       | (437,117                                   | )          | (324,813 | ) |
| Future net cash  flows before income taxes                                                      |       | 6,289,590                                  |       | 5,170,616 |   |
| Discount at 10%  per annum                                                                      |       | (2,650,272                                 | )          | (2,241,953 | ) |
| Discounted future  net cash flows before income taxes                                           |       | 3,639,318                                  |       | 2,928,663 |   |
| Future income  taxes, net of discount at 10% per annum                                          |       | (1,080,607                                 | )          | (919,540 | ) |
| Standardized measure of  discounted future netcash flows related to proved oil and gas reserves |       | $                                          | 2,558,711  |   | $ | 2,009,123 |   |

 

93

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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)**

The following arethe principal sources of change in the standardized measure of discountedfuture net cash flows.

| ** **                                                                                 | ** ** | **For the Year Ended December 31, 2005** | ** ** |
|--------------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                                                 | ** ** | **Total Company**                                                 | ** ** | **United States** | ** ** | **Canada** | ** ** |
| Beginning balance                                                                          |       |                                                                   | $          | 2,558,711 |   |   |   | $ | 2,558,711 |   |   | $ | — |   |
| Revisions to prior  years’ proved reserves:                                           |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Net changes in prices and production costs                                                 |       |                                                                   | 1,528,299  |   |   |   | 1,528,299 |   |   | — |   |
| Net changes due to revisions in quantity estimates                                         |       |                                                                   | 142,471    |   |   |   | 150,026 |   |   | (7,555 | ) |
| Net changes in estimates of future development costs                                       |       |                                                                   | (334,605   | ) |   |   | (334,605 | ) |   | — |   |
| Accretion of discount                                                                      |       |                                                                   | 363,932    |   |   |   | 363,932 |   |   | — |   |
| Changes in production rate and other                                                       |       |                                                                   | 215,382    |   |   |   | (154,108 | ) |   | 369,490 |   |
| Total revisions                                                                            |       |                                                                   | 1,915,479  |   |   |   | 1,553,544 |   |   | 361,935 |   |
| New field  discoveries and extensions, net of future production and development costs |       |                                                                   | 339,394    |   |   |   | 145,537 |   |   | 193,857 |   |
| Purchases of  properties                                                                   |       |                                                                   | 1,542,005  |   |   |   | 32,207 |   |   | 1,509,798 |   |
| Sales of oil and  gas produced, net of production costs                                    |       |                                                                   | (976,009   | ) |   |   | (864,505 | ) |   | (111,504 | ) |
| Previously  estimated development costs incurred                                           |       |                                                                   | 160,371    |   |   |   | 160,371 |   |   | — |   |
| Net change in  income taxes                                                                |       |                                                                   | (977,106   | ) |   |   | (364,431 | ) |   | (612,675 | ) |
| Net change in standardized measureof discounted  future net cash flows                     |       |                                                                   | 2,004,134  |   |   |   | 662,723 |   |   | 1,341,411 |   |
| Ending balance                                                                             |       |                                                                   | $          | 4,562,845 |   |   |   | $ | 3,221,434 |   |   | $ | 1,341,411 |   |

 

| ** **                                                                                 | ** ** | **For the Years Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                                                                 | ** ** | **2004**                                                 | ** ** | **2003** | ** ** |
| Beginning balance                                                                          |       | $                                                        | 2,009,123  |   | $ | 1,714,788 |   |
| Revisions to prior  years’ proved reserves:                                           |       |                                                     |       |   |   |
| Net changes in prices and production costs                                                 |       | 631,060                                                  |       | 434,060 |   |
| Net changes due to revisions in quantity estimates                                         |       | 39,661                                                   |       | 113,329 |   |
| Net changes in estimates of future development costs                                       |       | (154,659                                                 | )          | (21,781 | ) |
| Accretion of discount                                                                      |       | 292,866                                                  |       | 249,556 |   |
| Changes in production rate and other                                                       |       | (51,192                                                  | )          | (182,172 | ) |
| Total revisions                                                                            |       | 757,736                                                  |       | 592,992 |   |
| New field  discoveries and extensions, net of future production and development costs |       | 126,167                                                  |       | 241,946 |   |
| Purchases of  properties                                                                   |       | 596,173                                                  |       | 289,484 |   |
| Sales of  properties                                                                       |       | (58,570                                                  | )          | — |   |
| Sales of oil and  gas produced, net of production costs                                    |       | (808,986                                                 | )          | (737,628 | ) |
| Previously  estimated development costs incurred                                           |       | 98,135                                                   |       | 46,311 |   |
| Net change in income  taxes                                                                |       | (161,067                                                 | )          | (138,770 | ) |
| Net change in standardized measure of discounted future net cash flows           |       | 549,588                                                  |       | 294,335 |   |
| Ending balance                                                                             |       | $                                                        | 2,558,711  |   | $ | 2,009,123 |   |

