UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

(Amendment No. 1)

 

For the transition period from              to             

Commission file number:  1-7792

Pogo Producing Company

(Exact name of registrant as specified in its charter)

 

(713) 297-5000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

Securities registered pursuant to Section 12(g) of the Act:  None

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.       Yes x        No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.       Large accelerated filer x        Accelerated filer o        Non-accelerated filer o

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

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

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

 

DOCUMENTS INCORPORATED BY REFERENCE

 

 

EXPLANATORY NOTE

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

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

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

·       “Item 8—Financial Statements and Supplementary Data,” revised to provide additional disclosure relating to properties accounted for as discontinued operations in the Unaudited Supplementary Financial and Reserve Data and the Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves; and

·       “Item 15—Exhibits and Financial Statement Schedules,” revised to refer to certain previously-filed agreements and to make other conforming changes as a result of the filing of this amendment.

Other than as specified above, this amendment does not modify or affect the financial statements or the notes thereto in the Original 10-K. This amendment does not reflect events occurring after the filing of the Original 10-K and does not modify or update the disclosures therein in any way other than as required to reflect the amendments as described above and set forth below. In accordance with Rule 12b-15 promulgated under the Securities Exchange Act of 1934, the complete text of each affected item, as amended, is included herein. Unaffected items have not been repeated in this amendment.

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FORWARD LOOKING STATEMENTS

The statements included or incorporated by reference in this Annual Report on Form 10-K for the year ended December 31, 2005 (this “Annual Report”) include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included or incorporated by reference herein, other than statements of historical fact, are forward-looking statements. In some cases, you can identify Pogo Producing Company’s (the “Company”) forward-looking statements by the words “anticipate,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “goal,” and similar expressions. Such forward-looking statements include, without limitation, statements regarding expected production volumes, drilling of wells and related expenditures and other statements herein and therein regarding the timing of future events regarding the operations of the Company and its subsidiaries, and the statements under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations” regarding the Company’s anticipated future financial position and cash requirements. Although the Company believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company’s expectations (“Cautionary Statements”) are disclosed in this Annual Report and in other filings by the Company with the Securities and Exchange Commission (the “Commission”). All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. The Company’s actual results could differ materially from those anticipated in these forward-looking statements as a result of the factors set forth below, the risk factors described under the caption “Risk Factors” and other factors set forth in or incorporated by reference in this Annual Report. These factors include:

·       the cyclical nature of the oil and natural gas industries

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

·       uncertainties associated with the United States and worldwide economies

·       current and potential governmental regulatory actions in countries where the Company operates

·       substantial competition from larger companies

·       the Company’s ability to implement cost reductions

·       the Company’s ability to acquire and integrate oil and gas reserves

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

·       fluctuations in foreign currency exchange rates in areas of the world where the Company conducts operations

·       covenant restrictions in the Company’s debt agreements

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

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

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CERTAIN DEFINITIONS

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

PART I

ITEM 1.   Business.

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

The Company organizes its exploration and production activities principally into five operating regions, as well as a New Ventures Group and an Unconventional Resources Group. The operating regions are its Canadian Operations, its Western U.S. Region, which is active in the Permian Basin area in New Mexico and West Texas, the Panhandle of Texas, the San Juan Basin in New Mexico and in the Madden Unit in Wyoming; its Gulf Coast Region, which includes the Company’s onshore operations principally in South Texas and Louisiana; its Gulf of Mexico Region, which is responsible for the Company’s operations offshore Texas and Louisiana in the Gulf of Mexico; and the Asia and Pacific Region, which has responsibility for the Company’s operations in New Zealand. The Company’s New Ventures Group is primarily responsible for identifying new projects and opportunities for the Company outside the United States and the Unconventional Resources Group is responsible for identifying new unconventional resource opportunities in North America.

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

Domestic Onshore Operations

The Company’s Gulf Coast Region is headquartered in Houston, Texas, with field offices in Laredo and Manvel, Texas and Thibodaux, Louisiana. The Company’s Western U.S. Region has an office in Midland, Texas, two field offices in southeastern New Mexico, one field office in West Texas and two field offices in the Texas Panhandle. The Company conducts its onshore operations in the United States directly and through its wholly-owned subsidiaries. Domestic onshore reserves as of December 31, 2005, accounted for approximately 54% of the Company’s total proved reserves, with the Gulf Coast Region and the Western U.S. Region contributing approximately 15% and 39%, respectively, of the Company’s total

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proved reserves. During 2005, approximately 79% of the Company’s natural gas production and 38% of its oil and condensate production was from its domestic onshore properties, contributing approximately 60% 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 approximately 22,420 acres located in South Texas. The Company owns various working interests in the Los Mogotes Field, which average approximately 71% across the field, and is the operator of a majority of those working interests. In 2005, the Company’s interests in Los Mogotes produced an average of approximately 53 MMcf per day of natural gas, accounting for approximately 21% of the Company’s natural gas production for the period. As of December 31, 2005, the Company’s proved reserves associated with the Los Mogotes Field were 41 MBbls of oil, condensate and natural gas liquids and 111,327 MMcf of natural gas, which together represented approximately 5.5% of the Company’s total proved reserves. As of that date, the Company’s leasehold interests in the field included 14,380 net acres of developed lands and 902 net acres of undeveloped lands, with approximately 98 net producing wells and 142 gross producing wells. The map below depicts the location of the field.

The Madden Unit, which is part of the Company’s Western Region, is a federal unit operated by a third party and consists of approximately 80,000 acres of the Wind River Basin located in Central Wyoming. The Company owns various working interests in the Madden Unit, which average approximately 14.5% across the unit area. In 2005, the Company’s interests in the Madden Unit produced an average of approximately 40 MMcf per day of natural gas, accounting for approximately 16% of the Company’s natural gas production for the period. As of December 31, 2005, the Company’s proved reserves associated with the Madden Unit were 82 MBbls of oil, condensate and natural gas liquids and 269,823 MMcf of natural gas, which together represented approximately 13.2% of the Company’s total proved reserves. As of that date, the Company’s leasehold interests in the unit included 3,471 net acres of developed lands and 7,351 net acres of undeveloped lands, with approximately 29 net producing wells and 205 gross producing wells. The map below depicts the location of the unit.

