10-K405 1 0001.txt FORM 10-K -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ---------------- FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 [_] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the transition period from to Commission File No. 1-7792 POGO PRODUCING COMPANY (Exact name of registrant as specified in its charter) Delaware 74-1659398 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 5 Greenway Plaza, P.O. Box 2504 Houston, Texas 77252-2504 (Address of principal executive (Zip Code) offices) Registrant's telephone number, including area code: (713) 297-5000 ---------------- Securities registered pursuant to Section 12(b) of the Act: Title of each class: Name of each exchange on which Common Stock, $1 par value registered: New York Stock Exchange Preferred Stock Purchase Rights Pacific Exchange Pogo Trust I 6 1/2% Cumulative New York Stock Exchange Quarterly Income New York Stock Exchange Convertible Preferred Securities, Series A Securities registered pursuant to Section 12(g) of the Act: 5 1/2% Convertible Subordinated Notes due June 15, 2006 ---------------- 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 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 [_] 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] The aggregate market value of the Common Stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $595,449,518 as of March 1, 2000 (based on $26.91 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange Composite Tape on such date). 40,770,183 shares of the registrant's Common Stock were outstanding as of March 1, 2001. DOCUMENT INCORPORATED BY REFERENCE Portions of the Company's definitive Proxy Statement respecting the annual meeting of shareholders to be held on April 24, 2001 (to be filed not later than 120 days after December 31, 2000) are incorporated by reference in Part III of this Form 10-K. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- FORWARD LOOKING STATEMENTS The statements included or incorporated by reference in this Report on Form 10-K for the year ended December 31, 2000 (this "Annual Report") include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included herein or therein other than statements of historical fact are forward-looking statements. When used herein or therein, the words "anticipate," "estimate," "expect," "objective," "projection," "forecast," "goal," and similar expressions are intended to identify forward-looking statements. Such forward-looking statements include, without limitation, the statements herein and therein regarding the timing of future events regarding the operations of Pogo Producing Company (the "Company") and its subsidiaries, and the statements set forth herein under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources" regarding the Company's anticipated future financial position and cash requirements. Although the Company believes that the expectations reflected in such 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 risk factors set forth below 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 . our ability to successfully and profitably find and produce oil and gas . uncertainties associated with the United States and worldwide economies . current and potential governmental regulatory actions in countries where the Company owns an interest . substantial competition from larger companies . the Company's ability to implement cost reductions . 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 owns an interest, particularly Southeast Asia . covenant restrictions in the Company's indebtedness . the Company's ability to successfully complete the merger with NORIC Corporation ("NORIC") and to integrate the operations of its subsidiary, North Central Oil Corporation ("North Central") into the Company Many of those 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. 1 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 contained in this Annual Report, unless otherwise noted, are reported on a "net" basis. Information regarding production, 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 located offshore in the Gulf of Mexico, onshore in selected areas in New Mexico, Texas and Louisiana, and internationally, primarily in the Gulf of Thailand and in Canada. As of December 31, 2000, the Company had interests in 99 lease blocks offshore Louisiana and Texas, approximately 341,376 gross acres onshore in the United States and Canada, approximately 714,053 gross acres offshore in the Kingdom of Thailand, approximately 193,631 gross acres in the Danish and U.K. sectors of the North Sea and approximately 778,136 gross acres in Hungary. On November 19, 2000, the Company entered into an agreement and plan of merger with NORIC and certain shareholders of NORIC signatories thereto, which provided for the merger (the "Merger") of the Company and NORIC. The Company expects the Merger to occur in mid-March following satisfaction of all conditions precedent including approval by the Company's shareholders at a meeting scheduled for March 13, 2001. The principal asset of NORIC is its wholly-owned subsidiary, North Central, a company that explores for and produces oil and natural gas principally in onshore and offshore Gulf Coast areas and Wyoming. A more complete description of North Central and the Merger is set forth in the Company's definitive proxy statement filed with the Commission on February 6, 2001. Following consummation of the Merger, the Company will file a copy of North Central's audited annual consolidated financial statements for the year ended December 31, 2000. Except where expressly noted, the information contained in this Annual Report relates only to the Company and does not include either historical information regarding North Central or the future impact of the Merger on the Company. The Company organizes its exploration and production activities principally into four operating divisions and a New Ventures Group. The operating divisions are its Offshore Division, which is responsible for the Company's operations offshore Texas and Louisiana in the Gulf of Mexico, its Western Division, which is active in the Permian Basin area in New Mexico and West Texas, its Onshore Division, which includes the Company's onshore operations principally in South Texas, East Texas, Louisiana and Western Canada (principally in the provinces of