 

94

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**Quarterly Results—Unaudited**

Summariesof the Company’s results of operations by quarter for the years 2005 and 2004are as follows:

| ** **                                              | ** ** | **Quarter Ended**                                                               | ** ** |
|---------------------------------------------------------|------------|--------------------------------------------------------------------------------------|------------|
| ** **                                              | ** ** | **Mar. 31**                                                                     | ** ** | **June 30** | ** ** | **Sept. 30** | ** ** | **Dec. 31** | ** ** |
| ** **                                              | ** ** | **(Expressed in thousands, except per share amounts)** | ** ** |
| **2005**                                                |       |                                                                                 |       |   |   |   |   |   |   |
| Revenues                                                |       | $                                                                                    | 255,746    |   | $ | 274,564 |   | $ | 275,812 |   | $ | 419,577 |   |
| Gross profit(a)                                         |       | $                                                                                    | 92,424     |   | $ | 144,757 |   | $ | 152,200 |   | $ | 206,321 |   |
| Income from  continuing operations                      |       | $                                                                                    | 39,509     |   | $ | 73,978 |   | $ | 61,903 |   | $ | 114,679 |   |
| Income (loss)  from discontinued operations, net of tax |       | $                                                                                    | 19,727     |   | $ | 29,461 |   | $ | 411,625 | (c) | $ | (179 | ) |
| Net income                                              |       | $                                                                                    | 59,236     |   | $ | 103,439 |   | $ | 473,528 |   | $ | 114,500 |   |
| Basic earnings per  share(b):                           |       |                                                                                 |       |   |   |   |   |   |   |
| Income from continuing operations                       |       | $                                                                                    | 0.62       |   | $ | 1.23 |   | $ | 1.04 |   | $ | 1.98 |   |
| Income (loss) from discontinued operations              |       | $                                                                                    | 0.31       |   | $ | 0.48 |   | $ | 6.92 |   | $ | — |   |
| Basic earnings per share                                |       | $                                                                                    | 0.93       |   | $ | 1.71 |   | $ | 7.96 |   | $ | 1.98 |   |
| Diluted earnings per  share(b):                         |       |                                                                                 |       |   |   |   |   |   |   |
| Income from continuing operations                       |       | $                                                                                    | 0.63       |   | $ | 1.22 |   | $ | 1.03 |   | $ | 1.96 |   |
| Income (loss) from discontinued operations              |       | $                                                                                    | 0.30       |   | $ | 0.48 |   | $ | 6.86 |   | $ | — |   |
| Diluted earnings per share                              |       | $                                                                                    | 0.93       |   | $ | 1.70 |   | $ | 7.89 |   | $ | 1.96 |   |
| **2004**                                                |       |                                                                                 |       |   |   |   |   |   |   |
| Revenues                                                |       | $                                                                                    | 235,133    |   | $ | 250,697 |   | $ | 259,711 |   | $ | 242,147 |   |
| Gross profit(a)                                         |       | $                                                                                    | 125,183    |   | $ | 136,991 |   | $ | 132,748 |   | $ | 93,419 |   |
| Income from  continuing operations                      |       | $                                                                                    | 66,701     |   | $ | 67,080 |   | $ | 69,004 |   | $ | 46,250 |   |
| Income (loss)  from discontinued operations, net of tax |       | $                                                                                    | 4,939      |   | $ | (1,891 | ) | $ | 17,608 |   | $ | (7,937 | ) |
| Net income                                              |       | $                                                                                    | 71,640     |   | $ | 65,189 |   | $ | 86,612 |   | $ | 38,313 |   |
| Basic earnings per  share(b):                           |       |                                                                                 |       |   |   |   |   |   |   |
| Income from continuing operations                       |       | $                                                                                    | 1.05       |   | $ | 1.05 |   | $ | 1.08 |   | $ | 0.72 |   |
| Income (loss) from discontinued operations              |       | $                                                                                    | 0.08       |   | $ | (0.03 | ) | $ | 0.28 |   | $ | (0.12 | ) |
| Basic earnings per share                                |       | $                                                                                    | 1.13       |   | $ | 1.02 |   | $ | 1.36 |   | $ | 0.60 |   |
| Diluted earnings per  share(b):                         |       |                                                                                 |       |   |   |   |   |   |   |
| Income from continuing operations                       |       | $                                                                                    | 1.04       |   | $ | 1.04 |   | $ | 1.07 |   | $ | 0.72 |   |
| Income (loss) from discontinued operations              |       | $                                                                                    | 0.08       |   | $ | (0.03 | ) | $ | 0.28 |   | $ | (0.13 | ) |
| Diluted earnings  per share                             |       | $                                                                                    | 1.12       |   | $ | 1.01 |   | $ | 1.35 |   | $ | 0.59 |   |

