** **

**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

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**FORM 10-K**

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

 

**For the fiscal year ended December 31, 2006**

**OR**

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

 

**For the transition period from             to            **

**Commission file 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                       |
|                                     |       | NYSE Arca                                     |
| Preferred Stock Purchase  Rights         |       | New York Stock Exchange                       |

 

Securitiesregistered pursuant 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 Exchange Act.

Large accelerated filer  x        Accelerated filer  o        Non-acceleratedfiler  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, 2006, the aggregate market value ofthe registrant’s common stock held by non-affiliates of the registrant wasapproximately $2,675,000,000 based on the closing sale price as reported on theNew York Stock Exchange.

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

| Class                                    | ** ** | **Outstanding at February 23, 2007** |
|------------------------------------------|------------|-------------------------------------------|
| Common Stock, $1.00 par  value per share |       | 58,480,047 shares                         |

 

**DOCUMENTSINCORPORATED BY REFERENCE**

| Document                                                                                                               | ** ** | ** **    | ** ** | **Parts Into Which Incorporated** | ** ** | ** ** |
|------------------------------------------------------------------------------------------------------------------------|------------|---------------|------------|-----------------------------------|------------|------------|
| Portions of the Registrant’s Proxy Statement for our Annual Meeting of  Stockholders to be held May 15, 2007 |       | Part III |

 

 

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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, 2006 (this “Annual Report”) of PogoProducing Company (the “Company”) include “forward-looking statements” withinthe meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21Eof the Securities Exchange Act of 1934, as amended. All statements included orincorporated by reference herein, other than statements of historical fact, areforward-looking statements. In some cases, you can identify the Company’sforward-looking statements by the words “anticipate,” “estimate,” “expect,” “objective,”“projection,” “forecast,” “goal,” and similar expressions. Such forward-lookingstatements include, without limitation, 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, results of operations, and cash requirements. Although the Companybelieves that the expectations reflected in these forward-looking statementsare reasonable, it can give no assurance that such expectations will prove tohave been correct. Important factors that could cause actual results to differmaterially from the Company’s expectations (“Cautionary Statements”) aredisclosed in this Annual Report and in other filings by the Company with theSecurities and Exchange Commission (the “Commission”). All subsequent writtenand oral forward-looking statements attributable to the Company or personsacting on its behalf are expressly qualified in their entirety by theCautionary Statements. The Company’s actual results could differ materiallyfrom those anticipated in these forward-looking statements as a result of thefactors set forth below, the risk factors described under the caption “RiskFactors” and other factors set forth in or incorporated by reference in thisAnnual Report. These factors include:

·       thecyclical nature of the oil and natural gas industries

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

·       uncertaintiesassociated with the United States and worldwide economies

·       currentand potential governmental regulatory actions in countries where the Companyoperates

·       substantialcompetition from larger companies

·       theCompany’s ability to implement cost reductions

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

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

·       fluctuationsin foreign currency exchange rates in areas of the world where the Companyconducts operations

·       covenantrestrictions in the Company’s debt agreements

·       strategictransactions, including the sale of part or all of the Company, or changes tothe Company’s business plan, that may result from its strategic alternativeprocess

Many of these factors are beyond the Company’s abilityto control or predict. Management cautions against putting undue reliance onforward-looking statements or projecting any future results based on suchstatements or present or prior earnings levels.

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

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**CERTAINDEFINITIONS**

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

**PART I**

**ITEM1.**                *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 Vietnam and New Zealand. As ofDecember 31, 2006, the Company had interests in approximately 4,800,000gross leasehold acres in major oil and gas provinces in North America,approximately 6,354,000 gross acres in New Zealand and approximately 1,480,000gross acres in Vietnam. Over the last several years, the Company hastransitioned from a predominately offshore-focused company to one with amajority of its reserves located in the onshore regions of North America. As ofDecember 31, 2006, approximately 94% of the Company’s reserves are locatedonshore.

The Company organizes itsexploration and production activities principally into five operating regions,as well as a New Ventures Group. The operating regions are its CanadianOperations, its Western U.S. Region, which is active in the Permian Basin areaof West Texas and Southeast New Mexico, the Panhandle of Texas, the San JuanBasin in New Mexico and the Wind River Basin in Wyoming; its Gulf Coast Region,which includes the Company’s onshore operations principally in South Texas andLouisiana; its Gulf of Mexico Region, which is responsible for the Company’soperations offshore Texas and Louisiana in the Gulf of Mexico; and its Asia andPacific Region, which has responsibility for the Company’s operations in NewZealand and Vietnam. The New Ventures Group is primarily responsible foridentifying new projects and opportunities for the Company outside the UnitedStates.

On May 31, 2006, theCompany closed the sale of an undivided 50% interest in each of Pogo’s Gulf ofMexico oil and gas leasehold interests to Mitsui & Co., Ltd., Mitsui &Co. (U.S.A.), Inc. and Mitsui Oil Exploration Co., Ltd. for approximately$448.8 million. On May 2, 2006, the Company completed the acquisitionof Latigo Petroleum, Inc. (“Latigo”) for approximately $764.9 million.Latigo’s activities are concentrated in the Permian Basin and the Panhandle ofTexas.

*Recent Developments*

On February 15, 2007,the Company issued a press release confirming that its Board of Directors hadpreviously initiated the exploration of a range of strategic alternatives toenhance shareholder value, and was continuing to do so, including the possiblesale or merger of the Company, the sale of its Canadian, Gulf Coast, Gulf ofMexico or other significant assets, and changes to its business plan. TheCompany also announced that it had retained Goldman, Sachs & Co. andTD Securities Inc. as financial advisors for the process.

**Domestic OnshoreOperations**

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 is headquartered in 

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Midland, Texas, andmaintains an additional office in Tulsa, Oklahoma. In addition the Company hasfour field offices in West Texas, three field offices in southeastern NewMexico and three field offices in the Texas Panhandle. The Company conducts itsonshore operations in the United States directly and through its wholly-ownedsubsidiaries. Domestic onshore reserves as of December 31, 2006, accountedfor approximately 62% of the Company’s total proved reserves, with the GulfCoast Region and the Western U.S. Region contributing approximately 12% and50%, respectively, of the Company’s total proved reserves. During 2006,approximately 64% of the Company’s natural gas production and 39% of its oiland condensate production was from its domestic onshore properties, contributingapproximately 51% of the Company’s consolidated oil and gas revenues.

The Los Mogotes Field,which is part of the Company’s Gulf Coast Region, consists of approximately22,420 gross acres located in South Texas. The Company owns various workinginterests in the Los Mogotes Field, which average approximately 71% across thefield, and is the operator of a majority of those working interests. In 2006,the Company’s interests in Los Mogotes produced an average of approximately 35MMcf per day of natural gas, accounting for approximately 13% of the Company’snatural gas production for the period. As of December 31, 2006, theCompany’s proved reserves associated with the Los Mogotes Field were45 MBbls of oil, condensate and natural gas liquids and 97,252 MMcf ofnatural gas, which together represented approximately 4.4% of the Company’stotal proved reserves. As of that date, the Company’s leasehold interests inthe field included 13,329 net acres of developed lands and 1,953 net acres ofundeveloped lands, with approximately 107 net producing wells and 161 grossproducing wells. The map below depicts the location of the field.

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The Madden Unit, which ispart of the Company’s Western Region, is a federal unit operated by a thirdparty and consists of approximately 80,000 acres in the Wind River Basinlocated in Central Wyoming. The Company owns various working interests in the MaddenUnit, which average approximately 14% across the unit area. In 2006, theCompany’s interests in the Madden Unit produced an average of approximately 36MMcf per day of natural gas, accounting for approximately 13% of the Company’snatural gas production for the period. As of December 31, 2006, theCompany’s proved reserves associated with the Madden Unit were 59 MBbls ofoil, condensate and natural gas liquids and 241,501 MMcf of natural gas,which together represented approximately 10.9% of the Company’s total provedreserves. As of that date, the Company’s leasehold interests in the unitincluded 3,094 net acres of developed lands and 7,353 net acres of undevelopedlands, with approximately 33 net producing wells and  236 gross producing wells. The map belowdepicts the location of the unit.

****

*Exploration andDevelopment*

The Company’s onshore capital and explorationexpenditures for 2006 were approximately $577,400,000, excluding approximately$998,500,000 of net property acquisitions. Comparable expenditures for 2005 and2004 were approximately $251,400,000 (excluding approximately $59,500,000 ofnet property acquisitions) and $196,500,000 (excluding approximately$489,600,000 of net property acquisitions), respectively. The increase in theCompany’s onshore capital and exploration expenditures for 2006, compared to2005, resulted primarily from expenditures related to increased exploratory anddevelopment drilling. The Company has currently budgeted approximately$720,000,000 for capital and exploration expenditures during 2007 in itsdomestic onshore areas.

The Company generally conducts its onshore activitiesthrough 100% ventures as well as joint ventures and other interest sharingarrangements with major and independent oil companies. The 

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Company and itssubsidiaries operate many of their onshore properties using both independentcontractors and field personnel that are employed by the Company or itssubsidiaries.

*WesternU.S. Region.*   The Company’s Western U.S.Region has actively explored in West Texas and Southeastern New Mexico for morethan 27 years. In addition to those areas, in recent years the Company hasexpanded its exploration and production efforts to also include the TexasPanhandle, the San Juan Basin of northwest New Mexico and the Wind River Basinof Wyoming. In 2006, the Company participated in the drilling of 258 wells inall of these areas (88% of which were successfully completed). The Companybelieves that during recent years it has been one of the more active companiesdrilling for oil and natural gas in the Permian Basin of West Texas,Southeastern New Mexico and the Texas Panhandle.

During 2007, the Company plans to drill approximately21 exploratory wells and 103 development wells in various known fields andexploratory prospects located in West Texas, southeast New Mexico, and theTexas Panhandle. Drilling objectives for these wells range in vertical depthfrom 4,500 feet to 17,000 feet below the surface and target numerous formationsincluding, among others, the Grayburg, Delaware (Bell Canyon, Cherry Canyon,Brushy Canyon), Spraberry, Bone Spring, Wolfcamp, Granite Wash, Strawn, Atoka,Morrow and Mississippian and Hunton formations.

The Company also plans to continue an activedevelopment drilling program in the San Juan Basin of northwest New Mexico.Twenty wells are expected to be drilled in several prospects in this areaduring 2007. The primary targets are the Fruitland Coal and Dakota formations.Drilling depths are expected to range from approximately 1,500 feet to 6,500feet.

The Company has actively participated in theexploration and development of the Madden Unit since it first acquired itsnon-operated working interest in 2001. The Madden Unit is characterized by gasproduction from multiple stratigraphic horizons of the Lower Fort Union, Lance,Mesaverde and Cody sands and the Madison dolomite. Production from the MaddenUnit is typically found at depths ranging from 5,500 to 25,000 feet. Some ofthe gas produced from the Madden Unit requires processing by the Lost Cabin GasPlant (in which the Company owns a partial interest) to make it pipelinequality. Of the 258 wells drilled in the Western Region in 2006, 36 ofthose wells were drilled in the Madden Unit.  Recent drilling activity in the unit hasfocused on the Lower Fort Union formation, where productive zones havehistorically been found at depths from approximately 5,500 feet to 11,000 feetbelow the surface. The company expects that the unit operator will conduct a2007 drilling program of approximately 25 to 30 wells which will target, amongother objectives, the Lower Fort Union Sands and the shallower (3,500 feet)Shotgun Sands.

*Acquisitionof Latigo.**  *On May 2,2006, the Company acquired Latigo Petroleum, Inc. a privately ownedexploration and production company, for a purchase price of approximately$764.9 million, including approximately $210 million to retire Latigo’s bankdebt and purchase price adjustments. As of December 31, 2006, provedreserves attributed to Latigo properties were approximately 29 MMBls of oil,condensate and natural gas liquids and 153,623 MMcf of natural gas. Thisacquisition included approximately 404,000 net acres of leasehold. Itsdevelopment activities are concentrated in Texas, including the Collie Field inReeves and Ward counties in West Texas, and the Courson Ranch area locatedprimarily in Roberts and Ochiltree Counties in the Texas Panhandle. Explorationopportunities in the Panhandle have been identified in multiple areas,including on a concentration of ranches controlled by Latigo which areprincipally located in Roberts and Hutchinson Counties, Texas. During 2007, thecompany plans to drill approximately 52 exploratory and development wells onits Latigo properties.

*Gulf Coast Region.*   TheCompany’s Gulf Coast Region is actively exploring for and developing oil andgas reserves, primarily in the coastal onshore areas of Louisiana and Texas.The Region’s staff is also responsible for the Company’s activities in theIllinois Basin in southern Indiana and the North Dakota portion of theWilliston Basin. The Company has interests in over 715,000 gross developed and 

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undeveloped leaseholdacres in this Region. During 2006, the Gulf Coast Region participated indrilling 65 wells, 82% of which were successfully completed. For 2007, theCompany’s budget for the Region includes participation in a total of 59 wellsof which 14 are exploratory wells and 45 are development wells.

The Gulf Coast Region’s development activities in 2006were focused on its 64,000 gross acres of leasehold in South Texas’ Webb andZapata Counties. The Region has been developing gas reserves primarily in itsLos Mogotes, Hundido, South Hundido and Hereford Ranch Fields that produce fromthe Eocene Wilcox formation, found at depths generally ranging from 7,000 to14,000 feet below the surface. The Company’s working interest in these wellsranges from 49% to 100% and the Company has historically operated over 80% ofits working interest in these wells. A total of 34 wells were drilled in thesefields in 2006. The Company has planned an active drilling program here and has27 locations budgeted for drilling in 2007. Identification of additionaldevelopment drilling locations in these fields is an iterative and continuingprocess. The Company believes that as additional locations are identified therewill be continued successful development of these properties in future years.

In Jefferson County, Texas, the Company is a 50%partner in an outside-operated venture to explore for Oligocene, Hackberry andVicksburg reservoirs. Approximately 77,000 gross acres are leased or optionedand three exploratory test wells are budgeted to be drilled in 2007.

In Polk and Tyler Counties, Texas, the Company’s GulfCoast Region is exploring the Cretaceous Woodbine and Austin Chalk Formationsfor new oil and gas reserves. The Company owns 128 square miles of new,proprietary 3-D seismic data and interpretation of that data has yieldeda number of exploratory prospects, which are generally 100% owned and operatedby the Company. The Company has interests in approximately 72,000 gross acresin this area. During 2006, the Company drilled and completed two high volumeAustin Chalk discovery wells.

During 2006, the Company’s Gulf Coast Regionparticipated in drilling four Miocene exploratory wells in South Louisiana thatwere unsuccessful. The Company expects to operate one exploratory test andparticipate in one outside operated exploratory test in this area in 2007. TheCompany is in the process of acquiring over 100 square miles of new 3-Dseismic data in central South Louisiana to explore for new Miocene prospects. TheCompany has interests in over 51,000 gross acres in the area and it intends tomaintain a 50% working interest in any prospects developed.

The Company is actively evaluating its contiguous8,000 gross acres of leasehold in Jack and Wise Counties, Texas to determinethe potential of the Mississippian Barnett Shale unconventional resource play. TheCompany holds a 75% working interest in this acreage. If test results warrant,the Company may drill additional wells here in 2007.

In southwest Indiana, the Company owns a 50% workinginterest in a Devonian New Albany Shale unconventional resource play that anindustry partner operates. Approximately 253,000 gross acres are under lease. During2006, the Company participated in drilling 13 productive gas wells. Fourteenhorizontal New Albany Shale wells are connected to a central facility.

The Company’s Gulf CoastRegion also evaluates the Company’s Mississippian Bakken Shale unconventionalresource play in Williams and Dunn Counties, North Dakota. During 2006, theCompany acquired a 100% working interest in over 81,000 gross acres and begandrilling test wells. The Company anticipates that it will drill additionalwells to appraise and develop this play in 2007.

**Domestic OffshoreOperations**

*Gulfof Mexico Region.*   Approximately6% of the Company’s total proved reserves as of December 31, 2006 werelocated in the Gulf of Mexico. During 2006, approximately 8% of the Company’snatural gas production and 21% of its oil, condensate and natural gas liquidsproduction were from the Company’s domestic offshore properties and togethercontributed approximately 17% of the Company’s 

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consolidated oil and gasrevenues. The Company’s exploration and development efforts in this region areprimarily focused in the shallower waters of the continental shelf.

During 2006, the Company’s wells in the Main PassBlock 61/62 Field, which is located on the continental shelf off thesoutheastern tip of Louisiana, produced an average of approximately 5,370 Bblsper day of oil, condensate and natural gas liquids, accounting forapproximately 15% of the Company’s liquid hydrocarbon production for theperiod. As of December 31, 2006, the Company’s proved reserves for theMain Pass Block 61/62 Field were 7,858 MBbls of oil, condensate andnatural gas liquids and 4,142 MMcf of natural gas, which togetherrepresented approximately 2.3% of the Company’s total proved reserves. TheCompany is the operator of a 50% 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, 2006, the Company’s leaseholdinterests in the Main Pass Block 61/62 Field included 4,995 net acres ofdeveloped lands and no undeveloped lands, with 17 net producing wells.

The Main Pass Block 61/62Field, which was brought online by the Company in 2002, consists of a series ofstratigraphic traps located on a regionally dipping slope, downdip at the UpperMiocene Shelf/Slope break. As of December 31, 2006, the Company isinjecting water for both pressure support and enhanced recovery in the twolarger reservoirs of the field through injection wells, while producing from 17wells. The map below depicts the location of the field.

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*Exploration andDevelopment*

The Company’s domestic offshore capital andexploration expenditures for 2006 were $47,700,000. Comparable expenditures for2005 and 2004 were approximately $88,700,000 and $150,300,000, respectively. Thedecrease in the Company’s domestic offshore capital and explorationexpenditures for 

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2006 were due in part tothe sale of 50% of the Company’s position in all offshore properties and fromdecreased expenditures for exploration and development wells and facilitiesconstruction. During 2006, the Company invested approximately $24,900,000 inexploration and development wells and $19,900,000 in facilities constructionfor its Gulf of Mexico operations. The Company has currently budgeted$37,000,000 for capital expenditures and development wells during 2007 in theGulf of Mexico, of which $9,700,000 is budgeted for development wells and$27,300,000 for workovers, facilities and abandonment operations. The Companyparticipated in drilling two wells during 2006 in the Gulf of Mexico Region,one of which was considered successful. At December 31, 2006, the Companyheld varying interests in 201 proved producing and proved shut-in oil and gaswells 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 53 of the 84 offshore leases in which it had aninterest as of December 31, 2006.

Platforms and related facilities are installed on anoffshore lease block when, in the judgment of the lease interest owners, thenecessary capital expenditures are justified. A decision to install a platformgenerally is made after the drilling of one or more exploratory wells withcontracted drilling equipment. Platform costs vary depending on, among otherfactors, the number of well slots, water depth, currents, sea floor conditions,and type of production handling equipment.

*Sale of 50% Interest inGulf of Mexico Properties.**  *On May 31,2006, the Company completed the sale of one-half of its federal and state Gulfof Mexico oil and gas leasehold interests and related pipelines and equipmentfor a purchase price of $500 million, or approximately $448.8 million aftercustomary purchase price adjustments, to MitEnergy Upstream LLC, an affiliateof Mitsui & Co., Ltd., Mitsui & Co. (U.S.A.), Inc. andMitsui Oil Exploration Co., Ltd. The sale of the 50% interest in theseproperties is equivalent to approximately 8 MBbls per day of oilproduction and 24 MMcf per day of natural gas production, in each case as of March 31,2006.

*Lease Acquisitions*

The Company hasparticipated, either on its own or with other companies, in bidding on andacquiring interests in federal and state leases offshore in the Gulf of Mexicosince 1970. As a result of such purchases and subsequent activities, as of December 31,2006, the Company owned interests in 73 federal leases and 11 state leasesoffshore Louisiana and Texas. Federal leases generally have primary terms offive, eight or ten years, depending on water depth, and state leases generallyhave terms of three or five years, depending on location, in each case subjectto extension by development and production operations.

**InternationalOperations**

The Company has conductedinternational exploration activities since the late 1970s in numerous oil andgas areas throughout the world. The Company currently holds acreage in Canada,New Zealand and Vietnam. The Company’s explorationists continue to evaluateother international opportunities that are consistent with its explorationstrategy and expertise. For a discussion of certain risks associated with theCompany’s international operations, see “Risk Factors—The Company’s foreign operationssubject it to additional risks,” “—The Company’s recent acquisitions aresignificant and may not be successful” and 

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“—TheCompany may not be able to obtain sufficient drilling equipment and experiencedpersonnel to conduct its operations.”

*Exploration andDevelopment*

The Company’s international capital and explorationexpenditures were approximately $327,100,000 (excluding approximately$22,400,000 of net property acquisitions) for 2006. Expenditures for 2005 and2004 were approximately $162,000,000 (excluding approximately $2,526,000,000 ofproperty acquisitions and approximately $71,095,000 of expenditures related todiscontinued Thailand and Hungary operations) and $148,900,000 (approximately$5,700,000 excluding Thailand and Hungary operations), respectively. Theincrease in the Company’s capital and exploration expenditures for 2006resulted primarily from increased expenditures for facilities costs andincreased drilling activity.

The Company has currentlybudgeted approximately $258,000,000 for capital and exploration expendituresduring 2007 in areas outside the United States, including approximately$250,000,000 in Canada.

**Canadian Operations**

The Company’s Canadian operations are conductedthrough a wholly-owned subsidiary, Northrock Resources Ltd. (“Northrock”),which was acquired by the Company from Unocal Corporation on September 27,2005 for approximately $1.7 billion. Northrock is headquartered in Calgary,Alberta, Canada and has Canadian field offices in Rocky Mountain House,Alberta, Grande Prairie, Alberta and in Estevan, Saskatchewan.

Northrock conducts its activities through jointventures with other Canadian oil and gas companies and operates its propertiesusing both independent contractors and field personnel.

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 gas reserves in Canada as of December 31,2006, accounted for approximately 32% of the Company’s total proved reserves. During2006, Northrock contributed approximately 28% of the Company’s natural gasproduction and 40% of its crude oil, condensate and natural gas liquidsproduction.

In addition to crude oiland natural gas reserves and production, Northrock has a significantundeveloped land base. As of December 31, 2006, Northrock had more thanone million net acres of undeveloped land for future exploration purposesincluding almost 300,000 net acres of undeveloped land in the NorthwestTerritories.

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*Exploration and Development*

In 2006 Northrock drilled163 gross wells of which 152 gross wells were successfully completed, for anoverall success rate of 93%. Drilling activity included 33 natural gas wells inthe Sunchild/Ferrier area of West Central Alberta and 25 wells in theMikwan/Huxley area of southern Alberta following a successful explorationprogram in 2005. These activities contributed significantly to the natural gasproduction growth that was experienced in Canada in 2006. The 2006 drilling programalso included eight successful Coal Bed Methane wells in the Mikwan/Huxley areaof Alberta of which five wells are expected to be tied-in by the middle of2007.

For 2007, Northrockexpects to continue an equally active exploration and development program andexpects to drill 139 wells including a large scale natural gas explorationprogram in the Alberta foothills. The exploration and development program inCanada for 2007 will focus on various known fields in both Alberta andSaskatchewan.

In addition to explorationand development initiatives in western Canada, Northrock has an approximate 32%working interest in an exploration project in the Central Mackenzie Valley inthe Northwest Territories near the route of the proposed Mackenzie Valley GasPipeline. For 2006, Northrock participated in drilling two wells in the CentralMackenzie Valley. The 2007 and 2008 winter exploration program is anticipatedto include the acquisition of both 2-D seismic and 3-D seismic withthe potential of drilling an additional well in the first quarter of 2008.

*Acquisitions*

Northrock also has anacquisition program focused on properties that compliment existing explorationand development initiatives and on identifying new areas where significantdevelopment opportunities are anticipated. In 2006, Northrock spent $34 millionto acquire interests in producing properties located primarily in theMikwan/Huxley area of Alberta. For 2007, the Company anticipates that Northrockwill continue to pursue incremental acquisition opportunities to supplement itsexploration and development program.

**Asia and Pacific Region**

*New Zealand.*   During 2004, the Company was grantedthree petroleum exploration licenses over approximately 1,044,000 acres in theoffshore Northern Taranaki Basin. During 2006, the Company farmed-out 50% ofits working interest in these three permits to two industry partners. Theprimary exploration term of these licenses is for five years, subject toextension for up to an additional ten years, provided that at least half of theacreage under each license has been relinquished and the permit holder hassubstantially complied with the terms of its permits. The Company committed toacquire 3-D seismic data over at least 1,000 square kilometers of thelicenses within the first two years of their primary term and to reprocess433 miles of existing 2-D seismic data. During 2004 and early 2005,the Company exceeded its work obligations with respect to both 3-Dseismic data acquisition and 2-D seismic data reprocessing. The 3-Dseismic data acquired by the Company has been processed and is being analyzed.The Company and its partners have agreed to drill at least one well in 2007with a rig that the Company has under contract. The Company also anticipatesacquiring additional 3-D seismic data over a portion of its NorthernTaranaki permit areas in 2007. The Company has a commitment to drill one wellon each of the three licenses by February 2008 or relinquish the licenses.Production permits of up to 40 years may be applied for if a commercial fieldis discovered.

During 2006, the Companywas granted a petroleum exploration license over approximately 21,460 squarekilometers (approximately 5.31 millionacres) in the offshore East Coast Basin. The primary term of this licenseis for five years, subject to extension for up to an additional ten years,provided that at least half 

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of theacreage under the license has been relinquished and the permit holder hassubstantially complied with the terms of the permit. The Company committed toreprocess 3,800 kilometers of existing 2-D seismic data and acquire 2000kilometers of new 2-D seismic data over the permit area within the firstyear of the primary term. The Company must commit to drill one well within thepermit area prior to May 2008 or relinquish the license. As in theNorthern Taranaki permit areas, a production permit of up to 40 years may beapplied for if a commercial field is discovered.

*Vietnam.*   TheCompany, together with a joint venture partner, entered into a ProductionSharing Contract with PetroVietnam, the state oil company of Vietnam, for Block124, which covers approximately 1.48 million acres offshore central Vietnam.The initial term of the contract is seven years, consisting of a three yearprimary phase during which the Company is committed to acquire, process andinterpret at least 800 square kilometers of 3-D seismic data and drilltwo exploration wells, followed by two consecutive year optional phases. Thecontract may be extended to a maximum term of 35 years if a commercial field isdiscovered.

*Thailand and 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 sales 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.

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.

Both the Thailand andHungary assets have been treated as discontinued operations. For furtherdiscussion, please refer to “Management’s Discussion and Analysis of FinancialCondition and Results of Operations.”

**Geographic and Other Information**

For financial informationabout geographic areas, see Note 10—Geographic Segment Information in the Notesto Consolidated Financial Statements, which is incorporated herein byreference. For a presentation of the Company’s revenues, net income and totalassets for the years ended December 31, 2006, 2005 and 2004, respectively,see “Financial Statements and 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 owns anapproximate 13.68% interest in the Lost Cabin Gas Plant located in the MaddenUnit, which currently is processing approximately 336 MMcf per day.

12

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*Sales*

The marketing of all ofthe Company’s onshore and offshore oil and gas production is subject to theavailability of pipelines and other transportation, processing and refiningfacilities, as well as the existence of adequate markets. As a result, even ifhydrocarbons are discovered in commercial quantities, a substantial period oftime could elapse before commercial production commences. If pipelinefacilities in an area are insufficient, the Company may have to await theconstruction or expansion of pipeline capacity before production from that areacan be marketed. The Company’s domestic onshore and offshore properties aregenerally located in areas where a pipeline infrastructure or othertransportation alternatives are well developed and there is adequateavailability in such pipelines or other transportation alternatives totransport the Company’s current and projected future production.

Most of the Company’sdomestic natural gas sales are currently made in the “spot market” for no morethan one month at a time at then-currently available prices or underlonger-term contracts with prices that are based on, and fluctuate with spotmarket prices. Prices on the spot market fluctuate with supply and demand.Domestic crude oil and condensate production is also generally sold one monthat a time at the price that is then-currently available or under longer-termcontracts with prices that also fluctuate in relationship to published marketprice.

Northrock, the Company’swholly-owned Canadian subsidiary, currently sells approximately 50% of its oilproduction under contracts with a six-month term but with prices based onmonthly market conditions. The remainder of Northrock’s crude oil production issold in the spot market for no more than one month at a time at then currentlyavailable prices. The majority of Northrock’s gas sales are month-to-month spotmarket sales at currently available prices. Approximately 60% of Northrock’sspot market, month-to-month sales of natural gas are sold under firm deliveryrequirements for the month of sales. The remaining approximate 40% of sales aresold under a best efforts basis. The Company believes that this 60-40 mixaffords it the necessary flexibility in its production to meet all firmdelivery requirements. A small portion of Northrock’s gas sales are underlonger-term contracts but with prices based on monthly market conditions andbest efforts delivery obligations.

Other than oil and naturalgas forward sales contracts that may exist from time to time, which aredescribed below in “—Miscellaneous; Competition and Market Conditions,” and thenatural gas contracts discussed above, the Company has no existing contractsthat require the delivery of fixed quantities of oil or natural gas, other thanon a best efforts basis.

In 2006, crude oil salesto Shell Trading Company and gas sales to NGX each constituted more than 10% ofthe Company’s consolidated revenues.

*Competition and Market Conditions*

The Company experiencescompetition from other oil and gas companies in all phases of its operations,as well as competition from other energy-related industries. See “Risk Factors—TheCompany faces significant 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 in oilor gas prices could have a material adverse effect on the Company’s cash flowand profitability. Sustained periods of low prices could cause the Company toshut-in existing production and also have a material adverse effect on itsoperations and financial condition. It could also result in a reduction offunds available under the Company’s bank credit 

13

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facilities.See “Management’s Discussion and Analysis of Financial Condition and Results ofOperations—Liquidity and Capital Resources; Credit Agreement.”

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, 2006, 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 total acres or wells in which the Company has an interest and “net”refers to gross acres or wells multiplied by the percentage working interestowned by the Company in such acres or wells.

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, 2006:

| ** **              | ** ** | **Developed Acreage(a)** | ** ** | **Undeveloped Acreage(b)** | ** ** |
|-------------------------|------------|-------------------------------|------------|---------------------------------|------------|
| ** **              | ** ** | **Gross**                     | ** ** | **Net**                         | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Domestic Onshore        |       |                          |       |                            |       |   |   |   |   |
| Louisiana               |       | 9,999                         |       | 4,872                           |       | 92,092 |   | 88,382 |   |
| New Mexico              |       | 116,886                       |       | 86,568                          |       | 115,405 |   | 74,060 |   |
| Texas                   |       | 429,142                       |       | 263,173                         |       | 570,322 |   | 428,846 |   |
| Indiana                 |       | 24,130                        |       | 10,983                          |       | 228,693 |   | 108,125 |   |
| Wyoming                 |       | 30,885                        |       | 3,895                           |       | 137,149 |   | 100,549 |   |
| Utah                    |       | 0                             |       | 0                               |       | 70,978 |   | 68,591 |   |
| Other                   |       | 34,663                        |       | 13,481                          |       | 287,968 |   | 177,357 |   |
| Total Domestic Onshore  |       | 645,705                       |       | 382,972                         |       | 1,502,607 |   | 1,045,910 |   |
| Domestic Offshore       |       |                          |       |                            |       |   |   |   |   |
| Louisiana               |       | 126,176                       |       | 27,876                          |       | 174,595 |   | 78,052 |   |
| Texas                   |       | 11,520                        |       | 2,643                           |       | 11,520 |   | 2,016 |   |
| Total Domestic Offshore |       | 137,696                       |       | 30,519                          |       | 186,115 |   | 80,068 |   |
| Total Domestic          |       | 783,401                       |       | 413,491                         |       | 1,688,722 |   | 1,125,978 |   |
| International           |       |                          |       |                            |       |   |   |   |   |
| Canada                  |       | 654,874                       |       | 319,998                         |       | 1,950,162 |   | 1,012,256 |   |
| New Zealand             |       | 0                             |       | 0                               |       | 6,354,000 |   | 5,832,000 |   |
| Vietnam                 |       | 0                             |       | 0                               |       | 1,480,000 |   | 1,480,000 |   |
| Total International     |       | 654,874                       |       | 319,998                         |       | 9,784,162 |   | 8,324,256 |   |
| Total Company           |       | 1,438,275                     |       | 733,489                         |       | 11,472,884 |   | 9,450,234 |   |

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(a)           “Developed acreage”consists of lease acres spaced or assignable to production on which wells havebeen drilled or completed to a point that would permit the production ofcommercial quantities of oil or natural gas.

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(b)          Approximately19% of the Company’s total offshore net undeveloped acreage has expiring termsin 2007 and approximately 9% of the Company’s total onshore net undevelopedacreage has expiring terms in 2008.

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

The following table showsthe average production (lifting) costs per unit of production during theperiods indicated. For a discussion of the Company’s average daily productionand the average sales prices received by the Company for such production, see “SelectedFinancial Data—Production (Sales) Data” and “Management’s Discussion andAnalysis of Financial Condition and Results of Operations—Results ofOperations; Oil and Gas Revenues.” Production (lifting) costs are defined asthe sum of lease operating expenses (which include insurance and producing welloverhead), production and other taxes and transportation costs.

| ** **                                       | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|--------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Average Production  (Lifting) Costs per Mcfe(a): | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Located in the United States                     |       | $          | 2.16       |       | $          | 1.45       |       | $ | 0.97 |   |
| Located in Canada                                |       | $          | 1.63       |       | $          | 1.47       |       | — |   |
| Total Company(b)                                 |       | $          | 1.98       |       | $          | 1.45       |       | $ | 0.97 |   |

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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)          TotalCompany average production costs exclude discontinued operations.

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*Productive Wells and Drilling Activity*

Thefollowing table shows the Company’s interest in productive oil and natural gaswells as of December 31, 2006. For purposes of this table “productivewells” are defined as wells producing hydrocarbons and wells “capable ofproduction” (i.e., natural gas wells waiting for pipeline connections ornecessary governmental certification to commence deliveries and oil wellswaiting to be connected to currently installed production facilities). “Netwells” for purposes of this table are defined to mean the sum of the Company’sworking interest net of royalties and other burdens. This table does notinclude exploratory or development wells that have located commercialquantities of oil or natural gas but that are not capable of commercialproduction without the installation of material production facilities or that,for a variety of reasons, the Company does not currently believe will be placedon production.

| ** **             | ** ** | **Oil Wells(a)(b)** | ** ** | **Natural  Gas Wells(a)(b)** | ** ** | **Total** | ** ** |
|------------------------|------------|--------------------------|------------|-----------------------------------|------------|-----------|------------|
| ** **             | ** ** | **Gross**                | ** ** | **Net**                           | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Domestic  Onshore**  | ** ** | **2,187**                | ** ** | **1,455.2**                       | ** ** | **2,083** | ** ** | **1,228.7** | ** ** | **4,270** | ** ** | **2,683.9** | ** ** |
| Operated               |       | 1,439                    |       | 1,332.3                           |       | 1,296     |       | 1,083.6 |   | 2,735 |   | 2,415.9 |   |
| Nonoperated            |       | 748                      |       | 122.9                             |       | 787       |       | 145.1 |   | 1,535 |   | 268.0 |   |
| **Domestic  Offshore** | ** ** | **127**                  | ** ** | **30.9**                          | ** ** | **52**    | ** ** | **12.3** | ** ** | **179** | ** ** | **43.2** | ** ** |
| Operated               |       | 47                       |       | 20.4                              |       | 29        |       | 9.7 |   | 76 |   | 30.1 |   |
| Nonoperated            |       | 80                       |       | 10.5                              |       | 23        |       | 2.6 |   | 103 |   | 13.1 |   |
| **Canada**             | ** ** | **1,573**                | ** ** | **840.0**                         | ** ** | **724**   | ** ** | **363.0** | ** ** | **2,297** | ** ** | **1,203.0** | ** ** |
| Operated               |       | 530                      |       | 477.0                             |       | 366       |       | 279.0 |   | 896 |   | 756.0 |   |
| Nonoperated            |       | 1,043                    |       | 363.0                             |       | 358       |       | 84.0 |   | 1,401 |   | 447.0 |   |
| **Total**              | ** ** | **3,887**                | ** ** | **2,326.1**                       | ** ** | **2,859** | ** ** | **1,604.0** | ** ** | **6,746** | ** ** | **3,930.1** | ** ** |
| Operated               |       | 2,016                    |       | 1,829.7                           |       | 1,691     |       | 1,372.3 |   | 3,707 |   | 3,202.0 |   |
| Nonoperated            |       | 1,871                    |       | 496.4                             |       | 1,168     |       | 231.7 |   | 3,039 |   | 728.1 |   |

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(a)           One or more completionsin the same bore hole are counted as one well. The data in the above tableincludes 35 gross (19.3 net) oil wells and 136 gross (83.6 net) natural gaswells with multiple completions.

(b)          The Company was in theprocess of drilling a total of 59 gross (7 Canada, 52 U.S.) and 38.8 net(5.3 Canada, 33.5 U.S.) oil and natural gas wells as of December 31,2006.