Alberta and British Columbia) and the International Division, which has responsibility for the Company's operations on its Block B8/32 Concession in the Kingdom of Thailand (the "Thailand Concession"), as well as the Company's exploration licenses in the North Sea. The Company's New Ventures Group is currently responsible for the Company's exploration activities in Hungary. Domestic Offshore Operations Historically, the Company's interests have been concentrated in the Gulf of Mexico, where approximately 33% of the Company's proved reserves were located as of December 31, 2000. During 2000, approximately 44% of the Company's natural gas production and approximately 27% of its oil and condensate production was from its domestic offshore properties, contributing approximately 35% of the Company's consolidated oil and 2 gas revenues. The Company's exploration and development efforts are primarily focused in shallower waters of the Outer Continental Shelf where the Company held interests in 79 lease blocks on December 31, 2000. In recent years, the Company has expanded its exploration efforts further offshore into deeper waters where the Company currently believes there are selective opportunities for discovering and profitably producing substantial quantities of oil and gas. As of December 31, 2000, the Company has interests in 20 lease blocks in water depths that range from 600 feet to approximately 4,900 feet. Exploration and Development The scope of exploration and development programs relating to the Company's offshore interests is affected by prices for oil and gas, and by federal, state and local legislation, regulations and ordinances applicable to the petroleum industry. The Company's domestic offshore capital and exploration expenditures for 2000 were approximately $63,600,000, or 12% higher than the Company's domestic offshore capital and exploration expenditures of approximately $56,900,000 (excluding approximately $1,500,000 of net property acquisitions) for 1999, and 6% lower than the Company's domestic offshore capital and exploration expenditures of approximately $68,000,000 (excluding approximately $5,000,000 of net property acquisitions) for 1998. The increase in the Company's domestic offshore capital and exploration expenditures for 2000, compared with 1999, resulted primarily from increased exploratory and development drilling and exploration expenditures on new 3-D seismic data. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." The Company has currently budgeted approximately $124,000,000 for capital and exploration expenditures during 2001 in the Gulf of Mexico. A substantial portion of this budget, over $60,000,000, is related to fabrication and installation of a platform on the Company's recently discovered Main Pass Blocks 61/62 Field and installation of subsea completions and platform tiebacks at the Company's Ewing Banks Blocks 871/872 Field and Mississippi Canyon Blocks 661/705 Field, all of which are currently expected to come on production prior to the end of 2001. The Company maintains a significant presence in the Gulf of Mexico where it participated in drilling 27 successful wells during 2000, bringing the total number of producing oil and gas wells in the Gulf of Mexico that the Company held an interest to 182 at December 31, 2000. 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 which 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 34 of the 99 offshore leases in which it had an interest on December 31, 2000. Platforms and related facilities are installed on an offshore lease block when, in the judgment of the lease interest owners, the necessary capital expenditures are justified. A decision to install a platform generally is made after the drilling of one or more exploratory wells with contracted drilling equipment. Platform costs vary depending on, among other factors, the number of well slots, water depth, currents, and sea floor conditions. Over the last several years, gross construction and installation cost of production platforms and related facilities located in shallower waters in which the Company shared a portion of the construction costs based on its ownership interest in the development ranged from approximately $3,000,000 to approximately $16,500,000. However, the Company's wholly-owned Main Pass Blocks 61/62 Field platform, which will be installed in 2001, is currently expected to cost approximately $29,000,000. Wells, platforms and related facilities are typically much more expensive in the deeper waters of the Gulf of Mexico. Occasionally, deep water developments can be performed by means of "subsea completion" technology with the production then piped back to an existing platform. The Company will participate in two subsea completion developments during 3 2001, at its Ewing Banks Blocks 871/872 Field and its Mississippi Canyon Blocks 661/705 Field, where the total facilities costs for both projects are currently estimated to be approximately $52,000,000 ($36,000,000 net to the Company's working interest). The Company believes that future development projects in the deep water areas of the Gulf of Mexico may require similar capital commitments, each of which must be justified in the then current and anticipated future product price environment. 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 December 1970. As a result of such purchases and subsequent activities, as of December 31, 2000, the Company owned interests in 93 federal leases and 6 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. As part of its strategy, the Company intends to continue an active lease evaluation program in the Gulf of Mexico in order to identify exploration and exploitation opportunities. During 2000, the Company was successful in acquiring interests in six lease blocks through federal Outer Continental Shelf oil and gas lease sales and two lease blocks by assignment from a third party. As in the case of prior sales, the extent to which the Company participates in future bidding on federal or state offshore lease sales will depend on the availability of funds and its estimates of hydrocarbon deposits, operating expenses and future revenues which reasonably may be expected from available lease blocks. Such estimates typically take into account, among other things, estimates of future hydrocarbon prices, federal regulations