----

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

(b)   The sum ofthe 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.

(c)    Includes approximately $403 million of after-tax gain on the saleof the Company’s Thailand operations.

**ITEM 9.     Changesin and Disagreements With Accountants on Accounting and Financial Disclosure.**

None.

95

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**ITEM 9A.   Controlsand Procedures.**

**Evaluationof Disclosure Controls and Procedures**

The Company’s managementhas evaluated, as of the end of the period covered by this report, with thesupervision and participation of its Chairman, President and Chief ExecutiveOfficer and its Senior Vice President and Chief Financial Officer, theeffectiveness of the Company’s disclosure controls and procedures as defined byRules 13a-15(e) and 15d-15(e) under the SecuritiesExchange Act of 1934. Based on that evaluation, such officers concluded thatthe disclosure controls and procedures were effective as of the date of thatevaluation.

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

The Company’s management is responsible forestablishing and maintaining adequate internal control over financialreporting, 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, 2005. The Company excluded theCanadian division from our assessment of internal control over financialreporting as of December 31, 2005 because the division was formed with theacquisition of Northrock Resources Ltd. in a purchase business combination onSeptember 27, 2005. The Canadian division is a wholly-owned subsidiary ofthe Company whose total assets and total revenues represent 49% and 11%, respectively,of the related consolidated financial statement amounts, as of and for the yearended December 31, 2005.

The Company’s management’sassessment of the effectiveness of our internal control over financialreporting as of December 31, 2005 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.  OtherInformation.**

None.

96

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**PART III**

**ITEM 10.**         *Directorsand 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 25, 2006, to be filedwithin 120 days of December 31, 2005 pursuant to Regulation 14A under theSecurities Exchange Act of 1934, as amended (the Company’s “2006 ProxyStatement”), is incorporated herein by reference. See also Item S-K 401(b) appearingin Part I of this Form 10-K.

**ITEM 11.**         *ExecutiveCompensation*.

The information responsiveto Item 402 of Regulation S-K in the Company’s 2006 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 considered “filed” with the Commission.

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

The information responsiveto Items 201(d) and 403 of Regulation S-K in the Company’s 2006 Proxy Statementis incorporated herein by reference.

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

The information responsiveto Item 404 of Regulation S-K in the Company’s 2006 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 2006 Proxy Statement isincorporated herein by reference.