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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.

| ** **        | ** ** | **2006**       | ** ** | **2005**   | ** ** | **2004**       | ** ** |
|-------------------|------------|----------------|------------|------------|------------|----------------|------------|
| ** **        | ** ** | **Productive** | ** ** | **Dry**    | ** ** | **Productive** | ** ** | **Dry** | ** ** | **Productive** | ** ** | **Dry** | ** ** |
| **Gross Wells:**  | ** ** |           | ** ** | ** ** |       | ** **     | ** ** |   | ** ** | ** ** |   | ** ** | ** ** |   | ** ** | ** ** |   | ** ** | ** ** |
| Domestic Onshore  |       |           |       | ** ** |       |           |       |   |   | ** ** |   |   |   |   |   | ** ** |   |   |   |
| Exploratory       |       |           | 21         | ** ** |       | 15             |       |   | 10 | ** ** |   | 3 |   |   | 1 | ** ** |   | 5 |   |
| Development       |       |           | 258        | ** ** |       | 29             |       |   | 204 | ** ** |   | 12 |   |   | 248 | ** ** |   | 9 |   |
| Domestic Offshore |       |           |       | ** ** |       |           |       |   |   | ** ** |   |   |   |   |   | ** ** |   |   |   |
| Exploratory       |       |           | 0          | ** ** |       | 1              |       |   | 2 | ** ** |   | 5 |   |   | 2 | ** ** |   | 2 |   |
| Development       |       |           | 1          | ** ** |       | 0              |       |   | — | ** ** |   | — |   |   | 8 | ** ** |   | — |   |
| Canada            |       |           |       | ** ** |       |           |       |   |   | ** ** |   |   |   |   |   | ** ** |   |   |   |
| Exploratory       |       |           | 28         | ** ** |       | 9              |       |   | 2 | ** ** |   | 1 |   |   | — | ** ** |   | — |   |
| Development       |       |           | 124        | ** ** |       | 2              |       |   | 37 | ** ** |   | 3 |   |   | — | ** ** |   | — |   |
| Total             |       |           | 432        | ** ** |       | 56             |       |   | 255 | ** ** |   | 24 |   |   | 259 | ** ** |   | 16 |   |
| **Net Wells:**    | ** ** |           | ** ** | ** ** |       | ** **     | ** ** |   | ** ** | ** ** |   | ** ** | ** ** |   | ** ** | ** ** |   | ** ** | ** ** |
| Domestic Onshore  |       |           |       | ** ** |       |           |       |   |   | ** ** |   |   |   |   |   | ** ** |   |   |   |
| Exploratory       |       |           | 15.7       | ** ** |       | 12.2           |       |   | 7.7 | ** ** |   | 2.2 |   |   | 0.6 | ** ** |   | 3.8 |   |
| Development       |       |           | 163.1      | ** ** |       | 17.7           |       |   | 70.2 | ** ** |   | 5.1 |   |   | 122.4 | ** ** |   | 4.6 |   |
| Domestic Offshore |       |           |       | ** ** |       |           |       |   |   | ** ** |   |   |   |   |   | ** ** |   |   |   |
| Exploratory       |       |           | 0.0        | ** ** |       | 0.6            |       |   | 2.0 | ** ** |   | 3.9 |   |   | 1.6 | ** ** |   | 1.8 |   |
| Development       |       |           | 0.5        | ** ** |       | 0.0            |       |   | — | ** ** |   | — |   |   | 6.2 | ** ** |   | — |   |
| Canada            |       |           |       | ** ** |       |           |       |   |   | ** ** |   |   |   |   |   | ** ** |   |   |   |
| Exploratory       |       |           | 23.6       | ** ** |       | 7.5            |       |   | 1.5 | ** ** |   | 1.0 |   |   | — | ** ** |   | — |   |
| Development       |       |           | 73.8       | ** ** |       | 1.5            |       |   | 21.9 | ** ** |   | 1.9 |   |   | — | ** ** |   | — |   |
| Total             |       |           | 276.7      | ** ** |       | 39.5           |       |   | 103.3 | ** ** |   | 14.1 |   |   | 130.8 | ** ** |   | 10.2 |   |

 

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*Reserves*

Thefollowing table sets forth information as to the Company’s net total proved andproved developed reserves as of December 31, 2006, 2005 and 2004, 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, for certain ofits domestic properties acquired from Latigo, Ryder Scott Company—Canada (“RyderScott Canada”), for all of its Canadian properties, and Miller and Lents, Ltd.(“Miller and Lents”), for certain of its onshore Gulf Coast and Rocky Mountainproperties, in accordance with criteria prescribed by the Commission. Thesummary reports of Ryder Scott, Ryder Scott Canada, and Miller and Lents,independent petroleum engineering firms, on the Company’s reserves are setforth as exhibits to this Annual Report on Form 10-K and areincorporated herein by reference. The Ryder Scott reports cover all of theCompany’s reserves, except for the Company’s Canadian areas, which are coveredby the Ryder Scott Canada report, and certain domestic onshore areas on theTexas/Louisiana Gulf Coast and in Wyoming, which are covered by the Miller andLents report. Reserves attributable to the Company’s operations in Thailand andHungary, operations that were disposed of in 2005 and are accounted for in theCompany’s financial statements as discontinued operations, are excluded fromthe table below and separately presented in the footnotes that follow thetable.

| ** **                                                                                 | ** ** | **As of December 31,** | ** ** |
|--------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                 | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Total Proved Reserves(a):**                                                              |       |                                  |       |   |   |   |   |
| Oil, condensate and natural gas liquids (MBbls)                                            |       |                                  |       |   |   |   |   |
| Located in the United  States                                                              |       | 98,718                                |       | 82,238 |   | 83,866 |   |
| Located in Canada                                                                          |       | 64,617                                |       | 61,803 |   | — |   |
| Total Company                                                                              |       | 163,335                               |       | 144,041 |   | 83,866 |   |
| Natural Gas (MMcf)                                                                         |       |                                  |       |   |   |   |   |
| Located in the United  States                                                              |       | 914,657                               |       | 891,298 |   | 933,981 |   |
| Located in Canada                                                                          |       | 318,313                               |       | 286,427 |   | — |   |
| Total Company                                                                              |       | 1,232,970                             |       | 1,177,725 |   | 933,981 |   |
| Present value of estimated future net cash flows,  before income taxes (in thousands) |       |                                  |       |   |   |   |   |
| Located in the United  States                                                              |       | $                                     | 2,979,261  |   | $ | 4,666,472 |   | $ | 3,639,318 |   |
| Located in Canada                                                                          |       | $                                     | 1,498,958  |   | $ | 1,954,086 |   | — |   |
| Total Company                                                                              |       | $                                     | 4,478,219  |   | $ | 6,620,558 |   | $ | 3,639,318 |   |
| **Total Proved Developed Reserves(b):**                                                    |       |                                  |       |   |   |   |   |
| Oil, condensate and natural gas liquids (MBbls)                                            |       |                                  |       |   |   |   |   |
| Located in the United  States                                                              |       | 67,685                                |       | 63,161 |   | 72,968 |   |
| Located in Canada                                                                          |       | 55,918                                |       | 55,413 |   | — |   |
| Total Company                                                                              |       | 123,603                               |       | 118,574 |   | 72,968 |   |
| Natural Gas (MMcf)                                                                         |       |                                  |       |   |   |   |   |
| Located in the United  States                                                              |       | 701,550                               |       | 685,301 |   | 769,753 |   |
| Located in Canada                                                                          |       | 236,791                               |       | 220,704 |   | — |   |
| Total Company                                                                              |       | 938,341                               |       | 906,005 |   | 769,753 |   |
| Present value of estimated future net cash flows,  before income taxes (in thousands) |       |                                  |       |   |   |   |   |
| Located in the United  States                                                              |       | $                                     | 2,515,279  |   | $ | 3,660,148 |   | $ | 3,122,860 |   |
| Located in Canada                                                                          |       | $                                     | 1,295,906  |   | $ | 1,653,299 |   | — |   |
| Total Company                                                                              |       | $                                     | 3,811,185  |   | $ | 5,313,447 |   | $ | 3,122,860 |   |

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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, 2004,the Company’s proved reserves in 

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Thailand consisted of32,517 MBbls and 37,307 MBbls of oil, condensate and natural gas liquids,respectively. The Company had no proved reserves in Hungary as of December 31,2004.

(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, the Company’s proved developed reserves in Thailand consisted of 19,607MBbls and 19,878 MMBbls of oil, condensate and natural gas liquids, respectively.The Company had no proved developed reserves in Hungary as of December 31,2004.

The following tablepresents a reconciliation of the PV-10 values set forth above for bothproved and proved developed reserves to the most directly comparable GAAP financialmeasure, which is the standardized measure of discounted future net cash flows.Management believes that presentation of PV-10 values is relevant anduseful to the Company’s investors because it presents the discounted future netcash flows attributable to both the Company’s proved and proved developedreserves prior to taking into account the effect of the non-property relatedexpense of estimated future income taxes. Because many factors that are uniqueto individual companies may impact the amount of future income taxes to bepaid, the use of a pre-tax measure such as PV-10 provides greatercomparability for investors when evaluating companies. Accordingly, investorsmay utilize the measure as a basis for comparison of the relative size andvalue of the Company’s reserves to other companies. Management also uses the PV-10measure when assessing the potential return on investment related to theCompany’s oil and gas properties. PV-10 is not a measure of financial oroperating performance under GAAP, nor should it be considered in isolation oras a substitute for the standardized measure of discounted future net cashflows as defined under GAAP. For the Company’s presentation of the standardizedmeasure of discounted future net cash flows, please see “Standardized Measureof Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves—Unaudited”following the notes to the consolidated financial statements in this report.

**Present Value GAAP to Non-GAAP Reconciliation**

| ** **                                                                                                   | ** ** | **As of December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                                   | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                                   | ** ** | **(thousands)**                       | ** ** |
| Present value of  estimated future net cash flows, before income taxes, of proved  developed reserves   |       | $                                     | 3,811,185  |   | $ | 5,313,447 |   | $ | 3,122,860 |   |
| Present value of  estimated future net cash flows, before income taxes, of proved  undeveloped reserves |       | 667,034                               |       | 1,307,111 |   | 516,447 |   |
| Present value of  estimated future net cash flows, before income taxes, of total proved  reserves       |       | $                                     | 4,478,219  |   | $ | 6,620,558 |   | $ | 3,639,307 |   |
| Future income  taxes, net of discount at 10% per annum                                                       |       | (1,125,251                            | )          | (2,057,713 | ) | (1,080,607 | ) |
| Standardized measure of  discounted future net cash flows related to proved oil and gas reserves             |       | $                                     | 3,352,968  |   | $ | 4,562,845 |   | $ | 2,558,700 |   |

 

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 cash flows, 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 15.1% ofthe Company’s total proved liquids reserves and approximately 14.9% of theCompany’s proved developed liquids reserves as of December 31, 2006. 

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All hydrocarbon liquidreserves are expressed in standard 42 gallon Bbls. All gas volumes and gassales are expressed in MMcf at the pressure and temperature bases of the areawhere the gas reserves are located.

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

| ** **                                         | ** ** | **As of December 31,** | ** ** |
|----------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                         | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
| Initial Weighted Average  Price (in Dollars):      |       |                                  |       |   |   |   |   |
| Oil, condensate  and natural gas liquids (per Bbl) |       |                                  |       |   |   |   |   |
| Located in the United States                       |       | $                                     | 55.20      |   | $ | 57.06 |   | $ | 40.82 |   |
| Located in Canada(a)                               |       | $                                     | 44.26      |   | $ | 42.86 |   | — |   |
| Natural Gas (per  Mcf)                             |       |                                  |       |   |   |   |   |
| Located in the United States                       |       | $                                     | 5.19       |   | $ | 8.15 |   | $ | 6.04 |   |
| Located in Canada                                  |       | $                                     | 5.49       |   | $ | 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 net revenues from gas reservesattributable to the Company’s interests, prices in effect at December 31,2006 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 cash flows from liquids attributable to theCompany’s interests, prices in effect at December 31, 2006 were used andthese prices were held constant through to depletion of the properties. Thefuture net cash flows are adjusted to reflect the Company’s net revenueinterest in these reserves as well as any ad valorem and other severance taxes,but do not include any provisions for corporate income taxes.

In calculating future net cash flows, the operatingcosts for the leases and wells include only those costs directly applicable tothe leases or wells. When applicable, the operating costs include a portion ofgeneral and administrative costs allocated directly to the leases and wellsunder terms of operating agreements. Development costs are based onauthorization for expenditure for the proposed work or actual costs for similarprojects. The current operating and development costs were held constantthroughout the life of the properties. The estimated net cost of abandonmentafter salvage was considered for the properties. No deduction was made forindirect costs such as general and administrative and overhead expenses, loanrepayments, interest expenses and exploration and development prepayments.Accumulated gas production imbalances, if any, have been taken into account.

Production data used to arrive at the estimates setforth above includes estimated production for the last few months of 2006. 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. Properties thatare not currently producing may start producing earlier or later thananticipated in the estimates of future production rates.

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There are numerous uncertainties in estimating thequantity of proved reserves and in projecting the future rates of production andtiming of development expenditures. Oil and gas reserve engineering must berecognized as a subjective process of estimating underground accumulations ofoil and gas that cannot be measured in an exact way, and estimates of otherengineers might differ materially from those of the Company, Ryder Scott, RyderScott Canada, and Miller and Lents. The accuracy of any reserve estimateis a function of the quality of available data and of engineering andgeological interpretation and judgment. Results of drilling, testing andproduction subsequent to the date of the estimate may justify revision of suchestimate, which may be material. Accordingly, reserve estimates are oftendifferent from the quantities of oil and gas that are ultimately recovered.

The Company isperiodically required to file estimates of its oil and gas reserve data withvarious U.S. governmental regulatory authorities and agencies, including theDepartment of Energy, the Federal Energy Regulatory Commission (“FERC”) and theFederal Trade Commission. In addition, estimates are from time to timefurnished to governmental agencies in connection with specific matters pendingbefore such agencies. The basis for reporting reserves to these agencies, insome cases, is not comparable to that used as a basis for the estimates setforth above in accordance with Commission guidelines because of the nature ofthe various reports required. The major differences generally includedifferences in the timing of such estimates, differences in the definition of reserves,requirements to report in some instances on a gross, net or total operatorbasis and requirements to report in terms of smaller geographical units. Since January 1,2005, no estimates by the Company of its total proved net oil or gas reserveswere filed with or included in reports to any federal authority or agency otherthan the Commission.

**GovernmentRegulations**

*Domestic andForeign Tax*

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

*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 be designatedas “hazardous wastes” under RCRA or other applicable statutes. If this were tooccur, the Company would become subject to more rigorous and costly operatingand disposal requirements.

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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.Under CERCLA, liable persons may be subject to joint and several liability forthe costs of cleaning up the hazardous substances that have been released intothe environment and for damages to natural resources, and it is not uncommonfor neighboring landowners and other third parties to file claims for personalinjury and property damage allegedly caused by the hazardous substancesreleased into the environment. The Company currently owns interests in oroperates numerous properties and facilities that for many years have been usedfor industrial activities, including oil and gas production operations.Hazardous substances, wastes, or hydrocarbons may have been released on orunder the properties owned or leased by the Company, or on or under otherlocations where such substances have been taken for disposal. In addition, someof these properties have been operated by third parties or by previous ownerswhose treatment and disposal or release of hazardous substances, wastes, orhydrocarbons, was not under the Company’s control. These properties and thesubstances disposed or released on them may be subject to CERCLA, RCRA andanalogous state laws. Under such laws, the Company could be required to removepreviously disposed substances and wastes (including substances disposed of orreleased by prior owners or operators), remediate contaminated property(including groundwater contamination, whether from prior owners or operators orother historic activities or spills), or perform remedial plugging or pitclosure operations to prevent future contamination. These laws and regulationsmay also expose the Company to liability for its acts that were in compliancewith applicable laws at the time the acts were performed. The Company maintainsinsurance against costs of clean-up operations, but is not fully insuredagainst all such risks. A serious incident of pollution may also result in theDepartment of the Interior requiring lessees under federal leases to suspend orcease operation in the affected area.

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

The Oil Pollution Act of 1990 (the “OPA”) andregulations thereunder impose a variety of regulations on “responsible parties”related to the prevention of oil spills and liability for damages resultingfrom such 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 more adverse to the Company than it will be to othersimilarly situated or less capitalized owners or operators in the Gulf ofMexico.

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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.The Government of Canada has put forward a Climate Change Plan for Canada,which suggests 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 2006, the Company incurred capitalexpenditures of approximately $6,382,000 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 $5,418,250 for expendituresinvolving environmental control facilities during 2007, 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 thatcould be drilled on the Company’s properties and to limit the allowableproduction from the successful wells completed on the Company’s properties,thereby limiting the Company’s revenues.

The Minerals Management Service (“MMS”) administersthe oil and gas leases held by the Company on federal onshore lands andoffshore tracts in the Outer Continental Shelf. The MMS holds a royaltyinterest in these federal leases on behalf of the federal government. While theroyalty interest percentage is fixed at the time that the lease is enteredinto, from time to time the MMS changes or reinterprets the 

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applicable regulationsgoverning its royalty interests, and such action can indirectly affect theactual royalty obligation that the Company is required to pay. However, theCompany believes that the regulations generally do not impact the Company toany greater extent than other similarly situated producers.

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

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

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

**Employees**

As of December 31, 2006, the Company and itssubsidiaries had 566 full-time employees, including 183 in its Calgary office.None of the Company’s employees are presently represented by a union forcollective 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 Ethics requiredto be disclosed by rules of the Commission or the New York Stock Exchangewill be posted on the Company’s Internet website within five business days andmaintained for at least twelve months.

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

***Natural gas and oilprices fluctuate widely, and low prices could have a material adverse impact onthe 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 recent acquisitions are significant andmay not be successful.***

In September 2005,the Company completed the acquisition of Northrock, the largest acquisition inits history. In May 2006, the Company completed the acquisition of Latigo,another significant acquisition for the Company. The Company may not be able torealize anticipated economic, operational and other benefits from these recentacquisitions due to the following risks and difficulties, among others:

·       theacquired properties may not produce revenues, earnings or cash flow atanticipated levels;

·       theCompany may have exposure to unanticipated liabilities and costs as a result ofthe acquisitions, some of which may materially exceed its estimates;

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

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

·       theCompany may experience material difficulties and additional costs inintegrating Northrock’s or Latigo’s operations, systems and personnel with itsown; and

·       the Company may need torecognize additional impairment expense in the future on the unproved propertyacquired in the acquisitions (including interest capitalized in future periods).

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***The natural gas andoil business involves many operating risks that can cause substantial losses orhinder 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.

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 in commercialquantities, a substantial period of time may elapse before commercialproduction commences. If pipeline facilities in an area are insufficient, theCompany 

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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 notbe able to obtain sufficient drilling equipment and experienced personnel toconduct 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. This may lead to difficulty and delays inconsistently obtaining services and equipment from vendors, obtaining drillingrigs and other equipment at favorable rates, and scheduling equipmentfabrication at factories and fabrication yards. This, in turn, may lead toprojects being delayed or experiencing increased costs.

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

TheCompany’s ownership and operations in Canada, New Zealand, Vietnam and anyother foreign areas where it does business are subject to the various risksinherent in foreign 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.

***The Company cannotcontrol the activities on properties it does not operate; operators of thoseproperties may act in ways that 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;

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·       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.

***Maintainingreserves and revenues in the future depends on successful exploration anddevelopment 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. In addition,pollution and environmental risks generally are not fully insurable. If asignificant accident or other event occurs and is not fully covered byinsurance, it could adversely affect the Company’s operations and financialcondition. Moreover, there is no assurance that recoveries for insured eventswill be sufficient to cover cash flow that the Company would have otherwisegenerated from affected properties.

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

The Company requiressubstantial capital to replace its reserves and generate sufficient cash flowto meet its financial obligations. If the Company cannot generate sufficientcash flow from operations or raise funds externally in the amounts and at thetimes needed, it may not be able to replace its reserves or meet its financialobligations. The Company’s ongoing capital requirements consist primarily ofthe following items:

·       fundingits 2007 capital and exploration budget of $720 million;

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

·       futuredividends.

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

·       availablecash and cash investments;

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·       cashprovided by operating activities;

·       fundsavailable under its credit facility;

·       itsuncommitted money market line(s) of credit; and

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

The Company financed asubstantial part of the Northrock acquisition utilizing cash on hand, proceedsfrom the offering of its 6.875% Senior Subordinated Notes due 2017 andborrowings under its revolving credit facility. In addition, the Companyfinanced a portion of its acquisition of Latigo utilizing borrowings under itsrevolving credit facility. Accordingly, these acquisitions reduce theavailability of those resources for other capital requirements. Moreover, theuncertainties and risks associated with future performance and revenues willultimately determine the Company’s liquidity and ability to meet anticipatedcapital requirements.

***Rights to repaymentor acceleration of up to $2.3 billion of the Company’s debt and other paymentswould be triggered by a change in a majority of the Board of Directors that isnot approved by incumbent directors.***

On February 23, 2007, ashareholder formally notified the Company that it intends to conduct a proxycontest at the Company’s 2007 annual meeting that would, if successful, resultin a change in a majority of the Board of Directors. As of February 28,2007, the Company had approximately $1.45 billion aggregate principal amount ofsenior subordinated notes outstanding and approximately $869 million ofoutstanding senior indebtedness, approximately $769 million of which wasoutstanding under its revolving credit facility.  If there is a change in a majority of theBoard of Directors not approved by a vote of two-thirds of the incumbentdirectors, the indentures governing the notes require the Company to offer torepurchase all outstanding notes at 101% of their principal amount and to repayall outstanding senior debt, including the credit facility, prior torepurchasing the notes (or obtain consent from the lenders allowing for suchrepurchase). Although such a change in a majority of the Board of Directorswould not, by itself, constitute an event of default under the credit facility,failure by the Company to perform its indenture obligations would allow thelenders under the credit facility to accelerate the credit facility debt.During 2007, two series of the Company’s notes, representing $800 million inaggregate principal amount, have generally traded below their principal facevalue, and the other two series, representing $650 million in aggregateprincipal amount, have generally traded above 101% of their principal amount.The Company cannot predict the actions its noteholders or lenders may take.However, the Company believes that holders whose notes were trading below therepurchase price at the time the rights were triggered would exercise theirrepurchase rights. Additionally, the Company believes that lenders under itscredit facility and holders whose notes were trading above the repurchase pricemay also exercise their repayment or repurchase rights, as the case may be, tothe extent they expect that the holders whose notes were trading below therepurchase price would exercise such rights or for other reasons. The Companydoes not have sufficient cash available to fund a repurchase of all or asubstantial portion of the senior subordinated notes or to repay all or asubstantial portion of outstanding debt under the credit facility.

Defaults under, or theacceleration of, the notes or credit facility could significantly and adverselyaffect the Company’s financial position. If the Company were not able torefinance the debt, it could be required to sell substantial assets at distressprices in order to satisfy its obligations or to seek protection under thefederal bankruptcy laws. Any refinancing of the Company’s existing debt withnew debt, if available, would likely involve substantial costs, including thepremium to repurchase notes from existing holders and transaction costsassociated with obtaining new debt. Such new debt may be on less favorableterms than the Company’s existing debt. Refinancing may also negatively impactthe Company’s strategic alternatives initiative.  

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A change in the majorityof the Board of Directors as a result of the pending proxy contest would alsotrigger an obligation to make payments under the Company’s executive employmentagreements (upon termination of employment by the executives during specifiedperiods or in specified circumstances) and under the Company’s severance andretention program.

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

The Company will continue to seek opportunities togenerate value through business combinations, purchases and sales of assets. TheCompany examines potential transactions on a regular basis, depending on marketconditions, available opportunities and other factors. In addition, the Companycompetes with other companies in pursuing acquisitions, many of which havegreater financial and other resources to acquire attractive companies andproperties. The successful acquisition of oil and gas properties requires anassessment of several factors, including recoverable reserves, development andexploratory potential, projected future cash flows that are, in part, basedupon future oil and gas prices, current and projected operating, general andadministrative and other costs, and contingent liabilities associated with theproperties or entities acquired, including potential environmental and otherliabilities. The accuracy of the Company’s assessment of these factors isinherently uncertain, and the Company’s review and assessment of potentialacquisitions will not reveal all existing or potential problems nor will itpermit the Company to become sufficiently familiar with the properties orentities to fully assess their deficiencies and capabilities. Even when problemsare identified, the other party may be unwilling or unable to provide effectivecontractual protection against all or part of the problems. Furthermore, theCompany may not be entitled to contractual indemnification for certainliabilities, or it may acquire the properties on an “as is, where is” basis.

Dispositions of portionsof the Company’s existing business or properties would be intended to result inthe realization of immediate value but would consequently result in lower cashflows over the longer term, unless the proceeds are reinvested in more productiveassets.

***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 competitors havesubstantially 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 

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Company’scompetitive position. These competitors may also be able to pay more forexploratory prospects and productive oil and natural gas properties and may beable to define, evaluate, bid for and purchase a greater number of propertiesand prospects than the Company can. The Company’s ability to explore for oiland natural gas prospects and to acquire additional properties in the futurewill depend on its ability to conduct operations and to evaluate and selectsuitable properties and transactions in this highly competitive environment.Moreover, the oil and natural gas industry itself competes with otherindustries in supplying the energy and fuel needs of industrial, commercial andother consumers. Increased competition causing oversupply or depressed pricescould greatly affect the Company’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.

***The Company issubject to legal limitations that may adversely affect the cost, manner orfeasibility of doing business.***

The Company and its subsidiariesare subject to extensive domestic and foreign laws and regulations on taxation,exploration and development, and environmental and safety matters in countrieswhere it owns or operates properties. These laws and regulations are undercontinuing review for amendment or expansion, and the Company could be forcedto expend significant resources to comply with new laws or regulations orchanges to existing requirements. Many laws and regulations require drillingpermits and govern the spacing of wells, the prevention of waste, rates ofproduction and other matters. These statutes and regulations, and any othersthat are passed by the jurisdictions where the Company has production couldlimit the total number of wells drilled or the total allowable production fromsuccessful wells, which could limit revenues. Noncompliance with these statutesor failure to establish exemptions from regulations could also result insubstantial penalties, require the posting of substantial surety bonds, or inthe 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.

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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.

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 the maintenanceof specified financial ratios. These restrictions may adversely affect theCompany’s ability to finance its future operations and capital needs, to reactto changes in its business or industry or to pursue available businessopportunities. 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 ormore restrictive covenants on the Company.

**ITEM 1B.   *Unresolved Staff Comments.***

None.

**ITEM 2.   *Properties.***

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

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

The Company is a party tovarious legal proceedings consisting of routine litigation incidental to itsbusinesses, but believes that any potential liabilities resulting from theseproceedings are adequately 

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coveredby insurance or are otherwise not material. See “Business—GovernmentRegulations; Other Laws and Regulations.”

**ITEM 4.**   *Submission of Matters to a Vote of Security Holders.*

No matters were submittedto a vote of the Company’s security holders during the fourth quarter of theyear ended December 31, 2006.

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

Officersof the Company are appointed annually by the Company’s Board of Directors toserve for the ensuing year or until their successors have been elected orappointed. The officers of the Company that have been designated as “executiveofficers” for purposes of Item 401(b) of Regulation S-K and “officers” forpurposes of Section 16 of the Exchange Act, their age as of December 31,2006, and the year each was elected to his current position are as follows:

| **Executive  Officer**  | ** ** | ** **                                                                | ** ** | **Executive Office** | ** ** | **Age** | ** ** | **Year  Elected** |
|-------------------------|------------|---------------------------------------------------------------------------|------------|----------------------|------------|---------|------------|-------------------|
| Paul G. Van Wagenen     |       | Chairman, President and  Chief Executive Officer                          |       | 60                   |       | 1991    |
| Stephen R. Brunner      |       | Executive Vice  President—Operations                                 |       | 48                   |       | 2002    |
| Jerry A. Cooper         |       | Executive Vice President  and Regional Manager—Western United States |       | 58                   |       | 2002    |
| John O. McCoy, Jr. |       | Executive Vice President  and Chief Administrative Officer                |       | 55                   |       | 2002    |
| David R. Beathard       |       | Senior Vice  President—Engineering                                   |       | 48                   |       | 2002    |
| Michael J. Killelea     |       | Senior Vice President,  General Counsel and Corporate Secretary           |       | 44                   |       | 2005    |
| James P. Ulm, II   |       | Senior Vice President  and Chief Financial Officer                        |       | 43                   |       | 2002    |
| Robert C. Marlowe       |       | Vice President—Accounting                                            |       | 44                   |       | 2004    |

 

Mr. Van Wagenen, who joined the Company in 1979,has served in his current position since 1991. Prior to assuming their presentpositions with the Company, the business experience of each of the otherexecutive officers for at least the last five years was as follows: Mr. Brunner,who joined the Company in 1994, served as Vice President—Operations from1997 - 2002; Mr. Cooper, who joined the Company in 1979, served asSenior Vice President and Western Division Manager from 1998 - 2002; Mr. McCoy,who joined the Company in 1978, served as Senior Vice President from1998 - 2002 and has served as Chief Administrative Officer since 1989; Mr. Beathard,who joined the Company in 1982, served as Vice President—Engineering from1997 - 2002; Mr. Killelea who joined the Company in 2000, served asVice President from 2001 - 2005, and has served as Corporate Secretary andGeneral Counsel since 2004 and 2000, respectively; Mr. Ulm, who joined theCompany in 1999, served as Vice President from 1999 - 2002, and has servedas Chief Financial Officer since 1999; and Mr. Marlowe, who joined theCompany in 1991, served as Controller from 1999 - 2004, and has served as VicePresident—Accounting since 2004.

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**PART II**

**ITEM5.**                *Market for the Registrant’s Common Equity; Related Stockholder Mattersand Issuer Purchases of Equity Securities.*

Thefollowing table shows the range of low and high sales prices of the Company’sCommon Stock (the “Common Stock”) on the New York Stock Exchange composite tapewhere the Common Stock trades under the symbol PPP. The Common Stock is alsolisted on the Pacific Exchange under the same symbol.

| ** **  | ** ** | **Low**    | ** ** | **High**   | ** ** |
|-------------|------------|------------|------------|------------|------------|
| **2006**    | ** ** | ** ** | ** ** | ** ** | ** ** |
| 1st Quarter |       | $          | 46.14      |       | $          | 60.42 |   |
| 2nd Quarter |       | $          | 39.35      |       | $          | 54.12 |   |
| 3rd Quarter |       | $          | 38.01      |       | $          | 48.76 |   |
| 4th Quarter |       | $          | 38.35      |       | $          | 54.34 |   |
| **2005**    | ** ** | ** ** | ** ** | ** ** | ** ** |
| 1st Quarter |       | $          | 41.59      |       | $          | 53.30 |   |
| 2nd Quarter |       | $          | 43.38      |       | $          | 54.53 |   |
| 3rd Quarter |       | $          | 51.59      |       | $          | 59.69 |   |
| 4th Quarter |       | $          | 48.04      |       | $          | 59.52 |   |

 

As of February 1,2007, there were 1,946 holders of record of the Company’s Common Stock.

In 2005, the Company paidfour quarterly dividends of $0.0625 per share on its Common Stock. On January 24,2006, the Company’s quarterly dividend was increased by 20% to $0.075 per shareon its Common Stock and the Company paid four quarterly dividends of thatamount during 2006. The declaration and payment of future dividends, and theamount of such dividends, will depend upon, among other things, the Company’sfuture earnings and financial condition, liquidity and capital requirements,the general economic and regulatory climate and other factors deemed relevantby the Company’s Board of Directors.

The Company’s revolvingcredit facility (the “Facility”), under which the Company has borrowed funds,and the Indentures relating to the Company’s 8.250% Senior Subordinated Notesdue 2011 (the “2011 Notes”), 7.875% Senior Subordinated Notes due 2013 (the “2013Notes”), 6.625% Senior Subordinated Notes due 2015 (the “2015 Notes”) and6.875% Senior Subordinated Notes due 2017 (the “2017 Notes”) contain covenantsthat may restrict the ability of the Company to pay future dividends on theCompany’s Common Stock. For further discussion of the covenants, see “Note 4,Long Term Debt” to the Consolidated Financial Statements in this report. TheCompany does not believe that any of these agreements will restrict the Company’sability to pay dividends on its Common Stock in the reasonably foreseeablefuture.

No equity securities ofthe Company not registered under the Securities Act of 1933 were sold by theCompany during the year ended December 31, 2006.

During the fourth quarterof the year ended December 31, 2006, no equity securities of the Companyof any class registered by the Company pursuant to Section 12 of the SecuritiesExchange Act of 1934 were purchased by or on behalf of the Company or any “affiliatedpurchaser” of the Company, as defined in Rule 10b-18(a)(3) underthe Securities Exchange Act.

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*Performance Graph.*Set forth below is a line graph comparing the change in the cumulative totalshareholder return on the Company’s Common Stock against the cumulative totalreturn of (i) the Standard & Poor’s 500 Stock Index and (ii) theStandard & Poor’s Oil and Gas Exploration and Production Index, each forthe period of five fiscal years commencing December 31, 2001 and endedDecember 31, 2006 and each of which assumes an initial value of $100 andreinvestment of all dividends.

**Comparison ofFive-Year Cumulative Total Shareholder Return**

Note: The stock price performance for the Company’sCommon Stock is not necessarily indicative of future performance.

Theperformance graph above is being furnished solely to accompany this annualreport on Form 10-K pursuant to Item 201(e) of Regulation S-K,and is not being filed for purposes of Section 18 of the SecuritiesExchange Act of 1934, as amended, and is not being incorporated by referenceinto any filing of the Company, whether made before or after the date hereof,regardless of any general incorporation language in such filing.

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

In thefollowing table, the Company’s financial, production and other data for 2005and 2006 reflect the Company’s acquisition of Northrock Resources (“Northrock”)from and on September 27, 2005. The Company’s financial, production, andother data for 2006 also reflect the acquisition of Latigo Petroleum, Inc.(“Latigo”) from and on May 2, 2006. The Company’s results for periodspresented prior to 2006 reflect its oil and gas exploration, development andproduction activities in the Kingdom of Thailand and Hungary as discontinuedoperations. The selected financial data should be read in conjunction with “Item7—Management’s Discussion and Analysis of Financial Condition and Results ofOperations” and the audited consolidated financial statements and notes theretoincluded under “Item 8—Financial Statements and Supplementary Data.”

| ** **                                                                                         | ** ** | **For the Year Ended December 31,**                                              | ** ** |
|----------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------|------------|
| ** **                                                                                         | ** ** | **2006**                                                                                                  | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                         | ** ** | **(Expressed in millions, except per share and production data)** | ** ** |
| **Financial Data**                                                                                 | ** ** | ** **                                                                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues:                                                                                          |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Crude oil and condensate                                                                           |       | $                                                                                                         | 653.5      |   | $ | 468.3 |   | $ | 417.1 |   | $ | 426.4 |   | $ | 282.0 |   |
| Natural gas                                                                                        |       | 642.8                                                                                                     |       | 695.4 |   | 512.6 |   | 397.3 |   | 231.3 |   |
| Natural gas liquids                                                                                |       | 79.1                                                                                                      |       | 52.5 |   | 43.4 |   | 32.4 |   | 24.4 |   |
| Oil and gas revenues                                                                               |       | 1,375.4                                                                                                   |       | 1,216.2 |   | 973.1 |   | 856.1 |   | 537.7 |   |
| Other                                                                                              |       | 369.6                                                                                                     | (a)        | 9.5 |   | 3.5 |   | 2.4 |   | 4.4 |   |
| Total                                                                                              |       | $                                                                                                         | 1,745.0    |   | $ | 1,225.7 |   | $ | 976.6 |   | $ | 858.5 |   | $ | 542.1 |   |
| Income from continuing  operations before cumulative effect of change in accounting principle |       | $                                                                                                         | 446.2      |   | $ | 290.1 |   | $ | 249.0 |   | $ | 235.2 |   | $ | 68.6 |   |
| Income from discontinued  operations, net of tax                                                   |       | —                                                                                                    |       | 460.6 | (b) | 12.7 |   | 59.9 |   | 38.4 |   |
| Cumulative effect of  change in accounting principle                                               |       | —                                                                                                    |       | — |   | — |   | (4.2 | )(c) | — |   |
| Net income                                                                                         |       | $                                                                                                         | 446.2      |   | $ | 750.7 |   | $ | 261.7 |   | $ | 290.9 |   | $ | 107.0 |   |
| Per share data:                                                                                    |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Basic income from  operations before cumulative effect of change in accounting principle—     |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| From continuing  operations                                                                        |       | $                                                                                                         | 7.74       |   | $ | 4.80 |   | $ | 3.90 |   | $ | 3.76 |   | $ | 1.18 |   |
| From discontinued  operations                                                                      |       | —                                                                                                    |       | 7.63 |   | 0.20 |   | 0.96 |   | 0.67 |   |
| Basic income from  operations before cumulative effect of change in accounting principle           |       | $                                                                                                         | 7.74       |   | $ | 12.43 |   | $ | 4.10 |   | $ | 4.72 |   | $ | 1.85 |   |
| Diluted income from  operations before cumulative effect of change in accounting principle—   |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| From continuing  operations                                                                        |       | $                                                                                                         | 7.68       |   | $ | 4.76 |   | $ | 3.87 |   | $ | 3.67 |   | $ | 1.16 |   |
| From discontinued  operations                                                                      |       | —                                                                                                    |       | 7.56 |   | 0.19 |   | 0.93 |   | 0.61 |   |
| Diluted income from  operations before cumulative effect of change in accounting principle    |       | $                                                                                                         | 7.68       |   | $ | 12.32 |   | $ | 4.06 |   | $ | 4.60 |   | $ | 1.77 |   |
| Cash dividends on common  stock                                                                    |       | $                                                                                                         | 0.30       |   | $ | 0.25 |   | $ | 0.2125 |   | $ | 0.20 |   | $ | 0.12 |   |
| Price range of common  stock:                                                                      |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| High                                                                                               |       | $                                                                                                         | 60.42      |   | $ | 59.69 |   | $ | 51.34 |   | $ | 49.50 |   | $ | 39.28 |   |
| Low                                                                                                |       | $                                                                                                         | 38.01      |   | $ | 41.59 |   | $ | 39.25 |   | $ | 34.29 |   | $ | 23.00 |   |
| Weighted average number  of common shares outstanding                                              |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Basic                                                                                              |       | 57.6                                                                                                      |       | 60.4 |   | 63.8 |   | 62.5 |   | 57.9 |   |
| Diluted                                                                                            |       | 58.1                                                                                                      |       | 60.9 |   | 64.4 |   | 64.6 |   | 64.3 |   |
| Long-term debt at year  end                                                                        |       | $                                                                                                         | 2,319.7    |   | $ | 1,643.5 |   | $ | 755.0 |   | $ | 487.3 |   | $ | 722.9 |   |
| Shareholders’ equity at  year end                                                             |       | $                                                                                                         | 2,567.4    |   | $ | 2,098.6 |   | $ | 1,727.9 |   | $ | 1,453.7 |   | $ | 1,077.8 |   |
| Total assets at year end                                                                           |       | $                                                                                                         | 6,971.1    |   | $ | 5,675.7 |   | $ | 3,481.1 |   | $ | 2,758.7 |   | $ | 2,491.6 |   |
| **Production  (Sales) Data**                                                                       | ** ** | ** **                                                                                                | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net daily average  production and weighted average price:                                          |       |                                                                                                      |       |   |   |   |   |   |   |   |   |
| Natural gas (MMcf per  day)                                                                        |       | 279.6                                                                                                     |       | 250.2 |   | 244.3 |   | 210.4 |   | 201.3 |   |
| Price (per Mcf)                                                                                    |       | $                                                                                                         | 6.30       |   | $ | 7.62 |   | $ | 5.73 |   | $ | 5.17 |   | $ | 3.15 |   |
| Crude oil and condensate  (Bbl per day)                                                            |       | 31,180                                                                                                    |       | 25,734 |   | 29,530 |   | 40,173 |   | 30,971 |   |
| Price (per Bbl)                                                                                    |       | $                                                                                                         | 57.42      |   | $ | 49.85 |   | $ | 38.59 |   | $ | 29.08 |   | $ | 24.95 |   |
| Natural gas liquids (Bbl  per day)                                                                 |       | 5,744                                                                                                     |       | 4,162 |   | 4,220 |   | 4,109 |   | 4,480 |   |
| Price (per Bbl)                                                                                    |       | $                                                                                                         | 37.71      |   | $ | 34.56 |   | $ | 28.09 |   | $ | 21.59 |   | $ | 14.94 |   |

 

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| ** **                                                 | ** ** | **For the Year Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2006**                                                     | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                 | ** ** | **(Expressed in millions)**                        | ** ** |
| **Capital Expenditures (including  interest capitalized)** | ** ** | ** **                                                   | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil and gas:                                               |       |                                                         |       |   |   |   |   |   |   |   |   |
| Domestic Onshore—                                     |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | $                                                            | 210.2      |   | $ | 117.1 |   | $ | 29.0 |   | $ | 26.2 |   | $ | 14.5 |   |
| Development                                                |       | 371.2                                                        |       | 143.3 |   | 159.5 |   | 118.0 |   | 117.2 |   |
| Purchase of properties                                     |       | 1,046.2                                                      |       | 46.0 |   | 583.8 |   | 177.7 |   | — |   |
| Domestic Offshore—                                    |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | 12.1                                                         |       | 63.8 |   | 54.3 |   | 28.1 |   | 33.6 |   |
| Development                                                |       | 35.1                                                         |       | 20.9 |   | 74.0 |   | 23.9 |   | 100.7 |   |
| Purchase of properties                                     |       | —                                                       |       | — |   | 24.7 |   | — |   | — |   |
| Canada—                                               |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | 75.1                                                         |       | 9.1 |   | — |   | — |   | — |   |
| Development                                                |       | 230.9                                                        |       | 55.8 |   | — |   | — |   | — |   |
| Purchase of properties                                     |       | 36.8                                                         |       | 2,616.9 |   | — |   | — |   | — |   |
| Other international—                                  |       |                                                         |       |   |   |   |   |   |   |   |   |
| Exploration                                                |       | 0.1                                                          |       | — |   | 5.6 |   | 0.1 |   | — |   |
| Development                                                |       | —                                                       |       | 0.1 |   | — |   | — |   | — |   |
| Total oil and gas                                          |       | 2,017.7                                                      |       | 3,073.0 |   | 930.9 |   | 374.0 |   | 266.0 |   |
| Other                                                      |       | 4.7                                                          |       | 6.0 |   | 6.2 |   | 2.5 |   | 3.3 |   |
| Total                                                      |       | $                                                            | 2,022.4    |   | $ | 3,079.0 |   | $ | 937.1 |   | $ | 376.5 |   | $ | 269.3 |   |

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(a)              Includes a pre-tax gain of $302.7 million from the saleof an undivided 50% of the Company’s Gulf of Mexico oil and gas leaseholdinterests and related pipelines and equipment to an affiliate of Mitsui &Co., Ltd.

