UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

 

For the fiscal year ended December 31, 2006

OR

 

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, 2006, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was approximately $2,675,000,000 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

 

FORWARD LOOKING STATEMENTS

The statements included or incorporated by reference in this Annual Report on Form 10-K for the year ended December 31, 2006 (this “Annual Report”) of Pogo Producing Company (the “Company”) 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 the Company’s 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, results of operations, 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

·       strategic transactions, including the sale of part or all of the Company, or changes to the Company’s business plan, that may result from its strategic alternative process

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 Vietnam and New Zealand. As of December 31, 2006, the Company had interests in approximately 4,800,000 gross leasehold acres in major oil and gas provinces in North America, approximately 6,354,000 gross acres in New Zealand and approximately 1,480,000 gross acres in Vietnam. 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, 2006, approximately 94% 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. The operating regions are its Canadian Operations, its Western U.S. Region, which is active in the Permian Basin area of West Texas and Southeast New Mexico, the Panhandle of Texas, the San Juan Basin in New Mexico and the Wind River Basin in Wyoming; its Gulf Coast Region, which includes the Company’s onshore operations principally in South Texas 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 its Asia and Pacific Region, which has responsibility for the Company’s operations in New Zealand and Vietnam. The New Ventures Group is primarily responsible for identifying new projects and opportunities for the Company outside the United States.

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

Recent Developments

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

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 is headquartered in

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Midland, Texas, and maintains an additional office in Tulsa, Oklahoma. In addition the Company has four field offices in West Texas, three field offices in southeastern New Mexico and three 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, 2006, accounted for approximately 62% of the Company’s total proved reserves, with the Gulf Coast Region and the Western U.S. Region contributing approximately 12% and 50%, respectively, of the Company’s total proved reserves. During 2006, approximately 64% of the Company’s natural gas production and 39% of its oil and condensate production was from its domestic onshore properties, contributing approximately 51% of the Company’s consolidated oil and gas revenues.

The Los Mogotes Field, which is part of the Company’s Gulf Coast Region, consists of approximately 22,420 gross 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 2006, the Company’s interests in Los Mogotes produced an average of approximately 35 MMcf per day of natural gas, accounting for approximately 13% of the Company’s natural gas production for the period. As of December 31, 2006, the Company’s proved reserves associated with the Los Mogotes Field were 45 MBbls of oil, condensate and natural gas liquids and 97,252 MMcf of natural gas, which together represented approximately 4.4% of the Company’s total proved reserves. As of that date, the Company’s leasehold interests in the field included 13,329 net acres of developed lands and 1,953 net acres of undeveloped lands, with approximately 107 net producing wells and 161 gross producing wells. The map below depicts the location of the field.

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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 in the Wind River Basin located in Central Wyoming. The Company owns various working interests in the Madden Unit, which average approximately 14% across the unit area. In 2006, the Company’s interests in the Madden Unit produced an average of approximately 36 MMcf per day of natural gas, accounting for approximately 13% of the Company’s natural gas production for the period. As of December 31, 2006, the Company’s proved reserves associated with the Madden Unit were 59 MBbls of oil, condensate and natural gas liquids and 241,501 MMcf of natural gas, which together represented approximately 10.9% of the Company’s total proved reserves. As of that date, the Company’s leasehold interests in the unit included 3,094 net acres of developed lands and 7,353 net acres of undeveloped lands, with approximately 33 net producing wells and  236 gross producing wells. The map below depicts the location of the unit.

Exploration and Development

The Company’s onshore capital and exploration expenditures for 2006 were approximately $577,400,000, excluding approximately $998,500,000 of net property acquisitions. Comparable expenditures for 2005 and 2004 were approximately $251,400,000 (excluding approximately $59,500,000 of net property acquisitions) and $196,500,000 (excluding approximately $489,600,000 of net property acquisitions), respectively. The increase in the Company’s onshore capital and exploration expenditures for 2006, compared to 2005, resulted primarily from expenditures related to increased exploratory and development drilling. The Company has currently budgeted approximately $720,000,000 for capital and exploration expenditures during 2007 in its domestic onshore areas.