**PART IV**

**ITEM 15.**         *Exhibits and 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                                              |       |   | 54         | ** ** |   |
|   |       | Consolidated Statements of Income for the Years Ended  December 31, 2005, 2004 and 2003          |       |   | 56         | ** ** |   |
|   |       | Consolidated  Balance Sheets as of December 31, 2005 and 2004                                    |       |   | 57         | ** ** |   |
|   |       | Consolidated  Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and  2003     |       |   | 59         | ** ** |   |
|   |       | Consolidated Statements of Shareholders’ Equity                                                  |       |   | 61         | ** ** |   |
|   |       | Notes to Consolidated Financial Statements for the  Years Ended December 31, 2005, 2004 and 2003 |       |   | 62         | ** ** |   |
|   |       | Unaudited Supplementary Financial and Reserves Data                                                   |       |   | 89         | ** ** |   |

 

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

All Financial Statement Schedules have been omittedbecause they are not required, are not applicable or the information requiredhas been included elsewhere herein.

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**3.****                Exhibits:**

| *2.1 |   | Share Purchase Agreement dated July 8, 2005  among Unocal Canada Limited, Unocal Canada Alberta Hub Limited, Unocal  Corporation, Pogo Canada, ULC and Pogo Producing Company (a copy of any omitted  schedule will be furnished supplementally to the Commission upon request)  (Exhibit 10.1, Current Report on Form 8-K filed July 12,  2005, File No. 1-7792).                                                                                                                                                                                                                            |
|------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *2.2 |   | Stock Purchase Agreement dated as of June 17,  2005 among Pogo Producing Company and Pogo Overseas Production B.V., as  sellers, PTTEP Offshore Investment Company Limited and Mitsui Oil Exploration  Co., Ltd., as purchasers, and PTT Exploration and Production Public Company  Limited, as guarantor for PTTEP Offshore Investment Company Limited (a copy  of any omitted schedule will be furnished supplementally to the Commission  upon request) (Exhibit 2.1, Quarterly Report on Form 10-Q for  the quarter ended June 30, 2005, File No. 1-7792).                                |
| *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. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                            |
| *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 |   | Indenture, dated as of March 29, 2005 between  Pogo Producing Company and The Bank of New York Trust Company, N.A., as  Trustee (Exhibit 4.1, Quarterly Report on Form 10-Q for the  quarter ended March 31, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                          |
| *4.2 |   | Form of 6.625% Senior Subordinated Note  (Exhibit 4.1, Quarterly Report on Form 10-Q for the quarter  ended March 31, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| *4.3 |   | Registration Rights Agreement dated March 29,  2005, by and among Pogo Producing Company and the parties thereto  (Exhibit 4.3, Quarterly Report on Form 10-Q for the quarter  ended March 31, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                        |
| *4.4 |   | Indenture dated as of September 23, 2005  between Pogo Producing Company and The Bank of New York Trust Company, N.A.  (Exhibit 4.1, Current Report on Form 8-K filed  September 29, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                  |
| *4.5 |   | Form of 6.875% Senior Subordinated Note  (Exhibit 4.1, Current Report on Form 8-K filed  September 29, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
| *4.6 |   | Registration Rights Agreement dated as of  September 23, 2005 among Pogo Producing Company and the initial  purchasers named therein (Exhibit 4.2, Current Report on Form 8-K  filed September 29, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                    |
| *4.7 |   | 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). |

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| *4.8   |   | First Amendment to Credit Agreement, dated as of  August 31, 2005 but effective as of September 27, 2005, among Pogo  Producing Company, the various financial institutions which are or may become  parties to the Credit Agreement, as amended thereby (collectively, the  “Lenders”), Bank of Montreal, as administrative agent for the Lenders, Bank  of America, N.A., Toronto Dominion (Texas) LLC and BNP Paribas, as  Co-Syndication Agents for the Lenders, Wachovia Bank, National Association,  as Documentation Agent for the Lenders, and Citibank, N.A. and The Bank of  Nova Scotia, as managing agents for the Lenders (Exhibit 4.3, Current  Report on Form 8-K filed September 29, 2005, File No. 1-7792). |
|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *4.9   |   | 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| *4.10  |   | 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| *4.11  |   | 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 10.34,inclusive)**