and taxation policies applicable to the petroleum industry. It is also the Company's objective to acquire certain producing leasehold properties in areas where additional low-risk drilling or improved production methods by the Company can provide attractive rates of return. Onshore Operations The Company's Onshore Division has staffs in Houston, Texas and Calgary, Alberta, Canada. The Company's Western Division has an office in Midland, Texas. The Company conducts its onshore operations in the United States directly and through its wholly-owned subsidiary, Arch Petroleum Inc. ("Arch"). The Company conducts its operations in Canada through its wholly-owned subsidiary, Pogo Canada Ltd. The Company's onshore operations constitute a growing area of the Company's reserves and production. Onshore reserves as of December 31, 2000, accounted for approximately 27% of the Company's total proved reserves. During 2000, approximately 20% of the Company's natural gas production and 25% of its oil and condensate production was from its onshore properties, contributing approximately 26% of the Company's consolidated oil and gas revenues. If the Merger with North Central is successfully completed, the Company currently anticipates that North Central's onshore operations will be integrated into the Company's Onshore and Western Divisions. Exploration and Development A major drilling objective of the Company in the Permian Basin is the Brushy Canyon (Delaware) formation which generally produces oil from depths of 6,000 to 9,000 feet. Since the Company began exploring in the Brushy Canyon (Delaware) formation in October 1989, it has participated in drilling 451 wells in the Permian Basin and West Texas areas through December 31, 2000, including 42 wells in 2000. The Company believes that during the past eight years it has been one of the most active companies drilling for oil and natural gas in the southeastern New Mexico (Lea and Eddy Counties) portion of the Permian Basin where the Company has interests in over 119,000 gross acres. Fields in the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of the Permian Basin are generally characterized by multiple producing zones in most wells. The Company has achieved rapid cost recovery with respect to its New Mexico wells drilled to date because of relatively low capital costs and high initial rates of production. 4 In Southwest Louisiana, the Company has participated in drilling 30 wells since 1996, including five wells in 2000, to test various prospects, primarily in the Hackberry and Yegua formations, almost all of which were identified on proprietary 3-D seismic surveys that the Company and its industry partners have acquired since 1995. The Company recently acquired a 3-D seismic survey covering approximately 39,000 acres in Southwest Louisiana. Interpretation of this data has identified seven drilling opportunities on acreage controlled by the Company, the first of which was being drilled as of December 31, 2000. The Company is also active in the James Lime play in North Texas and the Barnett Shale play in North Central Texas. In Canada, Pogo Canada Ltd. operates primarily in the province of Alberta, where it drilled four successful wells in 2000 and has currently budgeted to drill another nine wells in 2001. The Company generally conducts its onshore activities through joint ventures and other interest-sharing arrangements with major and independent oil companies. The Company operates many of its own onshore properties using independent contractors. The Company's onshore capital and exploration expenditures were approximately $55,100,000 (excluding approximately $8,400,000 of net property acquisitions) for 2000, or 114% higher than the Company's onshore capital and exploration expenditures of approximately $25,700,000 (excluding approximately $25,100,000 of net property acquisitions) for 1999, and 13% higher than the Company's onshore capital and exploration expenditures of approximately $48,800,000 (excluding approximately $133,100,000 of net property acquisitions, including approximately $131,500,000 related to the acquisition of Arch) for 1998. The increase in the Company's onshore capital and exploration expenditures for 2000, compared to 1999 and 1998, resulted primarily from increased exploratory and development drilling in all of its onshore core areas. The Company has currently budgeted approximately $64,500,000 for capital and exploration expenditures during 2001 in its onshore U.S. and Canadian areas. These amounts are exclusive of any capital and exploration expenditures on North Central properties after they are acquired, which the Company currently expects to be in the range of $75,000,000 for the calendar year. Lease Acquisitions As it has in recent years, in 2000 the Company also successfully participated in various onshore federal, state and provincial lease sales and acquired interests in prospective acreage from private individuals. As of December 31, 2000, the Company held interests in approximately 99,000 gross (44,000 net) acres onshore in the United States and Canada. International Operations The Company has conducted international exploration activities since the late 1970's in numerous oil and gas areas throughout the world. During 2000, the Company reorganized a substantial portion of its international operations under a new Dutch holding company known as Pogo Overseas Production B.V. Currently, a wholly-owned subsidiary of Pogo Overseas Production, Thaipo Limited ("Thaipo") maintains an office in Bangkok, Thailand from which it oversees operations on the Thailand Concession. Thaipo currently owns, directly or indirectly, a 46.34% working interest in the entire Thailand Concession. The remainder of the working interest is owned, directly or indirectly by Chevron Offshore (Thailand) Limited ("Chevron") (46.34%), a subsidiary of Chevron Corporation, and Palang Sophon Limited ("Palang") (7.32%). Through its majority ownership of Palang, Chevron owns or controls, directly or indirectly, 53.66% of the working interests in the Thailand Concession. Chevron is currently the operator of the Thailand Concession. Through voting procedures in the joint operating agreement governing the Thailand Concession, and the close working relationship between Chevron's and Thaipo's exploration staffs, Thaipo continues to exert substantial influence over the development of the Thailand Concession. As of December 31, 2000, the Company's proved reserves located in the Kingdom of Thailand accounted for approximately 40% of the Company's total proved reserves. During 2000, approximately 36% of the Company's natural gas production and 48% of its oil and condensate production came from its operations on the Thailand Concession, contributing approximately 38% of the Company's consolidated oil and gas revenues. 