The Company generally conducts its onshore activities through 100% ventures as well as joint ventures and other interest sharing arrangements with major and independent oil companies. The

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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 Southeastern New Mexico for more than 27 years. In addition to those areas, in recent years the Company has expanded its exploration and production efforts to also include the Texas Panhandle, the San Juan Basin of northwest New Mexico and the Wind River Basin of Wyoming. In 2006, the Company participated in the drilling of 258 wells in all of these areas (88% of which were successfully completed). The Company believes that during recent years it has been one of the more active companies drilling for oil and natural gas in the Permian Basin of West Texas, Southeastern New Mexico and the Texas Panhandle.

During 2007, the Company plans to drill approximately 21 exploratory wells and 103 development wells in various known fields and exploratory prospects located in West Texas, southeast New Mexico, and the Texas Panhandle. Drilling objectives for these wells range in vertical depth from 4,500 feet to 17,000 feet below the surface and target numerous formations including, among others, the Grayburg, Delaware (Bell Canyon, Cherry Canyon, Brushy Canyon), Spraberry, Bone Spring, Wolfcamp, Granite Wash, Strawn, Atoka, Morrow and Mississippian and Hunton formations.

The Company also plans to continue an active development drilling program in the San Juan Basin of northwest New Mexico. Twenty wells are expected to be drilled in several prospects in this area during 2007. The primary targets are the Fruitland Coal and Dakota 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 Fort 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 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 258 wells drilled in the Western Region in 2006, 36 of those wells were drilled in the Madden Unit.  Recent drilling activity in the unit has focused on the Lower Fort Union formation, where productive zones have historically been found at depths from approximately 5,500 feet to 11,000 feet below the surface. The company expects that the unit operator will conduct a 2007 drilling program of approximately 25 to 30 wells which will target, among other objectives, the Lower Fort Union Sands and the shallower (3,500 feet) Shotgun Sands.

Acquisition of Latigo.   On May 2, 2006, the Company acquired Latigo Petroleum, Inc. a privately owned exploration and production company, for a purchase price of approximately $764.9 million, including approximately $210 million to retire Latigo’s bank debt and purchase price adjustments. As of December 31, 2006, proved reserves attributed to Latigo properties were approximately 29 MMBls of oil, condensate and natural gas liquids and 153,623 MMcf of natural gas. This acquisition included approximately 404,000 net acres of leasehold. Its development activities are concentrated in Texas, including the Collie Field in Reeves and Ward counties in West Texas, and the Courson Ranch area located primarily in Roberts and Ochiltree Counties in the Texas Panhandle. Exploration opportunities in the Panhandle have been identified in multiple areas, including on a concentration of ranches controlled by Latigo which are principally located in Roberts and Hutchinson Counties, Texas. During 2007, the company plans to drill approximately 52 exploratory and development wells on its Latigo properties.

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

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

The Gulf Coast Region’s development activities in 2006 were focused on its 64,000 gross acres of leasehold in South Texas’ Webb and Zapata Counties. The Region has been developing gas reserves primarily in its Los Mogotes, Hundido, South Hundido and Hereford Ranch Fields that produce from the Eocene Wilcox formation, found at depths generally ranging from 7,000 to 14,000 feet below the surface. The Company’s working interest in these wells ranges from 49% to 100% and the Company has historically operated over 80% of its working interest in these wells. A total of 34 wells were drilled in these fields in 2006. The Company has planned an active drilling program here and has 27 locations budgeted for drilling in 2007. Identification of additional development drilling locations in these fields is an iterative and continuing process. The Company believes that as additional locations are identified there will be continued successful development of these properties in future years.

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

In Polk and Tyler Counties, Texas, the Company’s Gulf Coast Region is exploring the Cretaceous Woodbine and Austin Chalk Formations for new oil and gas reserves. The Company owns 128 square miles of new, proprietary 3-D seismic data and interpretation of that data has yielded a number of exploratory prospects, which are generally 100% owned and operated by the Company. The Company has interests in approximately 72,000 gross acres in this area. During 2006, the Company drilled and completed two high volume Austin Chalk discovery wells.

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

The Company is actively evaluating its contiguous 8,000 gross acres of leasehold in Jack and Wise Counties, Texas to determine the potential of the Mississippian Barnett Shale unconventional resource play. The Company holds a 75% working interest in this acreage. If test results warrant, the Company may drill additional wells here in 2007.