| *10.1 |   | 1989 Incentive and Nonqualified Stock Option Plan of  Pogo Producing Company, as amended and restated effective January 25,  1994 (Exhibit 99, Definitive Proxy Statement on Schedule 14A, filed  March 22, 1994, File No. 1-7792).                                    |
|-------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *10.2 |   | Form of Stock Option Agreement under 1989  Incentive and Nonqualified Stock Option Plan, as amended and restated  effective January 22, 1991 (Exhibit 10(d)(1), Annual Report on  Form 10-K for the year ended December 31, 1991, File  No. 0-5468).         |
| *10.3 |   | Form of Director Stock Option Agreement under  1989 Incentive and Nonqualified Stock Option Plan as amended and restated  effective January 22, 1991 (Exhibit 10(d)(2), Annual Report on  Form 10-K for the year ended December 31, 1991, File  No. 0-5468). |
| *10.4 |   | 1995 Long-Term Incentive Plan (Exhibit 4(c),  Registration Statement on Form S-8 filed May 22, 1996, File  No. 333-04233).                                                                                                                                             |
| *10.5 |   | 1998 Incentive Plan (Exhibit 4.7, Registration  Statement on Form S-8 filed August 15, 2002, File  No. 333-98205).                                                                                                                                                     |
| *10.6 |   | 2000 Incentive Plan (Exhibit B to the Company’s  Definitive Proxy Statement filed on Schedule 14A, March 27, 2000, File  No. 001-7792).                                                                                                                                |
| *10.7 |   | 2002 Incentive Plan (Exhibit B to the Company’s  Definitive Proxy Statement filed on Schedule 14A, March 25, 2002, File  No. 001-7792).                                                                                                                                |

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| 10.8   |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and Paul  G. Van Wagenen, dated August 1, 2005.                                            |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.9   |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Stephen R. Brunner, dated August 1, 2005.                                             |
| 10.10  |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Jerry A. Cooper, dated August 1, 2005.                                                |
| 10.11  |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and John  O. McCoy, Jr., dated August 1, 2005.                                        |
| 10.12  |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  David R. Beathard, dated August 1, 2005.                                              |
| 10.13  |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Radford P. Laney, dated August 1, 2005.                                               |
| 10.14  |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and J.  Don McGregor, dated August 1, 2005.                                                |
| 10.15  |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Gerald A. Morton, dated August 1, 2005.                                               |
| 10.16  |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  James P. Ulm, II, dated August 1, 2005.                                          |
| 10.17  |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Bruce E. Archinal, dated August 1, 2005.                                              |
| 10.18  |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Michael J. Killelea, dated August 1, 2005.                                            |
| *10.32 |   | Form of Restricted Stock Award Agreement Under  Incentive Plans (Exhibit 10.2, Current Report on Form 8-K  filed August 1, 2005, 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 |   | Pogo Producing Company Retention Incentive Plan  effective September 27, 2005 (Exhibit 10.4, Quarterly Report on  Form 10-Q for the quarter ended September 30, 2005, File  No. 1-7792). |
| 12.1   |   | Statement showing computation of ratios of earnings  to fixed charges.                                                                                                                                            |
| 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 Ryder Scott Company - Canada                                                                                                                                                                           |
| 23.4   |   | Consent of Miller and Lents, Ltd.                                                                                                                                                                                 |
| 24     |   | Powers of Attorney from each director of Pogo  Producing Company whose signature is affixed to this Form 10-K for  year ended December 31, 2005.                                                        |
| 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.                                                                                                                               |

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| 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, 2005.                                                                                                 |
| 99.2  |   | Summary Report of Ryder Scott Company—Canada for the  year ended December 31, 2005.                                                                                           |
| 99.3  |   | Summary Report of Miller and Lents, Ltd. for the  year ended December 31, 2005.                                                                                                    |
| *99.4 |   | Summary Report of Ryder Scott Company, L.P. for the  year ended December 31, 2004 (Exhibit 99.1, Annual Report on  Form 10-K for the year ended December 31, 2004). |
| *99.5 |   | Summary Report of Miller and Lents, Ltd. for the  year ended December 31, 2004 (Exhibit 99.2, Annual Report on  Form 10-K for the year ended December 31, 2004).    |
| *99.6 |   | 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). |
| *99.7 |   | 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).    |

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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 2, 2006 |                      |   |

 

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, 2006.

|                                                     | **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/ CHARLES G. GROAT                                |           |                                     |
| **Charles G. Groat**                                |           | Director                                 |

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| /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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