5 Exploration and Development The Company's international capital and exploration expenditures were approximately $53,400,000 for 2000, or 52% lower than the Company's international capital and exploration expenditures of approximately $111,500,000 for 1999 and 50% lower than the Company's international capital and exploration expenditures of approximately $107,400,000 for 1998. The decrease in the Company's international capital and exploration expenditures for 2000, compared to 1999 and 1998, resulted primarily from decreased expenditures due to completion of the Benchamas Field Phase I development which was substantially completed in 1999, that was not entirely offset by increased exploration drilling expenditures in the Kingdom of Thailand and increased exploration expenditures in Hungary and the North Sea. Substantially all of the Company's international capital expenditures for 2000 were related to the Company's license in the Kingdom of Thailand. However, during 2000, the Company incurred approximately $3,600,000 in exploration expenditures in Hungary, the North Sea and other parts of the world, with a majority of these expenditures related to 2-D seismic data acquisition in Hungary. The Company has currently budgeted approximately $86,600,000 for capital and exploration expenditures during 2001 in Thailand and other areas outside North America, including Hungary and the North Sea. Approximately $30,000,000 of these funds will be used to order, build and construct six platforms to be installed in the Kingdom of Thailand and almost $17,000,000 is budgeted for 3-D seismic surveys and exploratory drilling in Hungary. Thailand Concession Benchamas Field. In July 1997, the government of Thailand designated a portion of the Thailand Concession comprising approximately 102,000 acres as the Benchamas and Pakakrong production area or the "Benchamas Field." Production from the Benchamas Field commenced production in July 1999 from three production platforms, with natural gas and oil from these platforms delivered by undersea pipeline to a central processing and compression platform where the oil, condensate and natural gas is processed and separated. The natural gas is sold to The Petroleum Authority of Thailand ("PTT") and delivered into export pipelines for transportation to shore, while the oil and condensate produced from the field is stored on board a Floating Storage and Offloading system ("FSO"), known as the "Benchamas Explorer," for sale and ultimate transfer to shore by oil tanker. The FSO is moored in the Benchamas Field. Its capacity is approximately 1,400,000 Bbls of crude and condensate. Benchamas Field Phase I development was completed during the first quarter of 2000. It resulted in the drilling of 55 wells in the field, including 38 producing wells (14 of which were horizontal wells) and 17 water injection wells. Current Benchamas Field Phase II development plans call for the construction and installation of up to five more platforms in the field, with installation of the first platform currently expected to commence in the fourth quarter of 2001. Tantawan Field. In August 1995, at the request of Thaipo and its joint venture partners, the government of Thailand designated a portion of the Thailand Concession comprising approximately 68,000 acres as the Tantawan production area or the "Tantawan Field." Initial production from the Tantawan Field commenced on February 1, 1997. Currently, there are approximately 40 wells producing from five platforms. Oil and gas production from the Tantawan Field is gathered through pipelines from the platforms into a Floating Production Storage and Offloading system (an "FPSO") named the "Tantawan Explorer." The FPSO is a converted oil tanker with a capacity of slightly less than 1,000,000 Bbls, that is moored in the Tantawan Field, on which hydrocarbon processing, separation, dehydration, compression, metering and other production-related equipment is installed. Following processing on board the FPSO, natural gas produced from the field is delivered to PTT through an export pipeline. Oil and condensate produced from the field is stored on board the FPSO and transferred to shore by oil tanker. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources." Maliwan Field. In September 1997, the government of Thailand designated an additional approximately 91,000 acres of the Thailand Concession as the Maliwan production area or the "Maliwan Field." Development plans for this area are currently under way. Three additional wells were drilled in this area during 2000 and additional wells are planned for 2001. Current plans call for setting a small platform in the Maliwan 6 Field and to commence producing from it in the fourth quarter of 2001. Initial production from this first platform will be taken to the Benchamas Field production handling facilities for processing and sale. Other Portions of the Thailand Concession. Thaipo and its joint venture partners have identified other potentially promising areas on the Thailand Concession and surrounding acreage. In November 2000, approximately 124,000 additional acres of the Thailand Concession, known as the North Jarmjuree area, were designated as a production area. Development plans for this area are still being formulated. Two exploration wells were drilled in this area during 2000. Another five wells are currently budgeted for 2001 in the North Jarmjuree and surrounding areas. During 2000, Thaipo and its joint venture partners drilled three wells on areas of the Thailand Concession that are not currently designated as production areas and have currently budgeted to drill additional exploration wells, commencing in February 2001. Interpretation of the data provided by these wells and 3-D seismic data covering these areas is ongoing. Platforms are installed on the Thailand Concession in fields where, in the judgment