(b)             Includes approximately $408 million of after-tax gainon the sale of the Company’s operation in Hungary and Thailand.

(c)              Effective January 1, 2003, the Company adopted theprovisions of Statement of Financial Accounting Standards No. 143 (“SFAS143”), “Accounting for Asset Retirement Obligations.”  This new accounting standard required achange in the accounting for asset retirement obligations. See “Management’sDiscussion and Analysis of Financial Condition and Results of Operations,Application of Critical Accounting Policies and Management’s Estimates, FutureDevelopment and Abandonment Costs” for further discussion of the provisions ofSFAS 143.

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

Statements in the following discussion may beforward-looking and involve risks and uncertainties. The Company’s financialresults are most directly affected by changing prices for its production.Changing prices can influence not only current results of operations but thedetermination of the Company’s proved reserves and available sources offinancing, including the determination of the borrowing base under its bankcredit facility. The Company’s results depend not only on hydrocarbon pricesgenerally, but on its ability to market its production on favorable terms.  On a longer term basis, the Company’sfinancial condition and results of operations are affected by its ability toreplace reserves as they are produced through successful exploration,development and acquisition activities. The Company’s results could also beadversely affected by adverse regulatory developments and operational risksassociated with oil and gas operations. For further discussion of risks anduncertainties that may affect the Company’s results, see “Item 1A—Risk Factors”and the discussion below.

The following discussionof the Company’s financial condition and results of operations reflects therecasting as discontinued operations of the Company’s Thailand and Hungaryoperations for all periods presented prior to 2006. See Note 11—“Discontinued Operations”to the Consolidated Financial Statements in “Item 8—Financial Statements andSupplementary Data”. Except where noted, the following discussion relates tothe Company’s continuing activities only. However, the assets comprising theCompany’s continuing operations have changed substantially during the periodspresented, which affects comparability between periods. The Company acquiredNorthrock on September 27, 2005 and Latigo on May 2, 2006, anddisposed of 50% of its interests in its Gulf of Mexico properties on May 31,2006. For summary pro forma results of operations from the Company’s continuingoperations as if the Northrock and Latigo acquisitions had occurred on January 1,2004, please refer to Note 5—“Acquisitions” to the Consolidated FinancialStatements in “Item 8—Financial Statements and Supplementary Data”.

**Executive Overview**

The Company’s objective is to explore for, develop,acquire and produce oil and gas in select locations. In pursuit of thatobjective, the Company’s goal for each year is to add more oil and gas reservesthan it produces. The year 2006 marked the fifteenth consecutive year ofreserve replacement for the Company.

The Company pursues a balanced approach in core areaslocated in major oil and gas provinces in the United States and internationally.The Company follows a strict set of criteria when selecting areas of the worldin which to explore. Areas selected are viewed as having proven oil and gasresources, having reasonable economic terms and possessing low political risk.Following these criteria, the Company operates internationally in onshoreCanada and also conducts exploration activities in offshore New Zealand andVietnam. The Company also seeks to maintain a balanced mixture of the gas/oilratio of its proven reserves base. Over the last several years, the Company hastransitioned from a predominately offshore focused company to a company withthe majority of its reserves located in the onshore regions of North America.As of December 31, 2006, approximately 94% of the Company’s reserves arelocated onshore. As a result of this transition, the Company has lengthened itsreserves to production index to over 12 years.

At the end of 2006, proven reserves reached 2,213 Bcfeand production for the year averaged more than 83,500 BOE per day (501,000 Mcfeper day). Oil and gas pricing and production volumes are important componentsof an exploration and development company’s growth in net income and cash flow.

Oil and gas capital andexploration cash expenditures for 2006 were approximately $1.7 billion.Exploration and development operations were allocated approximately $943million, and approximately $787 million was spent on selective acquisitions inthe Company’s core areas of operations. For 2006 the 

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Companydrilled 488 wells with 432 successfully completed, an 89% success rate. During2006, approximately 497 Bcfe of proven reserves were added to the Company’sreserves ledger.

*2006 Results*

Total revenue for 2006 was$1,745.0 million and net income totaled $446.2 million, or $7.74 per share.Cash flow from operations totaled $651.9 million. As of December 31, 2006,long-term debt was $2,319.7 million, increasing from December 31, 2005 by$676.2 million. The Company’s debt to total capitalization ratio, anindicator of a company’s financial strength, was 47% at December 31, 2006and cash and cash equivalents decreased from $57.7 million at December 31,2005 to approximately $22.7 million at December 31, 2006. The increase indebt and the decrease in cash are both due primarily to the closing of theLatigo acquisition and increased capital expenditures.

*StrategicAlternatives Process*

On February 15, 2007,the Company confirmed that its Board of Directors previously initiated theexploration of a range of strategic alternatives to enhance shareholder valueand is continuing to do so, including the possible sale or merger of Pogo, thesale of its Canadian, Gulf Coast, Gulf of Mexico or other significant assets,and changes to the Company’s business plan. Pogo has retained Goldman, Sachs &Co. and TD Securities Inc. as financial advisors for the process.

*Acquisition ofLatigo Petroleum Inc.*

On May 2, 2006, theCompany completed the acquisition of Latigo Petroleum, Inc. (“Latigo”), aprivately held exploration and production company for approximately $764.9million. The purchase price was funded using cash on hand and debt financing. Asof December 31, 2006, Latigo’s estimated proved reserves wereapproximately 328 Bcfe. Latigo’s operations are concentrated in the PermianBasin and Panhandle of Texas.

*Sale of 50% of Gulfof Mexico Interests*

On May 31, 2006, theCompany closed the sale of an undivided 50 percent interest of each of its Gulfof Mexico oil and gas leasehold interests and related pipelines and equipmentto an affiliate of Mitsui & Co., Ltd., for approximately $448.8million. The proceeds were used to repay a portion of the debt used to financethe Latigo acquisition. As of December 31, 2005, the interests sold wereattributed approximately 143 Bcfe of net estimated proven oil and gas reserves.The Company recognized a pre-tax gain of $302.7 million related to the sale inthe second quarter of 2006.

*Issuance of SeniorSubordinated Notes*

On June 6, 2006, theCompany issued and sold $450 million aggregate principal amount of 7.875%Senior Subordinated Notes due 2013 (the “2013 Notes”). Net proceeds were usedto reduce outstanding debt under the Company’s credit facility.

*Recognition ofIncome Tax Benefit*

During 2006, the Company’sconsolidated effective tax rate was 10.6%, down from 36.7% in 2005.  This decrease relates to the enactment of areduction of the Alberta and Saskatchewan provincial tax rates, in addition toa reduction in the statutory Canadian federal income tax rate, which generateda one-time deferred tax benefit of approximately $112 million.

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*Commodity Derivatives*

Although the Company’scollars are effective as economic hedges, the sale of 50% of the Company’s Gulfof Mexico interests on May 31, 2006 and the forecasted shut-in hydrocarbonproduction from the Company’s Gulf of Mexico properties (resulting primarilyfrom hurricane activity during the third quarter of 2005) caused certain of thegas and crude oil collar contracts to lose their qualification for hedgeaccounting. The Company recognized a $7.3 million non-cash gain related tothese contracts in 2006.

*2007 Capital Budget*

The Company hasestablished a $720 million exploration and development budget (excludingproperty acquisitions) for 2007. The Company expects to spend approximately$199 million on exploration and $521 million on development activities. Thecapital budget calls for the drilling of approximately 370 wells during 2007,including wells in the United States, Canada, and New Zealand.

*2007 ProductionOutlook Update*

The Company provided 2007production guidance in its Form 8-K dated February 15, 2007. Theseestimates are subject to change, and actual results could differ materially,depending upon the amount of Gulf of Mexico production that remains shut-in,the timing of any such production coming back on-line, the availability ofoilfield services, acquisitions, divestitures and many other factors that arebeyond the Company’s control. Please read “Forward-Looking Statements.”

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

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

**Results ofOperations**

*Oil and GasRevenues*

The Company’s oil and gas revenues for 2006 were$1,375.4 million, an increase of approximately 13% from oil and gas revenues of$1,216.2 million for 2005, which were an increase of approximately 25% from oiland gas revenues of $973.1 million for 2004. The following table reflects ananalysis of variances in the Company’s oil and gas revenues (expressed inmillions) between years:

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| ** **                                                                | ** ** | **2006**             | ** ** | **2005**             | ** ** |
|---------------------------------------------------------------------------|------------|----------------------|------------|----------------------|------------|
| ** **                                                                | ** ** | **Compared to** | ** ** | **Compared to** | ** ** |
| ** **                                                                | ** ** | **2005**             | ** ** | **2004**             | ** ** |
| Increase (decrease) in  oil and gas revenues resulting from variances in: |       |                 |       |                 |       |   |   |   |   |
| **Natural  gas—**                                                    |       |                 |       |                 |       |   |   |   |   |
| Price                                                                     |       |                 | $          | (120.2               | )          |   |   | $ | 168.5 |   |   |
| Production                                                                |       |                 | 67.6       |                 |       |   | 14.4 |   |   |
|                                                                      |       |                 | (52.6      | )                    |       |   | 182.9 |   |   |
| **Crude  oil and condensate—**                                       |       |                 |       |                 |       |   |   |   |   |
| Price                                                                     |       |                 | 71.1       |                 |       |   | 121.8 |   |   |
| Production                                                                |       |                 | 114.1      |                 |       |   | (70.6 | ) |   |
|                                                                      |       |                 | 185.2      |                 |       |   | 51.2 |   |   |
| **Natural gas liquids (“NGL”)**                                 |       |                 | 26.5       |                 |       |   | 9.1 |   |   |
| Increase in oil  and gas revenues                                         |       |                 | $          | 159.1                |       |   |   | $ | 243.2 |   |   |

 

The increase in the Company’s oil and gas revenues in2006, compared to 2005, is related to increases in both the average price thatthe Company received for its oil and condensate production volumes and anincrease in the Company’s hydrocarbon production volumes, partially offset by adecrease in the average price that the Company received for its natural gasproduction volumes. The increase in the Company’s oil and gas revenues in 2005,compared to 2004, is related to increases in both the average price that theCompany received for its hydrocarbon production volumes and an increase in theCompany’s natural gas production volumes, partially offset by a decrease incrude oil and condensate production volumes. The increase in oil and gas revenuesfor 2006, compared to 2005 and for 2005 compared to 2004, was also the resultof an increase in NGL production volumes and in the average price that theCompany received for those volumes.

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| ** **                                         | ** ** | ** ** | ** ** | ** ** | ** ** | **% Change** | ** ** | ** ** | ** ** | **% Change** | ** ** |
|----------------------------------------------------|------------|------------|------------|------------|------------|-------------------|------------|------------|------------|-------------------|------------|
| ** **                                         | ** ** | ** ** | ** ** | ** ** | ** ** | **2005**          | ** ** | ** ** | ** ** | **2004**          | ** ** |
| ** **                                         | ** ** | ** ** | ** ** | ** ** | ** ** | **to**            | ** ** | ** ** | ** ** | **to**            | ** ** |
| ** **                                         | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2006**          | ** ** | **2004**   | ** ** | **2005**          | ** ** |
| **Comparison of Increases  (Decreases) in:**       | ** ** | ** ** | ** ** | ** ** | ** ** |              | ** ** | ** ** |       | ** **        | ** ** |   | ** ** | ** ** |   |
| **Natural Gas—**                              |       |       |       |       |       |              | ** ** | ** ** |       |              |       |   | ** ** | ** ** |   |
| Average prices                                     |       |       |       |       |       |              | ** ** | ** ** |       |              |       |   | ** ** | ** ** |   |
| United States(a)                                   | ** ** | **$**      | **6.19**   |       | $          | 7.46              | ** ** |       | **(17**    | **)%**            |       | $ | 5.73 | ** ** |   | **30** | **%** |   |
| Canada                                             | ** ** | **$**      | **6.50**   |       | $          | 10.96             | ** ** |       | **(41**    | **)%**            |       | $ | — | ** ** |   | **N/A** | ** ** |   |
| Company-wide average price                         | ** ** | **$**      | **6.30**   |       | $          | 7.62              | ** ** |       | **(17**    | **)%**            |       | $ | 5.73 | ** ** |   | **33** | **%** |   |
| Average daily  production volumes  (MMcf per day): |       |       |       |       |       |              | ** ** | ** ** |       |              |       |   | ** ** | ** ** |   |
| United States                                      | ** ** | **201.5**  |       | 231.6      | ** ** |              | **(13**    | **)%**     |       | 244.3             | ** ** |   | **(5** | **)%** |   |
| Canada(c)                                          | ** ** | **78.1**   |       | 18.6       | ** ** |              | **N/A**    | ** ** |       | —            | ** ** |   | **N/A** | ** ** |   |
| Company-wide average daily  production             | ** ** | **279.6**  |       | 250.2      | ** ** |              | **12**     | **%**      |       | 244.3             | ** ** |   | **2** | **%** |   |
| **Crude  Oil and Condensate—**                |       |       |       |       |       |              | ** ** | ** ** |       |              |       |   | ** ** | ** ** |   |
| Average prices                                     |       |       |       |       |       |              | ** ** | ** ** |       |              |       |   | ** ** | ** ** |   |
| United States(b)                                   | ** ** | **$**      | **62.73**  |       | $          | 50.90             | ** ** |       | **23**     | **%**             |       | $ | 38.59 | ** ** |   | **32** | **%** |   |
| Canada                                             | ** ** | **$**      | **50.40**  |       | $          | 44.29             | ** ** |       | **14**     | **%**             |       | $ | — | ** ** |   | **N/A** | ** ** |   |
| Company-wide average price                         | ** ** | **$**      | **57.42**  |       | $          | 49.85             | ** ** |       | **15**     | **%**             |       | $ | 38.59 | ** ** |   | **29** | **%** |   |
| Average daily  production volumes  (Bbls per day): |       |       |       |       |       |              | ** ** | ** ** |       |              |       |   | ** ** | ** ** |   |
| United States                                      | ** ** | **17,717** |       | 22,337     | ** ** |              | **(21**    | **)%**     |       | 29,530            | ** ** |   | **(24** | **)%** |   |
| Canada(c)                                          | ** ** | **13,463** |       | 3,397      | ** ** |              | **N/A**    | ** ** |       | —            | ** ** |   | **N/A** | ** ** |   |
| Company-wide average daily production              | ** ** | **31,180** |       | 25,734     | ** ** |              | **21**     | **%**      |       | 29,530            | ** ** |   | **(13** | **)%** |   |
| **Total  Liquid Hydrocarbons—**               |       |       |       |       |       |              | ** ** | ** ** |       |              |       |   | ** ** | ** ** |   |
| Average daily  production volumes  (Bbls per day)  |       | **36,924** |       | 29,896     |       |              | **24**     | **%**      |       | 33,750            |       |   | **(11** | **)%** |   |

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(a)           Average prices for theUnited States reflect the impact of the Company’s price hedging activity. Pricehedging activity reduced the average price per Mcf. of the Company’s UnitedStates natural gas production $0.03 and $0.11 during 2006 and 2005,respectively. The Company had no price hedging activity related to 2004 production.

(b)          Average prices for theUnited States include the impact of the Company’s price hedging activity. Pricehedging activity reduced the average price per Bbl of the Company’s crude oiland condensate production $0.01 and $0.20 during 2006 and 2005, respectively. TheCompany had no price hedging activity related to 2004 production.  For average prices, sales volumes equate toactual production.

(c)           Northrock Resources wasacquired by the Company on September 27, 2005. The average dailyproduction volumes for Canada in 2005 are presented on an annualized basis,calculated by dividing the production for the 96 day period that the Companyowned Northrock by 365 days. This presentation is intended to reflect theimpact of the acquisition and is not considered meaningful for comparisonpurposes. On a non-annualized basis, the average daily production for the 96day period was 70.7 MMcf of natural gas and 12,921 bbls of crude oil andcondensate.

*NaturalGas Production.*   Theincrease in the Company’s natural gas production during 2006, compared to 2005,was primarily due to the acquisitions of Northrock on September 27, 2005(which only made a partial year contribution to 2005 production) and Latigo on May 2,2006. The increased natural gas production from both of the acquisitions waspartially offset by decreased production in the Company’s 

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Gulf of Mexico regionresulting from the sale of 50% of the Company’s interest in its Gulf of Mexicoproperties on May 31, 2006, natural production declines, and the curtailmentof production in 2006 due to the infrastructure damage caused by HurricanesKatrina and Rita in the third quarter of 2005. The increase in the Company’snatural gas production during 2005, compared to 2004, was primarily related tothe addition of production from acquisitions made during late 2005 and late2004, partially offset by shut-in offshore production caused by HurricanesIvan, Katrina and Rita and, to a lesser extent, natural production declines.

*CrudeOil and Condensate Production.**  *The increase in the Company’s crudeoil and condensate production during 2006, compared to 2005, was primarily dueto the Northrock and Latigo acquisitions, partially offset by the Gulf ofMexico sale, natural production declines, and curtailment of productionresulting from hurricanes. The decrease in the Company’s crude oil andcondensate production during 2005, compared to 2004, resulted primarily fromthe shut-in of Gulf of Mexico platforms due to the effects of Hurricanes Ivan,Katrina and Rita (including Main Pass Block 61/62) during 2005 and, to a lesserextent, natural production declines. This decrease was partially offset by theaddition of production from the Northrock acquisition made on September 27,2005.

*NGL Revenues.**  *The Company’s oil and gas revenues,and its total liquid hydrocarbon production, reflect the production and sale bythe Company of NGL, which are liquid products that are extracted from naturalgas production. The increase in NGL revenues for 2006, compared with 2005,related to an increase in the average price that the Company received for itsNGL production to $37.71 in 2006 from $34.56 in 2005 and an increase in NGLproduction volumes. The increase in NGL revenues for 2005, compared with 2004,related to an increase in the average price that the Company received for itsNGL production to $34.56 in 2005 from $28.09 in 2004 and an increase in NGLproduction volumes.

*Gain (loss) on Saleof Assets*

Gain (loss) on the sale ofassets is derived from the sale of oil and gas properties and other assets,including tubular stock and vehicles. On May 31, 2006, the Company sold anundivided 50 percent interest in each and all of its Gulf of Mexico oil and gasleasehold interests and related pipelines and equipment to an affiliate ofMitsui & Co., Ltd., for approximately $448.8 million, after purchaseprice adjustments. The sale resulted in a pre-tax gain of $302.7 million. Thisgain, along with $2 million of pre-tax gains on sales of other properties andassets, has been reflected in the caption “Gain (loss) on sale of properties”in the Company’s results of operations.

*Other Revenues*

Other revenue is derivedfrom sources other than the current production of hydrocarbons. This revenueincludes, among other items: natural gas inventory sales, pipeline imbalancesettlements and revenue from salt water disposal activities. The increase inthe Company’s other revenues in 2006, compared to 2005 and 2004, is relatedprimarily to $59.1 million of natural gas inventory sales from the Company’sCanadian operations for 2006. Only $5.6 million of these gas inventory saleswere made in 2005 in the period subsequent to the Company’s acquisition ofNorthrock on September 27, 2005. Gas inventory sales are related solely tothe Company’s Canadian operations and were therefore not present in 2004.

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*Costs and Expenses*

| ** **                                                      | ** ** | ** **                                                                 | ** ** | ** ** | ** ** | **% Change** | ** ** | ** **                 | ** ** | **% Change** | ** ** |
|-----------------------------------------------------------------|------------|----------------------------------------------------------------------------|------------|------------|------------|--------------|------------|----------------------------|------------|--------------|------------|
| **Comparison of Increases (Decreases) in:** | ** ** | ** **                                                                 | ** ** | **2006**   | ** ** | **2005**     | ** ** | **2005 to 2006** | ** ** | **2004**     | ** ** | **2004 to 2005** | ** ** |
| ** **                                                      | ** ** | **(expressed in millions, except DD&A rate)** | ** ** |
| **Lease Operating Expenses**                                    | ** ** | **$**                                                                      | **264.8**  | ** ** | **$**      | **153.7**    | ** ** |                       | **72**     | **%**        |       | $ | 100.5 | ** ** |   | **53** | **%** |   |
| **General and Administrative  Expenses**                        | ** ** | **$**                                                                      | **129.5**  | ** ** | **$**      | **87.3**     | ** ** |                       | **48**     | **%**        |       | $ | 62.1 | ** ** |   | **41** | **%** |   |
| **Exploration Expenses**                                        | ** ** | **$**                                                                      | **31.8**   | ** ** | **$**      | **26.5**     | ** ** |                       | **20**     | **%**        |       | $ | 21.7 | ** ** |   | **22** | **%** |   |
| **Dry Hole and Impairment  Expenses**                           | ** ** | **$**                                                                      | **106.6**  | ** ** | **$**      | **87.2**     | ** ** |                       | **22**     | **%**        |       | $ | 61.6 | ** ** |   | **42** | **%** |   |
| **Depreciation, Depletion and**                                 | ** ** | ** **                                                                 | ** ** | ** ** | ** ** |         | ** ** | ** **                 | ** ** | ** **   | ** ** |   | ** ** | ** ** |   |
| **Amortization  (DD&A) Expenses**                           | ** ** | **$**                                                                      | **484.6**  | ** ** | **$**      | **312.2**    | ** ** |                       | **55**     | **%**        |       | $ | 251.9 | ** ** |   | **24** | **%** |   |
| DD&A rate                                                   | ** ** | **$**                                                                      | **2.65**   | ** ** | **$**      | **1.99**     | ** ** |                       | **33**     | **%**        |       | $ | 1.54 | ** ** |   | **29** | **%** |   |
| Mcfe produced                                                   | ** ** | **182.9**                                                                  | ** ** | **156.8**  | ** ** |         | **17**     | **%**                      |       | 163.5        | ** ** |   | **(4** | **)%** |   |
| **Production and Other Taxes**                                  | ** ** | **$**                                                                      | **78.4**   | ** ** | **$**      | **59.5**     | ** ** |                       | **32**     | **%**        |       | $ | 44.1 | ** ** |   | **35** | **%** |   |
| **Other**                                                       | ** ** | **$**                                                                      | **87.0**   | ** ** | **$**      | **(9.1**     | **)**      |                       | **(1052**  | **)%**       |       | $ | 8.4 | ** ** |   | **(209** | **)%** |   |
| **Interest—**                                              |       |                                                                       |       |       |       |         | ** ** | ** **                 |       |         |       |   | ** ** | ** ** |   |
| Charges                                                         | ** ** | **$**                                                                      | **(148.1** | **)**      | **$**      | **(68.7**    | **)**      |                       | **116**    | **%**        |       | $ | (29.3 | ) |   | **134** | **%** |   |
| Interest Income                                                 | ** ** | **$**                                                                      | **1.8**    | ** ** | **$**      | **8.3**      | ** ** |                       | **(78**    | **)%**       |       | $ | 0.5 | ** ** |   | **1488** | **%** |   |
| Capitalized Interest  Expense                                   | ** ** | **$**                                                                      | **77.7**   | ** ** | **$**      | **23.5**     | ** ** |                       | **231**    | **%**        |       | $ | 14.2 | ** ** |   | **65** | **%** |   |
| **Commodity Derivative Income  (Expense)**                      | ** ** | **$**                                                                      | **7.3**    | ** ** | **$**      | **(13.6**    | **)**      |                       | **(154**   | **)%**       |       | $ | — | ** ** |   | **N/A** | ** ** |   |
| **Loss on debt extinguishment**                                 | ** ** | **$**                                                                      | **—** | ** ** | **$**      | **—**   | ** ** |                       | **N/A**    | ** **   |       | $ | (13.8 | ) |   | **(100** | **)%** |   |
| **Income Tax Expense**                                          | ** ** | **$**                                                                      | **(53.1**  | **)**      | **$**      | **(167.9**   | **)**      |                       | **(68**    | **)%**       |       | $ | (148.9 | ) |   | **13** | **%** |   |
|                                                                 |            |                                                                            |            |            |            |              |            |                            |            |              |            |  |  |  |  |  |  |  |  |  |

 

*Lease OperatingExpenses*

The increase in lease operating expenses for 2006,compared to 2005, is primarily related the inclusion of a full year of expensesfor Northrock, which was acquired in late September 2005; the acquisitionof Latigo in May 2006; higher costs being charged by service companies in2006 relative to 2005; and, to a lesser extent, costs associated with hurricanerelated repairs. These higher expenses were only partially offset by thereduction in lease operating expense related to the sale of 50% of the Company’sGulf of Mexico offshore interests on May 31, 2006. The increase in leaseoperating expenses for 2005, compared to 2004, is related primarily toincreased expenses incurred related to onshore properties acquired by theCompany in the fourth quarter of 2004 and throughout 2005, increasedmaintenance expenses on several of the Company’s significant offshoreproperties due to damage from Hurricanes Ivan, Katrina and Rita (which wereonly partially offset by insurance recoveries), and also to higher costs beingcharged by service companies in 2005 relative to 2004. The Company currentlyexpects lease operating expenses to increase in future periods with theaddition of Latigo related expenses for an entire reporting period. Thisincrease in 2007 should be partially mitigated by the property sales discussedin “Gain (loss) on sale of assets” above.

On a per unit ofproduction basis, the Company’s total lease operating expenses were $1.45 perMcfe for 2006, $0.98 per Mcfe for 2005 and $0.61 per Mcfe for 2004. Theincreased unit costs in 2006 and 2005 were primarily related to the increasedexpenses discussed above, compounded by natural production declines and reducedoffshore hydrocarbon production related to hurricane damage.

*General andAdministrative Expenses*

The increase in general and administrative expensesfor 2006, compared with 2005, and 2005 compared with 2004, is primarily relatedto increases in the size of the Company’s workforce due to acquisitions,increased benefit expenses and increases in compensation. The Company currentlyexpects general and administrative expenses to increase in future periods withthe addition of Latigo related expenses for the entire reporting period and theestablishment of a Change of Control Retention Program to provide retentionincentive for eligible employees during 2007. See Note 7—“Severance andRetention Incentive Program” to the Consolidated Financial Statements in “Item8—Financial Statements and Supplementary Data” for additional information onthe Change of Control Retention Program.

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On a per unit ofproduction basis, the Company’s general and administrative expenses were $0.71per Mcfe in 2006, $0.56 per Mcfe in 2005 and $0.38 per Mcfe in 2004. Theincreased unit costs resulted from the increases in expenses discussed above.

*Exploration Expenses*

Exploration expensesconsist primarily of exploratory geological and geophysical costs that areexpensed as incurred and rental payments required under oil and gas leases tohold non-producing properties (“delay rentals”). The increase in explorationexpenses for 2006, compared to 2005, resulted primarily from an increase inseismic activity in the Company’s Canadian and Vietnam operations and anincrease in delay rentals in the Company’s Canadian operation and Gulf Coastregion, partially offset by decreased seismic activity in the New Zealandoperation and a decrease in exploration activity in the Gulf of Mexico due tothe sale of 50% of the Company’s interests. The increase in explorationexpenses for 2005, compared to 2004, resulted primarily from increased seismicoperations in the Company’s New Zealand and Canadian operations, whichwere partially offset by decreased 3-D seismic acquisition activities inthe Gulf of Mexico and decreased seismic operations in the Company’s Gulf Coastregion.

*Dry Hole and Impairment Expenses*

Dry hole and impairmentexpenses relate to costs of unsuccessful exploratory wells drilled andimpairment of oil and gas properties. During 2006, the Company drilled 25 grossunsuccessful exploratory wells (20.3 net to the Company’s interest) for a totalcost of approximately $60.9 million; in 2005 the Company drilled 9 unsuccessfulexploratory wells (7.1 net to the Company’s interest) for a total cost of $67.1million; and in 2004 the Company drilled 7 unsuccessful exploratory wells (5.6net to the Company’s interest) for a total cost of $40.2 million.

Generally acceptedaccounting principles require that if the expected future cash flow of theCompany’s reserves on a proved property fall below the cost that is recorded onthe Company’s books, these costs must be impaired and written down to theproperty’s fair value. Depending on market conditions, including the prices foroil and natural gas, and the results of operations, a similar test may beconducted at any time to determine whether impairments are appropriate.Depending on the results of this test, an impairment could be required on someof the Company’s proved properties, and this impairment could have a materialnegative non-cash impact on the Company’s earnings and balance sheet. Unprovedproperties are reviewed quarterly to determine if there has been impairment ofthe carrying value, with any such impairment charged to expense in the period. Theevaluation of unproved properties requires management’s judgment to estimatethe fair value of leasehold and exploratory costs related to drilling activityin a given area. Drilling activities in an area by other companies may alsoeffectively condemn unproved properties. As a result of its review of provedand unproved properties, the Company recognized impairments to oil and gasproperties of approximately $45.7 million during 2006, approximately$20.1 million during 2005 and $21.4 million during 2004.

*Depreciation, Depletion and Amortization Expenses*

The Company’s provisionfor DD&A expense is based on its capitalized costs and is determined on acost center by cost center basis using the units of production method. TheCompany generally establishes cost centers for its onshore oil and gasactivities on the basis of a reasonable aggregation of properties with a commongeologic structural feature or stratigraphic condition. The Company generallycreates cost centers on a field-by-field basis for oil and gas activities in offshoreareas.

The increase in the Company’sDD&A expense for 2006, compared to 2005, resulted primarily from a decreasein the percentage of the Company’s production coming from fields that haveDD&A rates that are lower than the Company’s recent historical compositeDD&A rate (principally offshore fields and legacy onshore fields) and acorresponding increase in the percentage of the Company’s production comingfrom fields that have DD&A rates that are higher than the Company’s recenthistorical composite 

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rate(principally production from the Northrock and Latigo acquisitions). TheCompany currently expects its average DD&A rate to increase during 2007, asthe effects of the higher rate per Mcf Latigo properties and the sale of thelower rate per Mcf Gulf of Mexico properties have a greater impact on theCompany’s overall production profile.

The increase in theCompany’s DD&A expense for 2005, compared to 2004, resulted primarily froman increased DD&A rate caused by a decrease in the percentage of theCompany’s production coming from fields that have DD&A rates that are lowerthan the Company’s recent historical composite DD&A rate (principallyproperties in the Gulf of Mexico which were shut-in due to hurricane downtime)and a corresponding increase in the percentage of the Company’s productioncoming from fields that have DD&A rates that are higher than the Company’srecent historical composite rate (principally increased production fromproperties acquired through corporate acquisitions).

*Production and Other Taxes*

The increase in productionand other taxes for 2006, compared to 2005, and for 2005, compared to 2004, isprimarily related to increased severance taxes due to higher onshore productionvolumes and higher crude and condensate prices, partially offset by lowernatural gas prices, and higher ad valorem taxes due to acquisitions.

*Other*

Otherexpense includes the Company’s cost to move its products to market(transportation costs), natural gas purchase costs, accretion expense relatedto Company asset retirement obligations under generally accepted accountingprinciples, recognition of recoveries from business interruption insurance,write-down of tubular inventory values and various other operating expenses. Thefollowing table shows the significant items included in Other and the changesbetween periods (expressed in millions):

| ** **                       | ** ** | **For the Year Ended December 31,** | ** ** |
|----------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                       | ** ** | **   2006   **                 | ** ** | **   2005   ** | ** ** | **   2004   ** | ** ** |
| Gas inventory  purchases         |       |                                                         | $          | 56.0 |   |   |   | $ | 4.5 |   |   |   | $ | — |   |   |
| Transportation  costs            |       |                                                         | 18.9       |   |   |   | 14.6 |   |   |   | 13.3 |   |   |
| Accretion expense                |       |                                                         | 12.2       |   |   |   | 8.0 |   |   |   | 4.8 |   |   |
| Business  interruption insurance |       |                                                         | (9.2       | ) |   |   | (40.7 | ) |   |   | (11.1 | ) |   |
| Other                            |       |                                                         | 9.1        |   |   |   | 4.5 |   |   |   | 1.4 |   |   |
| Total                            |       |                                                         | $          | 87.0 |   |   |   | $ | (9.1 | ) |   |   | $ | 8.4 |   |   |

 

Gas inventory purchasesincreased in 2006 compared to 2005 due to the inclusion of a full year ofpurchases related to Northrock. Gas inventory purchases are related solely tothe Company’s Canadian operations and were therefore not present in 2004. Transportation costs increased in 2006compared to 2005 due to the Latigo acquisition and the inclusion of a full yearof costs related to Northrock. Accretion expense increased in 2006compared to 2005 due to increased estimates of future liabilities due to risingservice costs and the inclusion of a full year of expense related to Northrock.Accretion expense increased in 2005 compared to 2004 due to increased estimatesof future liabilities due to rising service costs and the acquisition ofNorthrock in the third quarter of 2005. The business interruption insurancerelates to claims from the shut-in of a significant portion of the Company’sGulf of Mexico production during 2006, 2005, and the fourth quarter of 2004 asa result of the infrastructure damage caused by Hurricanes Ivan, Katrina andRita.

*Interest*

*InterestCharges.**  *Theincrease in the Company’s interest charges for 2006, compared to 2005, was dueto an increase in the average amount of the Company’s outstanding debt during2006 (incurred primarily to fund the purchase of Northrock and Latigo) and, toa lesser extent, an increase in the average 

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interest rate on theCompany’s revolving credit facility from 5.84% in 2005 to 6.85% in 2006. Theincrease in the Company’s interest charges for 2005, compared to 2004, resultedprimarily from an increase in the average amount of the Company’s outstandingdebt during 2005 and, to a lesser extent, an increase in the average interestrate on the Company’s revolving credit facility from 3.67% in 2004 to 5.84% in2005. The Company incurred approximately $763 million in additional debt inconnection with the Latigo acquisition in May 2006 and $690 million inadditional debt in connection with the Northrock acquisition in September 2005,which had a significant impact on the Company’s 2006 and 2005 interest expense.The Company incurred $317 million in additional debt during December 2004primarily related to acquisitions, but this did not have a significant impacton the Company’s 2004 interest expense.

*InterestIncome.**  *Thedecrease in the Company’s interest income for 2006, compared to 2005 resultedfrom a decrease in the average amount of cash and cash equivalents temporarilyinvested. The cash and cash equivalents invested during 2005 increased from2004 primarily due to the proceeds from the sale of the Thailand Entities. Theseproceeds were subsequently used to fund a portion of the Northrock purchase.

*CapitalizedInterest.**  *Interestcosts related to financing major oil and gas projects in progress are requiredto be capitalized until the projects are substantially complete and ready fortheir intended use if projects are evaluated as successful. The increase incapitalized interest for 2006, compared to 2005, and for 2005, compared to2004, resulted from an increase in the average amount of capital expendituressubject to interest capitalization, as well as the increase in interest chargesdiscussed above. The average amount of capital expenditures subject to interestcapitalization was $1.1 billion, $358 million, and $210 million for theyears 2006, 2005, and 2004, respectively. In the fourth quarter of 2006, theCompany changed the classification of interest capitalized in the Statement ofCash Flows from an operating cash outflow to an investing cash outflow. The Companywill reflect this new classification in all future reporting periods.

*CommodityDerivative Income (Expense)*

Commodity derivativeincome (expense) for 2005 and 2006 represents gains or losses on derivativecontracts that no longer qualify for hedge accounting treatment. Although allof the Company’s collars are effective as economic hedges, the sale of 50% ofthe Company’s Gulf of Mexico interests on May 31, 2006, and the shut-inforecasted 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. The Company recordedrealized and unrealized gains (losses) related to these contracts of $7.3million and ($13.6) million for the periods ended December 31, 2006,and 2005, respectively. No such expense was incurred during 2004, as all of theCompany’s derivative contracts qualified for hedge accounting at that time.

*Loss on DebtExtinguishment*

The loss on debtextinguishment for 2004 is related to redemption premiums paid and/orunamortized debt issuance costs which were expensed due to the redemption ofthe 2009 Notes and the replacement of the Company’s previous bank creditfacility with a new credit facility.

*Income Tax Expense*

Changes in the Company’sincome tax expense are a function of the Company’s consolidated effective taxrate, the Company’s pre-tax income and the jurisdiction in which the income isearned. The decrease in the Company’s income tax expense for 2006, compared to2005, primarily resulted from favorable tax benefits in Canada during 2006, andthe favorable impact of cross-border financing related to the acquisition ofNorthrock Resources, reductions in the statutory federal income tax rates inCanada from 

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approximately26% to 19% (phased in through 2010), and the phase-in of a deduction in Canadafor Crown royalties. The increase in the Company’s tax expense for 2005,compared to 2004, resulted primarily from increased pre-tax income. The Company’sconsolidated effective tax rate for 2006, 2005 and 2004 was 10.6%, 36.7%, and37.4%, respectively.

*DiscontinuedOperations*

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

***Operating Results Data***

| ** **                                                   | ** ** | **Year Ended December 31,**               | ** ** |
|--------------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                                   | ** ** | **    2005    ** | ** ** | **    2004    ** | ** ** |
| Revenues                                                     |       |                                                     | $          | 252.8 |   |   |   | $ | 335.3 |   |   |
| Costs and  expenses                                          |       |                                                     | (126.5     | ) |   |   | (237.1 | ) |   |
| Other income                                                 |       |                                                     | 5.0        |   |   |   | 0.3 |   |   |
| Income before  income taxes                                  |       |                                                     | 131.3      |   |   |   | 98.5 |   |   |
| Income taxes                                                 |       |                                                     | (78.5      | ) |   |   | (85.8 | ) |   |
| Income before  gain from discontinued operations, net of tax |       |                                                     | 52.8       |   |   |   | 12.7 |   |   |
| Gain on sale, net  of tax of $9.7 million                    |       |                                                     | 407.8      |   |   |   | — |   |   |
| Income from discontinued  operations, net of tax             |       |                                                     | $          | 460.6 |   |   |   | $ | 12.7 |   |   |

 

The increase in incomefrom discontinued operations for 2005, compared to 2004, primarily relates togains recognized on the sale of the discontinued operations. The decrease inrevenues and expenses was primarily caused by the absence of Thailand revenuesand expenses after the sale date. The Company recognized no tax benefit for itscosts in Hungary, resulting in a high effective tax rate for each of theperiods presented.

