**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON,D.C. 20549**

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**FORM 10-K/A**

**(Amendment No. 1)**

| **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 October 24, 2006** |
|-----------------------------------------|------------|-------------------------------------|
| Common Stock, $1.00 par value per share |       | 58,389,247 shares                   |

 

**DOCUMENTSINCORPORATED BY REFERENCE**

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

 

 

 

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**EXPLANATORY NOTE**

Pogo Producing Company (the“Company”) is filing this amendment to its Annual Report on Form 10-Kfor the fiscal year ended December 31, 2005 that was originally filed onMarch 2, 2006 (the “Original 10-K”) in response to comments receivedfrom the Securities and Exchange Commission. This amendment includes thefollowing items:

·       “Item 1—*Business*,”revised to enhance disclosures regarding certain of the Company’s properties;

·       “Item 1A—*Risk Factors*,”revised to change the title of the risk factor “The Company’s reserve data are estimates andshould not be unduly relied on” to “The Company’s reserve data are estimates;”

·       “Item 8—*Financial Statements andSupplementary Data*,” revised to provide additional disclosurerelating to properties accounted for as discontinued operations in theUnaudited Supplementary Financial and Reserve Data and the Standardized Measureof Discounted Future Net Cash Flows Related to Proved Oil andGas Reserves; and

·       “Item 15—*Exhibits and FinancialStatement Schedules*,” revised to refer tocertain previously-filed agreements and to make other conforming changes as aresult of the filing of this amendment.

**Other than as specifiedabove, this amendment does not modify or affect the financial statements or thenotes thereto in the Original 10-K*.*****This amendment does notreflect events occurring after the filing of the Original 10-K and doesnot modify or update the disclosures therein in any way other than as requiredto reflect the amendments as described above and set forth below. In accordancewith Rule 12b-15 promulgated under the Securities Exchange Act of1934, the complete text of each affected item, as amended, is included herein.Unaffected items have not been repeated in this amendment.

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**FORWARD LOOKINGSTATEMENTS**

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:

·       the cyclical nature of theoil and natural gas industries

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

·       uncertainties associatedwith the United States and worldwide economies

·       current and potentialgovernmental regulatory actions in countries where the Company operates

·       substantial competitionfrom larger companies

·       the Company’s ability toimplement cost reductions

·       the Company’s ability toacquire and integrate oil and gas reserves

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

·       fluctuations in foreigncurrency exchange rates in areas of the world where the Company conductsoperations

·       covenant restrictions inthe Company’s debt agreements

Many of thesefactors are beyond the Company’s ability to control or predict. Managementcautions against putting undue reliance on forward-looking statements orprojecting any future results based on such statements or present or priorearnings levels.

All subsequent written and oral forward-lookingstatements attributable to the Company and persons acting on the Company’sbehalf are qualified in their entirety by the Cautionary Statements containedin this section and elsewhere in this Annual Report.

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**CERTAIN DEFINITIONS**

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

**PART I**

**ITEM 1.**   *Business*.

The Company wasincorporated in 1970 and is engaged in oil and gas exploration, development,acquisition and production activities on its properties primarily located inNorth America, both onshore and offshore, and in New Zealand. As of December 31,2005, the Company owned approximately 3,885,000 gross leasehold acres in majoroil and gas provinces in North America and approximately 1,044,000 gross acresin New Zealand. Over the last several years, the Company has transitioned froma predominately offshore-focused company to one with a majority of its reserveslocated in the onshore regions of North America. As of December 31, 2005,approximately 86% of the Company’s reserves are located onshore.

The Companyorganizes its exploration and production activities principally into fiveoperating regions, as well as a New Ventures Group and an UnconventionalResources Group. The operating regions are its Canadian Operations, its WesternU.S. Region, which is active in the Permian Basin area in New Mexico and WestTexas, the Panhandle of Texas, the San Juan Basin in New Mexico and in theMadden Unit in Wyoming; its Gulf CoastRegion, which includes the Company’s onshore operations principally in SouthTexas and Louisiana; its Gulf of Mexico Region, which is responsible for theCompany’s operations offshore Texas and Louisiana in the Gulf of Mexico; andthe Asia and Pacific Region, which has responsibility for the Company’soperations in New Zealand. The Company’s New Ventures Group is primarilyresponsible for identifying new projects and opportunities for the Companyoutside the United States and the Unconventional Resources Group is responsiblefor identifying new unconventional resource opportunities in North America.

On August 17, 2005, the Company closed the saleof its Thailand properties for approximately $820 million. On September 27,2005, the Company completed the acquisition of Northrock Resources, Ltd. (“Northrock”)for approximately $1.7 billion. Northrock’s activities are concentrated inSaskatchewan and Alberta with key exploration plays in Canada’s NorthwestTerritories, British Columbia and the Alberta Foothills.

**DomesticOnshore Operations**

The Company’s Gulf Coast Region is headquartered inHouston, Texas, with field offices in Laredo and Manvel, Texas and Thibodaux,Louisiana. The Company’s Western U.S. Region has an office in Midland, Texas,two field offices in southeastern New Mexico, one field office in West Texasand two field offices in the Texas Panhandle. The Company conducts its onshoreoperations in the United States directly and through its wholly-ownedsubsidiaries. Domestic onshore reserves as of December 31, 2005, accountedfor approximately 54% of the Company’s total proved reserves, with the GulfCoast Region and the Western U.S. Region contributing approximately 15% and39%, respectively, of the Company’s total 

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proved reserves. During2005, approximately 79% of the Company’s natural gas production and 38% of itsoil and condensate production was from its domestic onshore properties, contributingapproximately 60% of the Company’s consolidated oil and gas revenues.

The Los Mogotes Field, which is part of theCompany’s Gulf Coast Region, consists of approximately 22,420 acres located in South Texas. The Company ownsvarious working interests in the Los Mogotes Field, which average approximately71%across the field, and is the operator of a majority of thoseworking interests. In 2005, the Company’s interests in Los Mogotes produced anaverage of approximately 53 MMcf per day of natural gas, accounting forapproximately 21% of the Company’s natural gas production for the period. As of December 31, 2005, the Company’s provedreserves associated with the Los Mogotes Field were 41 MBblsof oil, condensate and natural gas liquids and 111,327 MMcf of natural gas, which together represented  approximately5.5% of the Company’s total proved reserves. Asof that date, the Company’s leasehold interests in the fieldincluded 14,380 net acres of developed lands and 902 net acres of undevelopedlands, with approximately 98 net producing wells and 142 gross producing wells. The mapbelow depicts the location of the field.

****

The Madden Unit, which is part of the Company’s WesternRegion, is a federal unit operated by a third party and consists of approximately 80,000 acres of the Wind River Basin located in CentralWyoming. The Company owns various working interests in the Madden Unit, whichaverage approximately 14.5% across the unit area. In 2005, the Company’sinterests in the Madden Unit produced an average of approximately 40 MMcf perday of natural gas, accounting for approximately 16% of the Company’s naturalgas production for the period. As ofDecember 31, 2005, the Company’s proved reserves associated with the Madden Unit were 82 MBblsof oil, condensate and natural gas liquids and 269,823 MMcf of natural gas, which together represented approximately  13.2% of the Company’s total proved reserves. Asof that date, the Company’s leasehold interests in the unitincluded 3,471 net acres of developed lands and 7,351 net acres of undevelopedlands, with approximately 29 netproducing wells and 205 grossproducing wells. The map below depicts the location of the unit.

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*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$177,700,000 of net property acquisitions), respectively. The increase in theCompany’s onshore capital and exploration expenditures for 2005, compared to2004, 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 

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in this area during 2006. Theprimary targets are the Fruitland Coal and Mesaverde formations. Drillingdepths are expected to range from approximately 1,500 feet to 6,500 feet.

TheCompany has actively participated in the exploration and development of theMadden Unit since it first acquired its non-operated working interest in 2001.The Madden Unit is characterized by gas production from multiple stratigraphichorizons of the Lower Ft. Union, Lance,  Mesaverde and Cody sands and the Madison dolomite. Production from theMadden Unit is typically found at depths ranging from 5,500 to 20,000 feet  and  24,000 to 25,000 feet.  Some of the gas  producedfrom  the Madden Unit requires processing bythe Lost Cabin Gas Plant (inwhich the Company owns a partial interest) to make it pipeline quality. ****Of the 210 wells drilled in the Western Region in 2005, 66 ofthose wells were drilled in the Madden Unit, 88% of which were successfullycompleted.  The Company continues to activelyparticipate in the exploration and development of the Madden Unit and expects  the operatorof the unit  to conduct a drilling program of approximately61 development wells and one exploratory well in 2006. Recent drillingactivity in the unit has focused on the Lower Fort Union formation, whereproductive zones have historically been found from approximately 5,500 feet to11,000 feet below the surface. Alsoin progress is an exploratory test well with aprojected total depth of 20,585 feet in theFrontier horizon, located above the Madison dolomite.****

During 2005, the Company’sWestern U.S. Region acquired, in several transactions, proved producingproperties located in southeast New Mexico, West Texas and the Texas Panhandleto complement its existing asset base. The aggregate purchase price for thesetransactions was approximately $46 million.