of Thaipo and its joint venture partners, 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 and the area where the platform would be located has been designated a production area by the government of the Kingdom of Thailand. See "Contractual Terms Governing the Thailand Concession and Related Production." Platforms are used to accommodate both development drilling and additional exploratory drilling. A key focus of Thaipo and its joint venture partners has been to reduce the average cost of the platforms that they install so as to improve the overall economics of the project. The gross cost of the first five production platforms and related facilities in the Tantawan Field and the first three production platforms in the Benchamas Field averaged approximately $20,000,000 per platform. However, employing advanced platform facility design and advanced drilling and completion techniques, including slimhole, batch and horizontal drilling, the six new minimum facility platforms that have been ordered for installation in late 2001 and 2002 are expected to cost closer to $9,000,000 per platform. Platform costs vary and more (or less) expensive platforms could be required in the future depending on, among other factors, the number of slots, water depth, currents and sea floor conditions and the amount of facilities required to be placed on the platform. Other Areas of the World North Sea. On December 1, 1998, Pogo North Sea Ltd., a British subsidiary of the Company, together with two joint venture partners, were successful in obtaining a license from the United Kingdom governing approximately 113,000 acres in the British sector of the North Sea. Terms of the license provided for a minimum work commitment that involved the acquisition, processing and interpretation of 3-D seismic data over the block. This work commitment has been satisfied. The initial exploratory term of this license expires on December 1, 2004, unless otherwise extended or a production license is granted. Pogo North Sea Ltd. and its joint venture partners have acquired 3-D seismic data over the license and the surrounding area and are currently evaluating it for potential drilling prospects. On August 5, 1999, the Danish government approved the assignment of a 40% working interest in License 13/98 covering approximately 81,000 acres in the Danish sector of the North Sea. The Company's license interest is currently held by a Danish subsidiary known as Pogo Denmark ApS. The initial term of the license goes through June 14, 2004, unless otherwise extended or a production license is granted. Pogo Denmark ApS and its joint venture partners have acquired and interpreted 2-D and new 3-D seismic surveys over the license. A prospect has been identified and an exploratory well to test this prospect is currently budgeted for the latter part of this year. Hungary. On April 20, 1999, the Company's subsidiary Pogo Hungary Ltd. ("Pogo Hungary") was awarded a license to explore for oil and gas on approximately 778,000 acres in the Szolnok and Tompa areas of central and south central Hungary. The exploration term of the license is four years, with areas where commercial accumulation of hydrocarbons being held through the economic productive life of such reserves. During 2000, Pogo Hungary acquired over 888 kilometers of modern 2-D seismic data in the Szolnok area. 7 Interpretation of this data is ongoing. During the last quarter of 2000, Pogo Hungary commenced simultaneous acquisition of two 3-D seismic surveys. One 3-D survey covers approximately 129,000 acres, or a substantial portion, of the Tompa area, and the other covers approximately 42,000 acres of the Szolnok area and is referred to as the Kenderes 3-D survey. Pogo Hungary has identified another highly prospective area in the southern portion of the Szolnok area known as the Koros area, where it currently intends to acquire another 3-D survey during the latter half of this year. Depending upon the results of these surveys, Pogo Hungary has currently budgeted a multi-well drilling program for the latter half of this year in both the Tompa and Szolnok areas. In addition, Pogo Hungary continues to evaluate other international opportunities that are consistent with the Company's international exploration strategy and expertise. Contractual Terms Governing the Thailand Concession and Related Production The Thailand Concession was granted in August 1991. The initial exploratory term for the Thailand Concession expired on July 31, 2000. However, Thaipo and its joint venture partners were granted an extension of the exploration through July 1, 2001. Similar one-year extensions can also be applied for through July 1, 2005. Thaipo and its joint venture partners intend to continue to apply for extensions until they believe that all of the acreage has been adequately evaluated. For those portions of the Thailand Concession that have been designated as production areas, the initial production period term is 20 years, which is also subject to extension, generally for a term of ten years. See also "Miscellaneous; Sales." To date, the Benchamas Field, Tantawan Field, Maliwan Field and North Jarmjuree areas have been designated as production areas. Subject to governmental approval, other portions of the Thailand Concession may be designated production areas in the future. Production resulting from the Thailand Concession is subject to a royalty ranging from 5% to 15% of oil and gas sales, plus certain fixed U.S. dollar amounts payable at specified cumulative production levels. Revenue from production in Thailand is also subject to local income taxes and other similar governmental charges including a Special Remuneratory Benefit tax ("SRB"). Thaipo and its joint venture partners have entered into a thirty-year Gas Sales Agreement with PTT (the "Gas Sales Agreement"), governing gas production from the Tantawan Field and the Benchamas Field. The terms of the Gas Sales Agreement currently include a minimum daily contract quantity ("DCQ") of 125 MMcf per day, subject to certain exceptions and will in the future be based on a percentage of the remaining proved reserves, but in any event, will not be less than 125 MMcf per day. In addition, the Gas Sales Agreement gives PTT the right to nominate in any given week, 115% of DCQ or approximately 144 MMcf per day. During 2000, gas sales to PTT