**Liquidity and Capital Resources**

The Company’s primaryneeds for cash are for exploration, development, acquisition and production ofoil and gas properties, repayment of principal and interest on outstanding debtand payment of income taxes. The Company funds its exploration and developmentactivities primarily through internally generated cash flows and budgetscapital expenditures based on projected cash flows. The Company adjusts capitalexpenditures in response to changes in oil and natural gas prices, drilling andacquisition results and cash flow. The Company has historically utilized netcash provided by operating activities, available cash, debt, and equity ascapital resources to obtain necessary funding for all other cash needs.

The Company’s cash flowprovided by operating activities for 2006 was $651.9 million. This compares tocash flow from operating activities of $845.5 million in 2005 and $738.7million in 2004. The resulting changes are attributable to the reasonsdescribed under “Results of Operations” above. Cash flows used in investingactivities for 2006 were $1,332.3 million, which included the approximately$764.9 million Latigo transaction that was funded using available cash on hand,the net proceeds from the Company’s offering of the 2013 Notes, and additionalborrowings under the revolving credit facility. Cash flows provided byfinancing activities were $644.7 million for 2006. During 2006, the Company issued$450 million principal amount of 2013 Notes (see description below) andborrowed cash of $226 million (net of repayments) under its revolving creditfacility and money market lines. During 2006, the Company also paid for therepurchase of $7.7 million of its common stock and paid $17.5 million of commonstock dividends. As of December 31, 2006, the Company had cash and cashequivalents of $22.7 million and long-term debt obligations of $2.3 billion(excluding debt discount) with no repayment obligations until 2009. The 

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Companymay determine to repurchase outstanding debt in the future, including in openmarket transactions, privately negotiated transactions or otherwise, dependingon market conditions, liquidity requirements, contractual restrictions andother factors.

Effective October 20,2006, the Company’s lenders redetermined the borrowing base under its $1 billionrevolving credit facility at $1.5 billion. As of February 21, 2007, theCompany had an outstanding balance of $823 million under its facility. Assuch, the available borrowing capacity under the facility was $177 million.

*Corporate Acquisitions*

On May 2, 2006, theCompany completed the acquisition of Latigo Petroleum, Inc. (“Latigo”), aprivately held corporation for approximately $764.9 million in cash, includingtransaction costs. The purchase price was funded using cash on hand and debtfinancing. Latigo’s operations are concentrated in west Texas and the TexasPanhandle with key exploration plays in the Texas Panhandle. The Companyacquired Latigo primarily to strengthen its position in domestic explorationand development properties.

In addition to the Latigoacquisition, the Company also completed the corporate acquisition of a Canadiancompany on February 21, 2006 for cash consideration totaling approximately$18.6 million.

*2013 Notes*

On June 6, 2006, theCompany issued $450 million principal amount of 7.875% senior subordinatednotes due 2013. The proceeds from the sale of the 2013 Notes were used to paydown obligations under the Company’s bank revolving credit agreement. The 2013Notes bear interest at a rate of 7.875%, payable semi-annually in arrears on May 1and November 1 of each year. The 2013 Notes are general unsecured seniorsubordinated obligations of the Company, and are subordinated in right ofpayment to the Company’s senior indebtedness, which currently includes theCompany’s obligations under the bank revolving credit agreement and LIBOR rateadvances. The Company, at its option, may redeem the 2013 Notes in whole or inpart, at any time on or after May 1, 2010, at a redemption price of103.938% of their principal amount and decreasing percentages thereafter. The Companymay also redeem a portion of the 2013 Notes prior to May 1, 2009 withproceeds from equity offerings, and some or all of the Notes prior to May 1,2010, in each case by paying specified premiums. The indenture governing the2013 Notes also imposes certain covenants on the Company, including covenantslimiting: incurrence of indebtedness, including senior indebtedness; paymentsof dividends, stock repurchases, and redemption of subordinated debt; the salesof assets or subsidiary capital stock; transactions with affiliates; liens;agreements restricting dividends and distributions by subsidiaries; and mergersor consolidations.

In the event of a “changeof control”, as defined in the 2013 Note agreement, the repayment terms of the2013 Notes could be accelerated. For additional discussion, see “Change ofControl” below.

*LIBOR Rate Advances*

Under separate PromissoryNote Agreements with various lenders, LIBOR rate advances are made available tothe Company on an uncommitted basis up to $100 million. Advances drawn underthese agreements are reflected as long-term debt on the Company’s balance sheetbecause the Company currently has the ability and intent to reborrow suchamounts under its Credit Agreement. The Company’s 2011 Notes, 2013 Notes, 2015Notes and 2017 Notes may restrict all or a portion of the amounts that may beborrowed under the Promissory Note Agreements. The Promissory Note Agreementspermit either party to terminate the letter agreements at any time uponthree-business days notice. As of February 21, 2007 there was $100 millionoutstanding under these agreements.

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*Change of Control*

On February 23, 2007,a shareholder that beneficially owns approximately 7.9% of the Company’s stock,formally provided notice to the Company of its intention to conduct a proxycontest at the Company’s 2007 Annual Meeting that would, if successful, resultin a change in a majority of the Board of Directors by (i) nominatingthree persons in opposition to the Board’s nominees and (ii) proposingamendments to the Company’s bylaws to expand the Board and elect threeadditional nominees. Directors are elected by a plurality of vote of theshareholders, and amendments to the Company’s bylaws must be approved by amajority of the shares outstanding. If there is a change in a majority of theBoard of Directors not approved by a vote of two-thirds of the incumbentdirectors, the indentures governing the Company’s senior subordinated notesrequire the Company to offer to repurchase all outstanding notes at 101% oftheir principal amount and to repay all outstanding senior debt, including thecredit facility, prior to repurchasing the notes (or obtain consent from thelenders allowing for such repurchase). Although such a change in a majority of the Board of Directors wouldnot, by itself, constitute an event of default under the credit facility,failure by the Company to perform its indenture obligations would allow thelenders under the credit facility to accelerate the credit facility debt.  During 2007, two series of the Company’snotes, representing $800 million in aggregate principal amount, have generallytraded below their principal face value, and the other two series, representing$650 million in aggregate principal amount, have generally traded above 101% oftheir principal amount.  The Companycannot predict the actions its noteholders or lenders may take.  However, the Company believes that holderswhose notes were trading below the repurchase price at the time the rights weretriggered would exercise their repurchase rights.  Additionally, the Company believes thatlenders under its credit facility and holders whose notes were trading abovethe repurchase price may also exercise their repayment or repurchase rights, asthe case may be, to the extent they expect that the holders whose notes weretrading below the repurchase price would exercise such rights or for otherreasons.  The Company does not havesufficient cash available to fund a repurchase of all or a substantial portionof the senior subordinated notes or to repay all or a substantial portion ofoutstanding debt under the credit facility.

Defaults under, or theacceleration of, the notes or credit facility could significantly and adverselyaffect the Company’s financial position. If the Company were not able to refinance the debt, it could be requiredto sell substantial assets at distress prices in order to satisfy itsobligations or to seek protection under the federal bankruptcy laws.  Any refinancing of the Company’s existingdebt with new debt, if available, would likely involve substantial costs,including the premium to repurchase notes from existing holders and transactioncosts associated with obtaining new debt. Such new debt may be on less favorable terms than the Company’s existingdebt.  Refinancing may also negativelyimpact the Company’s strategic alternatives initiative.

A change in the majorityof the Board of Directors as a result of the pending proxy contest would alsotrigger an obligation to make payments under the Company’s executive employmentagreements (upon termination of employment by the executives during specifiedperiods or in specified circumstances) and under the Company’s severance andretention program.

*Future Capital and Other Expenditure Requirements*

The Company’s capital andexploration budget for 2007, which does not include any amounts that may beexpended for acquisitions or any interest which may be capitalized resultingfrom projects in progress, was established by the Company’s Board of Directorsat $720 million. The Company has included 370 gross wells in its 2007 capitaland exploration budget, including wells to be drilled in the United States,Canada and New Zealand. As of February 21, 2007, the Company anticipatesthat its available cash and cash investments, cash provided by operatingactivities and funds available under its revolving credit facility will besufficient to fund the Company’s ongoing operating, interest and general andadministrative expenses, 

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itsauthorized capital budget, and dividend payments at current levels for theforeseeable future. The declaration and amount of future dividends on theCompany’s common stock will depend upon, among other things, the Company’sfuture earnings and financial condition, liquidity and capital requirements,its ability to pay dividends and other payments under covenants contained inits debt instruments, the general economic and regulatory climate and otherfactors deemed relevant by the Company’s Board of Directors.

*Other Material Long-Term Commitments*

*Contractual Obligations.*   TheCompany’s material contractual obligations include long-term debt, operatingleases, and other contracts. Material contractual obligations for which theultimate settlement amounts are not fixed and determinable include derivativecontracts that are sensitive to future changes in commodity prices and otherfactors. See “Item 7A. Quantitative and Qualitative Disclosure about MarketRisk.” A summary of the Company’s known contractual obligations as of December 31,2006 are set forth on the following table**:**

| ** **                       | ** ** | **Payments due by period (in millions)** | ** ** |
|----------------------------------|------------|-------------------------------------------------------------------|------------|
| ** **                       | ** ** | ** **                                                        | ** ** | **Less than** | ** ** | **1 - 3** | ** ** | **4 - 5** | ** ** | **More than** | ** ** |
| ** **                       | ** ** | **Total**                                                         | ** ** | **1 Year** | ** ** | **Years** | ** ** | **Years** | ** ** | **5 Years** | ** ** |
| Long Term Debt(a)                |       | $                                                                 | 3,183.8    |   | $ | 106.2 |   | $ | 1,084.4 |   | $ | 400.6 |   | $ | 1,592.6 |   |
| Operating Lease  Obligations(b)  |       | 187.6                                                             |       | 22.5 |   | 35.4 |   | 30.3 |   | 99.4 |   |
| Purchase  Obligations(c)         |       | 36.1                                                              |       | 6.5 |   | 19.7 |   | 1.1 |   | 8.8 |   |
| Asset Retirement  Obligations(d) |       | 1,038.7                                                           |       | 3.8 |   | 8.6 |   | 5.0 |   | 1,021.3 |   |
| Other  Obligations(e)(f)         |       | 12.2                                                              |       | 12.2 |   | — |   | — |   | — |   |
| Total                            |       | $                                                                 | 4,458.4    |   | $ | 151.2 |   | $ | 1,148.1 |   | $ | 437.0 |   | $ | 2,722.1 |   |

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

(b)          Operatingleases principally include the Company’s office lease commitments, gas storagefee commitments and various other equipment rentals, including gas compressors.Where rented equipment such as compressors is considered essential to theoperation of the lease, the Company has assumed that such equipment will beleased for the estimated productive life of the reserves, even if the contractterminates prior to such date. See Note 6 to the Consolidated FinancialStatements.

(c)           Thisrepresents i) the Company’s share of the contractual commitments for drillingrigs that have a term greater than six months or which cannot be terminated atthe end of the well that is currently being drilled and ii) firm transportationagreements representing “ship-or-pay” arrangements whereby the Company hascommitted to ship certain volumes of gas for a fixed transportation fee(principally from the Madden Field in Wyoming). The Company entered into thesearrangements to ensure its access to gas markets and expects to producesufficient volumes to satisfy substantially all of its firm transportationobligations.

(d)          Thisrepresents the Company’s estimate of future asset retirement obligations on anundiscounted basis. Because these costs typically extend many years into thefuture, estimating these future costs requires management to make estimates andjudgments that are subject to future revisions based upon numerous factors,including the rate of inflation, changing technology and the political andregulatory environment. See Note 16 to the Consolidated Financial Statements.

(e)           Thisincludes the Company’s estimated retention payments to be made as part of theChange of Control Retention Program and payments to be made to the RegisteredRetirement Savings Plan on behalf of Northrock employees. See Note 7 to theConsolidated Financial Statements.

(f)             Asof December 31, 2006, the Company has a projected benefit obligation of$12.3 million related to its pension plan. It has been excluded from this tabledue to the uncertainty of the timing of the funding of the obligation. See Note12 to the Consolidated Financial Statements.

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

*ProductionSharing Contract.**  *During2006, the Company, together with a joint venture partner, entered into aProduction Sharing Contract with PetroVietnam, the state oil company ofVietnam. Under this agreement, PetroVietnam may exercise the option to hold aparticipating working interest of up to 20% of any commercial discovery made inthe Block 124 area. The Company currently has no production or proved reservesin Vietnam.

*SuretyBonds.**  *Inthe ordinary course of the Company’s business and operations, it is required topost surety bonds from time to time with third parties, including governmentalagencies, primarily to cover self insurance, site restoration, equipmentdismantlement, plugging and abandonment obligations. As of December 31,2006, the Company had obtained surety bonds from a number of insurance andbonding institutions covering certain operations in the United States in theaggregate amount of approximately $9.9 million that are not included inthe table presented above. In connection with their administration of offshoreleases in the Gulf of Mexico, the MMS annually evaluates each lessee’s pluggingand abandonment liabilities. The MMS reviews this information and applies certainfinancial tests including, but not limited to, current asset and net worthtests. The MMS determines whether each lessee is financially capable of payingthe estimated costs of such plugging and abandonment liabilities. The Companymust annually provide the MMS with financial information. If the Company doesnot satisfy the MMS requirements, it could be required to post supplementalbonds. In the past, the Company has not been required to post supplementalbonds; however, there can be no assurance that the Company will satisfy thefinancial tests and remain on the list of MMS lessees exempt from thesupplemental bonding requirements. The Company cannot predict or quantify theamount of any such supplemental bonds or the annual premiums related thereto andtherefore has not included them in the prior table, but the amount could besubstantial.

*Guarantees and Letters ofCredit.**  *Asof February 21, 2007, approximately $2.6 million in letters of credit hadbeen issued on the Company’s behalf relating to its Canadian operations.

*Credit*Agreement*and BorrowingBase Determination*

*Credit Agreement.**  *The Company has a revolving creditfacility (the “Credit Agreement”) that provides for a $1.0 billion revolvingloan facility terminating on December 16, 2009. The amount that may beborrowed under the Credit Agreement may not exceed a borrowing base determinedat least semiannually using the administrative agent’s usual and customarycriteria for oil and gas reserve valuation, adjusted for incurrences of otherindebtedness since the last redetermination of the borrowing base. As of February 21,2007, the borrowing base was $1.5 billion. The credit agreement provides thatin specified circumstances involving an increase in ratings assigned to Pogo’sdebt, Pogo may elect for the borrowing base limitation to no longer apply torestrict available borrowings. The next redetermination of 

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the borrowing baseis expected to occur by May 1, 2007. A significant decline in the pricesthat the Company is expected to receive for its future oil and gas productioncould have a material negative impact on the borrowing base under the CreditAgreement which, in turn, could have a material negative impact on the Company’sliquidity. If at a redetermination of the borrowing base, the lenders reducethe borrowing base below the amount then outstanding under the Credit Agreementand other senior debt arrangements, the Company must repay the excess to thelenders in no more than four substantially equal monthly installments,commencing not later than 90 days after the Company is notified of the newborrowing base. Until the deficiency is eliminated, increases in some applicableinterest rate margins apply. Borrowings under the credit facility bearinterest, at the Company’s election, at a prime rate or Eurodollar rate, plusin each case an applicable margin. In addition, a commitment fee is payable onthe unused portion of each lender’s commitment. The applicable interest ratemargin varies from 0% to 0.25% in the case of borrowings based on the primerate and from 1.00% to 2.00% in the case of borrowings based on the Eurodollarrate, depending on the utilization level in relation to the borrowing base and,in the case of Eurodollar borrowings, ratings assigned to the Company’s debt.The Credit Agreement includes procedures for additional financial institutionsselected by the Company to become lenders under the agreement, or for anyexisting lender to increase its commitment in an amount approved by the Companyand the lender, subject to a maximum of $250 million for all such increases incommitments of new or existing lenders. The Credit Agreement also permitsshort-term swing-line loans up to $10 million and the issuance of letters ofcredit up to $75 million, which in each case reduce the credit available forrevolving credit borrowings. As of February 21, 2007, there was $823 millionoutstanding under the Credit Agreement.

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

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

*Successful EffortsMethod of Accounting*

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

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The application of the successful efforts method ofaccounting requires management’s judgment to determine the proper designationof wells as either developmental or exploratory, which will ultimatelydetermine the proper accounting treatment of the costs incurred. The resultsfrom a drilling operation can take considerable time to analyze, and thedetermination that commercial reserves have been discovered requires bothjudgment and application of industry experience. Wells may be completed that areassumed to be productive and actually deliver oil and gas in quantitiesinsufficient to be economic, which may result in the abandonment of the wellsat a later date. On occasion, wells are drilled which have targeted geologicstructures that are both developmental and exploratory in nature, and in suchinstances an allocation of costs is required to properly account for theresults. Delineation seismic costs incurred to select development locationswithin a productive oil and gas field are typically treated as developmentcosts and capitalized, but often these seismic programs extend beyond theproved reserve areas and therefore management must estimate the portion ofseismic costs to expense as exploratory. The evaluation of oil and gasleasehold acquisition costs included in unproved properties requires management’sjudgment to estimate the fair value of such properties. Drilling activities inan area by other companies may also effectively condemn leasehold positions.

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

*Reserve Estimates*

The Company’s estimates ofoil and gas reserves are, by necessity, projections based on geologic andengineering data, and there are uncertainties inherent in the interpretation ofsuch data as well as the projection of future rates of production and thetiming of development expenditures. Reserve engineering is a subjective processof estimating underground accumulations of oil and gas that are difficult tomeasure. The accuracy of any reserve estimate is a function of the quality ofavailable data, engineering and geological interpretation and judgment.Estimates of economically recoverable oil and gas reserves and future net cashflows necessarily depend upon a number of variable factors and assumptions,such as historical production from the area compared with production from otherproducing areas, the assumed effect of regulations by governmental agencies,and assumptions governing future oil and gas prices, future operating costs,severance taxes, development costs and workover costs, all of which may in factvary considerably from actual results. The future drilling costs associatedwith reserves assigned to proved undeveloped locations may ultimately increaseto the extent that these reserves are later determined to be uneconomic. Forthese reasons, estimates of the economically recoverable quantities of expectedoil and gas attributable to any particular group of properties, classificationsof such reserves based on risk of recovery, and estimates of the future netcash flows may vary substantially. Any significant variance in the assumptionscould materially affect the estimated quantity and value of the reserves, whichcould affect the carrying value of the Company’s oil and gas properties and/orthe rate of depletion of such oil and gas properties. Actual production,revenues and expenditures with respect to the Company’s reserves will likelyvary from estimates, and such variances may be material. The Company had adownward reserve revision equivalent to 0.93% of proved reserves during theyear ended December 31, 2006, while the years ended December 31, 2005and 2004 had upward reserve revisions equivalent to 2.75% and 1.05% of provedreserves, respectively. Reserve revisions result from a variety of sources suchas changes in well performance related to the efficiency of natural drivemechanisms and the improved understanding of drainage areas. A significantreduction in the 2006 year end price for natural gas resulted in reducedforecasted economic recovery, which more than offset improved performance. Forthe years ended December 31, 2005 and 2004, increased product pricesaugmented improved well performance. If the estimates of proved reserves wereto decline, the rate at which the Company records depletion expense wouldincrease. Holding all other factors constant, a 1% reduction in the Company’sproved reserve 

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estimateat December 31, 2006 would result in an annual increase in DD&Aexpense of approximately $5 million.

*Impairment of Oiland Gas Properties*

The Company reviews itsproved oil and gas properties for impairment on an annual basis or wheneverevents and circumstances indicate a potential decline in the recoverability oftheir carrying value. The Company estimates the expected future cash flows fromits proved oil and gas properties and compares these future cash flows to thecarrying amount of the oil and gas properties to determine if the carrying amountis recoverable. If the carrying amount exceeds the estimated undiscountedfuture cash flows, the Company will adjust the carrying amount of the oil andgas properties to its fair value in the current period. The factors used todetermine fair value include, but are not limited to, estimates of reserves,future commodity pricing, future production estimates, anticipated capitalexpenditures, and a discount rate commensurate with the risk associated withrealizing the expected cash flows projected. 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 Company hasrecognized impairment expense in 2006, 2005 and 2004. Given the complexitiesassociated with oil and gas reserve estimates and the history of pricevolatility in the oil and gas markets, events may arise that will require theCompany to record an impairment of its oil and gas properties and there can beno assurance that such impairments will not be required in the future nor thatthey will not be material.

*Fair Values ofDerivative Instruments*

The estimated fair values of the Company’s derivativeinstruments are recorded on the Company’s consolidated balance sheet.Historically, substantially all of the Company’s derivative instruments haveinitially represented cash flow hedges of the price of future oil and naturalgas production. Therefore, while fair values of such hedging instruments mustbe estimated at the end of each reporting period, the related changes in suchfair values are not included in the Company’s consolidated results ofoperations, to the extent they are expected to offset the future cash flowsfrom oil and natural gas production. Instead, the changes in fair value ofhedging instruments are recorded directly to shareholders’ equity until thehedged oil or natural gas quantities are produced and sold.

The estimation of fair values for the Company’shedging derivatives requires substantial judgment. The Company estimates thefair values of its derivatives on a monthly basis using an option-pricingmodel. To utilize the option-pricing model, the Company uses various factorsthat include closing exchange prices on the NYMEX, over-the-counter quotations,volatility and the time value of options. The estimated future prices arecompared to the prices fixed by the hedge agreements, and the resultingestimated future net cash inflows (outflows) over the lives of the hedges arediscounted using the Company’s current borrowing rates under its revolvingcredit facility. These pricing and discounting variables are sensitive tomarket volatility as well as changes in future price forecasts, regional pricedifferentials and interest rates. Historically, the majority of the Company’s derivativeinstruments have been hedges of the price of crude oil and natural gasproduction. The Company is not involved in any derivative trading activities.

Derivative contracts thatdo not initially qualify for hedge accounting treatment or lose their qualificationfor hedge accounting treatment (such as those contracts that lost thequalification for hedge accounting treatment during 2005 due to curtailedproduction resulting from hurricane damage or during 2006 due to the sale of50% of the Company’s interests in the Gulf of Mexico) are carried at their fairvalue on the Company’s consolidated balance sheet. The Company recognizes allchanges in the fair value of these contracts in the Company’s consolidatedresults of operations in the period in which the change occurs in the caption “Commodityderivative expense.”

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*BusinessCombinations/Acquisitions*

In 2006, the Company grew through the acquisition ofLatigo Petroleum, Inc. This acquisition was accounted for using thepurchase method of accounting. Under the purchase method, the acquiring companyadds to its balance sheet the estimated fair values of the acquired company’sassets and liabilities. Any excess of the purchase price over the fair valuesof the tangible and intangible net assets acquired is recorded as goodwill. Goodwilland other intangibles with an indefinite useful life are assessed forimpairment at least annually. The Company has never recorded any goodwill inconnection with its business combinations/acquisitions. However, there can be noassurance that the Company will not do so in the future.

There are variousassumptions made by the Company in determining the fair values of an acquiredcompany’s assets and liabilities. The most significant assumptions, and theones requiring the most judgment, involve the estimated fair values of the oiland gas properties acquired. To determine the estimated fair value of bothproved and unproved properties, the Company prepares estimates of oil, naturalgas and NGL reserves. These estimates are based on work performed by theCompany’s engineers and outside petroleum reservoir consultants. The judgmentsassociated with the estimation of reserves are described earlier in thissection. The fair value of the estimated reserves acquired in a business combinationis then calculated based on the Company’s estimates of future net revenues fromoil, natural gas and NGL production. The Company’s estimates of future pricesare based on its own analysis of pricing trends. These estimates are based oncurrent data obtained with regard to regional and worldwide supply and demanddynamics, such as economic growth forecasts. They are also based on industrydata regarding natural gas storage availability, drilling rig activity, changesin delivery capacity and trends in regional pricing differentials. Future priceforecasts from independent third parties are also taken into account inarriving at the Company’s own pricing estimates. The Company’s estimates offuture prices are applied to the estimated reserve quantities acquired toarrive at estimated future net revenues. For estimated proved reserves, thefuture net revenues are then discounted to derive a fair value for suchreserves. The fair value of proved reserves is then used to estimate the fairvalue of proved property costs acquired in a business combination. The Companyalso applies these same general principles in arriving at the fair value ofunproved reserves acquired in a business combination. These unproved reservesare generally classified as either probable or possible reserves. The fairvalue of probable and possible reserves is then used to estimate the fair valueof unproved property costs acquired in a business combination. Because of theirvery nature, probable and possible reserve estimates are less precise thanthose of proved reserves. Generally, in the Company’s business combinations,the determination of the fair values of oil and gas properties requires morejudgment than the estimates of fair values for other acquired assets andliabilities.

*Future Developmentand Abandonment Costs*

Future development costs include costs incurred toobtain access to proved reserves, including drilling costs and the installationof production equipment. Future abandonment costs include costs to dismantleand relocate or dispose of our production platforms, gathering systems, wellsand related structures and restoration costs of land and seabed. We developestimates of these costs for each of our properties based upon the type ofproduction structure, depth of water, reservoir characteristics, depth of thereservoir, market demand for equipment, currently available procedures andconsultations with construction and engineering consultants. Because thesecosts typically extend many years into the future, estimating these futurecosts is difficult and requires management to make estimates and judgments thatare subject to future revisions based upon numerous factors, including changingtechnology, the ultimate settlement amount, inflation factors, credit adjusteddiscount rates, timing of settlement and changes in the political, legal,environmental and regulatory environment. The Company reviews its assumptionsand estimates of future abandonment costs on an annual basis. We account forfuture abandonment costs pursuant to 

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SFAS 143, whichrequires that the fair value of a liability for an asset retirement obligationbe recorded in the period in which it is incurred and the corresponding costcapitalized by increasing the carrying amount of the related long-lived asset.The liability is accreted to its present value each period, and the capitalizedcost is depreciated over the useful life of the related asset. If the liabilityis settled for an amount other than the recorded amount, a gain or loss isrecognized.

Holding all other factorsconstant, if the Company’s estimate of future abandonment costs is revisedupward, earnings would decrease due to higher DD&A expense. Likewise, ifthese estimates were revised downward, earnings would increase due to lowerDD&A expense. It would require an increase in the present value of theCompany’s estimated future abandonment cost of approximately $17 million(representing an increase of approximately 10.19% to the Company’s December 31,2006 asset retirement obligation) to increase the Company’s DD&A rate by$0.01 per Mcfe for the year ended December 31, 2006.

*Recognition ofInsurance Recoveries*

The Company recognizesestimated proceeds from insurance recoveries only when the amount of therecovery is determinable and when the Company believes that the proceeds areprobable of recovery. When the amount of the estimated recoveries has beendetermined and when the Company has concluded that the recovery is probable,the recoveries are recognized in the results of operations. Business interruptionproceeds are recorded as a reduction of “Other” expense and property repair anddebris removal recoveries are recorded as a reduction of “Lease operatingexpense”.

*Pension and OtherPost-Retirement Benefits*

Accounting for pensionsand other post-retirement benefits involves several assumptions including theexpected rates of return on plan assets, determination of discount rates forremeasuring plan obligations, determination of inflation rates regardingcompensation levels and health care cost projections. The Company develops itsdemographics and utilizes the work of actuaries to assist with the measurementof employee-related obligations. The assumptions used vary from year-to-year,which will affect future results of operations. Any differences among theseassumptions and the results actually experienced will also impact futureresults of operations. An analysis of the effect of a 1% change in health carecost trends on post-retirement benefits is included in Note 12 to theConsolidated Financial Statements.

*Income Taxes*

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

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

*Other Matters*

*Inflation.**  *Publicly held companies are askedto comment on the effects of inflation on their business. As of February 21,2007, annual inflation in terms of the decrease in the general purchasing powerof the 

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dollar is runningat a moderate rate. While the Company, like other companies, continues to beaffected by fluctuations in the purchasing power of the dollar due toinflation, such effect is not considered significant as of February 21,2007.

*Recent AccountingPronouncements*

On July 13, 2006, the Financial Accounting StandardsBoard (“FASB”) issued FASB Interpretation No. 48 (“FIN 48”), “Accountingfor Uncertainty in Income Taxes—an interpretation of FAS 109”. FIN 48 clarifiesthe accounting for uncertainty in income taxes recognized in an enterprise’s financial statements inaccordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN48 prescribes a recognition threshold and measurement attribute for thefinancial statement recognition and measurement of a tax position taken orexpected to be taken in a tax return. FIN 48 also provides guidance onde-recognition, classification, interest and penalties, accounting in interimperiods, disclosure, and transition. FIN 48 is effective for fiscal yearsbeginning after December 15, 2006 and will be adopted by the Company as ofJanuary 1, 2007. The adoption of FIN 48 is not expected to result in anadjustment to the Company’s financial statements.

In September, 2006, the FASB issued Statement of FinancialAccounting Standards No. 157, “Fair Value Measurements” (SFAS 157”).SFAS 157 defines fair value, establishes a framework for measuring fairvalue, and expands disclosures about fair value measurements. The Statement iseffective for financial statements issued for fiscal years beginning afterNovember 15, 2007. The adoption of SFAS 157 is not expected to have amaterial impact on the Company’s financial statements.

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

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

**Commodity PriceRisk**

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

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**Interest Rate Risk**

Fromtime to time, the Company has entered into various financial instruments, suchas interest rate swaps, to manage the impact of changes in interest rates. Asof February 21, 2007, the Company has no open interest rate swap orinterest rate lock agreements. Therefore, the Company’s exposure to changes ininterest rates primarily results from its short-term and long-term debt withboth fixed and floating interest rates. The following table presents principalor notional amounts (stated in millions) and related average interest rates byyear of maturity for the Company’s debt obligations and their indicated fairmarket value at December 31, 2006:

| ** **             | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** | **Total** | ** ** | **Fair Value** | ** ** |
|------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|---------------------|------------|
| Long-Term Debt:        |       |     |       |     |       |     |       |     |       |     |       |           |       |      |       |                |       |   |   |   |   |   |   |   |   |   |   |
| Variable Rate          |       |     | $          | —   |       |     |       | $        | —     |     |       | $              | 872.0      |      |       | $                   | —     |   |   | $ | — |   |   | $ | — |   |   | $ | 872.0 |   |   | $ | 872.0 |   |   |
| Average Interest Rate  |       |     | —     |     |       |     | —     |     |       | 6.84     | %          |           | —     |      |       | —              |       |   | — |   |   | 6.84 | % |   | — |   |   |
| Fixed Rate             |       |     | $          | —   |       |     |       | $        | —     |     |       | $              | —     |      |       | $                   | —     |   |   | $ | 200.0 |   |   | $ | 1,250.0 |   |   | $ | 1,450.0 |   |   | $ | 1,429.0 |   |   |
| Average Interest  Rate |       |     | —     |     |       |     | —     |     |       | —   |       |           | —     |      |       | 8.25                | %          |   | 7.18 | % |   | 7.32 | % |   | — |   |   |

 

**Foreign CurrencyExchange Rate Risk**

In addition to the U.S.dollar, the Company and certain of its subsidiaries conduct a substantialportion of their business in foreign currencies and are therefore subject toforeign currency exchange rate risk on cash flows related to sales, expenses,financing and investing transactions. Currently, the Company’s greatestexposure to exchange rate fluctuations is for transactions being conducted inCanadian dollars, while the exposures in New Zealand and Vietnam currencies areimmaterial at this time. As of February 21, 2007, the Company is not aparty to any foreign currency exchange agreement.

**Current HedgingActivity**

As of December 31, 2006, the Company held variousderivative instruments. The Company has entered into natural gas and crude oiloption agreements referred to as “collars”. Collars are designed to establishfloor and ceiling prices on anticipated future natural gas and crude oilproduction. The Company has designated a significant portion of these contractsas cash flow hedges designed to achieve a more predictable cash flow, as wellas to reduce 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 derivative transactions are generally settledbased upon the average of the reporting settlement prices on the NYMEX for thelast three trading days of a particular contract month. The oil derivativetransactions are generally settled based on the average of the reportingsettlement prices for West Texas Intermediate on the NYMEX for each trading dayof a particular calendar month. For any particular collar transaction, thecounterparty is required to make a payment to the Company if the settlementprice for any settlement period is below the floor price for such transaction,and the Company is required to make a payment to the counterparty if thesettlement price for any settlement period is above the ceiling price of suchtransaction.

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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 31,2006 are as follows:

| ** **                              | ** ** | ** ** | ** ** | **NYMEX**    | ** ** | **Fair Value**   | ** ** |
|-----------------------------------------|------------|------------|------------|--------------|------------|-----------------------|------------|
| ** **                              | ** ** | ** ** | ** ** | **Contract** | ** ** | **of**                | ** ** |
| **Contract Period and**       | ** ** | ** ** | ** ** | **Price**    | ** ** | **Asset/(Liability)** | ** ** |
| **Type of Contract**          | ** ** | ** ** | ** ** | **Volume**   | ** ** | **Floor**             | ** ** | **Ceiling** | ** ** | **(in millions)** | ** ** |
| ***Natural Gas Contracts  (MMBtu)(a)*** |       |       |       |         |       |                  |       |   |   |   |   |
| Collar Contracts:                       |       |       |       |         |       |                  |       |   |   |   |   |
| January 2007 - December 2007  |       | 5,475      |       | $            | 6.00       |                  | $          | 12.00 |   |   | $ | 1.6 |   |   |
| January 2007 - December 2007  |       | 1,825      |       | $            | 6.00       |                  | $          | 12.15 |   |   | $ | 0.5 |   |   |
| January 2007 - December 2007  |       | 9,125      |       | $            | 6.00       |                  | $          | 12.50 |   |   | $ | 2.9 |   |   |
| January 2007 - December 2007  |       | 913        |       | $            | 8.00       |                  | $          | 13.40 |   |   | $ | 1.4 |   |   |
| January 2007 - December 2007  |       | 2,738      |       | $            | 8.00       |                  | $          | 13.50 |   |   | $ | 4.2 |   |   |
| January 2007 - December 2007  |       | 913        |       | $            | 8.00       |                  | $          | 13.52 |   |   | $ | 1.4 |   |   |
| January 2007 - December 2007  |       | 913        |       | $            | 8.00       |                  | $          | 13.65 |   |   | $ | 1.4 |   |   |
| January 2008 - December 2008  |       | 1,830      |       | $            | 8.00       |                  | $          | 12.05 |   |   | $ | 1.5 |   |   |
| January 2008 - December 2008  |       | 2,745      |       | $            | 8.00       |                  | $          | 12.10 |   |   | $ | 2.3 |   |   |
| January 2008 - December 2008  |       | 915        |       | $            | 8.00       |                  | $          | 12.25 |   |   | $ | 0.8 |   |   |
| ***Crude Oil Contracts (Barrels)***     |       |       |       |         |       |                  |       |   |   |   |   |
| Collar Contracts:                       |       |       |       |         |       |                  |       |   |   |   |   |
| January 2007 - December 2007  |       | 1,460,000  |       | $            | 50.00      |                  | $          | 75.00 |   |   | $ | (2.2 | ) |   |
| January 2007 - December 2007  |       | 365,000    |       | $            | 50.00      |                  | $          | 75.25 |   |   | $ | (0.6 | ) |   |
| January 2007 - December 2007  |       | 3,650,000  |       | $            | 50.00      |                  | $          | 77.50 |   |   | $ | (3.9 | ) |   |
| January 2007 - December 2007  |       | 182,500    |       | $            | 60.00      |                  | $          | 82.75 |   |   | $ | 0.3 |   |   |
| January 2007 - December 2007  |       | 547,500    |       | $            | 60.00      |                  | $          | 83.00 |   |   | $ | 0.9 |   |   |
| January 2007 - December 2007  |       | 182,500    |       | $            | 60.00      |                  | $          | 84.00 |   |   | $ | 0.3 |   |   |
| January 2008 - December 2008  |       | 183,000    |       | $            | 60.00      |                  | $          | 80.00 |   |   | $ | 0.1 |   |   |
| January 2008 - December 2008  |       | 183,000    |       | $            | 60.00      |                  | $          | 80.05 |   |   | $ | 0.1 |   |   |
| January 2008 - December 2008  |       | 183,000    |       | $            | 60.00      |                  | $          | 80.10 |   |   | $ | 0.1 |   |   |
| January 2008 - December 2008  |       | 366,000    |       | $            | 60.00      |                  | $          | 80.25 |   |   | $ | 0.2 |   |   |
|                                         |            |            |            |              |            |                       |            |  |  |  |  |  |  |  |  |  |

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(a)           MMBtumeans million British Thermal Units.

Althoughall of the Company’s collars are effective as economic hedges, the sale of 50%of the Company’s Gulf of Mexico interests on May 31, 2006 and the shut-inforecasted 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. The Company now recognizesall future changes in the fair value of these collar contracts in theconsolidated statement of income for the period in which the change occursunder the caption “Commodity derivative income(expense).’’ As of December 31,2006, the Company had the following collar contracts that no longer qualify forhedge accounting:

| ** **                             | ** ** | ** ** | ** ** | **NYMEX**    | ** ** | **Fair Value**   | ** ** |
|----------------------------------------|------------|------------|------------|--------------|------------|-----------------------|------------|
| ** **                             | ** ** | ** ** | ** ** | **Contract** | ** ** | **of**                | ** ** |
| **Contract Period and**      | ** ** | ** ** | ** ** | **Price**    | ** ** | **Asset/(Liability)** | ** ** |
| **Type of Contract**         | ** ** | ** ** | ** ** | **Volume**   | ** ** | **Floor**             | ** ** | **Ceiling** | ** ** | **(in millions)** | ** ** |
| ***Natural  Gas Contracts (MMBtu)***   |       |       |       |         |       |                  |       |   |   |   |   |   |   |
| Collar Contracts:                      |       |       |       |         |       |                  |       |   |   |   |   |   |   |
| January 2007 - December 2007 |       |       | 7,300      |         |       | $                     | 6.00       |   | $ | 12.15 |   |   | $ | 2.2 |   |   |
| January 2007 - December 2007 |       |       | 3,650      |         |       | $                     | 6.00       |   | $ | 12.20 |   |   | $ | 1.1 |   |   |
|                                        |            |            |            |              |            |                       |            |  |  |  |  |  |  |  |  |  |  |  |

 

Additional informationabout the Company’s hedging activities can be found in Note 14—“CommodityDerivatives and Hedging Activities” in this report.

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTINGFIRM

To the Stockholders and Board of Directors of PogoProducing Company:

We have completedintegrated audits of Pogo Producing Company's consolidated financial statementsand of its internal control over financial reporting as of December 31,2006, in accordance with the standards of the Public Company AccountingOversight Board (United States).  Ouropinions, based on our audits, are presented below.

*Consolidated financial statements*

In our opinion, the accompanyingconsolidated balance sheets and the related consolidated statements of income,of stockholders' equity and of cash flows present fairly, in all materialrespects, the financial position of Pogo Producing Company and its subsidiariesat December 31, 2006 and 2005, and the results of their operations andtheir cash flows for each of the three years in the period ended December 31,2006 in conformity with accounting principles generally accepted in the UnitedStates of America. These financial statements are the responsibility of theCompany’s management. Our responsibility is to express an opinion on thesefinancial statements based on our audits. We conducted our audits of these statements in accordance with thestandards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit of financial statements includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financialstatements, assessing the accounting principles used and significant estimatesmade by management, and evaluating the overall financial statement presentation.We believe that our audits provide a reasonable basis for our opinion.