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Exploration and Development

The Company’s onshore capital and exploration expenditures for 2005 were approximately $251,400,000 (excluding approximately $59,500,000 of net property acquisitions). Comparable expenditures for 2004 and 2003 were approximately $196,500,000 (excluding approximately $489,600,000 of net property acquisitions) and $142,400,000 (excluding approximately $177,700,000 of net property acquisitions), respectively. The increase in the Company’s onshore capital and exploration expenditures for 2005, compared to 2004, resulted primarily from expenditures related to increased exploratory and development drilling. The Company has currently budgeted approximately $430,000,000 for capital and exploration expenditures during 2006 in its domestic onshore areas.

The Company generally conducts its onshore activities through joint ventures and other interest sharing arrangements with major and independent oil companies. The Company and its subsidiaries operate many of their onshore properties using both independent contractors and field personnel that are employed by the Company or its subsidiaries.

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

During 2006, the Company plans to drill approximately six exploratory wells and 104 development wells in various known fields and exploratory prospects located in southeast New Mexico, West Texas and the Texas Panhandle. Drilling objectives for these wells range in vertical depth from 3,500 feet to 18,000 feet below the surface and target numerous formations including, among others, the Brown Dolomite, Canyon, Delaware (Brushy Canyon), Spraberry, Bone Spring, Wolfcamp, Granite Wash, Strawn, Atoka and Morrow formations.

The Company also plans to continue an active development drilling program in the San Juan Basin, which is located in northwest New Mexico. Nineteen wells are expected to be drilled in multiple prospects

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

The Company has actively participated in the exploration and development of the Madden Unit since it first acquired its non-operated working interest in 2001. The Madden Unit is characterized by gas production from multiple stratigraphic horizons of the Lower Ft. Union, Lance, Mesaverde and Cody sands and the Madison dolomite. Production from the Madden Unit is typically found at depths ranging from 5,500 to 20,000 feet and 24,000 to 25,000 feet. Some of the gas produced from the Madden Unit requires processing by the Lost Cabin Gas Plant (in which the Company owns a partial interest) to make it pipeline quality. Of the 210 wells drilled in the Western Region in 2005, 66 of those wells were drilled in the Madden Unit, 88% of which were successfully completed. The Company continues to actively participate in the exploration and development of the Madden Unit and expects the operator of the unit to conduct a drilling program of approximately 61 development wells and one exploratory well in 2006. Recent drilling activity in the unit has focused on the Lower Fort Union formation, where productive zones have historically been found from approximately 5,500 feet to 11,000 feet below the surface. Also in progress is an exploratory test well with a projected total depth of 20,585 feet in the Frontier horizon, located above the Madison dolomite.

During 2005, the Company’s Western U.S. Region acquired, in several transactions, proved producing properties located in southeast New Mexico, West Texas and the Texas Panhandle to complement its existing asset base. The aggregate purchase price for these transactions was approximately $46 million.

Gulf Coast Region.   The Company’s Gulf Coast Region is actively exploring for, acquiring and developing oil and gas reserves, primarily in the coastal onshore areas of Louisiana and Texas. Other areas of activity include the East Texas Basin and the Illinois Basin in southern Indiana. During 2005, the Gulf Coast Region participated in drilling 19 wells, 95% of which were successfully completed. For 2006, the Company has budgeted to participate in 21 exploratory wells and 45 development wells.

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

The Company has actively participated in the development of the Los Mogotes Field since it acquired its initial interest in 2001. The field is characterized by gas production from the Asche, Charco and Lobo members of the Wilcox formation, found at depths ranging from 7,000 to 14,000 feet below the surface. During 2005, the Company participated in drilling 10 wells in this field, all of which were successfully completed. The Company plans to continue an active drilling program in Los Mogotes during 2006, with 49 locations identified to be drilled and 25 of those budgeted to be drilled in 2006.

In East Texas, the Company’s Gulf Coast Region is exploring the Woodbine and Austin Chalk Formations for new oil and gas reserves in Polk and Tyler Counties. The Company acquired 128 square miles of new, proprietary   3-D seismic data in 2005 and interpretation of that data has yielded a number of exploratory prospects which are 100% owned and operated by the Company. The Company controls approximately 80,000 acres in this area.

During 2005, the Company’s Gulf Coast Region participated in drilling two Miocene exploratory wells in South Louisiana. For 2006 in South Louisiana, the Company has agreed to participate in the drilling of

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

In October 2005, the Company obtained a 50% working interest in an unconventional resource play in southwest Indiana that an industry partner operates. Approximately 225,000 gross acres have been leased, seven horizontal New Albany Shale gas wells have been drilled and gas from a production pilot comprised of four of those wells is being produced and sold. Five exploratory wells and an additional 5 to 15 development wells are contemplated for 2006.

Domestic Offshore Operations

Gulf of Mexico Region.   Approximately 14% of the Company’s proved reserves as of December 31, 2005 were located in the Gulf of Mexico. During 2005, approximately 14% of the Company’s natural gas production and 50% of its oil and condensate production from the Company’s domestic offshore properties contributed approximately 30% of the Company’s consolidated oil and gas revenues. The Company’s exploration and development efforts in this region are primarily focused in the shallower waters of the continental shelf.