*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 Wilcoxformation, found at depths ranging from 7,000 to 14,000 feet below the surface.Currently, five wells are scheduled to be drilled in South Hundido and HundidoField in 2006. Elsewhere in South Texas, the Company operated and successfullycompleted an appraisal gas well offsetting the 2004 South Rosita Prospectdiscovery well in Duval County, Texas. Additional development drilling isplanned for this prospect during 2006. The Company also intends to activelyexplore various portions of the Vicksburg and Wilcox trends of Texas during2006.

The Company has actively participated in thedevelopment of the Los Mogotes Field since it acquired its initial interest in2001. The field is characterized by gas production from the Asche, Charco andLobo members of the Wilcox formation, found at depths ranging from 7,000 to14,000 feet below the surface. During 2005, the Company participated in drilling 10 wells inthis field, all of which were successfully completed. The Company plans tocontinue an active drilling program in Los Mogotes during 2006, with 49locations identified to be drilled and 25 of those budgeted to be drilled in2006.

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 

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three outside-operatedexploratory wells. In addition, the Company will operate four exploratory testsin this area in 2006. The Company also plans to operate and begin to acquire 100-plussquare miles of new 3-D seismic in central South Louisiana.

In October 2005, theCompany obtained a 50% working interest in an unconventional resource play insouthwest Indiana that an industry partner operates. Approximately 225,000gross acres have been leased, seven horizontal New Albany Shale gas wells havebeen drilled and gas from a production pilot comprised of four of those wellsis being produced and sold. Five exploratory wells and an additional 5 to 15development 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.

During 2005, the Company’s wells in the Main PassBlock 61/62 Field, which is located on thecontinental shelf off the southeastern tip of Louisiana, produced an average ofapproximately 9,800 Bbls/d of oil, condensate and natural gas liquids,accounting for approximately 38% of the Company’s liquid hydrocarbon productionfor the period. As ofDecember 31, 2005, the Company’s proved reserves for the Main Pass Block 61/62 Field were 16,477 MBbls of oil, condensate and natural gasliquids and 13,530 MMcf of natural gas, which together represented  approximately 5.5% of theCompany’s total proved reserves. TheCompany is the operator of a 100% working interest in Main Pass Block 61/62Field, subject to a 5% overriding royalty interest in Main Pass Block 61. TheCompany’s interests are owned through federal leases administered by theMinerals Management Service (“MMS”), in which the MMS has retained a 16.67% royalty interest. As of December 31, 2005, the Company’s leasehold interests in the MainPass Block 61/62 Field included 9,989 net acres of developed lands and noundeveloped lands, with 17 net producing wells. In 2005, the field was shut-in for approximately 49 days due to hurricaneactivity.

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The MainPass Block 61/62 Field, which was brought online by the Company in 2002,consists of a series of stratigraphic traps located on a regionally dippingslope, downdip at the Upper Miocene Shelf/Slope break. As of December 31, 2005, the Company is injectingwater for both pressure supportand enhanced recoveryin the two larger reservoirs of the field through injection wells, whileproducing from 17 wells. The mapbelow depicts the location of the field.

*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 ofMexico operations. The Company has currently budgeted approximately $91,000,000for capital and exploration expenditures during 2006 in the Gulf of Mexico, ofwhich $63,600,000 is budgeted for exploration and development wells and$23,300,000 for facilities construction. The Company participated in drillingseven wells during 2005 in the Gulf of Mexico Region, two of which wereconsidered successful. At December 31, 2005, the Company held varyinginterests in 175 producing oil and gas wells in the Gulf of Mexico.

Leases acquired by the Company and other participantsin its bidding groups are customarily committed, on a block-by-block basis, toseparate operating agreements under which the appointed operator supervisesexploration and development operations for the account and at the expense ofthe group. These agreements usually contain terms and conditions that havebecome relatively standardized in the industry. Major decisions regardingdevelopment and operations typically require the consent of at least a majority(in working interest) of the participants. Because the Company generally has ameaningful working interest position, the Company believes it can significantlyinfluence (but not always control) decisions regarding development andoperations on most of the leases in which it has a working interest, eventhough it may not be the operator of a particular lease. The Company is theoperator on all or a portion of 56 of the 88 offshore leases in which it had aninterest as of December 31, 2005.

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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 and mosthas 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 ofDecember 31, 2005, the Company owned interests in 76 federal leases and 12state leases offshore Louisiana and Texas. Federal leases generally haveprimary terms of five, eight or ten years, depending on water depth, and stateleases generally have terms of three or five years, depending on location, ineach case subject to extension by development and production operations.

**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 ofexpenditures related to discontinued Thailand and Hungary operations) for 2005.Expenditures for 2004 and 2003 were approximately $148,900,000 (approximately$5,700,000 excluding Thailand and Hungary operations) and $138,000,000(approximately $67,000 excluding Thailand and Hungary operations), 

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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.Northrock conducts its activities through joint ventures with other oil and gascompanies and operates its properties using field personnel and independentcontractors.

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, Northrock has participated in drilling two wells in theMackenzie Delta and is expected to participate in the drilling of twoadditional wells in the first quarter of 2006.

*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 

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half of the acreage undereach license has been relinquished and the permit holder has substantiallycomplied with the terms of its permits. The Company committed to acquire 3-Dseismic data over at least 1,000 square kilometers of the licenses within thefirst two years of their primary term and to reprocess 433 miles ofexisting 2-D seismic data. During 2004 and early 2005, the Companyexceeded its work obligations with respect to both 3-D seismic dataacquisition and 2-D seismic data reprocessing. The 3-D seismic dataacquired by the Company has been processed and is being analyzed with a goal ofcommitting 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.The Company’s Thailand concession consisted of approximately 608,000 acres inthe central portions of the Gulf of Thailand. The Company recognized an aftertax gain of approximately $403 million on the sale of the Thailand assets for2005.

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’s Discussion and Analysis of Financial Condition and Results ofOperations.”

**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 endedDecember 31, 2005, 2004 and 2003, respectively, see “Financial Statementsand Supplementary Data.”

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 

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Companyalso owns an approximate 15% interest in the Lost Cabin Gas Plant located inthe Madden Unit, which currently isprocessing in excess of 340 MMcf per day.

*Sales*

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

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 in relationshipto 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 discussedabove, the Company has no existing contracts that require the delivery of fixedquantities of 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 

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financial condition. Itcould also result in a reduction of funds available under the Company’s bankcredit facilities. See “Management’s Discussion and Analysis of FinancialCondition and Results of Operations—Liquidity and Capital Resources; CreditAgreement.”

Because it is impossibleto predict future oil and gas price movements with any certainty, the Companyfrom time to time enters into contracts to hedge against future market pricechanges on a portion of its production. While intended to limit the negative effectof price declines, some forms of hedging transactions could effectively limitthe Company’s participation in price increases, which could be significant, forthe covered period. As of December 31, 2005, the Company was a party tocertain natural gas or crude oil option contracts (see “Quantitative andQualitative Disclosures About Market Risk—Current Hedging Activity”). When theCompany does engage in certain types of hedging activities, it may satisfy itsobligations with its own production or by the purchase (or sale) of third-partyproduction. The Company may also offset delivery obligations under thesehedging transactions requiring physical delivery with equivalent agreements,thereby effecting a purely cash transaction.

**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.

TheCompany owns interests in developed and undeveloped oil and gas acreage invarious parts of the world. These ownership interests generally take the formof “working interests” in oil and gas leases that have varying terms. Thefollowing table shows the Company’s interest in developed and undeveloped oiland gas acreage under lease as of December 31, 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.

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(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.

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

Thefollowing table shows the average production (lifting) costs per unit ofproduction during the periods indicated. For a discussion of the Company’saverage daily production and the average sales prices 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)           Production costs wereconverted to common units of measure on the basis of relative energy content.Such production costs exclude all depletion, depreciation and amortizationassociated with property and equipment.

(b)          Total Company averageproduction costs exclude discontinued operations.

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*Productive Wellsand 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 wells thathave 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)           One or more completionsin the same bore hole are counted as one well. The data in the above tableincludes 48 gross (31.3 net) oil wells and 143 gross (8.5 net) natural gaswells with multiple completions.

(b)          The Company was in theprocess 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. TheCompany had no proved developed reserves in Hungary as of December 31,2004 or December 31, 2003.