averaged approximately 145 MMcf per day. Due to an abundance of natural gas under contract to PTT from other producers, PTT has generally not taken significantly more than this amount. The DCQ is the minimum daily volume that PTT has agreed to take, or pay for if not taken, under the agreement. Thaipo and its joint venture partners are subject to certain penalties if they are unable to meet the DCQ, principal among which is a decrease in sales price of up to 25% of the then current sales price. Thaipo is currently meeting the minimum DCQ requirements, however, there can be no assurance that Thaipo will be able to continue to meet them in the future, in which case the penalty provisions of the Gas Sales Agreement would reduce the price received by Thaipo for its gas sold to PTT under the Gas Sales Agreement. The sales price under the Gas Sales Agreement is subject to automatic semi- annual adjustments based upon a formula which takes into account changes in: Singapore fuel oil prices; the U.S. Bureau of Labor Statistics Oilfield Machinery and Tool Index; the Thai wholesale producer price index; and the U.S./Thai currency exchange rate. However, the Gas Sales Agreement provides for adjustment on a more frequent basis in the event that certain indices and factors on which the price is based fluctuate outside a given range. As of December 31, 2000, the Company was receiving an average price of approximately $2.33 per Mcf under the Gas Sales Agreement. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Results of Operations; Foreign Currency Transaction Gain (Loss)" and "Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues." 8 Miscellaneous Other Assets The Company and a subsidiary, Pogo Offshore Pipeline Co., own interests in eight pipelines (excluding field gathering pipelines) through which offshore hydrocarbon production is transported. Through a wholly-owned subsidiary, Pogo Onshore Pipeline Company, the Company owns and operates a six inch in diameter pipeline that runs from just outside of Fort Worth, Texas to Wichita Falls, Texas. Industrial Natural Gas, L.C., a subsidiary of the Company, markets the sale and transmission of natural gas through this pipeline. In addition, the Company owns an approximately 19% interest in a cryogenic gas processing plant near Erath, Louisiana, which entitles it to process up to 186 MMcf of natural gas and 5,478 Bbls of natural gas liquids per day. The plant is not currently operating at full capacity. As part of the Company's ongoing efforts to focus on its core business of finding and producing oil and natural gas, the Company is exploring sales opportunities for these and other non-core assets if a favorable price can be obtained. The Company does not currently expect that the sale of any or all of these non-core assets would have a substantial material impact on the Company's business or operations, taken as a whole. Sales The marketing of 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 may 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 offshore properties are generally located in areas where a pipeline infrastructure is well developed and there is adequate availability in such pipelines to transport the Company's current and projected future production. Pogo may not be able to successfully market all of the oil and natural gas we find and could produce on the Thailand Concession. Currently, the only purchaser of natural gas is PTT, which maintains a monopoly over gas transmission and distribution in Thailand, including ownership of the two major (34 inches and 36 inches in diameter, respectively) natural gas pipelines that traverse our Thailand Concession. All oil and condensate production from the Tantawan Field is initially stored aboard the FPSO and is then sold to various third parties, including PTT, on a tanker load by tanker load basis at prices based on then current world oil prices, typically with reference to the Malaysian Tapis Blend crude oil benchmark price. Oil sales from our Thailand Concession are influenced by a number of factors including, among others, tanker availability, world-wide crude oil demand, size of the lifting and the perceived quality of crude oil produced. In addition, because much of the oil produced from the Thailand Concession is associated with natural gas, limitations on Thaipo's ability to produce natural gas could limit crude oil production as well. The crude oil purchaser is generally responsible for sending a tanker to off load the oil and condensate it has purchased. Crude oil and condensate production from the Benchamas Field is initially stored aboard the FSO and such production is currently also sold on a tanker load by tanker load basis, similar to the way Tantawan Field crude is currently marketed. Crude oil and condensate from the northern portion of the Maliwan Field, which is currently under development, is currently expected to also be processed at the Benchamas processing facilities and stored aboard the FSO for sale. See "International Operations; Contractual Terms Governing the Thailand Concession and Related Production." The marketing of onshore oil and gas production is also subject to the availability of pipelines, crude oil hauling and other transportation, processing and refining facilities as well as the existence of adequate markets. Generally, the Company's onshore oil and gas production is located in areas where commercial production of economic discoveries can be rapidly effectuated. Most of the Company's North American natural gas sales (exclusive of forward gas sales contracts) are currently made in the "spot market" for no more than one month at a time at then currently available prices. Prices on the spot market fluctuate with demand. Crude oil and condensate production is also generally sold 9 one month at a time at the price that is then currently available. Other than any oil and natural gas futures contracts which may exist from time to time, and which are referred to in "Miscellaneous; Competition and Market Conditions," and the Gas Sales Agreement with PTT for production from the Tantawan and Benchamas Fields (see "International Operations; Contractual Terms Governing the Thailand Concession and Related Production"), 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. With the exception of PTT, to whom all of the Company's gas production