*Internal controlover financial reporting*

Also, in our opinion, management’s assessment,included in Management's Annual Report on Internal Control Over FinancialReporting appearing under Item 9A, that the Company maintained effectiveinternal control over financial reporting as of December 31, 2006 based oncriteria established in *Internal Control—IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission (COSO), is fairly stated, in all material respects, basedon those criteria.  Furthermore, in ouropinion, the Company maintained, in all material respects, effective internalcontrol over financial reporting as of December 31, 2006, based oncriteria 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 Company AccountingOversight Board (United States). Those standards require that we plan andperform the audit to obtain reasonable assurance about whether effectiveinternal control over financial reporting was maintained in all materialrespects. An audit of internal control over financial reporting includesobtaining an understanding of internal control over financial reporting,evaluating management’s assessment, testing and evaluating the design andoperating 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. Acompany’s internal 

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control over financialreporting includes those policies and procedures that (i) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company;(ii) provide reasonable assurance that transactions are recorded as necessaryto permit preparation of financial statements in accordance with generallyaccepted accounting principles, and that receipts and expenditures of thecompany are being made only in accordance with authorizations of management anddirectors of the company; and (iii) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or dispositionof the company’s assets that could have a material effect on the financialstatements. 

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 inManagement’s Report on Internal Control Over Financial Reporting, managementhas excluded Latigo Petroleum, Inc. (Latigo) from its assessment of internalcontrol over financial reporting as of December 31, 2006 because Latigo wasacquired in a purchase business combination during 2006. We have also excluded Latigofrom our audit of internal control over financial reporting. Latigo is awholly-owned subsidiary of the Company whose total assets and total revenuesrepresent 16% and 5%, respectively, of the related consolidated financialstatement amounts as of and for the year ended December 31, 2006.

Houston, Texas

March 1, 2007

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**POGO PRODUCING COMPANY & SUBSIDIARIESCONSOLIDATED STATEMENTS OF INCOME**

| ** **                                           | ** ** | **Year Ended December 31,**   | ** ** |
|------------------------------------------------------|------------|----------------------------------------------|------------|
| ** **                                           | ** ** | **2006**                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                           | ** ** | **(Expressed in millions,**        | ** ** |
| ** **                                           | ** ** | **except per share amounts)** | ** ** |
| **Revenues:**                                        | ** ** | ** **                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil and gas                                          |       | $                                            | 1,375.4    |   | $ | 1,216.2 |   | $ | 973.1 |   |
| Gain (loss) on sale of properties                    |       | 304.7                                        |       | 0.1 |   | (0.3 | ) |
| Other                                                |       | 64.9                                         |       | 9.4 |   | 3.8 |   |
| Total                                                |       | 1,745.0                                      |       | 1,225.7 |   | 976.6 |   |
| **Operating  Costs and Expenses:**                   | ** ** | ** **                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Lease operating                                      |       | 264.8                                        |       | 153.7 |   | 100.5 |   |
| General and administrative                           |       | 129.5                                        |       | 87.3 |   | 62.1 |   |
| Exploration                                          |       | 31.8                                         |       | 26.5 |   | 21.7 |   |
| Dry hole and impairment                              |       | 106.6                                        |       | 87.2 |   | 61.6 |   |
| Depreciation, depletion and amortization             |       | 484.6                                        |       | 312.2 |   | 251.9 |   |
| Production and other taxes                           |       | 78.4                                         |       | 59.5 |   | 44.1 |   |
| Other                                                |       | 87.0                                         |       | (9.1 | ) | 8.4 |   |
| Total                                                |       | 1,182.7                                      |       | 717.3 |   | 550.3 |   |
| **Operating  Income**                                |       | 562.3                                        |       | 508.4 |   | 426.3 |   |
| **Interest:**                                        | ** ** | ** **                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Charges                                              |       | (148.1                                       | )          | (68.7 | ) | (29.3 | ) |
| Income                                               |       | 1.8                                          |       | 8.3 |   | 0.5 |   |
| Capitalized                                          |       | 77.7                                         |       | 23.5 |   | 14.2 |   |
| **Commodity  Derivative Income (Expense)**           |       | 7.3                                          |       | (13.6 | ) | — |   |
| **Loss on  debt extinguishment**                     |       | —                                       |       | — |   | (13.8 | ) |
| **Foreign  Currency Transaction Gain (Loss)**        |       | (1.7                                         | )          | 0.1 |   | — |   |
| **Income  From Continuing Operations Before Taxes**  |       | 499.3                                        |       | 458.0 |   | 397.9 |   |
| **Income  Tax Expense**                              |       | (53.1                                        | )          | (167.9 | ) | (148.9 | ) |
| **Income  From Continuing Operations**               |       | 446.2                                        |       | 290.1 |   | 249.0 |   |
| **Income  from Discontinued Operations, net of tax** |       | —                                       |       | 460.6 |   | 12.7 |   |
| **Net  Income**                                      |       | $                                            | 446.2      |   | $ | 750.7 |   | $ | 261.7 |   |
| **Earnings  per Common Share:**                      | ** ** | ** **                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic                                                |       |                                         |       |   |   |   |   |
| Income from continuing operations                    |       | $                                            | 7.74       |   | $ | 4.80 |   | $ | 3.90 |   |
| Income from discontinued operations                  |       | —                                       |       | 7.63 |   | 0.20 |   |
| Net income                                           |       | $                                            | 7.74       |   | $ | 12.43 |   | $ | 4.10 |   |
| Diluted                                              |       |                                         |       |   |   |   |   |
| Income from continuing operations                    |       | $                                            | 7.68       |   | $ | 4.76 |   | $ | 3.87 |   |
| Income from discontinued operations                  |       | —                                       |       | 7.56 |   | 0.19 |   |
| Net income                                           |       | $                                            | 7.68       |   | $ | 12.32 |   | $ | 4.06 |   |
| **Dividends  per Common Share**                      |       | $                                            | 0.30       |   | $ | 0.25 |   | $ | 0.2125 |   |

 

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

63

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**POGO PRODUCING COMPANY & SUBSIDIARIES**CONSOLIDATED BALANCESHEETS

| ** **                                                  | ** ** | **December 31,**                 | ** ** |
|-------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                  | ** ** | **2006**                              | ** ** | **2005** | ** ** |
| ** **                                                  | ** ** | **(Expressed in millions)** | ** ** |
| **ASSETS**                                                  | ** ** | ** **                            | ** ** | ** ** | ** ** |
| **Current Assets:**                                         | ** ** | ** **                            | ** ** | ** ** | ** ** |
| Cash and cash equivalents                                   |       | $                                     | 22.7       |   | $ | 57.7 |   |
| Accounts receivable                                         |       | 175.8                                 |       | 198.8 |   |
| Other receivables                                           |       | 47.6                                  |       | 19.9 |   |
| Federal income taxes receivable                             |       | 55.8                                  |       | 21.7 |   |
| Deferred income tax                                         |       | —                                |       | 12.2 |   |
| Inventories—product                                    |       | 15.5                                  |       | 13.2 |   |
| Inventories—tubulars                                   |       | 27.7                                  |       | 19.1 |   |
| Commodity derivative contracts                              |       | 10.9                                  |       | — |   |
| Other                                                       |       | 12.2                                  |       | 4.2 |   |
| Total current assets                                        |       | 368.2                                 |       | 346.8 |   |
| **Property and Equipment:**                                 | ** ** | ** **                            | ** ** | ** ** | ** ** |
| Oil and gas, on  the basis of successful efforts accounting |       |                                  |       |   |   |
| Proved properties                                           |       | 7,369.0                               |       | 6,254.5 |   |
| Unproved properties                                         |       | 1,033.2                               |       | 872.2 |   |
| Other, at cost                                              |       | 50.7                                  |       | 40.5 |   |
|                                                        |       | 8,452.9                               |       | 7,167.2 |   |
| Accumulated depreciation,  depletion, and amortization      |       |                                  |       |   |   |
| Oil and gas                                                 |       | (1,863.1                              | )          | (1,858.3 | ) |
| Other                                                       |       | (32.7                                 | )          | (24.5 | ) |
|                                                        |       | (1,895.8                              | )          | (1,882.8 | ) |
| Property and equipment, net                                 |       | 6,557.1                               |       | 5,284.4 |   |
| **Other Assets:**                                           | ** ** | ** **                            | ** ** | ** ** | ** ** |
| Commodity derivative contracts                              |       | 5.0                                   |       | — |   |
| Other                                                       |       | 40.8                                  |       | 44.5 |   |
|                                                        |       | 45.8                                  |       | 44.5 |   |
|                                                        |       | $                                     | 6,971.1    |   | $ | 5,675.7 |   |

 

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

64

----

**POGO PRODUCINGCOMPANY & SUBSIDIARIESCONSOLIDATED BALANCE SHEETS**

| ** **                                                                                                      | ** ** | **December 31,**                 | ** ** |
|-----------------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                                                                      | ** ** | **2006**                              | ** ** | **2005** | ** ** |
| ** **                                                                                                      | ** ** | **(Expressed in millions)** | ** ** |
| **LIABILITIES AND  SHAREHOLDERS’ EQUITY**                                                                  | ** ** | ** **                            | ** ** | ** ** | ** ** |
| **Current Liabilities:**                                                                                        | ** ** | ** **                            | ** ** | ** ** | ** ** |
| Accounts payable—operating activities                                                                      |       | $                                     | 181.2      |   | $ | 167.3 |   |
| Accounts payable—investing activities                                                                      |       | 159.1                                 |       | 137.1 |   |
| Income taxes payable                                                                                            |       | 0.8                                   |       | 2.0 |   |
| Accrued interest payable                                                                                        |       | 26.0                                  |       | 20.2 |   |
| Accrued payroll and related benefits                                                                            |       | 5.1                                   |       | 3.7 |   |
| Commodity derivative contracts                                                                                  |       | —                                |       | 52.3 |   |
| Deferred income tax                                                                                             |       | 7.2                                   |       | — |   |
| Other                                                                                                           |       | 22.4                                  |       | 12.5 |   |
| Total current liabilities                                                                                       |       | 401.8                                 |       | 395.1 |   |
| **Long-Term Debt**                                                                                              |       | 2,319.7                               |       | 1,643.4 |   |
| **Deferred Income Tax**                                                                                         |       | 1,478.0                               |       | 1,316.9 |   |
| **Asset Retirement Obligation**                                                                                 |       | 156.3                                 |       | 149.4 |   |
| **Other Liabilities and Deferred Credits**                                                                      |       | 47.9                                  |       | 72.3 |   |
| Total liabilities                                                                                               |       | 4,403.7                               |       | 3,577.1 |   |
| **Commitments and Contingencies (Note 6)**                                                                      |       | —                                |       | — |   |
| **Shareholders’  Equity:**                                                                                 | ** ** | ** **                            | ** ** | ** ** | ** ** |
| Preferred stock, $1 par; 4,000,000 shares authorized                                                            |       | —                                |       | — |   |
| Common stock, $1 par; 200,000,000 shares authorized,  and 65,794,206 and 65,275,106 shares issued, respectively |       | 65.8                                  |       | 65.3 |   |
| Additional capital                                                                                              |       | 971.4                                 |       | 977.9 |   |
| Retained earnings                                                                                               |       | 1,892.9                               |       | 1,464.2 |   |
| Accumulated other comprehensive income (loss)                                                                   |       | (1.4                                  | )          | (30.0 | ) |
| Deferred compensation                                                                                           |       | —                                |       | (17.5 | ) |
| Treasury stock (7,365,359 shares, at cost)                                                                      |       | (361.3                                | )          | (361.3 | ) |
| Total shareholders’ equity                                                                                 |       | 2,567.4                               |       | 2,098.6 |   |
|                                                                                                            |       | $                                     | 6,971.1    |   | $ | 5,675.7 |   |

 

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

65

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**POGO PRODUCING COMPANY & SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS**

| ** **                                                                                                              | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                                                              | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                                                              | ** ** | **(Expressed in millions)**      | ** ** |
| **Cash flows from operating activities:**                                                                               | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Cash received from  customers                                                                                           |       | $                                          | 1,400.4    |   | $ | 1,238.4 |   | $ | 978.5 |   |
| Operating,  exploration and general and administrative expenses paid                                                    |       | (583.1                                     | )          | (332.0 | ) | (243.3 | ) |
| Income taxes paid                                                                                                       |       | (139.1                                     | )          | (197.8 | ) | (159.6 | ) |
| Income taxes  received                                                                                                  |       | 3.2                                        |       | 0.2 |   | 0.4 |   |
| Interest paid                                                                                                           |       | (59.2                                      | )          | (51.3 | ) | (30.0 | ) |
| Cash received (paid)  related to commodity derivative contracts                                                         |       | 2.7                                        |       | (11.4 | ) | — |   |
| Business  interruption insurance proceeds                                                                               |       | 15.5                                       |       | 47.1 |   | — |   |
| Other                                                                                                                   |       | 11.5                                       |       | 7.6 |   | (1.7 | ) |
| Net cash provided  by continuing operating activities                                                                   |       | 651.9                                      |       | 700.8 |   | 544.3 |   |
| Net cash provided  by discontinued operating activities                                                                 |       | —                                     |       | 144.7 |   | 194.4 |   |
| Net cash provided  by operating activities                                                                              |       | 651.9                                      |       | 845.5 |   | 738.7 |   |
| **Cash flows from investing activities:**                                                                               | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Capital  expenditures                                                                                                   |       | (930.4                                     | )          | (374.9 | ) | (285.9 | ) |
| Purchase of  properties                                                                                                 |       | (88.9                                      | )          | (131.8 | ) | (189.6 | ) |
| Acquisition of  corporations, net of cash acquired of $1.8 million, $32.9 million and  $11.9 million, respectively |       | (779.5                                     | )          | (1,704.6 | ) | (270.4 | ) |
| Sale of properties  and corporations, net of $51.5 million cash on hand in 2005                               |       | 451.4                                      |       | 764.1 |   | 1.5 |   |
| Purchase of  current investments                                                                                        |       | —                                     |       | (16.8 | ) | (15.0 | ) |
| Sale of current  investments                                                                                            |       | —                                     |       | 122.3 |   | 15.0 |   |
| Commodity  derivative contracts                                                                                         |       | (0.4                                       | )          | (8.6 | ) | — |   |
| Hurricane-related  insurance proceeds                                                                                   |       | 15.5                                       |       | 17.9 |   | — |   |
| Net cash used in  continuing investing activities                                                                       |       | (1,332.3                                   | )          | (1,332.4 | ) | (744.4 | ) |
| Net cash used in  discontinued investing activities                                                                     |       | —                                     |       | (57.8 | ) | (217.3 | ) |
| Net cash used in  investing activities                                                                                  |       | (1,332.3                                   | )          | (1,390.2 | ) | (961.7 | ) |
| **Cash flows from financing activities:**                                                                               | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Borrowings under  senior debt agreements                                                                                |       | 2,419.0                                    |       | 3,865.0 |   | 2,010.0 |   |
| Payments under  senior debt agreements                                                                                  |       | (2,193.0                                   | )          | (3,774.0 | ) | (1,594.0 | ) |
| Proceeds from  issuance of new financing                                                                                |       | 450.0                                      |       | 797.3 |   | — |   |
| Purchase of  Company stock                                                                                              |       | (7.7                                       | )          | (351.8 | ) | — |   |
| Payments (to) from  discontinued operations                                                                             |       | —                                     |       | 138.3 |   | (25.0 | ) |
| Redemption of debt                                                                                                      |       | —                                     |       | — |   | (157.8 | ) |
| Proceeds from  exercise of stock options and realization of tax benefits                                                |       | 5.2                                        |       | 11.2 |   | 12.0 |   |
| Payment of cash  dividends on common stock                                                                              |       | (17.5                                      | )          | (15.2 | ) | (13.6 | ) |
| Payment of senior  debt acquired through corporate purchase                                                             |       | —                                     |       | — |   | (50.0 | ) |
| Payment of  financing issue costs and other                                                                             |       | (11.3                                      | )          | (14.9 | ) | (3.8 | ) |
| Net cash provided  by continuing financing activities                                                                   |       | 644.7                                      |       | 655.9 |   | 177.8 |   |
| Net cash (used in)  provided by discontinued financing activities                                                       |       | —                                     |       | (139.6 | ) | 25.0 |   |
| Net cash provided  by financing activities                                                                              |       | 644.7                                      |       | 516.3 |   | 202.8 |   |
| Effect of exchange rate  changes on cash                                                                                |       | 0.7                                        |       | (0.3 | ) | 2.2 |   |
| Net decrease in cash and  cash equivalents                                                                              |       | (35.0                                      | )          | (28.7 | ) | (18.0 | ) |
| Cash and cash equivalents  from continuing operations, beginning of the year                                            |       | 57.7                                       |       | 33.5 |   | 55.8 |   |
| Cash and cash equivalents  from discontinued operations, beginning of the year                                     |       | —                                     |       | 52.9 |   | 48.7 |   |
| Cash and cash equivalents at the end of the year                                                                        |       | $                                          | 22.7       |   | $ | 57.7 |   | $ | 86.5 |   |

 

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

66

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**POGO PRODUCING COMPANY ANDSUBSIDIARIESCONSOLIDATED STATEMENT OF CASH FLOWS—CONTINUED**

| ** **                                                                        | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                        | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                        | ** ** | **(Expressed in thousands)**     | ** ** |
| **Reconciliation of net income to  net cash provided by operating activities:**   | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income                                                                        |       | $                                          | 446.2      |   | $ | 750.7 |   | $ | 261.7 |   |
| Adjustments to reconcile net income to net cash  provided by operating activities |       |                                       |       |   |   |   |   |
| Income from discontinued operations, net of tax                                   |       | —                                     |       | (460.6 | ) | (12.7 | ) |
| (Gains) losses on sales                                                           |       | (304.7                                     | )          | (0.1 | ) | 0.3 |   |
| Depreciation, depletion and amortization                                          |       | 484.6                                      |       | 312.2 |   | 251.9 |   |
| Dry hole and impairment                                                           |       | 106.6                                      |       | 87.2 |   | 61.6 |   |
| Other                                                                             |       | 6.5                                        |       | (6.8 | ) | 8.5 |   |
| Deferred income taxes                                                             |       | (43.2                                      | )          | 9.1 |   | 3.1 |   |
| Change in assets  and liabilities:                                                |       |                                       |       |   |   |   |   |
| (Increase) decrease in accounts receivable                                        |       | 28.7                                       |       | (9.9 | ) | (26.7 | ) |
| Increase in federal income taxes receivable                                       |       | (37.4                                      | )          | (43.2 | ) | (12.7 | ) |
| Increase in inventory—product                                                |       | (2.3                                       | )          | (12.1 | ) | — |   |
| (Increase) decrease in other assets                                               |       | (5.3                                       | )          | 2.3 |   | 3.5 |   |
| Increase (decrease) in accounts payable                                           |       | (39.0                                      | )          | 54.3 |   | 12.7 |   |
| Increase (decrease) in income taxes payable                                       |       | (2.3                                       | )          | 1.9 |   | (0.7 | ) |
| Increase (decrease) in accrued interest payable                                   |       | 8.2                                        |       | 15.7 |   | (5.4 | ) |
| Increase in accrued payroll and related benefits                                  |       | 1.4                                        |       | 0.2 |   | 0.3 |   |
| Increase (decrease) in other current liabilities                                  |       | 3.9                                        |       | (2.7 | ) | (3.7 | ) |
| Increase in deferred credits                                                      |       | —                                     |       | 2.6 |   | 2.6 |   |
| Net cash provided  by continuing operating activities                             |       | 651.9                                      |       | 700.8 |   | 544.3 |   |
| Net cash provided  by discontinued operating activities                           |       | —                                     |       | 144.7 |   | 194.4 |   |
| Net cash provided by  operating activities                                        |       | $                                          | 651.9      |   | $ | 845.5 |   | $ | 738.7 |   |

 

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

67

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**POGO PRODUCING COMPANY & SUBSIDIARIESCONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY**(Expressed inmillions)

| ** **                                                             | ** ** | ** **   | ** ** | ** **     | ** ** | ** **   | ** ** | **Accumulated**   | ** ** | ** **       | ** ** | ** **   | ** ** | ** **             | ** ** | ** **        | ** ** |
|------------------------------------------------------------------------|------------|--------------|------------|----------------|------------|--------------|------------|-------------------|------------|------------------|------------|--------------|------------|------------------------|------------|-------------------|------------|
| ** **                                                             | ** ** | ** **   | ** ** | ** **     | ** ** | ** **   | ** ** | **Other**         | ** ** | **Deferred**     | ** ** | ** **   | ** ** | ** **             | ** ** | ** **        | ** ** |
| ** **                                                             | ** ** | ** **   | ** ** | ** **     | ** ** | ** **   | ** ** | **Comprehensive** | ** ** | **Compensation** | ** ** | ** **   | ** ** | ** **             | ** ** | **Comprehensive** | ** ** |
| ** **                                                             | ** ** | **Common**   | ** ** | **Additional** | ** ** | **Retained** | ** ** | **Income**        | ** ** | **Restricted**   | ** ** | **Treasury** | ** ** | **Shareholders’** | ** ** | **Income**        | ** ** |
| ** **                                                             | ** ** | **Stock(a)** | ** ** | **Capital**    | ** ** | **earnings** | ** ** | **(Loss)**        | ** ** | **Stock**        | ** ** | **Stock**    | ** ** | **Equity**             | ** ** | **(Loss)**        | ** ** |
| **Balance at December 31, 2003**                                  |       |         | 63.8       |           |       |         | $          | 914.5             |       |             |       | $            | 480.6      |                   |       |              | $          | — |   |   |   | $ | (3.5 | ) |   |   | $ | (1.8 | ) |   |   | $ | 1,453.6 |   |   |   |   |   |   |
| Net income                                                             |       |         | —     |           |       |         | —     |              |       |             | 261.7      |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | 261.7 |   |   |   | $ | 261.7 |   |   |
| Stock option activity and other                                        |       |         | 0.5        |           |       |         | 16.8       |              |       |             | —     |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | 17.3 |   |   |   |   |   |   |
| Shares issued as compensation                                          |       |         | 0.3        |           |       |         | 12.4       |              |       |             | —     |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | 12.7 |   |   |   |   |   |   |
| Issuance of restricted stock, less amortization of  $1.9 million       |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | —     |              |       |   | (6.4 | ) |   |   | — |   |   |   | (6.4 | ) |   |   |   |   |   |
| Dividends ($0.2125 per common share)                                   |       |         | —     |           |       |         | —     |              |       |             | (13.6      | )            |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | (13.6 | ) |   |   |   |   |   |
| Unrealized gain arising during the year on price  hedge contracts |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | 3.0        |              |       |   | — |   |   |   | — |   |   |   | 3.0 |   |   |   |   |   |   |
| Net unrealized gains on price hedge contracts                          |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | (0.4       | )                 |       |   | — |   |   |   | — |   |   |   | (0.4 | ) |   |   | 2.6 |   |   |
| Comprehensive income                                                   |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | — |   |   |   | $ | 264.3 |   |   |
| **Balance at December 31, 2004**                                  |       |         | 64.6       |           |       |         | $          | 943.7             |       |             |       | $            | 728.7      |                   |       |              | $          | 2.6 |   |   |   | $ | (9.9 | ) |   |   | $ | (1.8 | ) |   |   | $ | 1,727.9 |   |   |   |   |   |   |
| Net income                                                             |       |         | —     |           |       |         | —     |              |       |             | 750.7      |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | 750.7 |   |   |   | $ | 750.7 |   |   |
| Stock option activity and other                                        |       |         | 0.4        |           |       |         | 15.9       |              |       |             | —     |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | 16.3 |   |   |   |   |   |   |
| Shares issued as compensation                                          |       |         | 0.3        |           |       |         | 18.3       |              |       |             | —     |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | 18.6 |   |   |   |   |   |   |
| Issuance of restricted stock, less amortization of  $4.6 million       |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | —     |              |       |   | (7.6 | ) |   |   | — |   |   |   | (7.6 | ) |   |   |   |   |   |
| Dividends ($0.25 per common share)                                     |       |         | —     |           |       |         | —     |              |       |             | (15.2      | )            |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | (15.2 | ) |   |   |   |   |   |
| Share repurchase                                                       |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | —     |              |       |   | — |   |   |   | (359.5 | ) |   |   | (359.5 | ) |   |   |   |   |   |
| Unrealized loss arising during the year on price  hedge contracts      |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | (72.2      | )                 |       |   | — |   |   |   | — |   |   |   | (72.2 | ) |   |   |   |   |   |
| Reclassification adjustment included in net income                     |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | 16.7       |              |       |   | — |   |   |   | — |   |   |   | 16.7 |   |   |   |   |   |   |
| Net unrealized gains on price hedge contracts                          |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | — |   |   |   | (55.5 | ) |   |
| Foreign currency translation adjustment                                |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | 22.9       |              |       |   | — |   |   |   | — |   |   |   | 22.9 |   |   |   | 22.9 |   |   |
| Comprehensive income                                                   |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | — |   |   |   | $ | 718.1 |   |   |
| **Balance at December 31, 2005**                                  |       |         | 65.3       |           |       |         | $          | 977.9             |       |             |       | $            | 1,464.2    |                   |       |              | $          | (30.0 | ) |   |   | $ | (17.5 | ) |   |   | $ | (361.3 | ) |   |   | $ | 2,098.6 |   |   |   |   |   |   |
| Net income                                                             |       |         | —     |           |       |         | —     |              |       |             | 446.2      |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | 446.2 |   |   |   | $ | 446.2 |   |   |
| Stock option activity and other                                        |       |         | 0.1        |           |       |         | 6.1        |              |       |             |       |         |       |                   |       |              |       |   |   |   |   |   |   |   |   |   | 6.2 |   |   |   |   |   |   |
| Shares issued as compensation                                          |       |         | 0.4        |           |       |         |       |              |       |             |       |         |       |                   |       |              |       |   |   |   |   |   |   |   |   |   | 0.4 |   |   |   |   |   |   |
| Restricted stock activity                                              |       |         |       |           |       |         | 15.0       |              |       |             |       |         |       |                   |       |              |       |   |   |   |   |   |   |   |   |   | 15.0 |   |   |   |   |   |   |
| Cumulative adjustment—FAS 123(R)                                  |       |         |       |           |       |         | (27.6      | )                 |       |             |       |         |       |                   |       |              |       |   | 17.5 |   |   |   |   |   |   |   | (10.1 | ) |   |   |   |   |   |
| Dividends ($0.30 per common share)                                     |       |         |       |           |       |         |       |              |       |             | (17.5      | )            |       |                   |       |              |       |   |   |   |   |   |   |   |   |   | (17.5 | ) |   |   |   |   |   |
| Cumulative adjustment—FAS 158                                     |       |         |       |           |       |         |       |              |       |             |       |         |       |                   | (19.6      | )                 |       |   |   |   |   |   |   |   |   |   | (19.6 | ) |   |   |   |   |   |
| Unrealized gain arising during the year on price  hedge contracts |       |         |       |           |       |         |       |              |       |             |       |         |       |                   | 68.1       |              |       |   |   |   |   |   |   |   |   |   | 68.1 |   |   |   |   |   |   |
| Reclassification adjustment included in net income                     |       |         |       |           |       |         |       |              |       |             |       |         |       |                   | (8.5       | )                 |       |   |   |   |   |   |   |   |   |   | (8.5 | ) |   |   |   |   |   |
| Net unrealized gains on price hedge contracts                          |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | — |   |   |   | 59.6 |   |   |
| Foreign currency translation adjustment                                |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | (11.4      | )                 |       |   | — |   |   |   | — |   |   |   | (11.4 | ) |   |   | (11.4 | ) |   |
| Comprehensive income                                                   |       |         | —     |           |       |         | —     |              |       |             | —     |         |       |                   | —     |              |       |   | — |   |   |   | — |   |   |   | — |   |   |   | $ | 494.4 |   |   |
| **Balance  at December 31, 2006**                                 |       |         | 65.8       |           |       |         | $          | 971.4             |       |             |       | $            | 1,892.9    |                   |       |              | $          | (1.4 | ) |   |   | $ | — |   |   |   | $ | (361.3 | ) |   |   | $ | 2,567.4 |   |   |   |   |   |   |

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

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

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

**(1) Summary ofSignificant 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 and Vietnam.

The Company’s results for2005 and 2004 reflect its oil and gas exploration, development and productionactivities in the Kingdom of Thailand and Hungary as discontinued operations. Exceptwhere noted, the discussions in the following notes relate to the Company’scontinuing 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 acquired propertiesare all determined using estimates of oil and gas reserves. There are numerousuncertainties in estimating the quantity of reserves and in projecting thefuture rates of production and timing of development expenditures. Oil and gasreserve engineering must be recognized as a subjective process of estimatingunderground accumulations of oil and gas that cannot be measured in an exactway. Provedreserves of crude oil, condensate, natural gas and natural gas liquids areestimated quantities that geological and engineering data demonstrate withreasonable certainty to be recoverable in the future from known reservoirsunder existing economic and operating conditions. Reservoirs are consideredproved if economic producibility is supported by either actual production orconclusive formation test. Proved reserves do not include, for example,hydrocarbons that may be recovered from undrilled prospects or the recovery ofwhich is otherwise subject to reasonable doubt because of uncertainty as togeology, reservoir characteristics or economic factors. Proved developedreserves are reserves that can be expected to be recovered through existingwells with existing equipment and operating methods or through the applicationof fluid injection or other improved recovery techniques confirmed by a pilotproject or operation of an installed program. Proved undeveloped oil and gasreserves are reserves that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditureis required for recompletion. Proved undeveloped reserves on undrilled acreageare limited to those drilling units offsetting productive units that arereasonably certain of production when drilled and other undrilled units whereit can be demonstrated with certainty that there is continuity of productionfrom the existing productive formation. TheSecurities and Exchange Commission provides a complete definition of provedreserves in Rule 4-10(a) of Regulation 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.

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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, 2006 consisted ofapproximately 3,653,769 Mcf of natural gas valued at its estimated average costof $5.66 per Mcf and 78,361 barrels of crude oil and condensate at itsestimated average cost of $20.80 per barrel. Natural gas inventory used as storagefacility cushion gas to maintain operation pressure is carried as a long-termasset.

*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 Gas Activitiesand Depreciation, Depletion and Amortization—*

The Company follows the successful efforts method ofaccounting for its oil and gas activities. Under the successful efforts method,lease acquisition costs and all development costs are capitalized. Proved oiland gas properties are reviewed annually or when circumstances suggest the needfor such a review and, if required, the proved properties are written down totheir estimated fair value. Estimated fair value includes the estimated presentvalue of future net cash flows. Unproved properties are reviewed quarterly todetermine if there has been impairment of the carrying value, with any suchimpairment charged to expense in the period. The evaluation of unprovedproperties requires management’s judgment to estimate the fair value ofleasehold costs related to a given area. Drilling activities in an area byother companies may also effectively condemn unproved properties. Exploratorywell costs are capitalized until the results are determined. If proved reservesare not discovered, the exploratory well costs are expensed. The followingtable reflects the net changes in capitalized exploratory well costs pendingproved reserve determination during 2006, 2005 and 2004 (amounts expressed inmillions):

| ** **                                                                                     | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Balance at  January 1,                                                                    |       | $        | 7.1        |     | $          | 11.8     |       | $ | 1.0 |   |
| Additions to  capitalized exploratory well costs pending the determination of proved  reserves |       | 38.5     |       | 7.1      |       | 10.8     |       |
| Reclassifications  to proved oil and gas properties                                            |       | (7.1     | )          | (6.7     | )          | —   |       |
| Capitalized  exploratory well costs charged to expense                                         |       | —   |       | (5.1     | )          | —   |       |
| Balance at  December 31,                                                                  |       | $        | 38.5       |     | $          | 7.1      |       | $ | 11.8 |   |

 

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

As of December 31, 2006, the Company hasexploratory well costs of $0.3 million related to two Canadian wells that havebeen capitalized for a period greater than one year.

Interest costs related to financing major oil and gasprojects in progress are capitalized until the projects are evaluated or untilthe projects are substantially complete and ready for their intended use if theprojects are evaluated as successful. Other exploratory costs, such asgeological and geophysical costs and rental payments, are expensed as incurred.The provision for depreciation, depletion and amortization is based on thecapitalized costs as determined above, and is computed on a cost center by costcenter basis using the units of production method, with lease acquisition costsamortized over total proved reserves and other costs amortized over proveddeveloped reserves. Generally, the Company establishes cost centers for itsonshore oil and gas activities on the basis of a reasonable aggregation ofproperties with a common geologic structural feature or stratigraphiccondition. The Company generally creates cost centers on a field-by-field basisfor oil and gas activities in offshore areas.

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

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 valuation allowance for the amount of anytax benefit when the Company believes it is more likely than not thatsuch benefits will not be realized. Note 3 contains information about theCompany’s income taxes, including the components of income tax provision andthe composition of deferred income tax assets and liabilities.

*Price RiskManagement—*

The Company from time to time enters into commodityprice hedging contracts with respect to its oil and gas production to achieve amore predictable cash flow, as well as reduce its exposure to price volatility.The Company follows the provisions of Statement of Financial 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.

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 

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

incomeand be reclassified into earnings in the same period during which the hedgedforecasted transaction affects earnings. The remaining gain or loss on thederivative instrument (i.e. ineffectiveness,) if any, must be recognizedcurrently in earnings as “Other” revenue or expense. To the extent theforecasted transaction in a designated and qualifying hedge relationship is nolonger probable of occurring, gains and losses previously deferred in othercomprehensive income are immediately reclassified to earnings under the caption“Commodity derivative income(expense).’’ For those derivative instruments that do not qualify as a cash flowhedge instrument, 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 derivativeincome(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 “Other” expense andproperty damage recoveries are recorded as a reduction of “Lease operatingexpense”. During the years ended December 31, 2006, 2005, and 2004 theCompany recognized $9.2 million, $40.7 million, and $11.1 million, respectivelyof business interruption insurance recoveries related to deferred productionresulting from Hurricanes Ivan, Katrina and Rita. During the same periods, theCompany recorded reductions to lease operating expense of $18.5 million, $14.5million, and $4.9 million, respectively, for property damage recoveries.

*Treasury Stock—*

On January 25, 2005,the Company announced a plan to repurchase, through open market or privatelynegotiated transactions, not less than $275 million, or more than $375million of its common stock.  Therepurchased shares were accounted for as treasury stock. As of December 31,2006, the Company had completed the purchase of 7,310,000 shares under thisplan at a total cost of $359.5 million.

*Retirement andPost-Retirement Benefits—*

As of December 31,2006, the Company adopted Financial Accounting Statement (“FAS”) No. 158, “Employers’Accounting for Defined Benefit Pension and Other Postretirement Plans”, whichamends FAS No. 87, “Employers’ Accounting for Pensions”, No. 88, “Employers’Accounting for Settlements and Curtailments of Defined Benefit Pension Plansand for Termination Benefits”, No. 106, “Employers’ Accounting for PostretirementBenefits Other Than Pensions”, and No. 132(R), “Employers’ DisclosuresAbout Pensions and Other Postretirement Benefits – an amendment of FAS Nos. 87,88, and 106”. The Statement requires companies to recognize on their 2006balance sheets the funded status of their pension and other postretirementbenefit plans, measured as of the balance sheet date. The Statement alsorequires that the actuarial gains and losses and the prior service costs andcredits that arise during the period be recognized, net of tax, as componentsof other comprehensive income; these amounts in other comprehensive income willbe adjusted as they are subsequently amortized and recognized as net periodicbenefit costs. See Note 12 for additional information.

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

*Consolidated Statementsof Cash Flows—*

The Company considers allhighly liquid investments with a maturity date of three months or less to becash equivalents. Significant transactions may occur which do not directlyaffect cash balances and, accordingly, are not disclosed in the ConsolidatedStatements of Cash Flows. Significant non-cash transactions are disclosed inthe Consolidated Statements of Shareholders’ Equity relating to shares issuedas compensation and in Note 16 relating to asset retirement costs.

*Foreign Currency—*

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

The U.S. dollar is thefunctional currency for all areas of operations of the Company other thanCanada. Accordingly, monetary assets and liabilities and items of income andexpense denominated in a foreign currency are remeasured to U.S. dollars at therate of exchange in effect at the end of each month or the average for themonth, and the resulting gains or losses on foreign currency transactions areincluded in the consolidated statements of income for the period.

*Recent AccountingPronouncements*

In September, 2006, theFASB issued Statement of Financial Accounting Standards No. 157, “FairValue Measurements” (SFAS 157”). SFAS 157 defines fair value, establishes aframework for measuring fair value, and expands disclosures about fair valuemeasurements. The Statement is effective for financial statements issued forfiscal years beginning after November 15, 2007. The adoption ofSFAS 157 is not expected to have a material impact on the Company’sfinancial statements.

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

**(2) Earnings perShare**

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

| ** **                                                                                                                                                                                                   | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| ***Income  (numerator):***                                                                                                                                                                                   |       |     |       |     |       |     |       |
| Income from continuing operations                                                                                                                                                                            |       | $        | 446.2      |     | $          | 290.1    |       | $ | 249.0 |   |
| Income from discontinued operations, net of tax                                                                                                                                                              |       | —   |       | 460.6    |       | 12.7     |       |
| Net income—basic and diluted                                                                                                                                                                            |       | $        | 446.2      |     | $          | 750.7    |       | $ | 261.7 |   |
| ***Weighted  average shares (denominator):***                                                                                                                                                                |       |     |       |     |       |     |       |
| Weighted average shares—basic                                                                                                                                                                           |       | 57.6     |       | 60.4     |       | 63.8     |       |
| Dilution effect of stock options and unvested  restricted stock outstanding at end of period                                                                                                                 |       | 0.5      |       | 0.5      |       | 0.6      |       |
| Weighted average shares—diluted                                                                                                                                                                         |       | 58.1     |       | 60.9     |       | 64.4     |       |
| ***Earnings  per share:***                                                                                                                                                                                   |       |     |       |     |       |     |       |
| Basic:                                                                                                                                                                                                       |       |     |       |     |       |     |       |
| Income from continuing operations                                                                                                                                                                            |       | $        | 7.74       |     | $          | 4.80     |       | $ | 3.90 |   |
| Income from discontinued operations                                                                                                                                                                          |       | —   |       | 7.63     |       | 0.20     |       |
| Basic earnings per share                                                                                                                                                                                     |       | $        | 7.74       |     | $          | 12.43    |       | $ | 4.10 |   |
| Diluted:                                                                                                                                                                                                     |       |     |       |     |       |     |       |
| Income from continuing operations                                                                                                                                                                            |       | $        | 7.68       |     | $          | 4.76     |       | $ | 3.87 |   |
| Income from discontinued operations                                                                                                                                                                          |       | —   |       | 7.56     |       | 0.19     |       |
| Diluted earnings per share                                                                                                                                                                                   |       | $        | 7.68       |     | $          | 12.32    |       | $ | 4.06 |   |
| ***Antidilutive  securities;***                                                                                                                                                                              |       |     |       |     |       |     |       |
| Shares assumed not issued from options to purchase  common shares as the exercise prices are above the average market price for  the period or the effect of the assumed exercise would be antidilutive |       | 0.02     |       | —   |       | 0.02     |       |
| Average price                                                                                                                                                                                                |       | $        | 48.93      |     | $          | —   |       | $ | 49.02 |   |

 

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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 for each ofthe three years in the period ended December 31, 2006, are as follows(expressed in millions):

| ** **                                                  | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|-------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| United States                                               |       | $        | 424.0      |     | $          | 417.7    |       | $ | 403.8 |   |
| Foreign                                                     |       | 75.3     |       | 40.3     |       | (5.9     | )          |
| Income from  continuing operations before income taxes |       | $        | 499.3      |     | $          | 458.0    |       | $ | 397.9 |   |

 

Thecomponents of income tax expense (benefit) for each of the three years in theperiod ended December 31, 2006, are as follows (expressed in millions):

| ** **          | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------|------------|----------|------------|----------|------------|----------|------------|
| Current             |       |     |       |     |       |     |       |
| United States       |       | $        | 84.9       |     | $          | 156.9    |       | $ | 145.7 |   |
| Foreign             |       | 11.4     |       | 1.9      |       | 0.1      |       |
| Deferred            |       |     |       |     |       |     |       |
| United States       |       | 79.5     |       | (6.1     | )          | 3.1      |       |
| Foreign             |       | (122.7   | )          | 15.2     |       | —   |       |
| Income tax  expense |       | $        | 53.1       |     | $          | 167.9    |       | $ | 148.9 |   |

 

Total income tax expense for each of the three years in the period endedDecember 31, 2006, differs from the amounts computed by applying thestatutory federal income tax rate to income before taxes as follows (expressedas percent of pretax income):

| ** **                                  | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Federal statutory  income tax rate          |       | 35.0     | %          | 35.0     | %          | 35.0     | %          |
| Increases  (decreases) resulting from:      |       |     |       |     |       |     |       |
| Canadian income tax                         |       | (25.0    | )          | —   |       | —   |       |
| State income taxes, net of federal benefits |       | 1.3      |       | 1.6      |       | 1.5      |       |
| Other                                       |       | (0.7     | )          | 0.1      |       | 0.9      |       |
|                                        |       | 10.6     | %          | 36.7     | %          | 37.4     | %          |

 

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

During2006, the Company’s consolidated effective tax rate was 10.6%, down from 36.7%in 2005. This decrease relates to the enactment of a reduction of the Albertaand Saskatchewan provincial tax rates, in addition to a reduction in the statutoryCanadian federal income tax rate, which generated a one-time deferred taxbenefit of approximately $112 million.