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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 standardized measure of discounted future netcash flows. Management believes that presentation of PV-10 values isrelevant and useful to the Company’s investors because it presents thediscounted future net cash flows attributable to both the Company’s proved andproved developed reserves prior to taking into account the effect of thenon-property related expense of estimated future income taxes. Because manyfactors that are unique to individual companies may impact the amount of futureincome taxes to be paid, the use of a pre-tax measure such as PV-10provides greater comparability for investors when evaluating companies.Accordingly, investors may utilize the measure as a basis for comparison of therelative size and value of the Company’s reserves to other companies.Management also uses the PV-10 measure when assessing the potentialreturn on investment related to the Company’s oil and gas properties. PV-10is not a measure of financial or operating performance under GAAP, nor shouldit be considered in isolation or as a substitute for the standardized measureof discounted future net cash flows as defined under GAAP. For the Company’spresentation of the standardized measure of discounted future net cash flows,please see “Standardized Measure of Discounted Future Net Cash Flows Related toProved Oil and Gas Reserves—Unaudited” following the notes to the consolidatedfinancial 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 |   |

 

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.

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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 reservesattributable to the Company’s interests, prices in effect at December 31,2005 were used, 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 on authorizationfor expenditure for the proposed work or actual costs for similar projects. Thecurrent operating and development costs were held constant throughout the lifeof the properties. The estimated net cost of abandonment after salvage wasconsidered for the properties. No deduction was made for indirect costs such asgeneral and administrative and overhead expenses, loan 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 estimate is

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a function of the qualityof available data and of engineering and geological interpretation andjudgment. Results of drilling, testing and production subsequent to the date ofthe estimate may justify revision of such estimate, which may be material.Accordingly, reserve estimates are often different from the quantities of oiland gas that are ultimately recovered.

The Company 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 and ForeignTax*

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 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 

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be designated as “hazardouswastes”‘ under RCRA or other applicable statutes. If this were to occur, theCompany would become subject to more rigorous and costly operating and disposalrequirements.

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 or operatesnumerous properties and facilities that for many years have been used forindustrial activities, including oil and gas production operations. Hazardoussubstances, wastes, or hydrocarbons may have been released on or under theproperties owned or leased by the Company, or on or under other locations wheresuch substances have been taken for disposal. In addition, some of theseproperties have been operated by third parties or by previous owners whosetreatment 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 spills in United States waters. The OPA assigns liability to eachresponsible party for oil removal costs and a variety of public and privatedamages. While liability limits apply in some circumstances, a party cannottake advantage of liability limits if the spill was caused by gross negligenceor willful misconduct or resulted from violation of federal safety,construction or operating regulations. Few defenses exist to the liabilityimposed by the OPA. In addition, to the extent the Company’s offshore leaseoperations affect state waters, the Company may be subject to additional stateand local clean-up requirements or incur liability under state and local laws.The OPA also imposes ongoing requirements on responsible parties, includingproof of financial responsibility to cover at least some costs in a potentialspill. The amount of financial responsibility that the Company must currentlydemonstrate for its offshore platforms is $70,000,000. The Company believesthat it currently has established adequate proof of financial responsibilityfor its offshore facilities. However, the Company cannot predict whether thesefinancial responsibility requirements under the OPA amendments will result inthe imposition of substantial additional annual costs to the Company in thefuture or otherwise materially adversely affect the Company. The impact,however, should not be any 

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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 statestatutes as well as Canadian provincial and local laws that regulate theprotection of the health and safety of workers. In addition, the OSHA hazardcommunication standard requires that information be maintained about hazardousmaterials used or produced in operations and that this information be providedto 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 liabilityassociated with future regulations is currently unknown. The Company canprovide no assurances that the direct or indirect costs of such regulationswill not materially 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 facilities during 2006, including, among otherthings, anticipated site restoration costs and the installation ofenvironmental control equipment.

*Other Laws andRegulations*

Various laws and regulations often require permits fordrilling wells and also cover spacing of wells, the prevention of waste of oiland gas including maintenance of certain gas/oil ratios, rates of 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 that couldbe drilled on the Company’s properties and to limit the allowable productionfrom the successful wells completed on the Company’s properties, therebylimiting 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 royalty 

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interest in these federalleases on behalf of the federal government. While the royalty interestpercentage is fixed at the time that the lease is entered into, from time totime the MMS changes or reinterprets the applicable regulations governing itsroyalty interests, and such action can indirectly affect the actual royaltyobligation that the Company is required to pay. However, the Company believesthat the regulations generally do not impact the Company to any greater extentthan 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 www.pogoproducing.com as soon as reasonably practicableafter the Company electronically files such material with, or furnishes it to,the Commission. Additionally, the Company makes available free of charge on itsInternet website:

·       TheCompany’s Code of Business Conduct and Ethics

·       TheCompany’s Corporate Governance Guidelines

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

Any shareholder who sorequests may obtain a printed copy of any of these documents from the Company.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.

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**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.

***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,operational and other benefits from the acquisition due to the following risksand difficulties, 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.

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***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 loss of life, severe damage tofacilities, or pollution or other environmental damage. As a result, theCompany could incur substantial liabilities that could reduce or eliminate thefunds 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 

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may haveto wait for the construction or expansion of pipeline capacity before theCompany 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. Foreign CorruptPractices Act prohibits corporations and individuals, including the Company andits employees, from engaging in certain activities to obtain or retain businessor to influence a person working in an official capacity. Although the Companyhas implemented policies and procedures designed to ensure compliance withthese 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.

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***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 future dependson successful exploration and development activities and/or acquisitions.***

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 generally are not fully insurable. If a significantaccident or other event occurs and is not fully covered by insurance, it couldadversely affect the Company’s operations and financial condition. Moreover,there is no assurance that recoveries for insured events will be sufficient tocover cash flow that the Company would have otherwise generated from affectedproperties.

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***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 gas reserves;

·       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 equityofferings.

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 theavailability of those resources for other capital requirements. Moreover, theuncertainties and risks associated with future performance and revenues, asdescribed in these Risk Factors, will ultimately determine the Company’sliquidity and ability 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 properties or entities to fully assess their deficiencies and capabilities.Even when problems are identified, the other party may be unwilling or unableto provide effective contractual protection against all or part of the problems.Furthermore, the Company may not be entitled to contractual indemnification forcertain liabilities, or it may acquire the properties on an “as is, where is”basis. For a discussion of additional risks 

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associatedwith the Northrock acquisition, see “—The Company’s Acquisition of Northrockmay not be successful,” above.

***The Company’s reserve data are estimates.***

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 costsmay differ materially from those used in net present value estimates, andfuture net 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 theenergy and 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 thetechnologies that the Company currently uses or that it may implement in thefuture may become obsolete, and the Company may be adversely affected.

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***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 tocomply with those laws. Environmental laws may also affect the Company’s coststo acquire properties. The Company does not believe that its environmentalrisks are materially different from those of comparable companies in the oiland gas industry. However, there is no assurance that environmental laws willnot, in the future, result in decreased production, substantially increasedoperational costs or other adverse effects to the Company’s combined operationsand financial condition. Pollution and similar environmental risks generallyare not 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.

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

31

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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 more restrictivecovenants on the Company.

32

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**PART II**

**ITEM 8.   *Financial Statements and Supplementary Data***.

REPORT OF INDEPENDENTREGISTERED PUBLIC ACCOUNTING FIRM

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 financial statementsbased on our audits. We conducted our audits of these statements in accordancewith the standards of the Public Company Accounting Oversight Board (UnitedStates). Those standards require that we plan and perform the audit to obtainreasonable 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 obligationseffective January 1, 2003.

*Internal controlover financial reporting*

Also, in our opinion, management’s assessment,included in Management’s Report on Internal Control Over Financial Reportingappearing under Item 9A, that the Company maintained effective internal controlover financial reporting as of December 31, 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 

33

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and evaluating the designand operating effectiveness of internal control, and performing such otherprocedures as we consider necessary in the circumstances. We believe that ouraudit 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 thecompany; and (iii) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

Because of its 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

34

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**POGO PRODUCING 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.

35

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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,  and65,275,106  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.

38

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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.

39

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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.

40

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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.

41

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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 |   |

 

42

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

As of December 31,2005, the Company has no exploratory well costs that have been capitalized fora period greater than one year since the completion of drilling.

Interest costs related tofinancing major oil and gas projects in progress are capitalized until theprojects are evaluated or until the projects are substantially complete andready for their intended use if the projects are evaluated as successful. Otherexploratory costs are expensed as incurred. The provision for depreciation,depletion and amortization is based on the capitalized costs as determinedabove, and is computed on a cost center by cost center basis using the units ofproduction method, with lease acquisition costs amortized over total provedreserves and other costs amortized over proved developed reserves. Generally,the Company establishes cost centers on the basis of an oil or gas trend orplay for its onshore oil and gas activities. The Company generally creates costcenters on a field-by-field basis for oil and gas activities in the Gulf ofMexico. As described further below, the Company’s method of accounting forasset retirement obligations (i.e. future abandonment costs) changed effective January 1,2003.