In southwest Indiana, the Company owns a 50% working interest in a Devonian New Albany Shale unconventional resource play that an industry partner operates. Approximately 253,000 gross acres are under lease. During 2006, the Company participated in drilling 13 productive gas wells. Fourteen horizontal New Albany Shale wells are connected to a central facility.

The Company’s Gulf Coast Region also evaluates the Company’s Mississippian Bakken Shale unconventional resource play in Williams and Dunn Counties, North Dakota. During 2006, the Company acquired a 100% working interest in over 81,000 gross acres and began drilling test wells. The Company anticipates that it will drill additional wells to appraise and develop this play in 2007.

Domestic Offshore Operations

Gulf of Mexico Region.   Approximately 6% of the Company’s total proved reserves as of December 31, 2006 were located in the Gulf of Mexico. During 2006, approximately 8% of the Company’s natural gas production and 21% of its oil, condensate and natural gas liquids production were from the Company’s domestic offshore properties and together contributed approximately 17% of the Company’s

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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 2006, 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 5,370 Bbls per day of oil, condensate and natural gas liquids, accounting for approximately 15% of the Company’s liquid hydrocarbon production for the period. As of December 31, 2006, the Company’s proved reserves for the Main Pass Block 61/62 Field were 7,858 MBbls of oil, condensate and natural gas liquids and 4,142 MMcf of natural gas, which together represented approximately 2.3% of the Company’s total proved reserves. The Company is the operator of a 50% 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, 2006, the Company’s leasehold interests in the Main Pass Block 61/62 Field included 4,995 net acres of developed lands and no undeveloped lands, with 17 net producing wells.

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, 2006, 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 2006 were $47,700,000. Comparable expenditures for 2005 and 2004 were approximately $88,700,000 and $150,300,000, respectively. The decrease in the Company’s domestic offshore capital and exploration expenditures for

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

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, sea floor conditions, and type of production handling equipment.

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

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, 2006, the Company owned interests in 73 federal leases and 11 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, New Zealand and Vietnam. 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 recent acquisitions are significant and may not be successful” and

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“—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 $327,100,000 (excluding approximately $22,400,000 of net property acquisitions) for 2006. Expenditures for 2005 and 2004 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) and $148,900,000 (approximately $5,700,000 excluding Thailand and Hungary operations), respectively. The increase in the Company’s capital and exploration expenditures for 2006 resulted primarily from increased expenditures for facilities costs and increased drilling activity.

The Company has currently budgeted approximately $258,000,000 for capital and exploration expenditures during 2007 in areas outside the United States, including approximately $250,000,000 in Canada.

Canadian Operations

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

Northrock conducts its activities through joint ventures with other Canadian oil and gas companies and operates its properties using both independent contractors and field personnel.

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, 2006, accounted for approximately 32% of the Company’s total proved reserves. During 2006, Northrock contributed approximately 28% of the Company’s natural gas production and 40% of its crude oil, condensate and natural gas liquids production.

In addition to crude oil and natural gas reserves and production, Northrock has a significant undeveloped land base. As of December 31, 2006, Northrock had more than one million net acres of undeveloped land for future exploration purposes including almost 300,000 net acres of undeveloped land in the Northwest Territories.

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Exploration and Development

In 2006 Northrock drilled 163 gross wells of which 152 gross wells were successfully completed, for an overall success rate of 93%. Drilling activity included 33 natural gas wells in the Sunchild/Ferrier area of West Central Alberta and 25 wells in the Mikwan/Huxley area of southern Alberta following a successful exploration program in 2005. These activities contributed significantly to the natural gas production growth that was experienced in Canada in 2006. The 2006 drilling program also included eight successful Coal Bed Methane wells in the Mikwan/Huxley area of Alberta of which five wells are expected to be tied-in by the middle of 2007.

For 2007, Northrock expects to continue an equally active exploration and development program and expects to drill 139 wells including a large scale natural gas exploration program in the Alberta foothills. The exploration and development program in Canada for 2007 will focus on various known fields in both Alberta and Saskatchewan.