During 2005, the Company’s wells in the Main Pass Block 61/62 Field, which is located on the continental shelf off the southeastern tip of Louisiana, produced an average of approximately 9,800 Bbls/d of oil, condensate and natural gas liquids, accounting for approximately 38% of the Company’s liquid hydrocarbon production for the period. As of December 31, 2005, the Company’s proved reserves for the Main Pass Block 61/62 Field were 16,477 MBbls of oil, condensate and natural gas liquids and 13,530 MMcf of natural gas, which together represented approximately 5.5% of the Company’s total proved reserves. The Company is the operator of a 100% working interest in Main Pass Block 61/62 Field, subject to a 5% overriding royalty interest in Main Pass Block 61. The Company’s interests are owned through federal leases administered by the Minerals Management Service (“MMS”), in which the MMS has retained a 16.67% royalty interest. As of December 31, 2005, the Company’s leasehold interests in the Main Pass Block 61/62 Field included 9,989 net acres of developed lands and no undeveloped lands, with 17 net producing wells. In 2005, the field was shut-in for approximately 49 days due to hurricane activity.

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The Main Pass Block 61/62 Field, which was brought online by the Company in 2002, consists of a series of stratigraphic traps located on a regionally dipping slope, downdip at the Upper Miocene Shelf/Slope break. As of December 31, 2005, the Company is injecting water for both pressure support and enhanced recovery in the two larger reservoirs of the field through injection wells, while producing from 17 wells. The map below depicts the location of the field.

Exploration and Development

The Company’s domestic offshore capital and exploration expenditures for 2005 were $88,700,000. Comparable expenditures for 2004 and 2003 were approximately $150,300,000 and $60,500,000, respectively. The decrease in the Company’s domestic offshore capital and exploration expenditures for 2005, compared with 2004, resulted primarily from decreased expenditures for exploration and development wells and facilities construction. During 2005, the Company invested approximately $71,200,000 in exploration and development wells and $11,600,000 in facilities construction for its Gulf of Mexico operations. The Company has currently budgeted approximately $91,000,000 for capital and exploration expenditures during 2006 in the Gulf of Mexico, of which $63,600,000 is budgeted for exploration and development wells and $23,300,000 for facilities construction. The Company participated in drilling seven wells during 2005 in the Gulf of Mexico Region, two of which were considered successful. At December 31, 2005, the Company held varying interests in 175 producing oil and gas wells in the Gulf of Mexico.

Leases acquired by the Company and other participants in its bidding groups are customarily committed, on a block-by-block basis, to separate operating agreements under which the appointed operator supervises exploration and development operations for the account and at the expense of the group. These agreements usually contain terms and conditions that have become relatively standardized in the industry. Major decisions regarding development and operations typically require the consent of at least a majority (in working interest) of the participants. Because the Company generally has a meaningful working interest position, the Company believes it can significantly influence (but not always control) decisions regarding development and operations on most of the leases in which it has a working interest, even though it may not be the operator of a particular lease. The Company is the operator on all or a portion of 56 of the 88 offshore leases in which it had an interest as of December 31, 2005.

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Platforms and related facilities are installed on an offshore lease block when, in the judgment of the lease interest owners, the necessary capital expenditures are justified. A decision to install a platform generally is made after the drilling of one or more exploratory wells with contracted drilling equipment. Platform costs vary depending on, among other factors, the number of well slots, water depth, currents, and sea floor conditions.

Hurricanes Katrina and Rita

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

Lease Acquisitions

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

International Operations

The Company has conducted international exploration activities since the late 1970s in numerous oil and gas areas throughout the world. The Company currently holds acreage in Canada and New Zealand. The Company’s explorationists continue to evaluate other international opportunities that are consistent with its exploration strategy and expertise. For a discussion of certain risks associated with the Company’s international operations, see “Risk Factors—The Company’s foreign operations subject it to additional risks,” “—The Company’s integration of Northrock may not be successful” and “—The Company may not be able to obtain sufficient drilling equipment and experienced personnel to conduct its operations.”

Exploration and Development

The Company’s international capital and exploration expenditures were approximately $162,000,000 (excluding approximately $2,526,000,000 of property acquisitions and approximately $71,095,000 of expenditures related to discontinued Thailand and Hungary operations) for 2005. Expenditures for 2004 and 2003 were approximately $148,900,000 (approximately $5,700,000 excluding Thailand and Hungary operations) and $138,000,000 (approximately $67,000 excluding Thailand and Hungary operations),

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respectively. The increase in the Company’s capital and exploration expenditures for 2005 resulted primarily from expenditures for facilities costs and increased drilling activity.

The Company has currently budgeted approximately $204,000,000 for capital and exploration expenditures during 2006 in areas outside the United States, including approximately $200,000,000 in Canada.

Canadian Operations

The Company’s Canadian operations are conducted through Northrock, a wholly-owned subsidiary of the Company. Northrock is headquartered in Calgary, Alberta, Canada, and has field offices in Rocky Mountain House, Alberta, Grande Prairie, Alberta and in Estevan, Saskatchewan. Northrock conducts its activities through joint ventures with other oil and gas companies and operates its properties using field personnel and independent contractors.

Northrock’s principal producing properties are located in the Canadian provinces of Alberta, Saskatchewan and British Columbia. In addition, Northrock participates in an active exploration program in the Northwest Territories.

Crude oil and natural gas reserves in Canada, as of December 31, 2005, accounted for approximately 32% of the Company’s total proved reserves. During the fourth quarter of 2005, Northrock contributed approximately 27% of the Company’s natural gas production and 41% of its oil and condensate production.

Exploration and Development

Since the acquisition by the Company, Northrock has significantly expanded its existing exploration and development program, spending $78.1 million in the fourth quarter of 2005. During that time, Northrock drilled 43 wells, of which 39 wells were successfully completed. For 2006, Northrock will initiate a very active exploration and development program and expects to spend approximately $200 million to drill 184 wells, including 33 exploratory wells.

The exploration and development program in Canada will focus on various known fields in Alberta and Saskatchewan. In 2006, significant drilling activity is planned on recent exploration success in both southern Alberta and in southeast Saskatchewan. In addition to initiatives in Alberta and Saskatchewan, Northrock has an average 32% interest in an exploration project in the Mackenzie Delta in the Northwest Territories near the route of the proposed Mackenzie Valley Gas Pipeline. Since the acquisition, Northrock has participated in drilling two wells in the Mackenzie Delta and is expected to participate in the drilling of two additional wells in the first quarter of 2006.