The Company has from timeto time disposed of certain non-core properties and other assets that itconsiders to be under performing, to have little or no remaining upsidepotential, or which face significant future expenditures that would result inan unacceptable rate of return. Refer to the captions “(Gains) losses on sales”in the Consolidated Statements of Cash Flows.

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

*Income Taxes—*

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

*Price Risk Management—*

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 AccountingStandards No. 133 “Accounting for Derivative Instruments and HedgingActivities” (“SFAS 133”). SFAS 133, as amended, established accounting andreporting standards requiring that every derivative instrument (includingcertain derivative instruments embedded in other contracts) be recorded in thebalance sheet as either an asset or liability measured at its fair value. Thestatement requires that changes in the derivative’s fair value be recognizedcurrently in earnings unless specific hedge criteria are met. Specialaccounting for qualifying hedges allows a derivative’s gains and losses tooffset related results on the hedged item in the income statement, and requiresthat a company must formally document, designate and assess the effectivenessof transactions that receive hedge accounting. Based on the nature ofderivative instruments used by the Company, the historical volatility of oiland gas commodity prices and the recent production disruptions resulting fromhurricanes, the Company expects that SFAS 133 could increase volatility in theCompany’s earnings and other comprehensive income for future periods duringwhich derivative instruments are outstanding.

43

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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.’’ Forthose derivative instruments that do not qualify as a cash flow hedgeinstrument, the Company recognizes all future changes in the fair value ofthese instruments in the consolidated statement of income for the period inwhich the change occurs under the caption “Commodity derivative 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. The repurchased shares will be accounted for astreasury stock. As of December 31, 2005, the Company had completed thepurchase of 7,310,000 shares at a total cost 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” (“SFAS148”), for all Stock Awards granted, modified or settled after January 1,2003. On January 1, 2006, the Company will adopt the provisions of SFAS No. 123(revised 2004) (“SFAS 123R”), “Share-Based Payment”, which replaces the provisionsof SFAS 123. The adoption of SFAS 123R is not expected to have a materialeffect on the Company’s financial 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 

44

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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 netincome, 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 wasestimated on the date of grant using the Black-Scholes option pricing modelwith the following weighted-average assumptions used in 2004 and 2003,respectively: risk free interest rates of 3.00% and 2.30%, expected volatilityof 25.7% and 28.4%, dividend yields of 0.48% and 0.61%, and an expected life ofthe options of three and a half and three years. No stock options were grantedin 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 not disclosedin the Consolidated Statements of Cash Flows. Significant non-cash transactionsare disclosed in the Consolidated Statements of Shareholders’ Equity relatingto shares issued as compensation and in Note 14 relating to assetretirement 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 

45

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

foreigncurrency are remeasured to U.S. dollars at the rate of exchange in effect atthe end of each month or the average for the month, and the resulting gains orlosses on foreign currency transactions are included in the consolidatedstatements of income for the period.

*Prior YearReclassifications—*

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

**(2) Earningsper Share**

Earnings per common share(basic earnings per share) are based on the weighted average number of sharesof common stock outstanding during the periods indicated. Earnings per commonshare and potential common share (diluted earnings per share) consider theeffect of dilutive securities as set out below in thousands, except per shareamounts.

| ** **                                                                                                                                                                                                  | ** ** | **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 asthe exercise prices are above the  average market price for the periodor  the effect of the assumed exercise would be antidilutive |       | —   |       | 25       |       | 467      |       |
| Average price                                                                                                                                                                                               |       | $        | —     |     | $          | 49.02    |       | $ | 41.87 |   |

 

46

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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     | %          |

 

47

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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 assetsand 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 million valuation allowance at December 31, 2005 was related toexploration expenses the Company incurred in its foreign operations. During2005, the Company recorded an additional valuation allowance of $3.3 million,primarily related 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 

48

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

thatqualifies for the temporary incentive. Based on that decision, the Company repatriated  $497 million in extraordinary dividends, asdefined in the Act, during the third quarter of 2005. The Company alsorepatriated an additional $315 million that did not qualify for the temporaryincentive. As a result of the repatriation of $812 million, the Companyrecorded 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 2004at  interest rates of 5.837% and 3.665%, respectively    |       | $                     | 606,000    |   | $ | 515,000 |   |
| LIBOR Rate Advances, borrowings at December 31,  2005 and 2004at  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, 

49

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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, inthe case of Eurodollar borrowings, ratings assigned to the Company’s debt.

The Credit Facility contains various covenants,including among others restrictions on liens, restrictions on incurring otherindebtedness if a default under the credit agreement exists or would result orif a borrowing base deficiency would result, restrictions on dividends andother restricted payments if a default under the credit agreement exists orwould result, restrictions on mergers, restrictions on investments, andrestrictions on hedging activity of a speculative nature or with counterpartieshaving credit ratings below specified levels. Financial covenants include acovenant not to permit the Company’s ratio of consolidated debt to consolidatedtotal capitalization (determined without reduction for any non-cash 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 

50

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

51

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

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.

**(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 ResultsData**

| ** **                                                   | ** ** | **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        |   |   |

 

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

The following tablesummarizes information about stock options outstanding at December 31,2005

| ** **             | ** ** | **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) CommodityDerivatives and 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 aredesigned to establish floor and ceiling prices on anticipated future naturalgas and crude oil production. The Company has designated these contracts ascash flow hedges designed to achieve a more predictable cash flow, as well asto reduce its exposure to price volatility. While the use of these derivativeinstruments limits the downside risk of adverse price movements, they may alsolimit future revenues from favorable price movements. The use of derivativesalso involves the risk that the counterparties to such instruments will beunable to meet the financial terms of such contracts. Currently, the Companydoes not expect losses due to creditworthiness of its counterparties.

The gas hedging transactions are generally settledbased upon the average of the reporting settlement prices on the NYMEX for thelast three trading days of a particular contract month. The oil hedgingtransactions are generally settled based on the average of the reportingsettlement prices for West Texas Intermediate on the NYMEX for each trading dayof a particular calendar month. For any particular collar transaction, thecounterparty is required to make a payment to the Company if the settlementprice for any 

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

settlement period is belowthe floor price for such transaction, and the Company is required to make apayment to the counterparty if the settlement price for any settlement periodis above the ceiling 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:

| ** **                             | ** ** | ** ** | ** ** | **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 million BritishThermal Units.

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 

62

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

of December 31, 2005, the Company had thefollowing collar contracts that no longer qualify for hedge 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 |   |

 

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 thefirst quarter 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.

63

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

In December 2004, the Company completed theacquisition of two privately held corporations for approximately $282.5 millionin cash and a deferred payment of $26.4 million made in 2005 to the former ownerof one of the corporations. The corporations have subsequently been named PogoProducing (San Juan) Company and Pogo Producing (Texas Panhandle) Company(the “corporations”). The transactions included properties located primarily inthe San Juan basin of New Mexico and the Texas Panhandle. The Company acquiredthe corporations primarily to strengthen its position in domestic natural gasproperties. The Company recorded the estimated fair values of the assetsacquired and the liabilities assumed at the closing date of the transactions,which primarily consisted of oil and gas properties of $423.7 million,long term debt of $50.1 million and deferred tax liabilities of$67.4 million. No goodwill was recorded for the transactions.

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

*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 |   |

 

64

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

**(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 and capitalizedcosts are depreciated over the estimated useful life of the related assets.This periodic accretion expense is recorded as “Transportation and other” inthe consolidated statement of income. Upon settlement of the liability, theCompany will settle the obligation against its recorded amount and will recordany resulting gain or loss.

Activity related to theCompany’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.

65

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

**(15)Fair Value of Financial Instruments**

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

*Cash and Cash Equivalents*

Fair value is carryingvalue.

*Receivables and Payables*

Fair value isapproximately carrying value.

*Derivative Financial Instruments*

Fair value is carryingvalue.

*Debt and Other*

| Instrument                          | ** ** | **Basis of Fair Value Estimate**                                                                                        |
|-------------------------------------|------------|-------------------------------------------------------------------------------------------------------------------------|
| Bank revolving credit  agreement(s) |       | Fair value is carrying value as of December 31,  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.

 

66

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

**Oiland Gas Producing Activities**

The results of operationsfrom oil and gas producing activities (expressed in thousands) exclude non-oil and gas revenues, corporate general andadministrative expenses, other non oil and gas producing expenses, interestcharges, interest income and interest capitalized. Income tax (expense) orbenefit was determined by applying the statutory rates to pre-tax operatingresults with adjustments for permanent differences. The Total amounts reflectonly those activities related to the Company’s continuing operations.