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

Acquisitions

Northrock also has an acquisition program focused on properties that compliment existing exploration and development initiatives and on identifying new areas where significant development opportunities are anticipated. In 2006, Northrock spent $34 million to acquire interests in producing properties located primarily in the Mikwan/Huxley area of Alberta. For 2007, 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. During 2006, the Company farmed-out 50% of its working interest in these three permits to two industry partners. 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 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. The Company and its partners have agreed to drill at least one well in 2007 with a rig that the Company has under contract. The Company also anticipates acquiring additional 3-D seismic data over a portion of its Northern Taranaki permit areas in 2007. The Company has a commitment to drill one well on each of the three licenses by February 2008 or relinquish the licenses. Production permits of up to 40 years may be applied for if a commercial field is discovered.

During 2006, the Company was granted a petroleum exploration license over approximately 21,460 square kilometers (approximately 5.31 million acres) in the offshore East Coast Basin. The primary term of this license is for five years, subject to extension for up to an additional ten years, provided that at least half

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

Vietnam.   The Company, together with a joint venture partner, entered into a Production Sharing Contract with PetroVietnam, the state oil company of Vietnam, for Block 124, which covers approximately 1.48 million acres offshore central Vietnam. The initial term of the contract is seven years, consisting of a three year primary phase during which the Company is committed to acquire, process and interpret at least 800 square kilometers of 3-D seismic data and drill two exploration wells, followed by two consecutive year optional phases. The contract may be extended to a maximum term of 35 years if a commercial field is discovered.

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 sales 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.

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.

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 10—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, 2006, 2005 and 2004, 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 owns an approximate 13.68% interest in the Lost Cabin Gas Plant located in the Madden Unit, which currently is processing approximately 336 MMcf per day.

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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 approximately 50% 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 2006, crude oil sales to Shell Trading Company and gas sales to NGX each 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 financial condition. It could also result in a reduction of funds available under the Company’s bank credit

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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, 2006, 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 in such acres or wells.

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, 2006:

(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 19% of the Company’s total offshore net undeveloped acreage has expiring terms in 2007 and approximately 9% of the Company’s total onshore net undeveloped acreage has expiring terms in 2008.

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, 2006. 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 35 gross (19.3 net) oil wells and 136 gross (83.6 net) natural gas wells with multiple completions.

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

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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.

 

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Reserves

The following table sets forth information as to the Company’s net total proved and proved developed reserves as of December 31, 2006, 2005 and 2004, 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, for certain of its domestic properties acquired from Latigo, Ryder Scott Company—Canada (“Ryder Scott Canada”), for all of its Canadian properties, and Miller and Lents, Ltd. (“Miller and Lents”), for certain of its onshore Gulf Coast and Rocky Mountain properties, 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 reports cover 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 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, the Company’s proved reserves in

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Thailand consisted of 32,517 MBbls and 37,307 MBbls of oil, condensate and natural gas liquids, respectively. The Company had no proved reserves in Hungary as of December 31, 2004.

(b)          Excludes 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, 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. The Company had no proved developed reserves in Hungary as of December 31, 2004.

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

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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.

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 net revenues from gas reserves attributable to the Company’s interests, prices in effect at December 31, 2006 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 cash flows from liquids attributable to the Company’s interests, prices in effect at December 31, 2006 were used and these prices were held constant through to depletion of the properties. The future net cash flows 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 cash flows, 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 2006. 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.

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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 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.

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 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.

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

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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 2006, the Company incurred capital expenditures of approximately $6,382,000 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 $5,418,250 for expenditures involving environmental control facilities during 2007, 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 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

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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, 2006, the Company and its subsidiaries had 566 full-time employees, including 183 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 recent acquisitions are significant and may not be successful.

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

·       the acquired 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 acquisitions, some of which may materially exceed its estimates;

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

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

·       the Company may experience material difficulties and additional costs in integrating Northrock’s or Latigo’s operations, systems and personnel with its own; and

·       the Company may need to recognize additional impairment expense in the future on the unproved property acquired in the acquisitions (including interest capitalized in future periods).

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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.

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. 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. 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.

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;

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·       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. 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.

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’s ongoing capital requirements consist primarily of the following items:

·       funding its 2007 capital and exploration budget of $720 million;

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

·       future dividends.