Acquisitions

Northrock also has an active acquisition program focused on acquiring properties to complement existing initiatives or on new areas with anticipated significant development opportunities.

In the fourth quarter of 2005, Northrock spent $41.5 million on corporate acquisitions and to acquire interests in producing properties located primarily in southern Alberta and in southwest Saskatchewan. For 2006, the Company anticipates that Northrock will continue to pursue incremental acquisition opportunities to supplement its exploration and development program.

Asia and Pacific Region

New Zealand.   During 2004, the Company was granted three petroleum exploration licenses over approximately 1,044,000 acres in the offshore Northern Taranaki Basin. The primary exploration term of these licenses is for five years, subject to extension for up to an additional ten years, provided that at least

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half of the acreage under each license has been relinquished and the permit holder has substantially complied with the terms of its permits. The Company committed to acquire 3-D seismic data over at least 1,000 square kilometers of the licenses within the first two years of their primary term and to reprocess 433 miles of existing 2-D seismic data. During 2004 and early 2005, the Company exceeded its work obligations with respect to both 3-D seismic data acquisition and 2-D seismic data reprocessing. The 3-D seismic data acquired by the Company has been processed and is being analyzed with a goal of committing to drill multiple exploration wells in 2007, subject to rig availability. The Company has a commitment to drill one well on each of the three licenses by February 2008 or relinquish the license. Production permits of up to 40 years may be applied for if a commercial field is discovered.

Vietnam.   The Company, together with a joint venture partner, has been notified that it was the high bidder on Block 124, which covers approximately 1.48 million acres offshore along the coast of Vietnam. As of year end, the Company was negotiating with PetroVietnam, the state oil company of Vietnam, for a Production Sharing Contract covering Block 124.

Thailand and Hungary Dispositions

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

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

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

Geographic and Other Information

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

The business of exploration, development and production of crude oil and natural gas is capital intensive. The Company has historically needed and will continue to need substantial amounts of cash to fund its capital expenditure and working capital requirements. For further discussion, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and “Risk Factors—The Company has substantial capital requirements.”

Miscellaneous

Other Assets

The Company and a subsidiary, Pogo Offshore Pipeline Co., own interests in eight pipelines (excluding field gathering pipelines) through which offshore hydrocarbon production is transported. The

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Company also owns an approximate 15% interest in the Lost Cabin Gas Plant located in the Madden Unit, which currently is processing in excess of 340 MMcf per day.

Sales

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

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

Northrock, the Company’s wholly-owned Canadian subsidiary, currently sells the majority of its oil production under contracts with a six-month term but with prices based on monthly market conditions. The remainder of Northrock’s crude oil production is sold in the spot market for no more than one month at a time at then currently available prices. The majority of Northrock’s gas sales are month-to-month spot market sales at currently available prices. Approximately 60% of Northrock’s spot market, month-to-month sales of natural gas are sold under firm delivery requirements for the month of sales. The remaining approximate 40% of sales are sold under a best efforts basis. The Company believes that this 60-40 mix affords it the necessary flexibility in its production to meet all firm delivery requirements. A small portion of Northrock’s gas sales are under longer-term contracts but with prices based on monthly market conditions and best efforts delivery obligations.

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

In 2005, crude oil sales to Shell Trading Company constituted more than 10% of the Company’s consolidated revenues.

Competition and Market Conditions

The Company experiences competition from other oil and gas companies in all phases of its operations, as well as competition from other energy-related industries. See “Risk Factors—The Company faces significant competition and is smaller than many of its competitors.”  The Company’s profitability and cash flow are highly dependent upon the prices of oil and natural gas, which historically have been seasonal, cyclical and volatile. In general, prices of oil and gas are dependent upon numerous factors beyond the control of the Company, including various weather, economic, political and regulatory conditions. In addition, the decisions of the Organization of Petroleum Exporting Countries relating to export quotas also affect the price of crude oil. A future drop in oil or gas prices could have a material adverse effect on the Company’s cash flow and profitability. Sustained periods of low prices could cause the Company to shut-in existing production and also have a material adverse effect on its operations and

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financial condition. It could also result in a reduction of funds available under the Company’s bank credit facilities. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources; Credit Agreement.”

Because it is impossible to predict future oil and gas price movements with any certainty, the Company from time to time enters into contracts to hedge against future market price changes on a portion of its production. While intended to limit the negative effect of price declines, some forms of hedging transactions could effectively limit the Company’s participation in price increases, which could be significant, for the covered period. As of December 31, 2005, the Company was a party to certain natural gas or crude oil option contracts (see “Quantitative and Qualitative Disclosures About Market Risk—Current Hedging Activity”). When the Company does engage in certain types of hedging activities, it may satisfy its obligations with its own production or by the purchase (or sale) of third-party production. The Company may also offset delivery obligations under these hedging 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 interest owned by the Company Acreage.

The Company owns interests in developed and undeveloped oil and gas acreage in various parts of the world. These ownership interests generally take the form of “working interests” in oil and gas leases that have varying terms. The following table shows the Company’s interest in developed and undeveloped oil and gas acreage under lease as of December 31, 2005:

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

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(b)          Approximately 2% of the Company’s total onshore net undeveloped acreage is under leases that have minimum terms expiring in 2006. Approximately 0.7% of the Company’s total offshore net undeveloped acreage have expiring terms in 2006.

Average Production (Lifting) Costs per Unit of Production

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

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

(b)          Total Company average production costs exclude discontinued operations.