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

 

| ** **                                       | ** ** | **2004**          | ** ** |
|--------------------------------------------------|------------|-------------------|------------|
| ** **                                       | ** ** | **Other**         | ** ** | ** ** | ** ** | **United** | ** ** | ** ** | ** ** |
| ** **                                       | ** ** | **International** | ** ** | **Canada** | ** ** | **States** | ** ** | **Total** | ** ** |
| Revenues                                         |       |              | $          | — |   |   |   | $ | — |   |   | $ | 973,083 |   | $ | 973,083 |   |
| Lease operating expense                          |       |              | —     |   |   |   | — |   |   | (100,506 | ) | (100,506 | ) |
| Exploration expense                              |       |              | —     |   |   |   | — |   |   | (21,739 | ) | (21,739 | ) |
| Dry hole and impairment expense                  |       |              | (5,551     | )(c) |   |   | — |   |   | (56,083 | ) | (61,634 | ) |
| Depreciation, depletion and amortization expense |       |              | —     |   |   |   | — |   |   | (248,431 | ) | (248,431 | ) |
| Production and other taxes                       |       |              | —     |   |   |   | — |   |   | (44,104 | ) | (44,104 | ) |
| Transportation and accretion                     |       |              | —     |   |   |   | — |   |   | (19,488 | ) | (19,488 | ) |
| Pretax operating results                         |       |              | (5,551     | ) |   |   | — |   |   | 482,732 |   | 477,181 |   |
| Income tax expense                               |       |              | —     |   |   |   | — |   |   | (175,576 | ) | (175,576 | ) |
| Operating results from continuing operations(b)  |       |              | $          | (5,551 | ) |   |   | $ | — |   |   | $ | 307,156 |   | $ | 301,605 |   |

op

67

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

 

| ** **                                       | ** ** | **2003**          | ** ** |
|--------------------------------------------------|------------|-------------------|------------|
| ** **                                       | ** ** | **Other**         | ** ** | ** ** | ** ** | **United** | ** ** | ** ** | ** ** |
| ** **                                       | ** ** | **International** | ** ** | **Canada** | ** ** | **States** | ** ** | **Total** | ** ** |
| Revenues                                         |       |              | $          | — |   |   |   | $ | — |   |   | $ | 856,074 |   | $ | 856,074 |   |
| Lease operating expense                          |       |              | —     |   |   |   | — |   |   | (81,731 | ) | (81,731 | ) |
| Exploration expense                              |       |              | —     |   |   |   | — |   |   | (6,899 | ) | (6,899 | ) |
| Dry hole and impairment expense                  |       |              | —     |   |   |   | — |   |   | (30,673 | ) | (30,673 | ) |
| Depreciation, depletion and amortization expense |       |              | —     |   |   |   | — |   |   | (226,607 | ) | (226,607 | ) |
| Production and other taxes                       |       |              | —     |   |   |   | — |   |   | (23,735 | ) | (23,735 | ) |
| Transportation and accretion                     |       |              | —     |   |   |   | — |   |   | (16,949 | ) | (16,949 | ) |
| Pretax operating results                         |       |              | —     |   |   |   | — |   |   | 469,480 |   | 469,480 |   |
| Income tax expense                               |       |              | —     |   |   |   | — |   |   | (170,750 | ) | (170,750 | ) |
| Operating results from continuing operations(b)  |       |              | $          | — |   |   |   | $ | — |   |   | $ | 298,730 |   | $ | 298,730 |   |

----

(a)           Related to New Zealand.

(b)          Excludes operating results from discontinuedoperations of $52,850 in 2005, $28,779 in 2004 and $79,237 in 2003.

(c)           Related to the Danish North Sea.

68

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

The following table sets forth the Company’s costsincurred (expressed in thousands) for oil and gas producing activities,including capitalized interest, during the years indicated.

| ** **                                | ** ** | **2005**          | ** ** |
|-------------------------------------------|------------|-------------------|------------|
| ** **                                | ** ** | **Other**         | ** ** | ** ** | ** ** | **United** | ** ** | ** ** | ** ** | **  Discontinued  ** | ** ** |
| ** **                                | ** ** | **International** | ** ** | **Canada** | ** ** | **States** | ** ** | **Total** | ** ** | **Operations** | ** ** |
| Costs incurred                            |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |
| (capitalized unless otherwise indicated): |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Property acquisition                      |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved                                    |       |              | $          | — |   |    | $ | 1,786,916 |    | $ | 45,981 |    | $ | 1,832,897 |    |   | $ | — |   |   |
| Unproved                                  |       |              | —     |   |   | 830,016 |   | 50,843 |   | 880,859 |   |   | — |   |   |
| Exploration                               |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Capitalized                               |       |              | —     |   |   | 9,127 |   | 130,079 |   | 139,206 |   |   | 1,283 |   |   |
| Expensed                                  |       |              | 9,063      |   |   | 3,397 |   | 14,013 |   | 26,473 |   |   | — |  |   |
| Development                               |       |              | 129        |   |   | 55,796 |   | 164,194 |   | 220,119 |   |   | 69,616 |   |   |
| Asset retirement cost                     |       |              | —     |   |   | 49,927 |   | 3,256 |   | 53,183 |   |   | — |   |   |
| Total oil and gas costs  incurred         |       |              | $          | 9,192 |   |   | $ | 2,735,179 |   | $ | 408,366 |   | $ | 3,152,737 |   |   | $ | 70,899 |   |   |

 

| ** **                        | ** ** | ** ** | **2004** | ** ** | ** ** |
|-----------------------------------|------------|------------|----------|------------|------------|
| Property acquisition              |       |       |     |       |       |   |   |   |   |   |   |   |   |   |   |
| Proved                            |       |       | $        | —     |       |    | $ | — |    | $ | 612,975 |    | $ | 612,975 |    |   | $ | — |   |   |
| Unproved                          |       |       | —   |       |       | — |   | 26,904 |   | 26,904 |   |   | — |   |   |
| Exploration                       |       |       |     |       |       |   |   |   |   |   |   |   |   |   |   |
| Capitalized                       |       |       | 5,551    |       |       | — |   | 56,949 |   | 62,500 |   |   | 35,067 |   |   |
| Expensed                          |       |       | —   |       |       | — |   | 21,739 |   | 21,739 |   |   | 1,510 |   |   |
| Development                       |       |       | —   |       |       | — |   | 228,473 |   | 228,473 |   |   | 114,163 |   |   |
| Asset retirement cost             |       |       | —   |       |       | — |   | 14,330 |   | 14,330 |   |   | 4,034 |   |   |
| Total oil and gas costs  incurred |       |       | $        | 5,551      |       |   | $ | — |   | $ | 961,370 |   | $ | 966,921 |   |   | $ | 154,774 |   |   |

 

| ** **                       | ** ** | ** ** | **2003** | ** ** | ** ** |
|----------------------------------|------------|------------|----------|------------|------------|
| Property acquisition             |       |       |     |       |       |   |   |   |   |   |   |   |   |   |   |
| Proved                           |       |       | $        | —     |       |    | $ | — |    | $ | 182,660 |    | $ | 182,660 |    |   | $ | — |   |   |
| Unproved                         |       |       | —   |       |       | — |   | 12,403 |   | 12,403 |   |   | 3,475 |   |   |
| Exploration                      |       |       |     |       |       |   |   |   |   |   |   |   |   |   |   |
| Capitalized                      |       |       | —   |       |       | — |   | 43,499 |   | 43,499 |   |   | 23,803 |   |   |
| Expensed                         |       |       | —   |       |       | — |   | 6,832 |   | 6,832 |   |   | 648 |   |   |
| Development                      |       |       | —   |       |       | — |   | 135,424 |   | 135,424 |   |   | 116,616 |   |   |
| Asset retirement cost            |       |       | —   |       |       | — |   | 49,706 |   | 49,706 | (a) |   | 9,436 |   |   |
| Total oil and gas costs incurred |       |       | $        | —     |       |   | $ | — |   | $ | 430,524 |   | $ | 430,524 |   |   | $ | 153,978 |   |   |

----

(a)           Includes $47,893 of cumulative asset retirementcost recorded to adopt the provisions of SFAS 143 on January 1, 2003.

69

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

The following information regarding estimates ofthe Company’s proved oil and gas reserves, which are located onshore in theUnited States and Canada and offshore in United States waters of the Gulf ofMexico for continuing operations and were located offshore in the Kingdom ofThailand and in Hungary for discontinued operations, is based on reportsprepared by Ryder Scott Company, L.P. and reports prepared by the Company andreviewed by Ryder Scott Company—Canada and Miller & Lents, Ltd. Thedefinitions and assumptions that serve as the basis for the discussions underthe caption “Item 1, Business—Exploration and Production Data—Reserves”should be referred to in connection with the following information.  Only reserves data related to the Company’scontinuing operations is presented under the Total amounts.