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

·       available cash and cash investments;

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·       cash provided by operating activities;

·       funds available under its credit facility;

·       its uncommitted money market line(s) of credit; and

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

The Company financed a substantial part of the Northrock acquisition utilizing cash on hand, proceeds from the offering of its 6.875% Senior Subordinated Notes due 2017 and borrowings under its revolving credit facility. In addition, the Company financed a portion of its acquisition of Latigo utilizing borrowings under its revolving credit facility. Accordingly, these acquisitions reduce the availability of those resources for other capital requirements. Moreover, the uncertainties and risks associated with future performance and revenues will ultimately determine the Company’s liquidity and ability to meet anticipated capital requirements.

Rights to repayment or acceleration of up to $2.3 billion of the Company’s debt and other payments would be triggered by a change in a majority of the Board of Directors that is not approved by incumbent directors.

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

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

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A change in the majority of the Board of Directors as a result of the pending proxy contest would also trigger an obligation to make payments under the Company’s executive employment agreements (upon termination of employment by the executives during specified periods or in specified circumstances) and under the Company’s severance and retention program.

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. 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.

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 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

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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.

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.

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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.

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.

ITEM 1B.   Unresolved Staff Comments.

None.

ITEM 2.   Properties.

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

ITEM 3.   Legal Proceedings.

The Company is a party to various legal proceedings consisting of routine litigation incidental to its businesses, but believes that any potential liabilities resulting from these proceedings are adequately

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covered by insurance or are otherwise not material. See “Business—Government Regulations; Other Laws and Regulations.”

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

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

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

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

 

Mr. Van Wagenen, who joined the Company in 1979, has served in his current position since 1991. Prior to assuming their present positions with the Company, the business experience of each of the other executive officers for at least the last five years was as follows: Mr. Brunner, who joined the Company in 1994, served as Vice President—Operations from 1997 - 2002; Mr. Cooper, who joined the Company in 1979, served as Senior Vice President and Western Division Manager from 1998 - 2002; Mr. McCoy, who joined the Company in 1978, served as Senior Vice President from 1998 - 2002 and has served as Chief Administrative Officer since 1989; Mr. Beathard, who joined the Company in 1982, served as Vice President—Engineering from 1997 - 2002; Mr. Killelea who joined the Company in 2000, served as Vice President from 2001 - 2005, and has served as Corporate Secretary and General Counsel since 2004 and 2000, respectively; Mr. Ulm, who joined the Company in 1999, served as Vice President from 1999 - 2002, and has served as Chief Financial Officer since 1999; and Mr. Marlowe, who joined the Company in 1991, served as Controller from 1999 - 2004, and has served as Vice President—Accounting since 2004.

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PART II

ITEM 5.                Market for the Registrant’s Common Equity; Related Stockholder Matters and Issuer Purchases of Equity Securities.

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

 

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

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

The Company’s revolving credit facility (the “Facility”), under which the Company has borrowed funds, and the Indentures relating to the Company’s 8.250% Senior Subordinated Notes due 2011 (the “2011 Notes”), 7.875% Senior Subordinated Notes due 2013 (the “2013 Notes”), 6.625% Senior Subordinated Notes due 2015 (the “2015 Notes”) and 6.875% Senior Subordinated Notes due 2017 (the “2017 Notes”) contain covenants that may restrict the ability of the Company to pay future dividends on the Company’s Common Stock. For further discussion of the covenants, see “Note 4, Long Term Debt” to the Consolidated Financial Statements in this report. The Company does not believe that any of these agreements will restrict the Company’s ability to pay dividends on its Common Stock in the reasonably foreseeable future.

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

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

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

Comparison of Five-Year Cumulative Total Shareholder Return

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

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

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ITEM 6.              Selected Financial Data

In the following table, the Company’s financial, production and other data for 2005 and 2006 reflect the Company’s acquisition of Northrock Resources (“Northrock”) from and on September 27, 2005. The Company’s financial, production, and other data for 2006 also reflect the acquisition of Latigo Petroleum, Inc. (“Latigo”) from and on May 2, 2006. The Company’s results for periods presented prior to 2006 reflect its oil and gas exploration, development and production activities in the Kingdom of Thailand and Hungary as discontinued operations. The selected financial data should be read in conjunction with “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and notes thereto included under “Item 8—Financial Statements and Supplementary Data.”

 

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

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

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

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