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Productive Wells and Drilling Activity

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

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

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

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The following table shows the number of successful gross and net exploratory and development wells in which the Company has participated and the number of gross and net wells abandoned as dry holes during the periods indicated. An onshore well is considered successful upon the installation of permanent equipment for the production of hydrocarbons or when electric logs run to evaluate such wells indicate the presence of commercially producible hydrocarbons and the Company currently intends to complete such wells. Successful offshore wells consist of exploratory or development wells that have been completed or are “suspended” pending completion (which has been determined to be feasible and economic) and exploratory test wells that were not intended to be completed and that encountered commercially producible hydrocarbons. For accounting purposes, a well is considered a dry hole when the above criteria indicate that proved reserves have not been found. For purposes of this table, a well is classified as a dry hole in the period in which the Company reports permanent abandonment to the appropriate agency.

 

Reserves

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

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operations in Thailand and Hungary, operations that were disposed of in 2005 and are accounted for in the Company’s financial statements as discontinued operations, are excluded from the table below and separately presented in the footnotes that follow the table.

(a)           Excludes proved reserves located in Thailand and Hungary, as well as the present value of estimated future net revenues from such reserves. As of December 31, 2004 and 2003, the Company’s proved reserves in Thailand consisted of 32,517 MBbls and 37,307 MBbls of oil, condensate and natural gas liquids, respectively, and 145,689 MMcf and 165,188 MMcf of natural gas, respectively. As of December 31, 2003, the Company’s proved reserves in Hungary consisted of 10,131 MMcf of natural gas. The Company had no proved reserves in      Hungary as of December 31, 2004 and no proved reserves in Hungary of oil, condensate and natural gas liquids as of December 31, 2003.

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

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The following table presents a reconciliation of the PV-10 values set forth above for both proved and proved developed reserves to the most directly comparable GAAP financial measure, which is the standardized measure of discounted future net cash flows. Management believes that presentation of PV-10 values is relevant and useful to the Company’s investors because it presents the discounted future net cash flows attributable to both the Company’s proved and proved developed reserves prior to taking into account the effect of the non-property related expense of estimated future income taxes. Because many factors that are unique to individual companies may impact the amount of future income taxes to be paid, the use of a pre-tax measure such as PV-10 provides greater comparability for investors when evaluating companies. Accordingly, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s reserves to other companies. Management also uses the PV-10 measure when assessing the potential return on investment related to the Company’s oil and gas properties. PV-10 is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. For the Company’s presentation of the standardized measure of discounted future net cash flows, please see “Standardized Measure of 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

 

The PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company’s natural gas and oil reserves. The future prices received by the Company for the sales of its production may be higher or lower than the prices used in calculating the estimates of future net revenues, and the operating costs and other costs relating to such production may also increase or decrease from existing levels. Essentially all of the Company’s natural gas production is currently sold on the spot market.

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

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

(a)           The difference in initial weighted prices presented for Canada and the United States are primarily due to the medium gravity crude produced from the southwest Saskatchewan assets, which account for approximately 40% of the Canadian crude oil and condensate production.

In computing future revenues from gas reserves attributable to the Company’s interests, prices in effect at December 31, 2005 were used, including current market prices, contract prices and fixed and determinable price escalations where applicable. The gas prices that were used make no allowances for seasonal variations in gas prices that are likely to cause future yearly average gas prices to be different than December gas prices. For gas sold under contract, the contract gas price, including fixed and determinable escalations, exclusive of inflation adjustments, was used until the contract expires and then was adjusted to the current market price for the area and held at this adjusted price through to depletion of the reserves. In computing future revenues from liquids attributable to the Company’s interests, prices in effect at December 31, 2005 were used and these prices were held constant through to depletion of the properties. The future net revenues are adjusted to reflect the Company’s net revenue interest 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 revenues, the operating costs for the leases and wells include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. Development costs are based on authorization for expenditure for the proposed work or actual costs for similar projects. The current operating and development costs were held constant throughout the life of the properties. The estimated net cost of abandonment after salvage was considered for the properties. No deduction was made for indirect costs such as general and administrative and overhead expenses, loan repayments, 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 set forth above includes estimated production for the last few months of 2005. The future production rates from reservoirs now on production may be more or less than estimated because of, among other reasons, mechanical breakdowns and changes in market demand or allowables set by regulatory bodies. Properties that are not currently producing may start producing earlier or later than anticipated in the estimates of future production rates.

There are numerous uncertainties in estimating the quantity of proved reserves and in projecting the future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those of the Company, Ryder Scott, Ryder Scott Canada, and Miller and Lents. The accuracy of any reserve estimate is

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

The Company is periodically required to file estimates of its oil and gas reserve data with various U.S. governmental regulatory authorities and agencies, including the Department of Energy, the Federal Energy Regulatory Commission (“FERC”) and the Federal Trade Commission. In addition, estimates are from time to time furnished to governmental agencies in connection with specific matters pending before such agencies. The basis for reporting reserves to these agencies, in some cases, is not comparable to that used as a basis for the estimates set forth above in accordance with Commission guidelines because of the nature of the various reports required. The major differences generally include differences in the timing of such estimates, differences in the definition of reserves, requirements to report in some instances on a gross, net or total operator basis 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 reserves were filed with or included in reports to any federal authority or agency other than the Commission.

Government Regulations

Domestic and Foreign Tax

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

American Jobs Creation Act of 2004

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

Environmental Matters

The Company’s operations are subject to numerous foreign, federal, state and local environmental laws and regulations governing the release and/or discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, assessment of administrative and civil penalties, and even criminal prosecution. The Company believes it is in substantial compliance with applicable environmental laws and regulations. Further, the Company does not anticipate that compliance with existing environmental laws and regulations will have a material effect on its financial condition or results of operations. However, there can be no assurance that substantial costs for compliance will not be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations, and enforcement policies, could result in additional costs or liabilities that the Company cannot currently quantify.

The Company generates wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes or Canadian laws. The U.S. Environmental Protection Agency (“the EPA”), and state agencies have limited the approved methods of disposal for some types of hazardous and nonhazardous wastes. Some wastes handled by the Company in its field service activities that currently are exempt from treatment as hazardous wastes may in the future

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be designated as “hazardous wastes”‘ under RCRA or other applicable statutes. If this were to occur, the Company would become subject to more rigorous and costly operating and disposal requirements.