**Estimates of Proved Reserves**

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

|                                         |   |       |   | United      |   |        |   |   | Discontinued |   |
|----------------------------------------------|--------|------------|--------|-------------|--------|-------------|--------|--------|--------------|--------|
|                                         |   | Canada     |   | States      |   | Total       |   |   | Operations   |   |
| Proved Reserves as of December 31, 2002 |   | —     |   | 80,092,262  |   | 80,092,262  |   |   | 38,086,570   |   |
| Revisions of previous estimates              |   | —     |   | 6,338,668   |   | 6,338,668   |   |   | 3,625,838    |   |
| Extensions, discoveries and other additions  |   | —     |   | 2,982,400   |   | 2,982,400   |   |   | 3,323,071    |   |
| Purchase of properties                       |   | —     |   | 4,301,200   |   | 4,301,200   |   |   | —       |   |
| Estimated 2003 production                    |   | —     |   | (16,162,000 | )      | (16,162,000 | )      |   | (7,718,000   | )      |
| Proved Reserves as of December 31, 2003 |   | —     |   | 77,552,530  |   | 77,552,530  |   |   | 37,317,479   |   |
| Revisions of previous estimates              |   | —     |   | 5,012,763   |   | 5,012,763   |   |   | (730,971     | )      |
| Extensions, discoveries and other additions  |   | —     |   | 1,727,761   |   | 1,727,761   |   |   | 2,469,912    |   |
| Purchase of properties                       |   | —     |   | 13,775,000  |   | 13,775,000  |   |   | —       |   |
| Sale of properties                           |   | —     |   | (1,832,000  | )      | (1,832,000  | )      |   | —       |   |
| Estimated 2004 production                    |   | —     |   | (12,370,000 | )      | (12,370,000 | )      |   | (6,540,000   | )      |
| Proved Reserves as of December 31, 2004 |   | —     |   | 83,866,054  |   | 83,866,054  |   |   | 32,516,420   |   |
| Revisions of previous estimates              |   | (23,300    | )      | 5,537,272   |   | 5,513,972   |   |   | —       |   |
| Extensions, discoveries and other additions  |   | 3,083,600  |   | 1,801,097   |   | 4,884,697   |   |   | —       |   |
| Purchase of properties                       |   | 60,100,000 |   | 588,379     |   | 60,688,379  |   |   | —       |   |
| Sale of properties                           |   | —     |   | —      |   | —      |   |   | (28,496,442  | )      |
| Estimated 2005 production                    |   | (1,357,312 | )      | (9,554,925  | )      | (10,912,237 | )      |   | (4,019,978   | )      |
| Proved Reserves as of December 31, 2005 |   | 61,802,988 |   | 82,237,877  |   | 144,040,865 |   |   | —       |   |
| Proved Developed Reserves as of:             |   |       |   |        |   |        |   |   |         |   |
| December 31, 2002                       |   | —     |   | 74,041,149  |   | 74,041,149  |   |   | 23,831,851   |   |
| December 31, 2003                       |   | —     |   | 67,391,031  |   | 67,391,031  |   |   | 19,878,246   |   |
| December 31, 2004                       |   | —     |   | 72,968,008  |   | 72,968,008  |   |   | 19,606,216   |   |
| December 31,  2005                      |   | 55,413,014 |   | 63,160,705  |   | 118,573,719 |   |   | —       |   |

 

70

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

**Estimates of Proved Reserves**

**Natural Gas (MMcf)**

| ** **                                   | ** ** | ** ** | ** ** | **United** | ** ** | ** ** | ** ** | ** ** | **Discontinued** | ** ** |
|----------------------------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------------|------------|
| ** **                                   | ** ** | **Canada** | ** ** | **States** | ** ** | **Total**  | ** ** | ** ** | **Operations**   | ** ** |
| Proved Reserves as of December 31, 2002 |       | —     |       | 713,906    |       | 713,906    |       |       |             | 159,604    |   |   |
| Revisions of previous  estimates             |       | —     |       | 5,686      |       | 5,686      |       |       |             | 16,722     |   |   |
| Extensions, discoveries  and other additions |       | —     |       | 65,095     |       | 65,095     |       |       |             | 30,569     |   |   |
| Purchase of properties                       |       | —     |       | 129,119    |       | 129,119    |       |       |             | —     |   |   |
| Estimated 2003 production                    |       | —     |       | (76,802    | )          | (76,802    | )          |       |             | (31,576    | ) |   |
| Proved Reserves as of December 31, 2003 |       | —     |       | 837,004    |       | 837,004    |       |       |             | 175,319    |   |   |
| Revisions of previous  estimates             |       | —     |       | (16,357    | )          | (16,357    | )          |       |             | (4,497     | ) |   |
| Extensions, discoveries  and other additions |       | —     |       | 33,610     |       | 33,610     |       |       |             | 4,038      |   |   |
| Purchase of properties                       |       | —     |       | 172,022    |       | 172,022    |       |       |             | —     |   |   |
| Sale of properties                           |       | —     |       | (2,888     | )          | (2,888     | )          |       |             | —     |   |   |
| Estimated 2004 production                    |       | —     |       | (89,410    | )          | (89,410    | )          |       |             | (29,171    | ) |   |
| Proved Reserves as of December 31, 2004 |       | —     |       | 933,981    |       | 933,981    |       |       |             | 145,689    |   |   |
| Revisions of previous  estimates             |       | 954        |       | 6,280      |       | 7,234      |       |       |             | —     |   |   |
| Extensions, discoveries  and other additions |       | 32,646     |       | 29,063     |       | 61,709     |       |       |             | —     |   |   |
| Purchase of properties                       |       | 259,610    |       | 6,500      |       | 266,110    |       |       |             | —     |   |   |
| Sale of properties                           |       | —     |       | —     |       | —     |       |       |             | (127,926   | ) |   |
| Estimated 2005 production                    |       | (6,783     | )          | (84,526    | )          | (91,309    | )          |       |             | (17,763    | ) |   |
| Proved Reserves as of December 31, 2005 |       | 286,427    |       | 891,298    |       | 1,177,725  |       |       |             | —     |   |   |
| Proved Developed Reserves as of:             |       |       |       |       |       |       |       |       |             |       |   |   |
| December 31, 2002                       |       | —     |       | 600,255    |       | 600,255    |       |       |             | 87,301     |   |   |
| December 31, 2003                       |       | —     |       | 702,836    |       | 702,836    |       |       |             | 77,938     |   |   |
| December 31, 2004                       |       | —     |       | 769,753    |       | 769,753    |       |       |             | 83,095     |   |   |
| December 31, 2005                       |       | 220,704    |       | 685,301    |       | 906,005    |       |       |             | —     |   |   |

 

 

71

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**POGO PRODUCING COMPANY & SUBSIDIARIES**

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

The standardized measure of discounted future netcash flows from the production of proved reserves (expressed in thousands) isdeveloped as follows:

1.                Estimates are made of quantities of proved reservesand the future periods in which they are expected to be produced based onyear-end economic conditions.

2.                The estimated future gross revenues from provedreserves are priced on the basis of year-end market prices, except in thoseinstances where fixed and determinable natural gas price escalations are coveredby contracts.

3.                The future gross revenue streams are reduced byestimated future costs to develop and to produce the proved reserves, as wellas certain abandonment costs based on year-end cost estimates, and theestimated effect of future income taxes. These cost estimates are subject tosome uncertainty.

4.                The cash flows are discounted at 10% per annum.

72

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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 standardized measure of discounted future netcash flows does not purport to present the fair value of the Company’s oil andgas reserves. An estimate of fair value would also take into account, amongother things, the recovery of reserves in excess of proved reserves,anticipated future changes in prices and costs, a discount factor morerepresentative of the time value of money and the risks inherent in reserveestimates.