Theprincipal components of the Company’s deferred income tax assets andliabilities at December 31, 2006 and 2005 (expressed in millions) are asfollows:

| ** **                                                                          | ** ** | **December 31,** | ** ** |
|-------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                          | ** ** | **2006**              | ** ** | **2005** | ** ** |
| Deferred tax  assets:                                                               |       |                  |       |   |   |
| Foreign deferred tax assets and net operating loss  carry forwards                  |       | $                     | 2.1        |   | $ | 6.3 |   |
| Valuation allowance of deferred tax assets and  foreign net operating loss          |       | (2.1                  | )          | (6.3 | ) |
| Tax basis in excess of book basis for commodity  derivative contracts               |       | —                |       | 35.2 |   |
| Tax basis in excess of book basis for deferred  compensation and benefit plans |       | 21.3                  |       | 20.0 |   |
| Net operating loss carryforwards                                                    |       | 62.3                  |       | 2.4 |   |
| Other                                                                               |       | 4.9                   |       | 4.3 |   |
|                                                                                |       | 88.5                  |       | 61.9 |   |
| Deferred tax liabilities:                                                           |       |                  |       |   |   |
| Book basis in excess of tax basis for oil and gas  properties and equipment    |       | (1,567.0              | )          | (1,360.9 | ) |
| Other                                                                               |       | (6.7                  | )          | (5.7 | ) |
|                                                                                |       | (1,573.7              | )          | (1,366.6 | ) |
| Net deferred tax  liability                                                         |       | $                     | (1,485.2   | ) | $ | (1,304.7 | ) |

 

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 tax reporting.In addition, the Company recorded a deferred tax liability resulting from bookand tax basis differences for corporations acquired in 2004, 2005, and 2006.

As of December 31, 2006, the Company has a U.S.net operating loss (NOL) carryforward of approximately $178 million thatmay be used in future years to offset taxable income. The NOL was obtained aspart of the acquisition of Latigo Petroleum, Inc. The NOL is subject to certainlimitations on future utilization. The Company does not anticipate that theselimitations will affect the ultimate utilization of the NOL.

As of December 31, 2006, the Company has a foreignNOL carryforward of approximately $6.4 million that may be used in future yearsto offset foreign taxable income. The majority of these NOL carryforwards haveno expiration date, however their utilization may be subject to limitations asa result of enacted tax legislation within the applicable foreign jurisdictionand their realization is dependent upon generating sufficient taxable incomewithin the applicable foreign jurisdiction. The $2.1 million valuationallowance at December 31, 2006 was related to exploration expenses theCompany incurred in its foreign 

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

operations. During 2006,the Company reduced the foreign NOL carryforwards due to the liquidation ofseveral foreign subsidiaries.

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 $220.6 million at December 31, 2006.It is not practicable to determine the amount of U.S. income taxes that wouldbe payable upon remittance of the assets that represent those earnings.

On October 22, 2004, the President signed theAmerican Jobs Creation Act of 2004 (the “Act”). The Act provides a deductionfor income from qualified domestic production activities, which will be phasedin from 2005 through 2010. The Act also created a temporary incentive for U.S.corporations to repatriate accumulated income earned abroad by providing an 85percent dividends received deduction for certain dividends from controlledforeign corporations. The Company adopted a Domestic Reinvestment Plan thatqualifies for the temporary incentive. Based on that decision, the Companyrepatriated $497 million in extraordinary dividends, as defined in the Act,during the third quarter of 2005. The Company also repatriated an additional$315 million that did not qualify for the temporary incentive. As a result ofthe repatriation of $812 million, the Company recorded a U.S. tax expense of$24.1 million during 2005.

The Company and itssubsidiaries file income tax returns in the U.S. federal and various state andforeign jurisdictions. The Company is no longer subject to U.S. federal, state,or local tax examinations by tax authorities for years prior to 2003. TheCompany’s Canadian subsidiary is no longer subject to examinations by Canadiantaxing authorities for years prior to 2002. The Internal Revenue Service (“IRS”)completed the examination of the Company’s U.S. income tax returns through 2003in the fourth quarter of 2005, which resulted in a refund to the Company in2006 of $1.4 million. The IRS also reviewed the Company’s income tax return for2004 and indicated they do not presently intend to perform an examination ofthat tax return. Based on the results of the last examination, the Company doesnot anticipate that any adjustments made to the filings for open years wouldresult in a material change to its financial position.

On January 1, 2007,the Company will adopt the provisions of FASB Interpretation No.48 (“FIN 48”), “Accountingfor Uncertainty in Income Taxes.” The Company has determined that no uncertaintax positions exist where the Company would be required to make additional taxpayments. As a result, the Company has not recorded any additional liabilitiesfor any unrecognized tax benefits as of December 31, 2006, and will not berequired to record any on January 1, 2007.

The Company’s accountingpolicy is to recognize penalties and interest related to unrecognized taxbenefits as income tax expense. The Company does not have an accrued liabilityfor the payment of penalties and interest at December 31, 2006.

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

**(4)   Long-TermDebt**

Long-termdebt at December 31, 2006, and 2005, consists of the following (dollarsexpressed in millions):

| ** **                                                                                                                   | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                   | ** ** | **2006**              | ** ** | **2005** | ** ** |
| Senior debt—                                                                                                            |       |                  |       |   |   |
| Bank revolving  credit facility:                                                                                             |       |                  |       |   |   |
| LIBOR based loans, borrowings at December 31,  2006 and 2005 at interest rates of 6.8524% and 5.837%, respectively |       | $                     | 797.0      |   | $ | 606.0 |   |
| LIBOR Rate Advances, borrowings at December 31,  2006 and 2005 at interest rates of 6.6833% and 5.618%, respectively    |       | 75.0                  |       | 40.0 |   |
| Total senior debt                                                                                                            |       | 872.0                 |       | 646.0 |   |
| Subordinated debt—                                                                                                      |       |                  |       |   |   |
| 8.25% Senior subordinated notes, due 2011                                                                                    |       | 200.0                 |       | 200.0 |   |
| 7.875% Senior subordinated notes, due 2013                                                                                   |       | 450.0                 |       | — |   |
| 6.625% Senior subordinated notes, due 2015                                                                                   |       | 300.0                 |       | 300.0 |   |
| 6.875% Senior subordinated notes, due 2017                                                                                   |       | 500.0                 |       | 500.0 |   |
| Total  subordinated debt                                                                                                     |       | 1,450.0               |       | 1,000.0 |   |
| Unamortized  discount on 2015 Notes                                                                                          |       | (2.3                  | )          | (2.6 | ) |
| Long-term debt                                                                                                               |       | $                     | 2,319.7    |   | $ | 1,643.4 |   |

 

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 billion 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 31,2006, the borrowing base was $1.5 billion. The Credit Facility provides that inspecified circumstances involving an increase in ratings assigned to theCompany’s debt, the Company may elect for the borrowing base limitation to nolonger apply to restrict available borrowings. The Credit Facility alsoincludes procedures for additional financial institutions selected by theCompany to become lenders under the agreement, or for any existing lender toincrease its commitment in an amount approved by the Company and the lender,subject to a maximum of $250 million for all such increases in commitments ofnew or existing lenders. Additionally, the Credit Facility permits short-termswing-line loans up to $10 million and the issuance of letters of credit up to$75 million, which in each case reduce the credit available for revolvingcredit borrowings. All outstanding amounts owed under the Credit Facilitybecome 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 defaultwhich the Company considers usual and customary for an agreement of this type,including failure to make payments under the credit agreement, non-performanceof covenants and obligations continuing beyond any applicable grace period,default in the payment of other indebtedness in excess in principal amount of$25 million 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 

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

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 June 6, 2006, the Company issued $450 millionprincipal amount of 7.875% senior subordinated notes due 2013. The proceedsfrom the sale of the 2013 Notes were used to pay down obligations under theCompany’s bank revolving credit agreement. The 2013 Notes bear interest at arate of 7.875%, payable semi-annually in arrears on May 1 and November 1of each year. The 2013 Notes are general unsecured senior subordinatedobligations of the Company, and are subordinated in right of payment to theCompany’s senior indebtedness, which currently includes the Company’sobligations under the bank revolving credit agreement and LIBOR rate advances. TheCompany, at its option, may redeem the 2013 Notes in whole or in part, at anytime on or after May 1, 2010, at a redemption price of 103.938% of theirprincipal amount and decreasing percentages thereafter. The Company may alsoredeem a portion of the 2013 Notes prior to May 1, 2009 with proceeds fromequity offerings, and some or all of the Notes prior to May 1, 2010, ineach case by paying specified premiums. The indenture governing the 2013 Notesalso imposes certain covenants on the Company, including covenants limiting:incurrence of indebtedness, including senior indebtedness; payments ofdividends, stock repurchases, and redemption of subordinated debt; the sales ofassets or subsidiary capital stock; transactions with affiliates; liens; agreementsrestricting dividends and distributions by subsidiaries; and mergers orconsolidations.

On September 23, 2005, the Company issued $500million principal amount of 2017 Notes. The proceeds from the sale of the 2017Notes were used to fund a portion of the Northrock acquisition. The 2017 Notesbear 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 Credit Facility and LIBOR rate advances. The Company, atits option, may redeem the 2017 Notes in whole or in part, at any time on orafter October 1, 2010, at a redemption price of 103.4375% of theirprincipal amount and decreasing percentages thereafter. The Company may also 

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

redeem a portion of the2017 Notes prior to October 1, 2008 and some or all of the Notes prior to October 1,2010, in each case by paying specified premiums. The indenture governing the2017 Notes also imposes certain covenants on the Company including covenantslimiting: incurrence of indebtedness including senior indebtedness; restrictedpayments; the issuance and sales of restricted subsidiary capital stock;transactions with affiliates; liens; disposition of proceeds of assets sales;non-guarantor restricted subsidiaries; dividends and other payment restrictionsaffecting restricted subsidiaries; and merger, consolidations and the sale ofassets.

On March 29, 2005, the Company issued $300million principal amount of 2015 Notes at 99.101%. The proceeds from the saleof the 2015 Notes were used to pay down obligations under the Company’s bankCredit 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 obligations of theCompany, and are subordinated in right of payment to the Company’s seniorindebtedness, which includes the Company’s obligations under the CreditFacility and LIBOR rate advances. The Company, at its option, may redeem the2015 Notes in whole or in part, at any time on or after March 15, 2010, ata redemption price of 103.3125% of their principal amount and decreasingpercentages thereafter. The Company may also redeem a portion of the 2015 Notesprior 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 $200million principal amount of 2011 Notes. The 2011 Notes bear interest at a rateof 8.25%, payable semi-annually in arrears on April 15 and October 15of each year. The 2011 Notes are general unsecured senior subordinatedobligations of the Company, are subordinated in right of payment to the Company’ssenior indebtedness, which currently includes the Company’s obligations underthe Credit Facility and LIBOR rate advances. The Company, at its option, mayredeem the 2011 Notes in whole or in part, at any time on or after April 15,2006, at a redemption price of 104.125% of their principal amount anddecreasing percentages****thereafter.The indenture governing the 2011 Notes also imposes certain covenants on theCompany including covenants limiting: incurrence of indebtedness includingsenior indebtedness; restricted payments; the issuance and sales of restrictedsubsidiary capital stock; transactions with affiliates; liens; disposition ofproceeds of asset sales; non-guarantor restricted subsidiaries; dividends andother payment restrictions affecting restricted subsidiaries; and merger,consolidations and the sale of assets.

During 2004, the Companyredeemed all $150 million of its 10.375% Senior Subordinated Notes due 2009(the “2009 Notes”) at 105.188% of their face amount. On April 19, 2004,the Company paid $157.8 million (excluding accrued interest) in cash toholders of the 2009 Notes. The cash redemption payment was funded throughborrowings under the Company’s existing bank Credit Facility. The Companyrecorded a pre-tax expense on the redemption of the 2009 Notes of $10.9 millionin “Loss on debt extinguishment” during the year ended December 31, 2004.

A change in control in theownership of the Company, as defined in the subordinated note agreements, couldresult in the acceleration of debt repayment. See Note 6—“Commitments andContingencies’’ for further discussion.

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

**(5)   Acquisitions**

**2006—**On May 2, 2006, the Company completed the acquisition of LatigoPetroleum, Inc. (“Latigo”), a privately held corporation for approximately$764.9 million in cash, including transaction costs. The purchase price wasfunded using cash on hand and debt financing. At the date of purchase, Latigoowned approximately 100,100 net producing acres, plus approximately 304,600 netacres of undeveloped leasehold. Latigo’s operations are concentrated in westTexas and the Texas Panhandle with key exploration plays in the TexasPanhandle. The Company acquired Latigo primarily to strengthen its position indomestic exploration and development properties. The following is a calculationand final allocation of purchase price to the acquired assets and liabilitiesbased on their relative fair values:

| CALCULATION OF PURCHASE  PRICE (IN MILLIONS)   |   |   |    |
|------------------------------------------------|--------|--------|---------|
| Cash paid, including transaction costs         |   | $      | 764.9   |   |
| Plus fair market  value of liabilites assumed: |   |   |    |
| Deferred income taxes                          |   | 205.9  |    |
| Other liabilities                              |   | 55.1   |    |
| Total purchase  price for assets acquired      |   | $      | 1,025.9 |   |
| ALLOCATION OF  PURCHASE PRICE (IN MILLIONS)    |   |   |    |
| Proved oil and gas properties                  |   | $      | 846.9   |   |
| Unproved oil and gas properties                |   | 157.0  |    |
| Other assets                                   |   | 22.0   |    |
| Total                                          |   | $      | 1,025.9 |   |

 

In addition to the Latigo acquisition, the Companyalso completed the corporate acquisition of a Canadian company on February 21,2006 for cash consideration totaling approximately $18.6 million. The Companyrecorded the estimated fair value of assets and liabilities that consistedprimarily of $26.9 million of oil and gas properties and deferred taxliabilities of $8.0 million. No goodwill was recorded in connection with eitherof these transactions.

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

**2005—**OnSeptember 27, 2005, the Company completed the acquisition of Northrock forapproximately $1.7 billion in cash. The Company purchased all of theoutstanding shares of Northrock pursuant to a share purchase agreement that wasentered into on July 8, 2005. As of September 27, 2005, Northrockowned approximately 292,000 net producing acres, plus approximately 950,000 netacres of undeveloped leasehold. Northrock’s activities are concentrated inSaskatchewan and Alberta with key exploration plays in Canada’s NorthwestTerritories, British Columbia and the Alberta Foothills. The Company acquiredNorthrock primarily to strengthen its position in North American explorationand development properties. The following is a calculation and final allocationof purchase price to the acquired assets and liabilities based on theirrelative fair values:

| CALCULATION OF PURCHASE  PRICE (IN MILLIONS)   |   |   |    |   |
|------------------------------------------------|--------|--------|---------|--------|
| Cash paid, including transaction costs         |   | $      | 1,737.5 |   |   |
| Plus fair market  value of liabilites assumed: |   |   |    |   |
| Other liabilites                               |   | 100.5  |    |   |
| Asset retirement obligation                    |   | 38.8   |    |   |
| Deferred income taxes                          |   | 745.6  |    |   |
| Total purchase  price for assets acquired      |   | $      | 2,622.4 |   |   |
| ALLOCATION OF  PURCHASE PRICE (IN MILLIONS)    |   |   |    |   |
| Proved oil and gas properties                  |   | $      | 1,715.8 |   |   |
| Unproved oil and  gas properties               |   | 787.3  |    |   |
| Other assets                                   |   | 119.3  |    |   |
| Total                                          |   | $      | 2,622.4 |   |   |

 

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 $51 million.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.

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

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

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

*Pro FormaInformation*

Thefollowing summary presents unaudited pro forma consolidated results ofoperations for the three years ended December 31, 2006 for the Company’scontinuing operations as if the acquisitions of Latigo, Northrock, and thecorporations had each****occurred asof January 1, 2004. The pro forma results are for illustrative purposesonly and include, in addition to the pre-acquisition historical results ofLatigo, Northrock, and the corporations, adjustments such as increaseddepreciation, depletion and amortization expense resulting from the allocationof fair value to oil and gas properties acquired, increased interest expense onacquisition debt and the related tax effects of these adjustments. Theunaudited pro forma information (presented in millions of dollars, except pershare amounts) is not necessarily indicative of the operating results thatwould have occurred had the acquisitions been consummated at that date, nor arethey necessarily indicative of future operating results.

| ** **           | ** ** | **Year Ended December 31,** | ** ** |
|----------------------|------------|--------------------------------------------|------------|
| ** **           | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **           | ** ** | **(Unaudited)**                            | ** ** |
| **Pro  Forma:**      |       |                                       |       |   |   |   |   |
| Revenues             |       | $                                          | 1,786.6    |   | $ | 1,621.5 |   | $ | 1,423.1 |   |
| Net income           |       | 452.9                                      |       | 324.9 |   | 249.6 |   |
| Earnings per  share: |       |                                       |       |   |   |   |   |
| Basic                |       | $                                          | 7.86       |   | $ | 5.38 |   | $ | 3.91 |   |
| Diluted              |       | $                                          | 7.79       |   | $ | 5.33 |   | $ | 3.88 |   |

 

**(6)**          Commitmentsand Contingencies

The Company hascommitments for operating leases (primarily for office space) in Houston,Calgary, Midland, Laredo, Tulsa, Ho Chi Minh City, and New Plymouth, and forother equipment (including gas compressors). Rental expense for office spacewas $6.1 million in 2006, $3.3 million in 2005, and $2.9 million in 2004.Rental expense for other equipment was $10 million in 2006, $6.8 million in2005 and $5.5 million in 2004.

Future minimum leasepayments related to the Company’s operating leases at December 31, 2006are approximately $22.5 million in 2007; $18.4 million in 2008; $17 million in2009; $15.6 million in 2010; $14.7 million in 2011 and $99.4 millionthereafter. Where rented equipment such as compressors is considered essentialto the operation of the lease, the Company has assumed that such equipment willbe leased for the estimated productive life of the reserves, even if thecontract terminates prior to such date.

On February 23, 2007,a shareholder that beneficially owns approximately 7.9% of the Company’s stock,formally provided notice to the Company of its intention to conduct a proxycontest at the Company’s 2007 Annual Meeting that would, if successful, resultin a change in a majority of the Board of Directors by (i) nominatingthree persons in opposition to the Board’s nominees and (ii) proposingamendments to the Company’s bylaws to expand the Board and elect threeadditional nominees. Directors are elected by a plurality of vote of theshareholders, and amendments to the Company’s bylaws must be approved by amajority of the shares outstanding. If there is a change in a majority of theBoard of Directors not approved by a vote of two-thirds of the incumbentdirectors, the indentures governing the Company’s senior subordinated notesrequire the Company to offer to repurchase all outstanding notes at 101% oftheir principal amount and to repay all outstanding senior debt, including thecredit facility, prior 

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

torepurchasing the notes (or obtain consent from the lenders allowing for suchrepurchase).  Although such a change in amajority of the Board of Directors would not, by itself, constitute an event ofdefault under the credit facility, failure by the Company to perform itsindenture obligations would allow the lenders under the credit facility toaccelerate the credit facility debt. The Company does not have sufficient cashavailable to fund a repurchase of all or a substantial portion of the seniorsubordinated notes or to repay all or a substantial portion of outstanding debtunder the credit facility.

Defaults under, or theacceleration of, the notes or credit facility could significantly and adverselyaffect the Company’s financial position. If the Company were not able to refinance the debt, it could be requiredto sell substantial assets in order to satisfy its obligations or to seekprotection under the federal bankruptcy laws. Any refinancing of the Company’s existing debt with new debt, ifavailable, would likely involve substantial costs, including the premium torepurchase notes from existing holders and transaction costs associated withobtaining new debt.  Such new debt may beon less favorable terms than the Company’s existing debt.  Refinancing may also negatively impact theCompany’s strategic alternatives initiative.

A change in the majorityof the Board of Directors as a result of the pending proxy contest would alsotrigger an obligation to make payments under the Company’s executive employmentagreements (upon termination of employment by the executives during specifiedperiods or in specified circumstances) and under the Company’s severance andretention program.

**(7)**          Severanceand Retention Incentive Program

The Company has established a Change of ControlSeverance and Retention Program (the “Plan”), effective as of January 1,2007, to provide severance benefits and a retention incentive to  employees who are designated by the PlanAdministrator as eligible for benefits under the Plan in the event of a “Changein Control.” The Company expects to pay approximately $11.4 million inretention incentives under the program during 2007.

The Company had in place aretention incentive plan that covered personnel who were employed by Northrockon September 27, 2005 (the date of acquisition) and were still employed byNorthrock on September 27, 2006. On that latter date, the Company madepayments of $13.4 million related to the retention incentive plan. The Companyalso made retention incentive plan payments of $2 million to those personnelwho were employed by Latigo at both May 2, 2006, the date of acquisition,and November 2, 2006, six months thereafter.

**(8)**          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 forcustomers who have exceeded 10% of revenues in any given year (expressed inmillions):

| ** **             | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------|------------|----------|------------|----------|------------|----------|------------|
| Shell Trading  Company |       | $        | 96.4       |     | $          | 117.5    |       | $ | 147.1 |   |
| NGX                    |       | 146.6    |       | 19.3     |       | —   |       |
|                        |            |          |            |          |            |          |            |  |  |  |

 

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

**(9)**          CreditRisk

Substantially all of theCompany’s accounts receivable at December 31, 2006 and 2005, 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 not collateralized.  The Company provides reserves for specificallyidentified receivables from customers and joint interest owners that, in theopinion of management, are considered doubtful of collection. As of December 31,2006 and 2005, the Company’s allowances for doubtful accounts were notmaterial.

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

**(10)**   GeographicInformation

The Company’sreportable geographic information is identified below. The accounting policiesof the geographic regions are the same as those described in the summary ofsignificant accounting policies (Note 1). The Company evaluates performance basedon operating income (loss). Financial information by geographic region ispresented below:

| ** **                                              | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------|------------|---------------------------------------|------------|----------|------------|----------|------------|
| ** **                                              | ** ** | **(Expressed in millions)** | ** ** |
| **Long-Lived Assets:**                                  |       |                                  |       |     |       |     |       |
| As of December 31,                                 |       |                                  |       |     |       |     |       |
| United States                                           |       | $                                     | 3,751.3    |     | $          | 2,624.7  |       | $ | 2,538.2 |   |
| Canada                                                  |       | 2,805.8                               |       | 2,659.7  |       | —   |       |
| Total                                                   |       | $                                     | 6,557.1    |     | $          | 5,284.4  |       | $ | 2,538.2 |   |
| **Capital  Expenditures:**                              |       |                                  |       |     |       |     |       |
| (including interest  capitalized)                       |       |                                  |       |     |       |     |       |
| For the year ended  December 31,                   |       |                                  |       |     |       |     |       |
| United States                                           |       | $                                     | 1,676.8    |     | $          | 397.2    |       | $ | 931.4 |   |
| Canada                                                  |       | 345.5                                 |       | 2,681.8  |       | —   |       |
| Other International                                     |       | 0.1                                   |       | —   |       | 5.7      |       |
| Total                                                   |       | $                                     | 2,022.4    |     | $          | 3,079.0  |       | $ | 937.1 |   |
| **Revenues:**                                           |       |                                  |       |     |       |     |       |
| For the year ended  December 31,                   |       |                                  |       |     |       |     |       |
| United States*                                          |       | $                                     | 1,235.2    |     | $          | 1,085.7  |       | $ | 976.6 |   |
| Canada                                                  |       | 509.8                                 |       | 139.6    |       | —   |       |
| Other International                                     |       | —                                |       | 0.4      |       | —   |       |
| Total                                                   |       | $                                     | 1,745.0    |     | $          | 1,225.7  |       | $ | 976.6 |   |
| **Depreciation,  depletion, and amortization expense:** |       |                                  |       |     |       |     |       |
| For the year ended  December 31,                   |       |                                  |       |     |       |     |       |
| United States                                           |       | $                                     | 285.2      |     | $          | 261.3    |       | $ | 251.9 |   |
| Canada                                                  |       | 199.4                                 |       | 50.9     |       | —   |       |
| Total                                                   |       | $                                     | 484.6      |     | $          | 312.2    |       | $ | 251.9 |   |
| **Operating  income (loss):**                           |       |                                  |       |     |       |     |       |
| For the year ended  December 31,                   |       |                                  |       |     |       |     |       |
| United States*                                          |       | $                                     | 486.3      |     | $          | 474.1    |       | $ | 432.7 |   |
| Canada                                                  |       | 82.5                                  |       | 43.9     |       | —   |       |
| Other International                                     |       | (6.5                                  | )          | (9.6     | )          | (6.4     | )          |
| Total                                                   |       | $                                     | 562.3      |     | $          | 508.4    |       | $ | 426.3 |   |

----

*                    Includesgain on sale of properties of $304.7 million in 2006.

**(11)**   DiscontinuedOperations

Under SFAS No. 144, “Accountingfor the Impairment or Disposal of Long-Lived Assets”, the Company classifiesassets to be disposed of as held for sale or, if appropriate, discontinuedoperations when they have received appropriate approvals by the Company’smanagement or Board of Directors and when they meet other criteria. As of December 31,2005, the Company had completed the sale of the assets discussed below.

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

*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.

The Thailand Entities andPogo Hungary are classified as discontinued operations in the Company’sfinancial statements for 2004 and 2005. The summarized financial results andfinancial position data of the discontinued operations were as follows (amountsexpressed in millions):

***Operating ResultsData***

| ** **                                                   | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                   | ** ** | **2005**                                   | ** ** | **2004** | ** ** |
| Revenues                                                     |       |                                       | $          | 252.8 |   |   |   | $ | 335.3 |   |   |
| Costs and  expenses                                          |       |                                       | (126.5     | ) |   |   | (237.1 | ) |   |
| Other income                                                 |       |                                       | 5.0        |   |   |   | 0.3 |   |   |
| Income before  income taxes                                  |       |                                       | 131.3      |   |   |   | 98.5 |   |   |
| Income taxes                                                 |       |                                       | (78.5      | ) |   |   | (85.8 | ) |   |
| Income before  gain from discontinued operations, net of tax |       |                                       | 52.8       |   |   |   | 12.7 |   |   |
| Gain on sale, net  of tax of $9.7 million                    |       |                                       | 407.8      |   |   |   | — |   |   |
| Income from discontinued  operations, net of tax             |       |                                       | $          | 460.6 |   |   |   | $ | 12.7 |   |   |

 

**(12)**   EmployeeBenefit Plans

The Company has a tax-advantaged savings plan in whichall U.S. salaried employees may participate. Under such plan, a participatingemployee may allocate up to 30% of their salary, up to a maximum allowed bylaw, and the Company will then match the employee’s contribution on a dollarfor dollar basis up to the lesser of 6% of the employee’s salary or $15,000 in2006. 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 $1.9 million to the savingsplan in 2006, $1.5 million in 2005, and $1.4 million in 2004.

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

The Company has adopted atrusteed retirement plan for its U.S. salaried employees. The benefits arebased on years of service and the employee’s average compensation for fiveconsecutive years within the final ten years of service which produce the highestaverage compensation. The Company makes annual contributions to the plan in theamount of retirement plan cost accrued or the maximum amount that can bededucted for federal income tax purposes. During 2006 and 2005, the Companycontributed $7.0 million and $4.5 million to the plan, respectively. TheCompany will continue to monitor the plan to determine whether a contributionwill need to be made in 2007. The plan’s investment strategy and goals are toensure, over the long-term life of the retirement plan, an adequate pool ofsufficiently liquid assets to support the benefit obligations to participants,retirees and beneficiaries. Investment objectives are long-term in naturecovering typical market cycles of three to five years.

Although the Company hasno obligation to do so, the Company currently provides full medical benefits toits retired U.S. employees and dependents. For current employees, the Companyassumes all or a portion of post-retirement medical and term life insurancecosts based on the employee’s age and length of service with the Company. Thepost-retirement medical plan has no assets and is currently funded by theCompany on a pay-as-you-go basis. The expected Company contributions to thepost-retirement medical plan during 2007 are approximately $0.7 million.

The following two tablesset forth the plans’ status (in millions of dollars) as of and for the yearsended December 31 of the applicable year.

| ** **                                                    | ** ** | ** **               | ** ** | ** **            | ** ** | **Post-Retirement** | ** ** |
|---------------------------------------------------------------|------------|--------------------------|------------|-----------------------|------------|---------------------|------------|
| ** **                                                    | ** ** | **Retirement Plan** | ** ** | **Medical Plan** | ** ** |
| ** **                                                    | ** ** | **2006**                 | ** ** | **2005**              | ** ** | **2006**            | ** ** | **2005** | ** ** |
| **Change in benefit obligation**                              | ** ** | ** **               | ** ** | ** **            | ** ** | ** **          | ** ** | ** ** | ** ** |
| Benefit obligation at  beginning of year                      |       | $                        | 46.6       |                  | $          | 36.9                |       | $ | 21.9 |   | $ | 21.2 |   |
| Service cost                                                  |       | 5.3                      |       | 3.4                   |       | 2.6                 |       | 1.4 |   |
| Interest cost                                                 |       | 2.5                      |       | 2.1                   |       | 1.3                 |       | 1.0 |   |
| Plan amendments                                               |       | —                   |       | —                |       | 1.6                 |       | — |   |
| Benefits paid                                                 |       | (6.2                     | )          | (2.4                  | )          | (0.4                | )          | (0.4 | ) |
| Actuarial loss                                                |       | 5.1                      |       | 6.6                   |       | 2.5                 |       | (1.3 | ) |
| Benefit obligation at  end of year                            |       | $                        | 53.3       |                  | $          | 46.6                |       | $ | 29.5 |   | $ | 21.9 |   |
| **Change in plan assets**                                     | ** ** | ** **               | ** ** | ** **            | ** ** | ** **          | ** ** | ** ** | ** ** |
| Fair value of plan  assets at beginning of year               |       | $                        | 35.7       |                  | $          | 32.3                |       | $ | — |   | $ | — |   |
| Actual return on plan  assets                                 |       | 4.9                      |       | 1.6                   |       | —              |       | — |   |
| Employer contributions                                        |       | 7.0                      |       | 4.5                   |       | 0.4                 |       | 0.4 |   |
| Benefits paid                                                 |       | (6.2                     | )          | (2.4                  | )          | (0.4                | )          | (0.4 | ) |
| Administrative expenses                                       |       | (0.4                     | )          | (0.3                  | )          | —              |       | — |   |
| Fair value of plan  assets at end of year                     |       | $                        | 41.0       |                  | $          | 35.7                |       | $ | — |   | $ | — |   |
| **Overfunded  (underfunded) status**                          |       | $                        | (12.3      | )                     | $          | (10.9               | )          | $ | (29.5 | ) | $ | (21.9 | ) |
| **Reconciliation of funded status**                           |       |                     |       |                  |       |                |       |   |   |
| Funded status                                                 |       | $                        | (12.3      | )                     | $          | (10.9               | )          | $ | (29.5 | ) | $ | (21.9 | ) |
| Unrecognized actuarial  loss                                  |       | —                   |       | 20.6                  |       | —              |       | 3.8 |   |
| Unrecognized transition  (asset) or obligation                |       | —                   |       | —                |       | —              |       | — |   |
| Unrecognized prior  service cost                              |       | —                   |       | 0.6                   |       | —              |       | — |   |
| Net amount recognized                                         |       | $                        | (12.3      | )                     | $          | 10.3                |       | (29.5 | ) | (18.1 | ) |
| **Amount recognized in the  statement of financial position** |       |                     |       |                  |       |                |       |   |   |
| Other assets                                                  |       | $                        | —     |                  | $          | 10.3                |       | $ | — |   | $ | — |   |
| Current liabilities                                           |       | —                   |       | —                |       | (0.7                | )          | — |   |
| Deferred credits                                              |       | (12.3                    | )          | —                |       | (28.8               | )          | (18.1 | ) |
| **Net amount recognized**                                     |       | $                        | (12.3      | )                     | $          | 10.3                |       | (29.5 | ) | (18.1 | ) |
| **Accumulated benefit obligation**                            |       | $                        | 40.8       |                  | $          | 35.6                |       |   |   |   |   |

 

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

 

| ** **                                    | ** ** | ** **               | ** ** | ** **            | ** ** | ** ** | ** ** | **Post-Retirement** | ** ** |
|-----------------------------------------------|------------|--------------------------|------------|-----------------------|------------|------------|------------|---------------------|------------|
| ** **                                    | ** ** | **Retirement Plan** | ** ** | **Medical Plan** | ** ** |
| ** **                                    | ** ** | **2006**                 | ** ** | **2005**              | ** ** | **2004**   | ** ** | **2006**            | ** ** | **2005** | ** ** | **2004** | ** ** |
| Components of net  periodic benefit cost      |       |                     |       |                  |       |       |       |                |       |   |   |   |   |
| Service cost                                  |       | $                        | 5.3        |                  | $          | 3.4        |       | $                   | 2.6        |   | $ | 2.6 |   | $ | 1.4 |   | $ | 1.4 |   |
| Interest cost                                 |       | 2.5                      |       | 2.1                   |       | 1.8        |       | 1.3                 |       | 1.0 |   | 1.0 |   |
| Expected return on plan assets                |       | (2.8                     | )          | (2.6                  | )          | (2.6       | )          | —              |       | — |   | — |   |
| Amortization of prior service cost            |       | 0.1                      |       | 0.1                   |       | —     |       | —              |       | — |   | — |   |
| Amortization of transition (asset) obligation |       | —                   |       | —                |       | —     |       | —              |       | 0.3 |   | 0.3 |   |
| Amortization of net loss                      |       | 1.9                      |       | 1.2                   |       | 0.7        |       | 0.4                 |       | — |   | 0.2 |   |
|                                          |       | $                        | 7.0        |                  | $          | 4.2        |       | $                   | 2.5        |   | $ | 4.3 |   | $ | 2.7 |   | $ | 2.9 |   |

 

Thebalance in Accumulated Other Comprehensive Income (AOCI) at December 31,2006 consists of the following components (in millions of dollars):

| ** **          | ** ** | **Retirement** | ** ** | **Post-Retirement**   | ** ** |
|---------------------|------------|----------------|------------|-----------------------|------------|
| ** **          | ** ** | **Plan**       | ** ** | **Medical Plan** | ** ** |
| Actuarial loss      |       |           | $          | 0.3                   |       |   |   | $ | 0.9 |   |   |
| Prior service  cost |       |           | 14.6       |                  |       |   | 3.8 |   |   |
| Total               |       |           | $          | 14.9                  |       |   |   | $ | 4.7 |   |   |

 

Prior to the adoption of SFAS 158, the Company had nominimum pension liability that would have been reflected in AOCI.

Theamounts in AOCI expected to be recognized as net periodic benefit expense overthe next fiscal year are as follows (in millions of dollars):

| ** **          | ** ** | **Retirement** | ** ** | **Post-Retirement**   | ** ** |
|---------------------|------------|----------------|------------|-----------------------|------------|
| ** **          | ** ** | **Plan**       | ** ** | **Medical Plan** | ** ** |
| Actuarial loss      |       |           | $          | 0.1                   |       |   |   | $ | 0.2 |   |   |
| Prior service  cost |       |           | 2.0        |                  |       |   | 0.4 |   |   |
| Total               |       |           | $          | 2.1                   |       |   |   | $ | 0.6 |   |   |

 

Thefollowing table shows the incremental effects (in millions) of applying FASBStatement No. 158 on individual line items in the statement of financialposition as of December 31, 2006:

| ** **                       | ** ** | **Before application** | ** ** | ** **      | ** ** | **After application** | ** ** |
|----------------------------------|------------|-----------------------------|------------|-----------------|------------|----------------------------|------------|
| ** **                       | ** ** | **of FAS 158**    | ** ** | **Adjustments** | ** ** | **of FAS 158**   | ** ** |
| Other assets                     |       |                        | $          | 51.1            |       |                       |       | $ | (10.3 | ) |   |   | $ | 40.8 |   |   |
| Total assets                     |       |                        | 6,981.4    |            |       |                       | (10.3      | ) |   |   | 6,971.1 |   |   |
| Deferred credits                 |       |                        | 27.4       |            |       |                       | 20.5       |   |   |   | 47.9 |   |   |
| Deferred income  taxes           |       |                        | 1,489.2    |            |       |                       | (11.2      | ) |   |   | 1,478.0 |   |   |
| Total liabilities                |       |                        | 4,394.4    |            |       |                       | 9.3        |   |   |   | 4,403.7 |   |   |
| Accumulated OCI                  |       |                        | 18.2       |            |       |                       | (19.6      | ) |   |   | (1.4 | ) |   |
| Total shareholders’  equity |       |                        | 2,587.0    |            |       |                       | (19.6      | ) |   |   | 2,567.4 |   |   |

 

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

*Plan Assumptions*

| ** **                                             | ** ** | ** **               | ** ** | ** **            | ** ** | ** ** | ** ** | **Post-Retirement** | ** ** |
|--------------------------------------------------------|------------|--------------------------|------------|-----------------------|------------|------------|------------|---------------------|------------|
| ** **                                             | ** ** | **Retirement Plan** | ** ** | **Medical Plan** | ** ** |
| ** **                                             | ** ** | **2006**                 | ** ** | **2005**              | ** ** | **2004**   | ** ** | **2006**            | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Plan assumptions to determine  benefit obligations** | ** ** | ** **               | ** ** | ** **            | ** ** | ** ** | ** ** | ** **          | ** ** | ** ** | ** ** | ** ** | ** ** |
| Discount rate                                          |       | 5.75                     | %          | 5.50                  | %          | 5.75       | %          | 5.75                | %          | 5.50 | % | 5.75 | % |
| Rate of compensation increase                          |       | 5.50                     | %          | 5.50                  | %          | 5.50       | %          | —              |       | — |   | — |   |
| **Plan  assumptions to determine net cost**            | ** ** | ** **               | ** ** | ** **            | ** ** | ** ** | ** ** | ** **          | ** ** | ** ** | ** ** | ** ** | ** ** |
| Discount rate                                          |       | 5.50                     | %          | 5.75                  | %          | 6.00       | %          | 5.50                | %          | 5.75 | % | 6.00 | % |
| Expected long-term rate of return on plan assets       |       | 8.50                     | %          | 8.50                  | %          | 8.50       | %          | —              |       | — |   | — |   |
| Rate of compensation increase                          |       | 5.50                     | %          | 5.50                  | %          | 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 2006.