The federal Comprehensive Environmental Response, Compensation, and Liability Act, CERCLA or the “Superfund’’ law, and comparable state statutes and Canadian laws impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Under CERCLA, liable persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Company currently owns interests in or operates numerous properties and facilities that for many years have been used for industrial activities, including oil and gas production operations. Hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by the Company, or on or under other locations where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of hazardous substances, wastes, or hydrocarbons, was not under the Company’s control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging or pit closure operations to prevent future contamination. These laws and regulations may also expose the Company to liability for its acts that were in compliance with applicable laws at the time the acts were performed. The Company maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident of pollution may also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area.

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws and Canadian laws impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States and Canada. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the EPA or applicable state agencies. The Company has numerous applications pending before the EPA for National Pollutant Discharge Elimination System (“NPDES”) water discharge permits with respect to offshore drilling and production operations.

The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent the Company’s offshore lease operations affect state waters, the Company may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. The amount of financial responsibility that the Company must currently demonstrate for its offshore platforms is $70,000,000. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether these financial responsibility requirements under the OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely affect the Company. The impact, however, should not be any

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more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico.

Some of the Company’s operations also result in emissions of regulated air pollutants. The federal Clean Air Act and analogous state laws and Canadian laws require permits for facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. Failure to comply with these requirements could result in the imposition of substantial administrative, civil and even criminal penalties.

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

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called “greenhouse gases.”  Northrock’s exploration and production facilities and other operations and activities may emit greenhouse gases that may 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 reduction requirements for various industrial activities, including oil and gas exploration and production. Future federal legislation, together with provincial emission reduction requirements such as those proposed in Alberta’s Bill 37: Climate Change and Emissions Management, may require the reduction of emissions or emissions intensity produced by a corporation’s operations and facilities. Given the uncertainties regarding implementation of the Kyoto Protocol and related climate change policies, the potential liability associated with future regulations is currently unknown. The Company can provide no assurances that the direct or indirect costs of such regulations will not materially adversely affect the business of Northrock.

The Company is asked to comment on the costs it incurred during the prior year on capital expenditures for environmental control facilities and the amount it anticipates incurring during the coming year. The Company believes that, in the course of conducting its oil and gas operations, many of the costs attributable to environmental control facilities would have been incurred absent environmental regulations as prudent, safe oilfield practice. During 2005, the Company incurred capital expenditures of approximately $1,297,000 for environmental control facilities, primarily relating to the cost of installing environmental equipment, the installation of pit and firewall spill liners, and routine site restoration costs. The Company has budgeted approximately $2,600,000 for expenditures involving environmental control facilities during 2006, including, among other things, anticipated site restoration costs and the installation of environmental control equipment.

Other Laws and Regulations

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

The Minerals Management Service (“MMS”) administers the oil and gas leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The MMS holds a royalty

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interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the MMS changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater extent than other similarly situated producers.

FERC regulates the rates, terms and conditions applicable to the transportation of natural gas by interstate pipelines and to the storage of gas transported in interstate commerce. FERC generally requires cost-based rates, although under certain circumstances it approves market-based rates and other alternative rate mechanisms. State agencies are generally responsible for regulating intrastate gas transportation and storage. Gathering services are exempt from FERC regulation except in certain circumstances where the services are provided in connection with interstate transportation. State agencies typically have authority to regulate rates for gathering services provided within the respective states. To the extent FERC and the state agencies allow higher rates for transportation, storage, or gathering, gas prices received by the Company for the sale of its gas production may be adversely impacted. However, the impact should not be substantially different on the Company than it will be on other similar situated gas producers and sellers.

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

The provincial governments in Canada each impose lessor royalties on Crown mineral leases, and these are set by regulation. For leases where the lessor is not the provincial government, the royalty rate is negotiated between lessor and lessee.

Employees

As of December 31, 2005, the Company and its subsidiaries had 421 full-time employees, including 168 in its Calgary office. None of the Company’s employees are presently represented by a union for collective bargaining purposes.

Available Information

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

·       The Company’s Code of Business Conduct and Ethics

·       The Company’s Corporate Governance Guidelines

·       The Charters of the Company’s Audit, Compensation and Nominating and Corporate Governance  Committees

Any shareholder who so requests 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 required to be disclosed by rules of the Commission or the New York Stock Exchange will be posted on the Company’s Internet website within five business days and maintained for at least twelve months.

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ITEM 1A.   Risk Factors.

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

The Company’s revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. Oil and natural gas market prices have historically been seasonal, cyclical and volatile. The average prices that the Company has recently received for its production are significantly higher than their historic average. A future drop in oil and natural gas prices could have a material adverse effect on the Company’s cash flow and profitability. A sustained period of low prices could have a material adverse effect on the Company’s operations and financial condition and could also result in a reduction in funds available under the Company’s credit facility and associated prepayments. Lower prices may also reduce the amount of natural gas and oil that the Company can economically produce.

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

·       the level of consumer product demand;

·       weather conditions;

·       domestic and foreign governmental regulations;

·       the price and availability of alternative fuels;

·       political conditions in natural gas and oil producing regions;

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

·       the price of foreign imports; and

·       overall economic conditions.

The Company’s integration of Northrock may not be successful.

The acquisition of Northrock in September, 2005 is the largest acquisition in the Company’s history. The Company may not be able to realize anticipated economic, operational and other benefits from the acquisition due to the following risks and difficulties, among others:

·       Northrock’s properties may not produce revenues, earnings or cash flow at anticipated levels;

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

·       the Company may lose key employees on whom management is substantially dependent in the operation of Northrock’s assets;

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

·       the Company may experience material difficulties and additional costs in continuing to integrate Northrock’s operations, systems and personnel with those of the Company.