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

 

| ** **                                                                                                 | ** ** | **Year Ended December 31, 2004** | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| Future gross revenues                                                                                      |       | $                                                    | —     |   | $ | 8,850,237 |   | $ | 8,850,237 |   |   |   |   | $ | 1,724,267 |   |   |
| Future production costs                                                                                    |       | —                                               |       | (2,123,530 | ) | (2,123,530 | ) |   |   |   | (405,950 | ) |   |
| Future development and abandonment costs                                                                   |       | —                                               |       | (437,117 | ) | (437,117 | ) |   |   |   | (143,584 | ) |   |
| Future net cash flows before income taxes                                                                  |       | —                                               |       | 6,289,590 |   | 6,289,590 |   |   |   |   | 1,174,733 |   |   |
| Discount at 10% per annum                                                                                  |       | —                                               |       | (2,650,272 | ) | (2,650,272 | ) |   |   |   | (242,118 | ) |   |
| Discounted future net cash flows before income taxes                                                  |       | —                                               |       | 3,639,318 |   | 3,639,318 |   |   |   |   | 932,615 |   |   |
| Future income taxes, net of discount at 10% per  annum                                                     |       | —                                               |       | (1,080,607 | ) | (1,080,607 | ) |   |   |   | (395,759 | ) |   |
| Standardized measure of discounted future net cash flows related to proved oil and gas  reserves |       | $                                                    | —     |   | $ | 2,558,711 |   | $ | 2,558,711 |   |   |   |   | $ | 536,856 |   |   |

 

73

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**POGO PRODUCING COMPANY & SUBSIDIARIES**

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

 

| ** **                                                                                                 | ** ** | **Year Ended December 31, 2003** | ** ** |
|------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
|                                                                                                       |       |                                                 |       | United |   |   |   |   | Discontinued |   |
|                                                                                                       |       | Canada                                               |       | States |   | Total |   |   | Operations |   |
| Future gross revenues                                                                                      |       | $                                                    | —     |   | $ | 6,912,547 |   | $ | 6,912,547 |   |   |   |   | $ | 1,594,681 |   |   |
| Future production costs                                                                                    |       | —                                               |       | (1,417,118 | ) | (1,417,118 | ) |   |   |   | (394,466 | ) |   |
| Future development and abandonment costs                                                                   |       | —                                               |       | (324,813 | ) | (324,813 | ) |   |   |   | (195,346 | ) |   |
| Future net cash flows before income taxes                                                                  |       | —                                               |       | 5,170,616 |   | 5,170,616 |   |   |   |   | 1,004,869 |   |   |
| Discount at 10% per annum                                                                                  |       | —                                               |       | (2,241,953 | ) | (2,241,953 | ) |   |   |   | (243,531 | ) |   |
| Discounted future net cash flows before income taxes                                                  |       | —                                               |       | 2,928,663 |   | 2,928,663 |   |   |   |   | 761,338 |   |   |
| Future income taxes, net of discount at 10% per  annum                                                     |       | —                                               |       | (919,540 | ) | (919,540 | ) |   |   |   | (320,431 | ) |   |
| Standardized measure of discounted future net cash flows related to proved oil and gas  reserves |       | $                                                    | —     |   | $ | 2,009,123 |   | $ | 2,009,123 |   |   |   |   | $ | 440,907 |   |   |
|                                                                                                            |            |                                                      |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

The following are the principal sources of changein the standardized measure of discounted future net cash flows.

| ** **                                                                            | ** ** | **For the Year Ended December 31, 2005** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                                            | ** ** | ** **                                                             | ** ** | **United** | ** ** | ** ** | ** ** | ** ** | **Discontinued** | ** ** |
| ** **                                                                            | ** ** | **Canada**                                                             | ** ** | **States** | ** ** | **Total** | ** ** | ** ** | **Operations** | ** ** |
| Beginning balance                                                                     |       | $                                                                      | —     |   | $ | 2,558,711 |   | $ | 2,558,711 |   |   |   | $ | 536,856 |   |   |
| 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                                   |       | (7,555                                                                 | )          | 150,026 |   | 142,471 |   |   |   | — |   |   |
| Net changes in estimates of future development costs                             |       | —                                                                 |       | (334,605 | ) | (334,605 | ) |   |   | — |   |   |
| Accretion of discount                                                                 |       | —                                                                 |       | 363,932 |   | 363,932 |   |   |   | 54,402 |   |   |
| Changes in production rate and other                                                  |       | 369,490                                                                |       | (154,108 | ) | 215,382 |   |   |   | — |   |   |
| Total revisions                                                                       |       | 361,935                                                                |       | 1,553,544 |   | 1,915,479 |   |   |   | 54,402 |   |   |
| New field discoveries and extensions, net of  future production and development costs |       | 193,857                                                                |       | 145,537 |   | 339,394 |   |   |   | — |   |   |
| Purchases of properties                                                               |       | 1,509,798                                                              |       | 32,207 |   | 1,542,005 |   |   |   | — |   |   |
| Sales of properties                                                                   |       | —                                                                 |       | — |   | — |   |   |   | (819,357 | ) |   |
| Sales of oil and gas produced, net of production  costs                               |       | (111,504                                                               | )          | (864,505 | ) | (976,009 | ) |   |   | (197,234 | ) |   |
| Previously estimated development costs  incurred                                      |       | —                                                                 |       | 160,371 |   | 160,371 |   |   |   | 29,574 |   |   |
| Net change in income taxes                                                            |       | (612,675                                                               | )          | (364,431 | ) | (977,106 | ) |   |   | 395,759 |   |   |
| Net change in standardized measure of discounted  future net cash flows               |       | 1,341,411                                                              |       | 662,723 |   | 2,004,134 |   |   |   | (536,856 | ) |   |
| Ending balance                                                                        |       | $                                                                      | 1,341,411  |   | $ | 3,221,434 |   | $ | 4,562,845 |   |   |   | $ | — |   |   |

 

74

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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)**

 

| ** **                                                                            | ** ** | **For the Year Ended December 31, 2004** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
|                                                                                  |       |                                                                   |       | United |   |   |   |   | Discontinued |   |
|                                                                                  |       | Canada                                                                 |       | States |   | Total |   |   | Operations |   |
| Beginning balance                                                                     |       | $                                                                      | —     |   | $ | 2,009,123 |   | $ | 2,009,123 |   |   |   | $ | 440,907 |   |   |
| Revisions to prior years’ proved reserves:                                       |       |                                                                   |       |   |   |   |   |   |   |   |   |   |
| Net changes in prices and production costs                                            |       | —                                                                 |       | 631,060 |   | 631,060 |   |   |   | 237,010 |   |   |
| Net changes due to revisions in quantity  estimates                                   |       | —                                                                 |       | 39,661 |   | 39,661 |   |   |   | (14,429 | ) |   |
| Net changes in estimates of future development costs                             |       | —                                                                 |       | (154,659 | ) | (154,659 | ) |   |   | (7,007 | ) |   |
| Accretion of discount                                                                 |       | —                                                                 |       | 292,866 |   | 292,866 |   |   |   | 76,134 |   |   |
| Changes in production rate and other                                                  |       | —                                                                 |       | (51,192 | ) | (51,192 | ) |   |   | 7,778 |   |   |
| Total revisions                                                                       |       | —                                                                 |       | 757,736 |   | 757,736 |   |   |   | 299,486 |   |   |
| New field discoveries and extensions, net of  future production and development costs |       | —                                                                 |       | 126,167 |   | 126,167 |   |   |   | 86,796 |   |   |
| Purchases of properties                                                               |       | —                                                                 |       | 596,173 |   | 596,173 |   |   |   | — |   |   |
| Sales of properties                                                                   |       | —                                                                 |       | (58,570 | ) | (58,570 | ) |   |   | — |   |   |
| Sales of oil and gas produced, net of production  costs                               |       | —                                                                 |       | (808,986 | ) | (808,986 | ) |   |   | (265,160 | ) |   |
| Previously estimated development costs  incurred                                      |       | —                                                                 |       | 98,135 |   | 98,135 |   |   |   | 50,155 |   |   |
| Net change in income taxes                                                            |       | —                                                                 |       | (161,067 | ) | (161,067 | ) |   |   | (75,328 | ) |   |
| Net change in standardized measure of discounted  future net cash flows               |       | —                                                                 |       | 549,588 |   | 549,588 |   |   |   | 95,949 |   |   |
| Ending balance                                                                        |       | $                                                                      | —     |   | $ | 2,558,711 |   | $ | 2,558,711 |   |   |   | $ | 536,856 |   |   |