The Company determines the discount rate used tomeasure plan liabilities as of the December 31 measurement date for bothplans. The discount rate reflects the current rate at which the associatedliabilities could be effectively settled at the end of the year. In determiningthis rate, the Company reviews rates of return on fixed-income investments ofsimilar duration to the liabilities in the plan that receive high, investmentgrade ratings by recognized ratings agencies. Additionally, the Companyperforms an analysis of the Citigroup Pension Discount Curve (CPDC) as of thatdate for both plans. The CPDC uses spot rates that represent the equivalentyield on high quality, zero coupon bonds for specific maturities. These rateswere used to develop an equivalent single discount rate based on the plans’expected future benefit payment streams and duration of plan liabilities. Usingthis methodology, the Company determined a discount rate of 5.75% to be appropriateas of December 31, 2006, which is an increase of 0.25 percentage pointsfrom the rate used as of December 31, 2005.

Expectedbenefit payments for the retirement and the post-retirement medical plans forthe next ten years are as follows (expressed in millions):

| ** **            | ** ** | **Expected Benefit Payments** | ** ** |
|-----------------------|------------|-----------------------------------------|------------|
| **Year Ending**  | ** ** | **Retirement**                          | ** ** | **Post-Retirement** | ** ** |
| **December 31,** | ** ** | ** **                              | ** ** | **      Plan      ** | ** ** | **   Medical Plan   ** | ** ** |
| 2007                  |       |                                    | $          | 3.5 |   |   |   | $ | 0.7 |   |   |
| 2008                  |       |                                    | 5.3        |   |   |   | 0.8 |   |   |
| 2009                  |       |                                    | 5.0        |   |   |   | 0.9 |   |   |
| 2010                  |       |                                    | 4.9        |   |   |   | 1.1 |   |   |
| 2011                  |       |                                    | 6.1        |   |   |   | 1.2 |   |   |
| Next 5 Years          |       |                                    | 37.8       |   |   |   | 7.8 |   |   |
|                       |            |                                         |            |  |  |  |  |  |  |  |  |  |  |

 

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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**                                        | ** ** | **      2006      ** | ** ** | **      2005      ** | ** ** |
| Equity securities       |       |       | 100        | %                                                 |       |   | 89 | % |   |   | 87 | % |   |
| Debt securities         |       |       | 0          | %                                                 |       |   | 0 | % |   |   | 0 | % |   |
| Real estate             |       |       | 0          | %                                                 |       |   | 0 | % |   |   | 0 | % |   |
| Other                   |       |       | 0          | %                                                 |       |   | 11 | % |   |   | 13 | % |   |
| 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 2006. The rate is assumedto decrease gradually to 5% for 2013 and remain at that level thereafter. Thiscompares to the amounts used for 2005 measurement purposes, where a 10% 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 millions):

| ** **                                                        | ** ** | **One Percentage Point**   | ** ** |
|-------------------------------------------------------------------|------------|--------------------------------------|------------|
| ** **                                                        | ** ** | **  Increase  ** | ** ** | **  Decrease  ** | ** ** |
| Effect on total  of service and interest cost components for 2006 |       |                                 | $          | 0.8 |   |   |   | $ | (0.7 | ) |   |
| Effect on year-end 2006  post-retirement benefit obligation       |       |                                 | $          | 5.2 |   |   |   | $ | (4.2 | ) |   |

 

In December 2003, theMedicare Prescription Drug Improvement and Modernization Act of 2003 (the Act)was signed into law. The Act introduced a prescription drug benefit underMedicare (Medicare Part D), as well as a nontaxable federal subsidy tosponsors of retiree health care benefit plans that provide a benefit that is atleast actuarially equivalent to Medicare Part D. The Company has electednot to reflect changes in the Act in its 2006 financial statements since theCompany has concluded that the effects of the Act are not a significant eventthat calls for remeasurement under FAS 106.

**(13)**   Stock-BasedCompensation Plans

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”). Employeestock options generally become exercisable in three installments. Employeerestricted stock generally vests in four installments. The number of shares ofCompany common stock available for future issuance was 3,284,524, 3,637,057,and 3,975,757 as of December 31, 2006, 2005, and 2004, respectively. Stockoptions granted during and after 2003 expire 5 years from the date of grant, ifnot exercised. Stock options granted prior to 2003, if not exercised, expire 10years from the date of grant. 

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

Effective January 1, 2003, the Company adoptedthe fair value recognition provisions of Statement of Financial AccountingStandards No. 123, “Accounting for Stock Based Compensation” (“SFAS 123”)and the prospective method transition provisions of Statement of FinancialAccounting Standards No. 148, “Accounting for Stock Based Compensation—Transitionand Disclosure—an amendment of FAS No. 123” (“SFAS 148”) for allStock Awards granted, modified or settled after January 1, 2003. UnderSFAS 123, the Company recognized compensation cost for all Stock Awards oneither a straight-line basis over the vesting period or upon retirement,whichever was shorter (the nominal vesting period approach). On January 1,2006, the Company adopted the provisions of SFAS No. 123 (revised 2004) (“SFAS123R”), “Share-Based Payment”, which replaced the provisions of SFAS 123. Thecumulative effect of the change in accounting principle resulting from theadoption of SFAS 123R was recognized in the Company’s financial statementsthrough the elimination of previously recognized deferred compensation costs,with offsetting amounts recorded in the additional paid in capital accountwithin shareholders’ equity and the related deferred income tax payable. TheCompany adopted SFAS 123R using the modified prospective transition method. Underthat transition method, compensation cost recognized during the twelve monthsended December 31, 2006 includes (a) compensation cost for StockAwards granted prior to, but not yet vested as of January 1, 2006, basedon the grant date fair value estimated in accordance with the originalprovisions of SFAS 123, and (b) compensation cost for all Stock Awardgrants subsequent to January 1, 2006 based on the grant date fair valueestimated in accordance with SFAS 123R. Compensation cost for restricted stockand stock options is recognized using the nonsubstantive vesting periodapproach, i.e. (a) on a straight-line basis, over either the vestingperiod for the applicable Stock Award or until retirement eligibility age,whichever is shorter, or (b) over a six-month period for Stock Awards toemployees who have reached retirement eligibility age. The impact of using thenonsubstantive vs. the nominal vesting period approach would have resulted in areduction in after-tax compensation expense of $1.0 million for the year ended December 31,2006, and an increase in after-tax compensation expense of $3.1 million and$10.0 million for the years ended December 31, 2005, and 2004,respectively.

Thefollowing table illustrates the effect on the Company’s net income and earningsper share if the fair value recognition provisions of SFAS 123R for employeestock-based compensation had been applied to all Stock Awards outstandingduring the years ended December 31, 2005 and 2004 (in millions of dollars,except per share amounts): 

| ** **                                                                                                                                    | ** ** | **Year Ended**   | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                    | ** ** | **December 31,** | ** ** |
| ** **                                                                                                                                    | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Net income, as reported                                                                                                                       |       | $                     | 750.7      |   | $ | 261.7 |   |
| Add: Employee stock-based compensation expense, net  of related tax effects, included in net income, as reported                         |       | 5.4                   |       | 3.0 |   |
| Deduct: Total employee stock-based compensation expense,  determined under fair value method for all awards, net of related tax  effects |       | (6.8                  | )          | (6.7 | ) |
| Net income, pro forma                                                                                                                         |       | $                     | 749.3      |   | $ | 258.0 |   |
| Earnings  per share:                                                                                                                          |       |                  |       |   |   |
| Basic—as reported                                                                                                                        |       | $                     | 12.43      |   | $ | 4.10 |   |
| Basic—pro forma                                                                                                                          |       | $                     | 12.41      |   | $ | 4.04 |   |
| Diluted—as reported                                                                                                                      |       | $                     | 12.32      |   | $ | 4.06 |   |
| Diluted—pro forma                                                                                                                        |       | $                     | 12.30      |   | $ | 4.01 |   |

 

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

Restricted Stock

Thefair value of restricted stock grants is estimated based on the average of thehigh and low share price on the date of grant. The Company granted thefollowing shares of restricted stock during the periods indicated:

| ** **            | ** ** | ** ** | ** ** | **Weighted**        | ** ** |
|-----------------------|------------|------------|------------|---------------------|------------|
| ** **            | ** ** | ** ** | ** ** | **Average**         | ** ** |
| ** **            | ** ** | **Number** | ** ** | **Grant Date** | ** ** |
| **Year Ended**   | ** ** | **of**     | ** ** | **Fair Value** | ** ** |
| **December 31,** | ** ** | ** ** | ** ** | **Awards**          | ** ** | **(in millions)** | ** ** |
| 2006                  |       | 400,000    |       |                | $          | 17.8 |   |   |
| 2005                  |       | 351,800    |       |                | $          | 19.5 |   |   |
| 2004                  |       | 303,400    |       |                | $          | 13.2 |   |   |
|                       |            |            |            |                     |            |  |  |  |  |  |

 

Asummary of the status of the Company’s unvested restricted stock activityduring and as of the year ended December 31, 2006, is presented below:

| ** **                          | ** ** | ** ** | ** ** | **Weighted**        | ** ** |
|-------------------------------------|------------|------------|------------|---------------------|------------|
| ** **                          | ** ** | ** ** | ** ** | **Average**         | ** ** |
| ** **                          | ** ** | ** ** | ** ** | **Grant Date** | ** ** |
| ** **                          | ** ** | **Shares** | ** ** | **Fair Value** | ** ** |
| Unvested restricted  stock:         |       |       |       |                |       |   |   |
| Unvested at December 31, 2005  |       | 630,600    |       |                | $          | 51.57 |   |   |
| Granted                             |       | 400,000    |       |                | $          | 44.49 |   |   |
| Vested                              |       | (233,875   | )          |                | $          | 48.67 |   |   |
| Forfeited                           |       | (25,700    | )          |                | $          | 47.83 |   |   |
| Unvested at  December 31, 2006 |       | 771,025    |       |                | $          | 47.54 |   |   |

 

As of December 31,2006, there was approximately $27.1 million of total unrecognized compensationcost related to unvested restricted stock that is expected to be recognizedover a weighted average period of 1.5 years. Total compensation expense for restrictedstock for the years ended December 31, 2006, 2005, and 2004 was $15.6million ($9.9 million, net of tax), $7.1 million ($4.5 million, net of tax),and $3.3 million ($2.1 million, net of tax), respectively. The total fair valueof shares that vested and were distributed during the years ended December 31,2006, 2005 and 2004, was $10.7 million, $6.4 million, and $1.6 million,respectively, which resulted in the recognition of deferred tax assets inexcess of the benefits of the tax deductions (“excess tax deficiencies”) of$0.3 for 2006, and the recognition of the benefits of the tax deductions inexcess of deferred tax assets (“excess tax deductions”) of $0.5 million and$0.02 million for 2005 and 2004, respectively.

Stock Options

The Company granted options covering 30,000 shares ofstock during the period ended December 31, 2004. Those options had a grantdate fair market value of $0.3 million. No stock options were granted during2005 or 2006. The fair value of previous stock option grants that vested in2005 and 2006 was estimated on the date of grant using the Black-Scholes optionpricing model with the following weighted-average assumptions used for stockoption grants made in 2004 and 2003, respectively: risk free interest 

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

rates of 3.00% and 2.30%,expected volatility of 25.7% and 28.4%, dividend yields of 0.48% and 0.61%, andan expected life of the options of three and a half and three years. Totalcompensation expense for stock options for the years ended December 31,2006, 2005, and 2004 was $0.7 million ($0.5 million, net of tax), $1.4 million($0.9 million, net of tax) and $1.4 million ($0.9 million, net of tax),respectively. The total intrinsic value of stock options exercised during theyears ended December 31, 2006, 2005, and 2004 was $2.7 million, $7.3million, and $9.4 million respectively, resulting in excess tax deductions of$1.0 million, $2.7 million, and $3.3 million for the same respective periods.As of December 31, 2006, there was less than $0.1 million in unrecognizedcompensation cost related to unvested stock options that is expected to berecognized over a weighted average period of 4 months. The Company’s currentpractice is to issue new shares to satisfy stock option exercises. 

Asummary of the Company’s stock option activity during and as of the year ended December 31,2006, is presented below:

| ** **                           | ** ** | ** **         | ** ** | ** **   | ** ** | **Weighted**    | ** ** | ** **        | ** ** |
|--------------------------------------|------------|--------------------|------------|--------------|------------|-----------------|------------|-------------------|------------|
| ** **                           | ** ** | ** **         | ** ** | **Weighted** | ** ** | **Average**     | ** ** | **Aggregate**     | ** ** |
| ** **                           | ** ** | ** **         | ** ** | **Average**  | ** ** | **Remaining**   | ** ** | **Intrinsic**     | ** ** |
| ** **                           | ** ** | **Number of** | ** ** | **Exercise** | ** ** | **Contractual** | ** ** | **Value**         | ** ** |
| ** **                           | ** ** | **Awards**         | ** ** | **Price**    | ** ** | **Term**        | ** ** | **(millions)(a)** | ** ** |
| Outstanding,  December 31, 2005 |       | 1,782,236          |       |         | $          | 29.69           |       |              |       |   |   |   |   |   |   |   |
| Exercised                            |       | (144,800           | )          |         | $          | 30.95           |       |              |       |   |   |   |   |   |   |   |
| Canceled                             |       | (15,867            | )          |         | $          | 43.11           |       |              |       |   |   |   |   |   |   |   |
| Outstanding, December 31, 2006  |       | 1,621,569          |       |         | $          | 29.45           |       |              |       | 4.1 years |   |   |   | $ | 31.6 |   |   |
| Exercisable,  December 31, 2006 |       | 1,614,902          |       |         | $          | 29.37           |       |              |       | 4.1 years |   |   |   | $ | 31.6 |   |   |

----

(a)           Calculated based on theexercise price of underlying awards and the quoted price of the Company’scommon stock as of the balance sheet date.

Thefollowing table summarizes information about stock options outstanding at December 31,2006: 

| ** **             | ** ** | **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     |                         |       |   | 841 |   |   |   | $ | 18.30 |   |   | 47,500 |   |   | $ | 18.30 |   |   |
| $20.31 to $24.77       |       |                         | 607,101    |                         |       |   | 1,519 |   |   |   | $ | 23.30 |   |   | 607,101 |   |   | $ | 23.30 |   |   |
| $25.38 to $29.78       |       |                         | 604,600    |                         |       |   | 1,966 |   |   |   | $ | 29.58 |   |   | 604,600 |   |   | $ | 29.58 |   |   |
| $31.18 to $33.94       |       |                         | 40,000     |                         |       |   | 1,988 |   |   |   | $ | 31.36 |   |   | 40,000 |   |   | $ | 31.36 |   |   |
| $40.63 to $43.46       |       |                         | 304,034    |                         |       |   | 510 |   |   |   | $ | 41.82 |   |   | 304,034 |   |   | $ | 41.82 |   |   |
| $45.89 to $49.48       |       |                         | 18,334     |                         |       |   | 860 |   |   |   | $ | 48.38 |   |   | 11,667 |   |   | $ | 48.50 |   |   |
| Total                  |       |                         | 1,621,569  |                         |       |   | 1,481 |   |   |   | $ | 29.45 |   |   | 1,614,902 |   |   | $ | 29.37 |   |   |
|                        |            |                              |            |                              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Restricted Stock Units

The Company awardsRestricted 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. 

94

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

TheCompany recognizes compensation expense and a liability over the vesting periodbased on the average fair market value of Company common stock for the lastfive trading days of the period. On October 31, 2006, 43,979 of the Unitsvested, which resulted in payments of $2 million. As of December 31, 2006,there were 239,133 unvested Units. For the years ended December 31, 2006,and 2005, the Company recognized compensation expense related to the Units of$2.4 million and $0.4 million, respectively.

**(14)**   CommodityDerivatives and Hedging Activities 

During the year ended December 31, 2006, theCompany recognized $2.7 million of pre-tax gains in its oil and gas revenuesrelated to settled price hedge contracts, as well as a pre-tax gain of $3.4million due to ineffectiveness on unsettled hedge contracts During the yearended December 31, 2005, the Company recognized $11.3 million of pre-taxlosses in its oil and gas revenues from settled price hedge contracts, as wellas a pre-tax loss of $1.3 million due to ineffectiveness on unsettled hedgecontracts. During the year ended December 31, 2004, the Company did not recognize any gainsor losses from its hedging activities related to 2004 production, but didrecognize a pre-tax gain of $0.7 million due to ineffectiveness. Net unrealized gains on derivativeinstruments of $6.6 million, net of deferred taxes of $3.8 million, have beenreflected as a component of other comprehensive income for the year ended December 31,2006. Based on the fair market value of the hedge contracts as of December 31,2006, the Company would reclassify additional pre-tax gains of approximately$6.2 million (approximately $3.9 million after taxes) from accumulated othercomprehensive loss (shareholders’ equity) to net income during the next twelvemonths.

95

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

Theestimated fair value of the Company’s hedging transactions is based uponvarious factors that include closing exchange prices on the NYMEX, volatilityand the time value of options. Further details related to these hedgingactivities as of December 31, 2006 are as follows:

| ** **                              | ** ** | ** ** | ** ** | **NYMEX**    | ** ** | **Fair Value**   | ** ** |
|-----------------------------------------|------------|------------|------------|--------------|------------|-----------------------|------------|
| ** **                              | ** ** | ** ** | ** ** | **Contract** | ** ** | **of**                | ** ** |
| **Contract Period and**       | ** ** | ** ** | ** ** | **Price**    | ** ** | **Asset/(Liability)** | ** ** |
| **Type of Contract**          | ** ** | ** ** | ** ** | **Volume**   | ** ** | **Floor**             | ** ** | **Ceiling** | ** ** | **(in millions)** | ** ** |
| ***Natural  Gas Contracts (MMBtu)(a)*** | ** ** | ** ** | ** ** | ** **   | ** ** |                  |       |   |   |   |   |
| Collar Contracts:                       |       |       |       |         |       |                  |       |   |   |   |   |
| January 2007 - December 2007  |       | 5,475      | ** ** | $            | 6.00       |                  | $          | 12.00 |   |   | $ | 1.6 |   |   |
| January 2007 - December 2007  |       | 1,825      | ** ** | $            | 6.00       |                  | $          | 12.15 |   |   | $ | 0.5 |   |   |
| January 2007 - December 2007  |       | 9,125      |       | $            | 6.00       |                  | $          | 12.50 |   |   | $ | 2.9 |   |   |
| January 2007 - December 2007  |       | 913        |       | $            | 8.00       |                  | $          | 13.40 |   |   | $ | 1.4 |   |   |
| January 2007 - December 2007  |       | 2,738      |       | $            | 8.00       |                  | $          | 13.50 |   |   | $ | 4.2 |   |   |
| January 2007 - December 2007  |       | 913        |       | $            | 8.00       |                  | $          | 13.52 |   |   | $ | 1.4 |   |   |
| January 2007 - December 2007  |       | 913        |       | $            | 8.00       |                  | $          | 13.65 |   |   | $ | 1.4 |   |   |
| January 2008 - December 2008  |       | 1,830      |       | $            | 8.00       |                  | $          | 12.05 |   |   | $ | 1.5 |   |   |
| January 2008 - December 2008  |       | 2,745      |       | $            | 8.00       |                  | $          | 12.10 |   |   | $ | 2.3 |   |   |
| January 2008 - December 2008  |       | 915        |       | $            | 8.00       |                  | $          | 12.25 |   |   | $ | 0.8 |   |   |
| ***Crude  Oil Contracts (Barrels)***    | ** ** | ** ** | ** ** | ** **   | ** ** |                  |       |   |   |   |   |
| Collar Contracts:                       |       |       |       |         |       |                  |       |   |   |   |   |
| January 2007 - December 2007  |       | 1,460,000  |       | $            | 50.00      |                  | $          | 75.00 |   |   | $ | (2.2 | ) |   |
| January 2007 - December 2007  |       | 365,000    |       | $            | 50.00      |                  | $          | 75.25 |   |   | $ | (0.6 | ) |   |
| January 2007 - December 2007  |       | 3,650,000  |       | $            | 50.00      |                  | $          | 77.50 |   |   | $ | (3.9 | ) |   |
| January 2007 - December 2007  |       | 182,500    |       | $            | 60.00      |                  | $          | 82.75 |   |   | $ | 0.3 |   |   |
| January 2007 - December 2007  |       | 547,500    |       | $            | 60.00      |                  | $          | 83.00 |   |   | $ | 0.9 |   |   |
| January 2007 - December 2007  |       | 182,500    |       | $            | 60.00      |                  | $          | 84.00 |   |   | $ | 0.3 |   |   |
| January 2008 - December 2008  |       | 183,000    |       | $            | 60.00      |                  | $          | 80.00 |   |   | $ | 0.1 |   |   |
| January 2008 - December 2008  |       | 183,000    |       | $            | 60.00      |                  | $          | 80.05 |   |   | $ | 0.1 |   |   |
| January 2008 - December 2008  |       | 183,000    |       | $            | 60.00      |                  | $          | 80.10 |   |   | $ | 0.1 |   |   |
| January 2008  - December 2008 |       | 366,000    |       | $            | 60.00      |                  | $          | 80.25 |   |   | $ | 0.2 |   |   |
|                                         |            |            |            |              |            |                       |            |  |  |  |  |  |  |  |  |  |

----

(a)           MMBtu means millionBritish Thermal Units.

96

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

Althoughall of the Company’s collars are effective as economic hedges, the sale of 50%of the Company’s Gulf of Mexico interests on May 31, 2006 and the shut-inforecasted 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. The Company now recognizesall future changes in the fair value of these collar contracts in theconsolidated statement of income for the period in which the change occursunder the caption “Commodity derivative income (expense).’’  The Company recognized realized andunrealized gains (losses) related to these contracts of $7.3 million and($13.6) million for the periods ended December 31, 2006, and 2005,respectively. As of December 31, 2006, the Company had the followingcollar contracts that no longer qualify for hedge accounting:

| ** **                              | ** ** | ** ** | ** ** | **NYMEX  Contract** | ** ** | **Fair Value  of** | ** ** |
|-----------------------------------------|------------|------------|------------|---------------------|------------|-------------------------|------------|
| **Contract Period and**       | ** ** | ** ** | ** ** | **Price**           | ** ** | **Asset/(Liability)**   | ** ** |
| **Type of Contract**          | ** ** | ** ** | ** ** | **Volume**          | ** ** | **Floor**               | ** ** | **Ceiling** | ** ** | **(in millions)** | ** ** |
| ***Natural  Gas Contracts (MMBtu)***    | ** ** |       | ** ** | ** **          |       |                    | ** ** |   |   |   |   |   |   |
| Collar Contracts:                       |       |       |       | ** **          |       |                    |       |   |   |   |   |   |   |   |   |
| January 2007 - December 2007  |       |       | 7,300      | ** **          |       |                    | $          | 6.00 |   |   | $ | 12.15 |   |   | $ | 2.2 |   |   |
| January 2007  - December 2007 |       |       | 3,650      | ** **          |       |                    | $          | 6.00 |   |   | $ | 12.20 |   |   | $ | 1.1 |   |   |
|                                         |            |            |            |                     |            |                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**(15)**   Divestitures

On May 31, 2006, theCompany sold an undivided 50 percent interest in each and all of its Gulf ofMexico oil and gas leasehold interests and related pipelines and equipment toan affiliate of Mitsui & Co., Ltd., for approximately $448.8 million,after purchase price adjustments. The sale resulted in a pre-tax gain of $302.7million. This gain, along with $2 million of pre-tax gains on sales of otherproperties, has been reflected in the caption “Gain (loss) on sale ofproperties” in the Company’s results of operations.

**(16)**   AssetRetirement Obligations

The Company accounts for future abandonment costspursuant to SFAS 143, which requires that the fair value of a liability for anasset retirement obligation be recorded in the period in which it is incurredand the corresponding cost capitalized by increasing the carrying amount of therelated long-lived asset. The liability is accreted to its present value eachperiod, and the capitalized cost is depreciated over the useful life of therelated asset. If the liability is settled for an amount other than therecorded amount, a gain or loss is recognized.

97

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

Activityrelated to the Company’s ARO during the years ended December 31, 2006 and2005 is as follows (in thousands):

| ** **                                            | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                            | ** ** | **2006**                                   | ** ** | **2005** | ** ** |
| Initial ARO as of  January 1,                    |       |                                       | $          | 156.4 |   |   | $ | 74.0 |   |
| Liabilities incurred  during period                   |       |                                       | 3.6        | (a) |   | 41.9 | (a) |
| Liabilities settled  during period                    |       |                                       | (37.1      | )(b) |   | (7.1 | ) |
| Revisions to previous  estimate                       |       |                                       | 33.5       | (c) |   | 39.7 | (c) |
| Accretion expense                                     |       |                                       | 10.5       |   |   | 7.9 |   |
| Balance of ARO as of  December 31,               |       |                                       | $          | 166.9 |   |   | $ | 156.4 |   |
| Less: Current portion of  ARO as of December 31, |       |                                       | (10.6      | ) |   | (7.0 | ) |
| Long term portion of ARO as of December 31,      |       |                                       | $          | 156.3 |   |   | $ | 149.4 |   |

----

(a)           $1.9 million and $39.1million of this amount relates to acquistions during 2006 and 2005,respectively.

(b)          $31.8 million of thisamount relates to the sale of 50% of the Company’s interest in its Gulf ofMexico properties

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

For the years ended December 31,2006, 2005 and 2004, the Company recognized depreciation expense related to itsARC of $9.9 million, $4.5 million and $1.0 million, respectively.

**(17)**   ComprehensiveIncome

As of the indicateddates, the Company’s comprehensive income consisted of the following (in millions):

| ** **                                                                                                                                                                | ** ** | **Twelve Months Ended  December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                                                                                                                                | ** ** | **2006**                                             | ** ** | **2005** | ** ** | **2004** | ** ** |
| Net income                                                                                                                                                                |       | $                                                    | 446.2      |   | $ | 750.7 |   | $ | 261.7 |   |
| Foreign currency  translation adjustment, net of tax of ($3.2) million and $10.2 million,  respectively                                                              |       | (11.4                                                | )          | 22.9 |   | — |   |
| Change in fair value of  price hedge contracts, net of tax of $39.1 million, ($41.5) million, and  $1.6 million, respectively                                        |       | 68.1                                                 |       | (72.2 | ) | 3.0 |   |
| Reclassification  adjustment for hedge contract (gains) losses included in net income, net of  tax of ($4.9) million, $9.6 million, and ($0.2) million, respectively |       | (8.5                                                 | )          | 16.7 |   | (0.4 | ) |
| Comprehensive income                                                                                                                                                      |       | $                                                    | 494.4      |   | $ | 718.1 |   | $ | 264.3 |   |

 

**(18)**   FairValue of Financial Instruments

The following methods and assumptions were used toestimate the fair value of each class of financial instruments for which it ispracticable to estimate that value.

*Cash and Cash Equivalents*

Fair value is carryingvalue.

98

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

*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, 2006 and 2005 based on the market value  interest rates.           |
| LIBOR rate advances                 |       | Fair value is carrying  value as of December 31, 2006 and 2005 based on the market value  interest rates.           |
| 2011 Notes                          |       | Fair value is 102.5% and  104.1% of carrying value as of December 31, 2006 and 2005, based on  quoted market value. |
| 2013 Notes                          |       | Fair value is 101.5% of  carrying value as of December 31, 2006, based on quoted market value.                      |
| 2015 Notes                          |       | Fair value is 96.5% and  98.0% of carrying value as of December 31, 2006 and 2005, based on  quoted market value.   |
| 2017 Notes                          |       | Fair value is 96.0% and  97.1% of carrying value as of December 31, 2006 and 2005, based on  quoted market value.   |

 

Thecarrying value and estimated fair value of the Company’s financial instrumentsat December 31, 2006 and 2005 (in millions of dollars) are as follows:

| ** **                             | ** ** | **2006**     | ** ** | **2005**  | ** ** |
|----------------------------------------|------------|--------------|------------|-----------|------------|
| ** **                             | ** ** | **Carrying** | ** ** | **Fair**  | ** ** | **Carrying** | ** ** | **Fair** | ** ** |
| ** **                             | ** ** | **Value**    | ** ** | **Value** | ** ** | **Value** | ** ** | **Value** | ** ** |
| Cash and cash  equivalents             |       | $            | 22.7       |      | $          | 22.7 |   | $ | 57.7 |   | $ | 57.7 |   |
| Receivables                            |       | $            | 223.4      |      | $          | 223.4 |   | $ | 218.7 |   | $ | 218.7 |   |
| Payables                               |       | $            | (340.3     | )         | $          | (340.3 | ) | $ | (304.5 | ) | $ | (304.5 | ) |
| Debt:                                  |       |         |       |      |       |   |   |   |   |
| Bank revolving credit  agreement loans |       | $            | (797.0     | )         | $          | (797.0 | ) | $ | (606.0 | ) | $ | (606.0 | ) |
| LIBOR Rate Advances                    |       | $            | (75.0      | )         | $          | (75.0 | ) | $ | (40.0 | ) | $ | (40.0 | ) |
| 2011 Notes                             |       | $            | (200.0     | )         | $          | (205.0 | ) | $ | (200.0 | ) | $ | (208.3 | ) |
| 2013 Notes                             |       | $            | (450.0     | )         | $          | (456.8 | ) | $ | — |   | $ | — |   |
| 2015 Notes                             |       | $            | (297.7     | )         | $          | (287.3 | ) | $ | (297.5 | ) | $ | (291.4 | ) |
| 2017 Notes                             |       | $            | (500.0     | )         | $          | (480.0 | ) | $ | (500.0 | ) | $ | (485.6 | ) |

 

The Company occasionally enters into hedging contractsto minimize the impact of oil and gas price fluctuations. See Note 14 for afurther discussion of these contracts.

 

99

----

**POGO PRODUCING COMPANY & SUBSIDIARIESUNAUDITED SUPPLEMENTARY FINANCIAL AND RESERVES DATA**

**Oil and Gas Producing Activities**

The results of operations from oil and gas producingactivities (expressed in millions) exclude non-oil and gas revenues, corporategeneral and administrative expenses, other non oil and gas producing expenses,interest charges, interest income and interest capitalized. Income tax(expense) or benefit was determined by applying the statutory rates to pre-taxoperating results with adjustments for permanent differences. Except asindicated, the “Total” amounts reflect only those activities related to theCompany’s continuing operations.

| ** **                                        | ** ** | **2006**          | ** ** |
|---------------------------------------------------|------------|-------------------|------------|
| ** **                                        | ** ** | **Other**         | ** ** | ** ** | ** ** | **United** | ** ** | ** ** | ** ** |
| ** **                                        | ** ** | **International** | ** ** | **Canada** | ** ** | **States** | ** ** | **Total** | ** ** |
| Revenues                                          |       |              | $          | — |   |   | $ | 450.7 |   | $ | 924.7 |   | $ | 1,375.4 |   |
| Lease operating  expense                          |       |              | —     |   |   | (81.4 | ) | (183.4 | ) | (264.8 | ) |
| Exploration expense                               |       |              | (3.8       | ) |   | (15.9 | ) | (12.1 | ) | (31.8 | ) |
| Dry hole and  impairment expense                  |       |              | —     |   |   | (25.7 | ) | (80.9 | ) | (106.6 | ) |
| Depreciation,  depletion and amortization expense |       |              | —     |   |   | (197.6 | ) | (278.8 | ) | (476.4 | ) |
| Production and  other taxes                       |       |              | —     |   |   | (10.8 | ) | (67.6 | ) | (78.4 | ) |
| Transportation  and accretion                     |       |              | (0.6       | ) |   | (9.7 | ) | (29.9 | ) | (40.2 | ) |
| Pretax operating  results                         |       |              | (4.4       | ) |   | 109.6 |   | 272.0 |   | 377.2 |   |
| Income tax  (expense) benefit                     |       |              | 2.5        |   |   | 100.1 |   | (111.9 | ) | (9.3 | ) |
| Operating results from  continuing operations     |       |              | $          | (1.9 | ) |   | $ | 209.7 |   | $ | 160.1 |   | $ | 367.9 |   |

 

| ** **                                        | ** ** | **2005**          | ** ** |
|---------------------------------------------------|------------|-------------------|------------|
| ** **                                        | ** ** | **Other**         | ** ** | ** ** | ** ** | **United** | ** ** | ** ** | ** ** |
| ** **                                        | ** ** | **International** | ** ** | **Canada** | ** ** | **States** | ** ** | **Total** | ** ** |
| Revenues                                          |       |              | $          | — |   |   | $ | 134.1 |   | $ | 1,082.1 |   | $ | 1,216.2 |   |
| Lease operating  expense                          |       |              | —     |   |   | (17.7 | ) | (136.0 | ) | (153.7 | ) |
| Exploration  expense                              |       |              | (9.0       | )(a) |   | (3.4 | ) | (14.1 | ) | (26.5 | ) |
| Dry hole and  impairment expense                  |       |              | —     |   |   | (5.0 | ) | (82.2 | ) | (87.2 | ) |
| Depreciation,  depletion and amortization expense |       |              | —     |   |   | (50.5 | ) | (256.6 | ) | (307.1 | ) |
| Production and  other taxes                       |       |              | —     |   |   | (2.7 | ) | (56.8 | ) | (59.5 | ) |
| Transportation  and accretion                     |       |              | —     |   |   | (2.2 | ) | (25.0 | ) | (27.2 | ) |
| Pretax operating  results                         |       |              | (9.0       | ) |   | 52.6 |   | 511.4 |   | 555.0 |   |
| Income tax  (expense) benefit                     |       |              | —     |   |   | (18.1 | ) | (182.4 | ) | (200.5 | ) |
| Operating results from  continuing operations(b)  |       |              | $          | (9.0 | ) |   | $ | 34.5 |   | $ | 329.0 |   | $ | 354.5 |   |

 

100

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

 

| ** **                                        | ** ** | **2004**          | ** ** |
|---------------------------------------------------|------------|-------------------|------------|
| ** **                                        | ** ** | **Other**         | ** ** | **United** | ** ** | ** ** | ** ** |
| ** **                                        | ** ** | **International** | ** ** | **States** | ** ** | **Total** | ** ** |
| Revenues                                          |       |              | $          | — |   |   | $ | 973.1 |   | $ | 973.1 |   |
| Lease operating  expense                          |       |              | —     |   |   | (100.5 | ) | (100.5 | ) |
| Exploration  expense                              |       |              | —     |   |   | (21.7 | ) | (21.7 | ) |
| Dry hole and  impairment expense                  |       |              | (5.5       | )(c) |   | (56.1 | ) | (61.6 | ) |
| Depreciation,  depletion and amortization expense |       |              | —     |   |   | (248.5 | ) | (248.5 | ) |
| Production and  other taxes                       |       |              | —     |   |   | (44.1 | ) | (44.1 | ) |
| Transportation  and accretion                     |       |              | —     |   |   | (19.5 | ) | (19.5 | ) |
| Pretax operating  results                         |       |              | (5.5       | ) |   | 482.7 |   | 477.2 |   |
| Income tax  (expense) benefit                     |       |              | —     |   |   | (175.6 | ) | (175.6 | ) |
| Operating results from  continuing operations(b)  |       |              | $          | (5.5 | ) |   | $ | 307.1 |   | $ | 301.6 |   |

 

----

(a)           Relatedto New Zealand.

(b)          Excludesoperating results from discontinued operations of $52.9 million in 2005 and$28.8 million in 2004.

(c)           Relatedto the Danish North Sea.

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

| ** **                                                | ** ** | **2006**          | ** ** |
|-----------------------------------------------------------|------------|-------------------|------------|
|                                                           | ** ** | **Other**         | ** ** | ** ** | ** ** | **United** | ** ** | ** ** | ** ** |
| ** **                                                | ** ** | **International** | ** ** | **Canada** | ** ** | **States** | ** ** | **Total** | ** ** |
| Costs incurred  (capitalized unless otherwise indicated): |       |              |       |   |   |   |   |   |   |   |   |
| Property acquisition                                      |       |              |       |   |   |   |   |   |   |   |   |
| Proved                                                    |       |              | $          | — |   |   | $ | 21.4 |   | $ | 1,046.2 |   | $ | 1,067.6 |   |
| Unproved                                                  |       |              | —     |   |   | 15.4 |   | 67.1 |   | 82.5 |   |
| Exploration                                               |       |              |       |   |   |   |   |   |   |   |   |
| Capitalized                                               |       |              | 0.1        |   |   | 75.1 |   | 155.2 |   | 230.4 |   |
| Expensed                                                  |       |              | 3.8        |   |   | 15.9 |   | 12.1 |   | 31.8 |   |
| Development                                               |       |              | —     |   |   | 230.9 |   | 406.3 |   | 637.2 |   |
| Asset retirement cost                                     |       |              | —     |   |   | (2.4 | ) | 39.9 |   | 37.5 |   |
| Total oil and gas  costs incurred                         |       |              | $          | 3.9 |   |   | $ | 356.3 |   | $ | 1,726.8 |   | $ | 2,087.0 |   |

 
|                                  | ** ** | **2005**          | ** ** |
|----------------------------------|------------|-------------------|------------|
| ** **                       | ** ** | **Other**         | ** ** | ** ** | ** ** | **United** | ** ** | ** ** | ** ** | **Discontinued** | ** ** |
| ** **                       | ** ** | **International** | ** ** | **Canada** | ** ** | **States** | ** ** | **Total** | ** ** | **Operations** | ** ** |
| Property acquisition             |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved                           |       |              | $          | — |   |   | $ | 1,786.9 |   | $ | 46.0 |   | $ | 1,832.9 |   |   | $ | — |   |   |
| Unproved                         |       |              | —     |   |   | 830.0 |   | 50.8 |   | 880.8 |   |   | — |   |   |
| Exploration                      |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Capitalized                      |       |              | —     |   |   | 9.1 |   | 130.1 |   | 139.2 |   |   | 1.3 |   |   |
| Expensed                         |       |              | 9.1        |   |   | 3.4 |   | 14.0 |   | 26.5 |   |   | — |   |   |
| Development                      |       |              | 0.1        |   |   | 55.8 |   | 164.2 |   | 220.1 |   |   | 69.6 |   |   |
| Asset retirement cost            |       |              | —     |   |   | 49.9 |   | 3.3 |   | 53.2 |   |   | — |   |   |
| Total oil and gas costs incurred |       |              | $          | 9.2 |   |   | $ | 2,735.1 |   | $ | 408.4 |   | $ | 3,152.7 |   |   | $ | 70.9 |   |   |

 

101

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

 
|                                  | ** ** | **2004**          | ** ** |
|----------------------------------|------------|-------------------|------------|
| ** **                       | ** ** | **Other**         | ** ** | ** ** | ** ** | **United** | ** ** | ** ** | ** ** | **Discontinued** | ** ** |
| ** **                       | ** ** | **International** | ** ** | **Canada** | ** ** | **States** | ** ** | **Total** | ** ** | **Operations** | ** ** |
| Property acquisition             |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Proved                           |       |              | $          | — |   |   |   | $ | — |   |   | $ | 613.0 |   | $ | 613.0 |   |   | $ | — |   |   |
| Unproved                         |       |              | —     |   |   |   | — |   |   | 26.9 |   | 26.9 |   |   | — |   |   |
| Exploration                      |       |              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Capitalized                      |       |              | 5.6        |   |   |   | — |   |   | 57.0 |   | 62.6 |   |   | 35.1 |   |   |
| Expensed                         |       |              | —     |   |   |   | — |   |   | 21.7 |   | 21.7 |   |   | 1.5 |   |   |
| Development                      |       |              | —     |   |   |   | — |   |   | 228.5 |   | 228.5 |   |   | 114.2 |   |   |
| Asset retirement cost            |       |              | —     |   |   |   | — |   |   | 14.3 |   | 14.3 |   |   | 4.0 |   |   |
| Total oil and gas costs incurred |       |              | $          | 5.6 |   |   |   | $ | — |   |   | $ | 961.4 |   | $ | 967.0 |   |   | $ | 154.8 |   |   |

 

102

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

The followinginformation regarding estimates of the Company’s proved oil and gas reserves,which are located onshore in the United States and Canada and offshore inUnited States waters of the Gulf of Mexico for continuing operations and werelocated offshore in the Kingdom of Thailand and in Hungary for discontinuedoperations, is based on reports prepared by Ryder Scott Company, L.P. (“RyderScott”) and reports prepared by the Company and reviewed by Ryder Scott, forcertain of its domestic properties acquired from Latigo, Ryder ScottCompany—Canada (“Ryder Scott Canada”), for all of its Canadian properties, andMiller and Lents, Ltd. (“Miller and Lents”), for certain onshore Gulf Coast andRocky Mountain properties. The definitions and assumptions that serve as thebasis for the discussions under the caption “Item 1, Business—Exploration andProduction Data—Reserves” should be referred to in connection with thefollowing information.  Only reservesdata related to the Company’s continuing operations is presented under theTotal amounts.