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

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

Numerous risks affect the Company’s drilling activities, including the risk of drilling non-productive wells or dry holes. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. Also, the Company’s drilling operations could diminish or cease because of any of the following:

·       title problems;

·       weather conditions;

·       fires;

·       explosions;

·       blow-outs and surface cratering;

·       uncontrollable flows of underground natural gas, oil and formation water;

·       natural disasters;

·       pipe or cement failures;

·       casing collapses;

·       embedded oilfield drilling and service tools;

·       abnormally pressured formations;

·       environmental hazards such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

·       noncompliance with governmental requirements; or

·       shortages or delays in the delivery or availability of material, equipment or fabrication yards.

Offshore operations are also subject to a variety of operating risks related to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These hazards may interrupt production and can cause substantial losses to the Company due to injury or loss of life, severe damage to facilities, or pollution or other environmental damage. As a result, the Company could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions. Information regarding the impact of Hurricanes Katrina and Rita on the Company’s operations, please read “Business: Domestic Offshore Operations.”

Moreover, effective marketing of the Company’s natural gas production depends on a number of factors, such as the following:

·       existing market supply of and demand for natural gas;

·       the proximity of the Company’s reserves to pipelines;

·       the available capacity of such pipelines; and

·       government regulations.

The marketing of oil and natural gas production similarly depends on the availability of pipelines and other transportation, processing and refining facilities, and the existence of adequate markets. As a result, even if hydrocarbons are discovered in commercial quantities, a substantial period of time may elapse before commercial production commences. If pipeline facilities in an area are insufficient, the Company

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may have to wait for the construction or expansion of pipeline capacity before the Company can market production from that area.

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

In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for drilling rigs, drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the offshore oil and gas industry in particular. The market for oilfield services is currently very competitive. This may lead to difficulty and delays in consistently obtaining services and equipment from vendors, obtaining drilling rigs and other equipment at favorable rates, and scheduling equipment fabrication at factories and fabrication yards. Obtaining drilling rigs for our New Zealand operations is presently difficult. This, in turn, may lead to projects being delayed or experiencing increased costs.

The Company’s foreign operations subject it to additional risks.

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

·       currency restrictions and exchange rate fluctuations;

·       risks of increases in taxes and governmental royalties and renegotiation of contracts with governmental entities; and

·       changes in 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 international operations. In addition, if a dispute arises from foreign operations, foreign courts may have exclusive jurisdiction over the dispute, or the Company may not be able to subject foreign persons to the jurisdiction of United States courts.

Local laws and customs in many countries differ significantly from those in the United States. In many foreign countries, particularly in those with developing economies like Vietnam, it is common to engage in business practices that are prohibited by United States regulations applicable to the Company. The U.S. Foreign Corrupt Practices Act prohibits corporations and individuals, including the Company and its employees, from engaging in certain activities to obtain or retain business or to influence a person working in an official capacity. Although the Company has implemented policies and procedures designed to ensure compliance with these laws, there can be no assurance that all of the Company’s employees, contractors and agents, including those based in or from countries where practices which violate such United States laws may be customary, will not take actions in violation of the Company’s policies. Any such violation, even if prohibited by the Company’s policies, could have a material adverse effect on the Company’s business. In addition, the Company’s foreign competitors that are not subject to the U.S. Foreign Corrupt Practices Act or similar laws may be able to secure business or other preferential treatment in such countries by means that such laws prohibit with respect to the Company.

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

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

·       the operator may initiate exploration or development projects on a different schedule than the Company prefers;

·       the operator may propose to drill more wells or build more facilities on a project than the Company has funds for, which may mean that the Company cannot participate in those projects or share in revenues from those projects; and

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

Any of these events could significantly affect the Company’s anticipated exploration and development activities and the economic value of those properties to the Company.

Maintaining reserves and revenues in the future depends on successful exploration and development activities and/or acquisitions.

The Company must continually explore for and develop or acquire new oil and natural gas reserves to replace those produced and sold. The Company’s hydrocarbon reserves and revenues will decline if the Company is not successful in its drilling, exploration or acquisition activities. Although the Company has historically maintained its reserves base primarily through successful exploration and development operations, its future efforts may not be similarly successful.

The Company’s operations are subject to casualty risks against which it cannot fully insure.

The Company’s operations are subject to inherent casualty risks such as blowouts, fires, explosions, cratering, uncontrollable flows of oil, natural gas or well fluids, pollution and other environmental risks, marine hazards and natural disasters. If any such event occurred, the Company could be subject to substantial financial losses due to personal injury, property damage, environmental discharge, or suspension of operations. The impact on the Company of one of these events could be significant. Although the Company purchases insurance at levels it believes to be customary for a company of its size in its industry, the Company is not fully insured against all risks incident to its business. For some risks, the Company may not obtain insurance if it believes the cost of available insurance is excessive relative to the risks presented. For example, escalating costs for business interruption insurance may lead the Company to reduce or eliminate its business interruption coverage. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect the Company’s operations and financial condition. Moreover, there is no assurance that recoveries for insured events will be sufficient to cover cash flow that the Company would have otherwise generated from affected properties.

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The Company has substantial capital requirements.

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

·       funding its 2006 capital and exploration budget of $725 million;

·       other allocations for acquisition, development, production, exploration and abandonment of oil and natural gas reserves;

·       future dividends and stock repurchases.

The Company plans to finance anticipated ongoing expenses and capital requirements with funds generated from the following resources:

·       available cash and cash investments;

·       cash provided by operating activities;

·       funds available under the Company’s credit facility;

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

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

However, the Company financed a substantial part of the Northrock acquisition utilizing cash on hand and public debt issuance. In addition, the Company utilized borrowings under its credit facility related to the acquisition, thereby reducing the availability of those resources for other capital requirements. Moreover, the uncertainties and risks associated with future performance and revenues, as described in these Risk Factors, will ultimately determine the Company’s liquidity and ability to meet anticipated capital requirements.

The Company will continue to pursue acquisitions and dispositions.