 

| ** **                                                                            | ** ** | **For the Year Ended December 31, 2003** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                                            | ** ** | ** **                                                             | ** ** | **United** | ** ** | ** ** | ** ** | ** ** | **Discontinued** | ** ** |
| ** **                                                                            | ** ** | **Canada**                                                             | ** ** | **States** | ** ** | **Total** | ** ** | ** ** | **Operations** | ** ** |
| Beginning balance                                                                     |       | $                                                                      | —     |   | $ | 1,714,788 |   | $ | 1,714,788 |   |   |   | $ | 340,427 |   |   |
| Revisions to prior years’ proved reserves:                                       |       |                                                                   |       |   |   |   |   |   |   |   |   |   |
| Net changes in prices and production costs                                            |       | —                                                                 |       | 434,060 |   | 434,060 |   |   |   | 185,334 |   |   |
| Net changes due to revisions in quantity  estimates                                   |       | —                                                                 |       | 113,329 |   | 113,329 |   |   |   | 87,264 |   |   |
| Net changes in estimates of future development costs                             |       | —                                                                 |       | (21,781 | ) | (21,781 | ) |   |   | (48,445 | ) |   |
| Accretion of discount                                                                 |       | —                                                                 |       | 249,556 |   | 249,556 |   |   |   | 60,280 |   |   |
| Changes in production rate and other                                                  |       | —                                                                 |       | (182,172 | ) | (182,172 | ) |   |   | (12,095 | ) |   |
| Total revisions                                                                       |       | —                                                                 |       | 592,992 |   | 592,992 |   |   |   | 272,338 |   |   |
| New field discoveries and extensions, net of  future production and development costs |       | —                                                                 |       | 241,946 |   | 241,946 |   |   |   | 78,242 |   |   |
| Purchases of properties                                                               |       | —                                                                 |       | 289,484 |   | 289,484 |   |   |   | — |   |   |
| Sales of oil and gas produced, net of production  costs                               |       | —                                                                 |       | (737,628 | ) | (737,628 | ) |   |   | (250,353 | ) |   |
| Previously estimated development costs  incurred                                      |       | —                                                                 |       | 46,311 |   | 46,311 |   |   |   | 58,313 |   |   |
| Net change in income taxes                                                            |       | —                                                                 |       | (138,770 | ) | (138,770 | ) |   |   | (58,060 | ) |   |
| Net change in standardized measure of discounted  future net cash flows               |       | —                                                                 |       | 294,335 |   | 294,335 |   |   |   | 100,480 |   |   |
| Ending balance                                                                        |       | $                                                                      | —     |   | $ | 2,009,123 |   | $ | 2,009,123 |   |   |   | $ | 440,907 |   |   |

 

75

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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.

76

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**************PART IV

**ITEM 15.**         *Exhibits and Financial Statement Schedules*.

(a)           DocumentsFiled as Part of this Form 10-K/A.
|        | ** ** | ** **                                                                                             | ** ** | Page   | ** ** |
|--------|------------|--------------------------------------------------------------------------------------------------------|------------|--------|------------|
| **1.** | ** ** | **Financial Statements and  Supplementary Data:**                                                      | ** ** |   | ** ** | ** ** |   |
|   |       | Report of  Independent Registered Public Accounting Firm                                               |       |   | 33         | ** ** |   |
|   |       | Consolidated Statements of Income for the Years Ended  December 31, 2005, 2004 and 2003           |       |   | 35         | ** ** |   |
|   |       | Consolidated Balance  Sheets as of December 31, 2005 and 2004                                     |       |   | 36         | ** ** |   |
|   |       | Consolidated  Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and  2003      |       |   | 38         | ** ** |   |
|   |       | Consolidated  Statements of Shareholders’ Equity                                                  |       |   | 40         | ** ** |   |
|   |       | Notes to  Consolidated Financial Statements for the Years Ended December 31, 2005,  2004 and 2003 |       |   | 41         | ** ** |   |
|   |       | Unaudited  Supplementary Financial and Reserves Data                                                   |       |   | 67         | ** ** |   |

 

**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.

The Exhibits designated by an asterisk have beenpreviously filed with the SEC and are incorporated herein by reference. TheExhibits designated by two asterisks were filed on March 2, 2006 with theOriginal 10-K to which this Form 10-K/A relates. TheExhibits without any such designation are filed herewith. 

**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).                                                                                                                                                                                                                                                                                                                                                                          |

77

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| *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).                                                                                                                                               |
| *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.                                                                                                                                                                                                                                                                                    |

 

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**ExecutiveCompensation Plans and Arrangements (comprising Exhibits 10.1 through 10.32, inclusive)**
| *10.1  |   | 1989 Incentive and Nonqualified Stock Option Plan of  Pogo Producing Company, as amended and restated effective January 25,  1994 (Exhibit 99, Definitive Proxy Statement on Schedule 14A, filed  March 22, 1994, File No. 1-7792).                                    |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *10.2  |   | Form of Stock Option Agreement under 1989  Incentive and Nonqualified Stock Option Plan, as amended and restated  effective January 22, 1991 (Exhibit 10(d)(1), Annual Report on  Form 10-K for the year ended December 31, 1991, File  No. 0-5468).         |
| *10.3  |   | Form of Director Stock Option Agreement under  1989 Incentive and Nonqualified Stock Option Plan as amended and restated  effective January 22, 1991 (Exhibit 10(d)(2), Annual Report on  Form 10-K for the year ended December 31, 1991, File  No. 0-5468). |
| *10.4  |   | 1995 Long-Term Incentive Plan (Exhibit 4(c),  Registration Statement on Form S-8 filed May 22, 1996, File  No. 333-04233).                                                                                                                                             |
| *10.5  |   | 1998 Incentive Plan (Exhibit 4.7, Registration  Statement on Form S-8 filed August 15, 2002, File  No. 333-98205).                                                                                                                                                     |
| *10.6  |   | 2000 Incentive Plan (Exhibit B to the Company’s  Definitive Proxy Statement filed on Schedule 14A, March 27, 2000, File  No. 001-7792).                                                                                                                                |
| *10.7  |   | 2002 Incentive Plan (Exhibit B to the Company’s  Definitive Proxy Statement filed on Schedule 14A, March 25, 2002, File  No. 001-7792).                                                                                                                                |
| *10.8  |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and Paul G. Van Wagenen,  dated February 1, 2005 (Exhibit 10.8, Annual Report on  Form 10-K for the year ended December 31, 2004).                                          |
| *10.9  |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and Stephen R. Brunner, dated  February 1, 2005 (Exhibit 10.9, Annual Report on Form 10-K for  the year ended December 31, 2004).                                           |
| *10.10 |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated  February 1, 2005 (Exhibit 10.10, Annual Report on Form 10-K  for the year ended December 31, 2004).                                             |
| *10.11 |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and John O. McCoy, Jr.,  dated February 1, 2005 (Exhibit 10.11, Annual Report on  Form 10-K for the year ended December 31, 2004).                                     |
| *10.12 |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and David R. Beathard, dated  February 1, 2005 (Exhibit 10.12, Annual Report on Form 10-K  for the year ended December 31, 2004).                                           |
| *10.13 |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and Radford P. Laney, dated  February 1, 2005 (Exhibit 10.13, Annual Report on Form 10-K  for the year ended December 31, 2004).                                            |
| *10.14 |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and J. Don McGregor, dated  February 1, 2005 (Exhibit 10.14, Annual Report on Form 10-K  for the year ended December 31, 2004).                                             |
| *10.15 |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and Gerald A. Morton, dated  February 1, 2005 (Exhibit 10.15, Annual Report on Form 10-K  for the year ended December 31, 2004).                                            |

79

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| *10.16  |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and James P. Ulm, II,  dated February 1, 2005 (Exhibit 10.16, Annual Report on  Form 10-K for the year ended December 31, 2004). |
|---------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *10.17  |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and Bruce E. Archinal, dated  February 1, 2005 (Exhibit 10.18, Annual Report on Form 10-K  for the year ended December 31, 2004).     |
| *10.18  |   | Amended and Restated Executive Employment  Agreement by and between Pogo Producing Company and Michael J. Killelea,  dated February 1, 2005 (Exhibit 10.19, Annual Report on  Form 10-K for the year ended December 31, 2004).   |
| **10.19 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and Paul  G. Van Wagenen, dated August 1, 2005.                                                                               |
| **10.20 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Stephen R. Brunner, dated August 1, 2005.                                                                                |
| **10.21 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Jerry A. Cooper, dated August 1, 2005.                                                                                   |
| **10.22 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and John  O. McCoy, Jr., dated August 1, 2005.                                                                           |
| **10.23 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  David R. Beathard, dated August 1, 2005.                                                                                 |
| **10.24 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Radford P. Laney, dated August 1, 2005.                                                                                  |
| **10.25 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and J.  Don McGregor, dated August 1, 2005.                                                                                   |
| **10.26 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Gerald A. Morton, dated August 1, 2005.                                                                                  |
| **10.27 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  James P. Ulm, II, dated August 1, 2005.                                                                             |
| **10.28 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Bruce E. Archinal, dated August 1, 2005.                                                                                 |
| **10.29 |   | Extension Agreement to Amended and Restated  Executive Employment Agreement by and between Pogo Producing Company and  Michael J. Killelea, dated August 1, 2005.                                                                               |
| *10.30  |   | 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).                                                                          |
| *10.31  |   | 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).                                                                             |
| *10.32  |   | 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.                                                                                                                                                                                                                 |

80

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| 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.                                                                                                     |
| 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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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the Registrant has duly caused this amendment 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: October 27, 2006 |                      |   |

 

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