**Estimates of ProvedReserves**

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

| ** **                                   | ** ** | ** ** | ** ** | **United**  | ** ** | ** **  | ** ** | ** ** | ** ** | **Discontinued** | ** ** |
|----------------------------------------------|------------|------------|------------|-------------|------------|-------------|------------|------------|------------|------------------|------------|
| ** **                                   | ** ** | **Canada** | ** ** | **States**  | ** ** | **Total**   | ** ** | ** ** | ** ** | **Operations**   | ** ** |
| 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 |       |       |       | —           |       |
| Revisions of previous estimates              |       | 1,102,519  |       | 8,508,423   |       | 9,610,942   |       |       |       | —           |       |
| Extensions, discoveries and other additions  |       | 6,896,000  |       | 8,503,900   |       | 15,399,900  |       |       |       | —           |       |
| Purchase of properties                       |       | 186,000    |       | 23,421,000  |       | 23,607,000  |       |       |       | —           |       |
| Sale of properties                           |       | —     |       | (15,846,500 | )          | (15,846,500 | )          |       |       | —           |       |
| Estimated 2006 production                    |       | (5,370,507 | )          | (8,106,770  | )          | (13,477,277 | )          |       |       | —           |       |
| Proved Reserves as of December 31, 2006 |       | 64,617,000 |       | 98,717,930  |       | 163,334,930 |       |       |       | —           |       |
| Proved Developed  Reserves as of:            |       |       |       |        |       |        |       |       |       |             |       |
| 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 |       |       |       | —           |       |
| December 31,  2006                      |       | 55,917,925 |       | 67,685,050  |       | 123,602,975 |       |       |       | —           |       |

** **

103

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

**Estimatesof Proved Reserves**

**NaturalGas (MMcf)**

| ** **                                    | ** ** | ** ** | ** ** | **United** | ** ** | ** ** | ** ** | ** ** | ** ** | **Discontinued** | ** ** |
|-----------------------------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------------|------------|
| ** **                                    | ** ** | **Canada** | ** ** | **States** | ** ** | **Total**  | ** ** | ** ** | ** ** | **Operations**   | ** ** |
| 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  |       |       |       |             | —     |   |   |
| Revisions of previous estimates               |       | (15,028    | )          | (63,162    | )          | (78,190    | )          |       |       |             | —     |   |   |
| Extensions, discoveries and other additions   |       | 69,410     |       | 73,885     |       | 143,295    |       |       |       |             | —     |   |   |
| Purchase of properties                        |       | 5,990      |       | 134,477    |       | 140,467    |       |       |       |             | —     |   |   |
| Sale of properties                            |       | —     |       | (48,288    | )          | (48,288    | )          |       |       |             | —     |   |   |
| Estimated 2006 production                     |       | (28,486    | )          | (73,553    | )          | (102,039   | )          |       |       |             | —     |   |   |
| Proved Reserves  as of December 31, 2006 |       | 318,313    |       | 914,657    |       | 1,232,970  |       |       |       |             | —     |   |   |
| Proved Developed  Reserves as of:             |       |       |       |       |       |       |       |       |       |             |       |   |   |
| 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    |       |       |       |             | —     |   |   |
| December 31,  2006                       |       | 236,791    |       | 701,550    |       | 938,341    |       |       |       |             | —     |   |   |

 

104

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**POGO PRODUCING COMPANY & SUBSIDIARIES**

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

The standardizedmeasure of discounted future net cash flows from the production of provedreserves (expressed in millions) is developed as follows: 

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

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

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

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

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

| ** **                                                                                            | ** ** | **Year Ended December 31, 2006** | ** ** | ** ** |
|-------------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|------------|
| ** **                                                                                            | ** ** | ** **                                           | ** ** | **United** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                                            | ** ** | **Canada**                                           | ** ** | **States** | ** ** | **Total** | ** ** | ** ** |
| Future gross  revenues                                                                                |       | $                                                    | 4,275.5    |       | $ | 10,063.5 |   | $ | 14,339.0 |   |   |
| Future production  costs                                                                              |       | (1,315.4                                             | )          | (2,878.5   | ) | (4,193.9 | ) |   |
| Future  development and abandonment costs                                                             |       | (251.4                                               | )          | (1,324.5   | ) | (1,575.9 | ) |   |
| Future net cash  flows before income taxes                                                            |       | 2,708.7                                              |       | 5,860.5    |   | 8,569.2 |   |   |
| Discount at 10%  per annum                                                                            |       | (1,209.8                                             | )          | (2,881.3   | ) | (4,091.1 | ) |   |
| Discounted future  net cash flows before income taxes                                                 |       | 1,498.9                                              |       | 2,979.2    |   | 4,478.1 |   |   |
| Future income  taxes, net of discount at 10% per annum                                           |       | (343.3                                               | )          | (781.9     | ) | (1,125.2 | ) |   |
| Standardized measure of  discounted future net cash flows related to proved oil and gas reserves |       | $                                                    | 1,155.6    |       | $ | 2,197.3 |   | $ | 3,352.9 |   |   |

 

| ** **                                                                                       | ** ** | **Year Ended December 31, 2005** | ** ** | ** ** |
|--------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|------------|
| ** **                                                                                       | ** ** | ** **                                           | ** ** | **United** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                                       | ** ** | **Canada**                                           | ** ** | **States** | ** ** | **Total** | ** ** | ** ** |
| Future gross  revenues                                                                           |       | $                                                    | 4,834.5    |       | $ | 11,670.4 |   | $ | 16,504.9 |   |   |
| Future production  costs                                                                         |       | (1,169.8                                             | )          | (2,585.1   | ) | (3,754.9 | ) |   |
| Future  development and abandonment costs                                                        |       | (204.5                                               | )          | (709.6     | ) | (914.1 | ) |   |
| Future net cash  flows before income taxes                                                       |       | 3,460.2                                              |       | 8,375.7    |   | 11,835.9 |   |   |
| Discount at 10%  per annum                                                                       |       | (1,506.1                                             | )          | (3,709.2   | ) | (5,215.3 | ) |   |
| Discounted future  net cash flows before income taxes                                            |       | 1,954.1                                              |       | 4,666.5    |   | 6,620.6 |   |   |
| Future income  taxes, net of discount at 10% per annum                                           |       | (612.7                                               | )          | (1,445.1   | ) | (2,057.8 | ) |   |
| Standardized measure of  discounted future net cash flows related to proved oil and gas reserves |       | $                                                    | 1,341.4    |       | $ | 3,221.4 |   | $ | 4,562.8 |   |   |

 

 

105

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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, 2004** | ** ** |       |
|--------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|------------|
| ** **                                                                                       | ** ** | **United**                                           | ** ** | ** ** | ** ** | **Discontinued** | ** ** |   |
| ** **                                                                                       | ** ** | **States**                                           | ** ** | **Total**  | ** ** | **Operations** | ** ** |   |
| Future gross  revenues                                                                           |       | $                                                    | 8,850.2    |       | $ | 8,850.2 |   |   | $ | 1,724.3 |   |   |
| Future production  costs                                                                         |       | (2,123.5                                             | )          | (2,123.5   | ) |   | (406.0 | ) |   |
| Future  development and abandonment costs                                                        |       | (437.1                                               | )          | (437.1     | ) |   | (143.6 | ) |   |
| Future net cash  flows before income taxes                                                       |       | 6,289.6                                              |       | 6,289.6    |   |   | 1,174.7 |   |   |
| Discount at 10%  per annum                                                                       |       | (2,650.3                                             | )          | (2,650.3   | ) |   | (242.0 | ) |   |
| Discounted future  net cash flows before income taxes                                            |       | 3,639.3                                              |       | 3,639.3    |   |   | 932.7 |   |   |
| Future income  taxes, net of discount at 10% per annum                                           |       | (1,080.6                                             | )          | (1,080.6   | ) |   | (395.8 | ) |   |
| Standardized measure of  discounted future net cash flows related to proved oil and gas reserves |       | $                                                    | 2,558.7    |       | $ | 2,558.7 |   |   | $ | 536.9 |   |   |

 

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

| ** **                                                                            | ** ** | **For the Year Ended December 31, 2006** | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|------------|------------|
| ** **                                                                            | ** ** | ** **                                                             | ** ** | **United** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                            | ** ** | **Canada**                                                             | ** ** | **States** | ** ** | **Total** | ** ** | ** ** | ** ** |
| Beginning balance                                                                     |       | $                                                                      | 1,341.4    |       | $          | 3,221.4 |   | $ | 4,562.8 |   |   |   |
| Revisions to prior  years’ proved reserves:                                      |       |                                                                   |       |       |       |   |   |   |   |
| Net changes in prices  and production costs                                           |       | (433.8                                                                 | )          | (1,350.5   | )          | (1,784.3 | ) |   |   |
| Net changes due to  revisions in quantity estimates                                   |       | (20.3                                                                  | )          | (30.5      | )          | (50.8 | ) |   |   |
| Net changes in estimates  of future development  costs                                |       | (87.0                                                                  | )          | (570.0     | )          | (657.0 | ) |   |   |
| Accretion of discount                                                                 |       | 195.4                                                                  |       | 466.6      |       | 662.0 |   |   |   |
| Changes in production  rate and other                                                 |       | (117.4                                                                 | )          | 216.4      |       | 99.0 |   |   |   |
| Total revisions                                                                       |       | (463.1                                                                 | )          | (1,268.0   | )          | (1,731.1 | ) |   |   |
| New field discoveries  and extensions, net of future production and development costs |       | 224.4                                                                  |       | 233.2      |       | 457.6 |   |   |   |
| Purchases of properties                                                               |       | 15.8                                                                   |       | 616.3      |       | 632.1 |   |   |   |
| Sales of properties                                                                   |       | —                                                                 |       | (940.6     | )          | (940.6 | ) |   |   |
| Sales of oil and gas  produced, net of production costs                               |       | (348.8                                                                 | )          | (652.3     | )          | (1,001.1 | ) |   |   |
| Previously estimated  development costs incurred                                      |       | 116.6                                                                  |       | 324.2      |       | 440.8 |   |   |   |
| Net change in income taxes                                                            |       | 269.3                                                                  |       | 663.1      |       | 932.4 |   |   |   |
| Net change in  standardized measure of discounted future net cash flows               |       | (185.8                                                                 | )          | (1,024.1   | )          | (1,209.9 | ) |   |   |
| Ending balance                                                                        |       | $                                                                      | 1,155.6    |       | $          | 2,197.3 |   | $ | 3,352.9 |   |   |   |

 

106

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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, 2005** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                                            | ** ** | ** **                                                             | ** ** | **United** | ** ** | ** ** | ** ** | **Discontinued** | ** ** |
| ** **                                                                            | ** ** | **Canada**                                                             | ** ** | **States** | ** ** | **Total** | ** ** | **Operations** | ** ** |
| Beginning balance                                                                     |       | $                                                                      | —     |   | $ | 2,558.7 |   | $ | 2,558.7 |   |   | $ | 536.8 |   |   |
| Revisions to prior  years’ proved reserves:                                      |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Net changes in prices and production costs                                            |       | —                                                                 |       | 1,528.3 |   | 1,528.3 |   |   | — |   |   |
| Net changes due to revisions in quantity estimates                                    |       | (7.6                                                                   | )          | 150.0 |   | 142.4 |   |   | — |   |   |
| Net changes in estimates of future development costs                                  |       | —                                                                 |       | (334.6 | ) | (334.6 | ) |   | — |   |   |
| Accretion of discount                                                                 |       | —                                                                 |       | 363.9 |   | 363.9 |   |   | 54.4 |   |   |
| Changes in production rate and other                                                  |       | 369.5                                                                  |       | (154.1 | ) | 215.4 |   |   | — |   |   |
| Total revisions                                                                       |       | 361.9                                                                  |       | 1,553.5 |   | 1,915.4 |   |   | 54.4 |   |   |
| New field  discoveries and extensions, net of future production and development costs |       | 193.9                                                                  |       | 145.5 |   | 339.4 |   |   | — |   |   |
| Purchases of  properties                                                              |       | 1,509.8                                                                |       | 32.2 |   | 1,542.0 |   |   | — |   |   |
| Sales of properties                                                                   |       | —                                                                 |       | — |   | — |   |   | (819.4 | ) |   |
| Sales of oil and  gas produced, net of production costs                               |       | (111.5                                                                 | )          | (864.5 | ) | (976.0 | ) |   | (197.2 | ) |   |
| Previously  estimated development costs incurred                                      |       | —                                                                 |       | 160.4 |   | 160.4 |   |   | 29.6 |   |   |
| Net change in  income taxes                                                           |       | (612.7                                                                 | )          | (364.4 | ) | (977.1 | ) |   | 395.8 |   |   |
| Net change in standardized measure of discounted  future net cash flows               |       | 1,341.4                                                                |       | 662.7 |   | 2,004.1 |   |   | (536.8 | ) |   |
| Ending balance                                                                        |       | $                                                                      | 1,341.4    |   | $ | 3,221.4 |   | $ | 4,562.8 |   |   | $ | — |   |   |

 

| ** **                                                                            | ** ** | **For the Year Ended December 31, 2004** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------|------------|
| ** **                                                                            | ** ** | **United**                                                             | ** ** | ** ** | ** ** | ** ** | ** ** | **Discontinued** | ** ** |
| ** **                                                                            | ** ** | **   States   **                         | ** ** | **   Total   ** | ** ** | ** ** | ** ** | **Operations** | ** ** |
| Beginning balance                                                                     |       | $                                                                      | 2,009.1    |   | $ | 2,009.1 |   |   |   |   | $ | 440.9 |   |   |
| Revisions to  prior years’ proved reserves:                                      |       |                                                                   |       |   |   |   |   |   |   |   |   |
| Net changes in prices and production costs                                            |       | 631.1                                                                  |       | 631.1 |   |   |   |   | 237.0 |   |   |
| Net changes due to revisions in quantity estimates                                    |       | 39.7                                                                   |       | 39.7 |   |   |   |   | (14.4 | ) |   |
| Net changes in estimates of future development  costs                                 |       | (154.7                                                                 | )          | (154.7 | ) |   |   |   | (7.0 | ) |   |
| Accretion of discount                                                                 |       | 292.9                                                                  |       | 292.9 |   |   |   |   | 76.1 |   |   |
| Changes in production rate and other                                                  |       | (51.2                                                                  | )          | (51.2 | ) |   |   |   | 7.8 |   |   |
| Total revisions                                                                       |       | 757.8                                                                  |       | 757.8 |   |   |   |   | 299.5 |   |   |
| New field  discoveries and extensions, net of future production and development costs |       | 126.2                                                                  |       | 126.2 |   |   |   |   | 86.8 |   |   |
| Purchases of  properties                                                              |       | 596.2                                                                  |       | 596.2 |   |   |   |   | — |   |   |
| Sales of  properties                                                                  |       | (58.6                                                                  | )          | (58.6 | ) |   |   |   | — |   |   |
| Sales of oil and  gas produced, net of production costs                               |       | (809.0                                                                 | )          | (809.0 | ) |   |   |   | (265.2 | ) |   |
| Previously  estimated development costs incurred                                      |       | 98.1                                                                   |       | 98.1 |   |   |   |   | 50.1 |   |   |
| Net change in  income taxes                                                           |       | (161.1                                                                 | )          | (161.1 | ) |   |   |   | (75.3 | ) |   |
| Net change in standardized measure of discounted future  net cash flows               |       | 549.6                                                                  |       | 549.6 |   |   |   |   | 95.9 |   |   |
| Ending balance                                                                        |       | $                                                                      | 2,558.7    |   | $ | 2,558.7 |   |   |   |   | $ | 536.8 |   |   |

 

107

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**Quarterly Results—Unaudited**

Summaries of the Company’s results of operations byquarter for the years 2006 and 2005 are as follows:

| ** **                                               | ** ** | **Quarter Ended**                                                              | ** ** |
|----------------------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|
| ** **                                               | ** ** | **  Mar. 31  **                                            | ** ** | **  June 30  ** | ** ** | **  Sept. 30  ** | ** ** | **  Dec. 31  ** | ** ** |
| ** **                                               | ** ** | **(Expressed in millions, except per share amounts)** | ** ** |
| **2006**                                                 |       |                                                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Revenues                                                 |       |                                                                                | $          | 373.5 |   |   |   | $ | 674.6 |  (d) |   |   | $ | 353.8 |   |   |   | $ | 343.1 |   |   |
| Gross profit(a)                                          |       |                                                                                | $          | 139.0 |   |   |   | $ | 438.5 |  (d) |   |   | $ | 88.5 |   |   |   | $ | 25.8 |   |   |
| Net income (loss)                                        |       |                                                                                | $          | 67.5 |   |   |   | $ | 361.9 |  (d) |   |   | $ | 33.3 |   |   |   | $ | (16.5 | ) |   |
| Earnings per share(b):                                   |       |                                                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Basic                                                    |       |                                                                                | $          | 1.18 |   |   |   | $ | 6.31 |   |   |   | $ | 0.58 |   |   |   | $ | (0.29 | ) |   |
| Diluted                                                  |       |                                                                                | $          | 1.16 |   |   |   | $ | 6.25 |   |   |   | $ | 0.58 |   |   |   | $ | (0.29 | ) |   |
| **2005**                                                 |       |                                                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Revenues                                                 |       |                                                                                | $          | 255.8 |   |   |   | $ | 274.5 |   |   |   | $ | 275.8 |   |   |   | $ | 419.6 |   |   |
| Gross profit(a)                                          |       |                                                                                | $          | 92.4 |   |   |   | $ | 144.7 |   |   |   | $ | 152.3 |   |   |   | $ | 206.3 |   |   |
| Income from  continuing operations                       |       |                                                                                | $          | 39.5 |   |   |   | $ | 74.0 |   |   |   | $ | 61.9 |   |   |   | $ | 114.8 |   |   |
| Income (loss)  from discontinued operations, net of  tax |       |                                                                                | $          | 19.7 |   |   |   | $ | 29.5 |   |   |   | $ | 411.6 |  (c) |   |   | $ | (0.2 | ) |   |
| Net income                                               |       |                                                                                | $          | 59.2 |   |   |   | $ | 103.5 |   |   |   | $ | 473.5 |   |   |   | $ | 114.5 |   |   |
| 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                        |       |                                                                                | $          | 0.62 |   |   |   | $ | 1.22 |   |   |   | $ | 1.03 |   |   |   | $ | 1.96 |   |   |
| Income (loss) from discontinued operations               |       |                                                                                | $          | 0.31 |   |   |   | $ | 0.48 |   |   |   | $ | 6.86 |   |   |   | $ | — |   |   |
| Diluted earnings  per share                              |       |                                                                                | $          | 0.93 |   |   |   | $ | 1.70 |   |   |   | $ | 7.89 |   |   |   | $ | 1.96 |   |   |

----

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

(b)          The sum of theindividual quarterly earnings (loss) per share may not agree with year-to-dateearnings (loss) per share as each quarterly computation is based on the incomeor loss for that quarter and the weighted average number of common sharesoutstanding during that period.

(c)           Includes approximately$403 million of after-tax gain on the sale of the Company’s Thailandoperations.

(d)          Includesa pretax gain of $302.7 million from the sale of an undivided 50% of theCompany’s Gulf of Mexico oil and gas leasehold interests and related pipelinesand equipment to an affiliate of Mitsui & Co., Ltd.

108

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**ITEM 9.**      *Changes in and Disagreements with Accountants on Accounting andFinancial Disclosure.*

None.

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

**Evaluation ofDisclosure Controls and Procedures**

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

**Management’s Reporton Internal Control Over Financial Reporting**

The Company’s management is responsible forestablishing and maintaining adequate internal control over financialreporting, as such term is defined in Exchange Act Rules 13a-15(f).Under the supervision and with the participation of the Company’s management,including the Chairman, President and Chief Executive Officer and its SeniorVice President and Chief Financial Officer, the Company conducted an evaluationof the effectiveness of its internal control over financial reporting based onthe framework in *Internal Control—IntegratedFramework*issued by the Committee of Sponsoring Organizations of theTreadway Commission. Based on the Company’s evaluation under the framework in *Internal Control—Integrated Framework,*theCompany’s management concluded that its internal control over financialreporting was effective as of December 31, 2006. The Company excludedLatigo Petroleum, Inc. from its assessment of internal control overfinancial reporting as of December 31, 2006 because Latigo was acquired onMay 2, 2006. Latigo is a wholly-owned subsidiary of the Company whosetotal assets and total revenues represent 16% and 5%, respectively, of therelated consolidated financial statement amounts, as of and for the year endedDecember 31, 2006.

The Company’s management’sassessment of the effectiveness of its internal control over financialreporting as of December 31, 2006 has been audited byPricewaterhouseCoopers LLP, an independent registered public accounting firm,as stated in their report which is included herein.

**Changes in InternalControls**

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

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

None.

109

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**PART III**

**ITEM 10.**         *Directors,Executive Officers and Corporate Governance.*

The information responsive to Items 401, 405, 406 and407(c)(3), (d)(4) and (d)(5) of Regulation S-K in the Company’sdefinitive Proxy Statement for its annual meeting to be held on May 15,2007, to be filed within 120 days of December 31, 2006 pursuant toRegulation 14A under the Securities Exchange Act of 1934, as amended (theCompany’s “2007 Proxy Statement”), is incorporated herein by reference. Seealso Item S-K 401(b) appearing in Part I of this Form 10-K.

On May 25, 2006, the chief executive officer ofthe Company filed with the New York Stock Exchange (“NYSE”) the annualcertification required by Section 303A.12(a) of the NYSE Listed Company Manualindicating that he was not aware of any violation by the Company of NYSEcorporate governance listing standards. The Company has also filed as exhibitsto this Form 10-K the certifications required by Section 302 of theSarbanes-Oxley Act.

**ITEM11.**         *Executive Compensation*.

The information responsive to Items 402 and 407(e)(4) and(e)(5) of Regulation S-K in the Company’s 2007 Proxy Statement isincorporated herein by reference. The portion of the incorporated materialconsisting of the Report of the Compensation Committee on ExecutiveCompensation is not considered “filed” with the Commission.

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

The information responsiveto Items 201(d) and 403 of Regulation S-K in the Company’s 2007 ProxyStatement is incorporated herein by reference.

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

The information responsiveto Items 404 and 407(a) of Regulation S-K in the Company’s 2007 ProxyStatement is incorporated herein by reference.

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

The information responsive to Item 9(e) ofSchedule 14A in the Company’s 2007 Proxy Statement is incorporated herein byreference.

110

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**PART IV**

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

(a)    Documents Filed as Part of this Form 10-K.

|        | ** ** | ** **                                                                                             | ** ** | **Page**   |
|--------|------------|--------------------------------------------------------------------------------------------------------|------------|------------|
|   | **1.**     | **Financial Statements and  Supplementary Data:**                                                      | ** ** | ** ** |
|   |       | Report of Independent  Registered Public Accounting Firm                                               |       | 61         |
|   |       | Consolidated Statements of  Income for the Years Ended December 31, 2006, 2005 and 2004           |       | 63         |
|   |       | Consolidated Balance Sheets as of  December 31, 2006 and 2005                                     |       | 64         |
|   |       | Consolidated Statements of  Cash Flows for the Years Ended December 31, 2006, 2005 and 2004       |       | 66         |
|   |       | Consolidated Statements of  Shareholders’ Equity                                                  |       | 68         |
|   |       | Notes to Consolidated  Financial Statements for the Years Ended December 31, 2006, 2005 and  2004 |       | 69         |
|   |       | Unaudited Supplementary  Financial and Reserves Data                                                   |       | 100        |

 

**2.**                FinancialStatement Schedules:

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

**3.**                Exhibits: 

| *2.1 |   | Agreement and Plan of Merger dated April 13,  2006 by and among Latigo Petroleum, Inc., Pogo Producing Company and  Pogo Merger Sub 1, Inc. (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,  2006, File No. 1-7792).                                                                                                                                                                                                         |
|------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *2.2 |   | Purchase and Sale  Agreement dated April 20, 2006 between Pogo Producing Company and  MitEnergy Upstream LLC (a copy of any omitted schedule will be furnished  supplementally to the Commission upon request) (Exhibit 2.2, Quarterly  Report on Form 10-Q for the quarter ended June 30, 2006, File  No. 1-7792).                                                                                                                                                                                                                                                  |
| *2.3 |   | 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).                                                                                                                                                                                                   |
| *2.4 |   | 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).                                                                                                                                                                                                                                                                                                                                                                   |

111

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| *3.2  |   | Bylaws of Pogo Producing  Company, as amended and restated through July 16, 2002  (Exhibit 4.1, Quarterly Report on Form 10-Q for the quarter  ended June 30, 2002, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|-------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *4.1  |   | Indenture, dated as of  March 29, 2005 between Pogo Producing Company and The Bank of New York  Trust Company, N.A., as Trustee (Exhibit 4.1, Quarterly Report on  Form 10-Q for the quarter ended March 31, 2005, File  No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| *4.2  |   | Form of 6.625%  Senior Subordinated Note (Exhibit 4.1, Quarterly Report on Form 10-Q  for the quarter ended March 31, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
| *4.3  |   | Registration Rights  Agreement dated March 29, 2005, by and among Pogo Producing Company and  the parties thereto (Exhibit 4.3, Quarterly Report on Form 10-Q  for the quarter ended March 31, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| *4.4  |   | Indenture dated as of  September 23, 2005 between Pogo Producing Company and The Bank of New  York Trust Company, N.A. (Exhibit 4.1, Current Report on Form 8-K  filed September 29, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| *4.5  |   | Form of 6.875%  Senior Subordinated Note (Exhibit 4.1, Current Report on Form 8-K  filed September 29, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| *4.6  |   | Registration Rights  Agreement dated as of September 23, 2005 among Pogo Producing Company  and the initial purchasers named therein (Exhibit 4.2, Current Report on  Form 8-K filed September 29, 2005, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| *4.7  |   | Indenture dated as of  June 6, 2006 between Pogo Producing Company and The Bank of New York  Trust Company N.A. (Exhibit 4.1 of the Company’s Current Report on  Form 8-K filed June 8, 2006, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| *4.8  |   | Form of 7.875%  Senior Subordinated Note (Exhibit 4.1 of the Company’s Current Report on  Form 8-K filed June 8, 2006, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                |
| *4.9  |   | Registration Rights  Agreement dated as of June 6, 2006 among Pogo Producing Company and the  initial purchasers named therein (Exhibit 4.2 of the Company’s Current  Report on Form 8-K filed June 8, 2006, File No. 1-7792).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| *4.10 |   | 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).                                                                                                                                                |
| *4.11 |   | 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). |
| *4.12 |   | 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |

112

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| *4.13  |   | 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).                                                                                                                                                                                                                                      |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *4.14  |   | 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).                                                                                                                                                                                                     |
| *4.15  |   | Senior Loan Facility  dated May 2, 2006 by and among Pogo Producing Company, as the Borrower,  certain Lenders party thereto from time to time and Goldman Sachs Credit  Partners L.P., as the sole Lead Arranger and Book Runner, Syndication Agent,  Administration Agent and Lender (Exhibit 4.1 of the Company’s Current  Report on Form 8-K filed May 8, 2006, 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, 2006. Pogo Producing Company hereby agrees to furnish  to the Commission a copy of any such debt instrument upon request. |

 

**ExecutiveCompensation Plans and Arrangements (comprising Exhibits 10.1 through 10.41,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).                                           |

113

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| *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).                                                                |
| *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, 2006.  (Exhibit 10.1, Quarterly Report on Form 10-Q for the quarter  ended September 30, 2006, File No. 1-7792).     |
| *10.20 |   | Extension Agreement to  Amended and Restated Executive Employment Agreement by and between Pogo  Producing Company and Stephen R. Brunner, dated August 1, 2006.  (Exhibit 10.2, Quarterly Report on Form 10-Q for the quarter  ended September 30, 2006, File No. 1-7792).      |
| *10.21 |   | Extension Agreement to  Amended and Restated Executive Employment Agreement by and between Pogo  Producing Company and Jerry A. Cooper, dated August 1, 2006.  (Exhibit 10.3, Quarterly Report on Form 10-Q for the quarter  ended September 30, 2006, File No. 1-7792).         |
| *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,  2006. (Exhibit 10.4, Quarterly Report on Form 10-Q for the  quarter ended September 30, 2006, File No. 1-7792). |

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| *10.23 |   | Extension Agreement to  Amended and Restated Executive Employment Agreement by and between Pogo  Producing Company and David R. Beathard, dated August 1, 2006.  (Exhibit 10.5, Quarterly Report on Form 10-Q for the quarter  ended September 30, 2006, File No. 1-7792).     |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *10.24 |   | Extension Agreement to  Amended and Restated Executive Employment Agreement by and between Pogo  Producing Company and Radford P. Laney, dated August 1, 2006.  (Exhibit 10.6, Quarterly Report on Form 10-Q for the quarter  ended September 30, 2006, File No. 1-7792).      |
| *10.25 |   | Extension Agreement to Amended  and Restated Executive Employment Agreement by and between Pogo Producing  Company and J. Don McGregor, dated August 1, 2006.  (Exhibit 10.7, Quarterly Report on Form 10-Q for the quarter  ended September 30, 2006, File No. 1-7792).       |
| *10.26 |   | Extension Agreement to  Amended and Restated Executive Employment Agreement by and between Pogo  Producing Company and Gerald A. Morton, dated August 1, 2006.  (Exhibit 10.8, Quarterly Report on Form 10-Q for the quarter  ended September 30, 2006, File No. 1-7792).      |
| *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, 2006.  (Exhibit 10.9, Quarterly Report on Form 10-Q for the quarter  ended September 30, 2006, File No. 1-7792). |
| *10.28 |   | Extension Agreement to  Amended and Restated Executive Employment Agreement by and between Pogo  Producing Company and Bruce E. Archinal, dated August 1, 2006.  (Exhibit 10.10, Quarterly Report on Form 10-Q for the quarter  ended September 30, 2006, File No. 1-7792).    |
| *10.29 |   | Extension Agreement to  Amended and Restated Executive Employment Agreement by and between Pogo  Producing Company and Michael J. Killelea, dated August 1, 2006.  (Exhibit 10.11, Quarterly Report on Form 10-Q for the quarter  ended September 30, 2006, File No. 1-7792).  |
| *10.30 |   | Indemnification  Agreement by and between Pogo Producing Company and Jerry M. Armstrong, dated  April 25, 2006. (Exhibit 10.1, Quarterly Report on Form 10-Q  for the quarter ended March 31, 2006, File No. 1-7792).                                                               |
| *10.31 |   | Indemnification  Agreement by and between Pogo Producing Company and Robert H. Campbell, dated  April 25, 2006. (Exhibit 10.2, Quarterly Report on Form 10-Q  for the quarter ended March 31, 2006, File No. 1-7792).                                                               |
| *10.32 |   | Indemnification Agreement  by and between Pogo Producing Company and William L Fisher, dated  April 25, 2006. (Exhibit 10.3, Quarterly Report on Form 10-Q  for the quarter ended March 31, 2006, File No. 1-7792).                                                                 |
| *10.33 |   | Indemnification  Agreement by and between Pogo Producing Company and Thomas A. Fry, III,  dated April 25, 2006. (Exhibit 10.4, Quarterly Report on  Form 10-Q for the quarter ended March 31, 2006, File  No. 1-7792).                                                         |
| *10.34 |   | Indemnification  Agreement by and between Pogo Producing Company and Gerrit W. Gong, dated April 25,  2006. (Exhibit 10.5, Quarterly Report on Form 10-Q for the  quarter ended March 31, 2006, File No. 1-7792).                                                                   |

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| *10.35 |   | Indemnification  Agreement by and between Pogo Producing Company and Charles G. Groat, dated  April 25, 2006. (Exhibit 10.6, Quarterly Report on Form 10-Q  for the quarter ended March 31, 2006, File No. 1-7792).                                           |
|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *10.36 |   | Indemnification  Agreement by and between Pogo Producing Company and Carroll W. Suggs, dated  April 25, 2006. (Exhibit 10.7, Quarterly Report on Form 10-Q  for the quarter ended March 31, 2006, File No. 1-7792).                                           |
| *10.37 |   | Indemnification  Agreement by and between Pogo Producing Company and Paul G. Van Wagenen,  dated April 25, 2006. (Exhibit 10.8, Quarterly Report on  Form 10-Q for the quarter ended March 31, 2006, File  No. 1-7792).                                       |
| *10.38 |   | Indemnification  Agreement by and between Pogo Producing Company and Stephen A. Wells, dated  April 25, 2006. (Exhibit 10.9, Quarterly Report on Form 10-Q  for the quarter ended March 31, 2006, File No. 1-7792).                                           |
| *10.39 |   | 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).                                                                                                            |
| *10.40 |   | 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).                                                                                                               |
| *10.41 |   | 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).                                                                      |
| 10.42  |   | Pogo Producing Company  Change of Control Severance and Retention Program                                                                                                                                                                                                              |
| 21     |   | List of Subsidiaries of  Pogo Producing Company                                                                                                                                                                                                                                        |
| 23.1   |   | Consent of  PricewaterhouseCoopers LLP                                                                                                                                                                                                                                                 |
| 23.2   |   | Consent of Ryder Scott  Company, L.P.                                                                                                                                                                                                                                                  |
| 23.3   |   | Consent of Ryder Scott  Company—Canada                                                                                                                                                                                                                                            |
| 23.4   |   | Consent of Miller and  Lents, Ltd.                                                                                                                                                                                                                                                     |
| 23.5   |   | Consent of Ryder Scott  Company, L.P.                                                                                                                                                                                                                                                  |
| 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, 2006.                                                                                                                             |
| 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, 2006.                                                                                                                                                                                                |
| 99.2   |   | Summary Report of Ryder  Scott Company—Canada for the year ended December 31, 2006.                                                                                                                                                                                          |
| 99.3   |   | Summary Report of Miller  and Lents, Ltd. for the year ended December 31, 2006.                                                                                                                                                                                                   |
| 99.4   |   | Summary Report of Ryder  Scott Company, L.P. for the year ended December 31, 2006.                                                                                                                                                                                                |
| *99.5  |   | Summary Report of Ryder  Scott Company, L.P. for the year ended December 31, 2005  (Exhibit 99.1, Amendment No. 1 on Form 10-K/A, filed  October 27, 2006, to the Company’s Annual Report on Form 10-K  for the year ended December 31, 2005). |

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| *99.6 |   | Summary Report of Ryder  Scott Company—Canada for the year ended December 31, 2005  (Exhibit 99.2, Amendment No. 1 on Form 10-K/A, filed  October 27, 2006, to the Company’s Annual Report on Form 10-K  for the year ended December 31, 2005). |
|-------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| *99.7 |   | Summary Report of Miller  and Lents, Ltd. for the year ended December 31, 2005 (Exhibit 99.3,  Amendment No. 1 on Form 10-K/A, filed October 27, 2006,  to the Company’s Annual Report on Form 10-K for the year ended  December 31, 2005).          |
| *99.8 |   | 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).                                                                                                     |
| *99.9 |   | 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).                                                                                                        |

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*                    Asteriskindicates exhibits incorporated by reference as shown.

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the Registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized.
|                                      | POGO PRODUCING COMPANY    |
|--------------------------------------|---------------------------|
|                                 |    (REGISTRANT) |
|                                 | BY:                       | /s/ PAUL G. VAN WAGENEN |
| ** **                           | ** **                | **Paul G. Van Wagenen** |
| ** **                           | * *                  | *Chairman, President and Chief Executive Officer* |
| Date:   March 1, 2007 |                      |   |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the Registrant and inthe capacities indicated on March 1, 2007.
|                                                     | **Signatures** | ** **                               | ** ** | ** ** | **Title** | ** ** |
|-----------------------------------------------------|----------------|------------------------------------------|------------|------------|-----------|------------|
| /s/ PAUL G. VAN WAGENEN                             |           |                                     |
| **Paul G. Van Wagenen**                             | ** **     | ** **                               |
| *Chairman, President and Chief Executive Officer*   |           | Principal Executive Officer and Director |
| /s/ JAMES P. ULM, II                           |           |                                     |
| **James P. Ulm, II**                           | ** **     | ** **                               |
| *Senior Vice President and Chief Financial Officer* |           | Principal Financial Officer              |
| /s/ ROBERT C. MARLOWE                               |           |                                     |
| **Robert C. Marlowe**                               | ** **     | ** **                               |
| *Vice President—Accounting*                    |           | Principal Accounting Officer             |
| /s/ JERRY M. ARMSTRONG                              |           |                                     |
| **Jerry M. Armstrong**                              |           | Director                                 |
| /s/ ROBERT H. CAMPBELL                              |           |                                     |
| **Robert H. Campbell**                              |           | Director                                 |
| /s/ THOMAS A. FRY, III                         |           |                                     |
| **Thomas A. Fry, III**                         |           | Director                                 |
| /s/ GERRIT W. GONG                                  |           |                                     |
| **Gerrit W. Gong**                                  |           | Director                                 |
| /s/ CHARLES G. GROAT                                |           | ** **                               |
| **Charles G. Groat**                                |           | Director                                 |

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| /s/ CARROLL W. SUGGS  |       |       |
|-----------------------|------------|------------|
| **Carroll W. Suggs**  |       | Director   |
| /s/ STEPHEN A. WELLS  |       |       |
| **Stephen A. Wells**  |       | Director   |
| /s/ ROBERT C. MARLOWE |       |       |
| **Robert C. Marlowe** | ** ** | ** ** |
| *Attorney-in-Fact*    | * *   | * *   |

 

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