The Company will continue to seek opportunities to generate value through business combinations, purchases and sales of assets. The Company examines potential transactions on a regular basis, depending on market conditions, available opportunities and other factors. In addition, the Company competes with other companies in pursuing acquisitions, many of which have greater financial and other resources to acquire attractive companies and properties. Dispositions of portions of the Company’s existing business or properties would be intended to result in the realization of immediate value but would consequently result in lower cash flows over the longer term, unless the proceeds are reinvested in more productive assets. The successful acquisition of oil and gas properties requires an assessment of several factors, including recoverable reserves, development and exploratory potential, projected future cash flows that are, in part, based upon future oil and gas prices, current and projected operating, general and administrative and other costs, and contingent liabilities associated with the properties or entities acquired, including potential environmental and other liabilities. The accuracy of the Company’s assessment of these factors is inherently uncertain, and the Company’s review and assessment of potential acquisitions will not reveal all existing or potential problems nor will it permit the Company to become sufficiently familiar with the properties or entities to fully assess their deficiencies and capabilities. Even when problems are identified, the other party may be unwilling or unable to provide effective contractual protection against all or part of the problems. Furthermore, the Company may not be entitled to contractual indemnification for certain liabilities, or it may acquire the properties on an “as is, where is” basis. For a discussion of additional risks

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associated with the Northrock acquisition, see “—The Company’s Acquisition of Northrock may not be successful,” above.

The Company’s reserve data are estimates.

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

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

The Company faces significant competition and is smaller than many of its competitors.

The oil and gas industry is highly competitive. The Company competes with major and independent oil and natural gas companies for property acquisitions and for the equipment and labor required to operate and develop properties. Many of the Company’s competitors have substantially greater financial and other resources. As a result, those competitors may be better able to withstand sustained periods of unsuccessful drilling. In addition, larger competitors may be able to absorb the burden of any changes in applicable laws and regulations more easily than the Company can, which would adversely affect the Company’s competitive position. These competitors may also be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company can. The Company’s ability to explore for oil and natural gas prospects and to acquire additional properties in the future will depend on its ability to conduct operations and to evaluate and select suitable properties and transactions in this highly competitive environment. Moreover, the oil and natural gas industry itself competes with other industries in supplying the energy and fuel needs of industrial, commercial and other consumers. Increased competition causing oversupply or depressed prices could greatly affect the Company’s operational revenues.

The Company’s competitors may use superior technology.

The Company’s industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As the Company’s competitors use or develop new technologies, the Company may be placed at a competitive disadvantage, and competitive pressures may force the Company to implement new technologies at a substantial cost. In addition, the Company’s competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before the Company can. The Company cannot be certain that it will be able to implement technologies on a timely basis or at a cost that is acceptable to it. One or more of the technologies that the Company currently uses or that it may implement in the future may become obsolete, and the Company may be adversely affected.

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

The Company and its subsidiaries are subject to extensive domestic and foreign laws and regulations on taxation, exploration and development, and environmental and safety matters in countries where it owns or operates properties. These laws and regulations are under continuing review for amendment or expansion, and the Company could be forced to expend significant resources to comply with new laws or regulations or changes to existing requirements. Many laws and regulations require drilling permits and govern the spacing of wells, the prevention of waste, rates of production and other matters. These statutes and regulations, and any others that are passed by the jurisdictions where the Company has production could limit the total number of wells drilled or the total allowable production from successful wells, which could limit revenues. Noncompliance with these statutes or failure to establish exemptions from regulations could also result in substantial penalties, require the posting of substantial surety bonds, or in the suspension or termination of the Company’s operations.

The Company is subject to various environmental liabilities.

The Company could incur liability to governments or third parties for any unlawful discharge of oil, natural gas or other pollutants into the air, soil or water, including responsibility for remedial costs. The Company’s onshore and offshore operations could potentially discharge oil or natural gas into the environment in any of the following ways:

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

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

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

·       blowouts, cratering or explosions.

Environmental discharges may move through soil to water supplies or adjoining properties, giving rise to additional liabilities. Some laws and regulations could impose liability for failure to notify the proper authorities of a discharge and other failures to comply with those laws. Environmental laws may also affect the Company’s costs to acquire properties. The Company does not believe that its environmental risks are materially different from those of comparable companies in the oil and gas industry. However, there is no assurance that environmental laws will not, in the future, result in decreased production, substantially increased operational costs or other adverse effects to the Company’s combined operations and financial condition. Pollution and similar environmental risks generally are not fully insurable.

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

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

·       a counterparty to the Company’s derivative instruments is unable to satisfy its obligations;

·       production is delayed or less than expected; or

·       there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for the Company’s production.

Derivative instruments also may limit the Company’s ability to realize increased revenue from increases in the prices for oil and natural gas.

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

The Company is subject to restrictive debt covenants.

Covenants in the credit facility and the indentures governing the Company’s senior subordinated notes impose significant operating and financial restrictions on it, including the maintenance of specified financial ratios. These restrictions may adversely affect the Company’s ability to finance its future operations and capital needs, to react to changes in its business or industry or to pursue available business opportunities. If certain events of default occurred under these debt instruments, the Company’s outstanding indebtedness thereunder may be accelerated, and its assets may not be sufficient to repay such indebtedness. Moreover, any new indebtedness that the Company incurs may impose similar or more restrictive covenants on the Company.

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PART II

ITEM 8.   Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of Pogo Producing Company:

We have completed integrated audits of Pogo Producing Company’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Pogo Producing Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for employee stock-based compensation effective January 1, 2003. Additionally, as discussed in Note 14 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing

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and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded the Company’s Canadian division from it assessment of internal control over financial reporting as of December 31, 2005 because the division was formed with the acquisition of Northrock Resources Ltd. in a purchase business combination during 2005. We have also excluded the Canadian division from our audit of internal control over financial reporting. The Canadian division is a wholly-owned subsidiary of the Company whose total assets and total revenues represent 49% and 11%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2005.

PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 2, 2006

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POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME

 

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

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POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

 

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

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POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued)

 

 

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

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