in Thailand is sold, and Enron Corp. and its affiliates, to whom total sales constituted 13% of the Company consolidated domestic revenues, sales to no customer in 2000 constituted more than 10% of the Company's consolidated Thai or domestic revenues. Risks Associated with Acquisitions From time to time the Company acquires, and may acquire in the future, additional interests in oil and gas properties, either through acquisition of the properties themselves or, as in the case of the Arch and North Central acquisitions, indirectly through the purchase of an equity interest in the entity owning such properties. The successful acquisition of such properties requires an assessment of several factors, including recoverable reserves, projected future cash flows, which are in part based upon future oil and gas prices, current and projected operating, general and administrative and other costs, 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. To the extent reasonably practicable and possible under the specific circumstances of each acquisition, the Company performs a review of the properties or entities prior to their acquisition. The Company believes that its review procedures are generally consistent with current industry practices. The Company's review and assessment process 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 a part of the problems. The Company is generally not entitled to contractual indemnification for many liabilities, acquiring the properties on an "as is, where is" basis. In addition, successful acquisitions frequently require the successful integration of operations, equipment and, in the case of indirect acquisitions, personnel. There can be no assurance that the Company will be able to successfully integrate operations and properties that it acquires and still achieve the anticipated synergies, cost savings and efficiencies. 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. 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. The average prices that we currently receive for our production are near historic highs. A future drop in oil or gas prices could have a material adverse effect on our cash flow and profitability. Sustained periods of low prices could cause us to shut in existing production and could also have a material adverse effect on the Company's operations and financial condition. It could also result in a reduction of funds available under the Company's bank credit facilities. 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. Such hedging transactions, historically, have never exceeded 50% of the Company's total oil and gas production on an energy equivalent basis for any given period. 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 for the covered period, which increases could be significant. As of December 31, 2000, the 10 Company was a party to the natural gas hedging contracts described in "Quantitative and Qualitative Disclosure About Market Risk." When the Company does engage in hedging activities, it frequently may satisfy its obligations with its own production or by the purchase (or sale) of third party production. The Company may also cancel all delivery obligations by offsetting such obligations with equivalent agreements, thereby effecting a purely cash transaction. Operating and Uninsured Risks The Company's operations are subject to risks inherent in the exploration for and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, pollution and other environmental risks. Offshore oil and gas operations are subject to the additional hazards of marine and helicopter operations, such as capsizing, collision and adverse weather and sea conditions. These hazards could result in substantial losses to the Company due to injury or loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. The Company carries insurance which it believes is in accordance with customary industry practices, but is not fully insured against all risks incident to its business. Drilling activities are subject to numerous risks, including the risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and fabrication yards. In periods of increased drilling activity resulting from high commodity prices such as the Company is currently experiencing, 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 certain 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. In periods during which the industry experiences a substantial decline in oil and gas prices, many of the Company's partners, particularly the smaller ones, can experience liquidity and cash flow problems. These problems may lead to their attempting to delay or slow down the pace of drilling or project development in order to conserve cash, to a point that the Company believes is detrimental to the project. In most cases, the Company has the ability to influence the pace of development through joint operating agreements. Some partners may be unwilling or unable to pay their share of the costs of projects as they become due. At worst, a partner may declare bankruptcy and refuse or be unable to pay its share of the costs of a project. The Company would then be required to pay this partner's share of the project costs. In most instances, the Company believes that it is contractually protected from such an event through its ability to take over the non-paying partner's share of the project and by applicable oil and gas lien laws and bankruptcy laws. The Company believes that it would ultimately recover any sums that it is owed by non- paying partners that do not meet their share of the costs of a project in a timely fashion. Risks of Foreign Operations Ownership of property interests and production operations in Thailand and in any other areas outside the United States in which the Company may choose to do business, are subject to the various risks inherent in foreign operations. These risks may include, among other things, currency restrictions and exchange rate fluctuations, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection and other political risks, risks of increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies and other uncertainties arising out of foreign government sovereignty over the Company's international operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Results of Operations; Foreign Currency Transaction Gain (Loss)," and 11 "Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues." The Company's international operations may also be adversely affected by laws and policies of the United States affecting foreign trade, taxation and investment. In addition, in the event of a dispute arising from foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the United States. The Company seeks to manage these risks by concentrating its international exploration efforts in areas where the Company believes that the existing government is stable and favorably disposed towards United States exploration and production companies. Exploration and Production Data In the following data, "gross" refers to the total acres or wells in which the Company has an interest and "net" refers to gross acres or wells multiplied by the percentage working interest owned by the Company. Acreage The Company owns interests in developed and undeveloped oil and gas acreage in various parts of the world. These ownership interests generally take the form of "working interests" in oil and gas leases that have varying terms. The following table shows the Company's interest in developed and undeveloped oil and gas acreage under lease as of December 31, 2000:
Developed Undeveloped Acreage(a) Acreage(b) --------------- ------------------- Gross Net Gross Net ------- ------- --------- --------- Domestic Offshore Louisiana (State)......................... 3,167 1,564 1,571 727 Louisiana (Federal)....................... 171,287 47,008 176,129 75,388 Texas (Federal)........................... 28,800 6,687 51,145 14,082 ------- ------- --------- --------- Total Domestic Offshore................. 203,254 55,259 228,845 90,197 ------- ------- --------- --------- Onshore Louisiana................................. 4,177 1,061 9,344 4,209 New Mexico................................ 39,919 27,996 85,248 64,649 Texas..................................... 24,054 9,148 76,752 44,671 Canada.................................... 20,752 3,035 78,197 41,068 Other..................................... 2,853 333 80 15 ------- ------- --------- --------- Total Onshore........................... 91,755 41,573 249,621 154,612 ------- ------- --------- --------- ------- ------- --------- --------- Total North America..................... 295,009 96,832 478,466 244,809 ------- ------- --------- --------- International Gulf of Thailand.......................... 385,035 178,431 329,018 152,471 North Sea................................. -- -- 112,729 45,092 Hungary................................... -- -- 778,136 778,136 Denmark................................... -- -- 80,902 32,361 ------- ------- --------- --------- Total International..................... 385,035 178,431 1,300,785 1,008,060 ------- ------- --------- --------- Total Company........................... 680,044 275,263 1,779,251 1,252,869 ======= ======= ========= =========
-------- (a) "Developed acreage" consists of lease acres spaced or assignable to production (including acreage held by production) on which wells have been drilled or completed to a point that would permit production of commercial quantities of oil or natural gas. "Developed acreage" in Thailand includes all acreage designated as a production area by the Thai government, which currently includes the Benchamas Field, the Tantawan Field, the Maliwan Field and the North Jarmjuree production area. 12 (b) Approximately 24% of the Company's total domestic offshore net undeveloped acreage and approximately 13% of the Company's total onshore net undeveloped acreage are under leases that have terms expiring in 2001 (unless otherwise extended). Approximately 32% of total domestic offshore net undeveloped acreage and approximately 7% of total onshore net undeveloped acreage are under leases with terms expiring in 2002 (unless otherwise extended). All of the Company's undeveloped acreage in the Kingdom of Thailand must be relinquished to the Thai government on July 31, 2001, unless designated as a production area or another extension to the exploration term is granted by the Thai government. See "International Operations; Contractual Terms Governing the Thailand Concession and Related Production." In addition, the Company holds certain other types of mineral interests, including fee interests (which never expire) and royalty interests (which generally terminate when the underlying mineral lease expires). The Company owns varying fee and royalty interests in 10,800 gross acres in Texas and a royalty interest in 5,000 gross acres (125 net acres) offshore Louisiana. Productive Wells and Drilling Activity The following table shows the Company's interest in productive oil and natural gas wells as of December 31, 2000. For purposes of this table "productive wells" are defined as wells producing hydrocarbons and wells "capable of production" (e.g., 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). This table does not include exploratory or developmental wells which have located commercial quantities of oil or natural gas but which are not capable of commercial production without the installation of material production facilities or which, for a variety of reasons, the Company does not currently believe will be placed on production.
Natural Oil Gas Wells(a) Wells(a) ----------- ---------- Gross Net Gross Net ----- ----- ----- ---- Offshore United States................................ 101 28.5 81 25.3 Onshore (U.S. and Canada)............................. 763 512.2 120 53.5 Kingdom of Thailand................................... 52 23.9 39 17.9 --- ----- --- ---- Total............................................... 916 564.6 240 96.7 === ===== === ====
-------- (a) One or more completions in the same bore hole are counted as one well. The data in the above table includes 14 gross (3.9 net) oil wells and 4 gross (1.2 net) natural gas wells with multiple completions. 13 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. A well is considered a dry hole upon reporting of permanent abandonment to the appropriate agency.
2000 1999 1998 --------------- --------------- --------------- Productive Dry Productive Dry Productive Dry ---------- ---- ---------- ---- ---------- ---- Gross Wells: Offshore United States Exploratory.............. 4.0 5.0 4.0 -- 5.0 1.0 Development.............. 23.0 3.0 11.0 -- 2.0 -- Onshore United States and Canada Exploratory.............. 14.0 5.0 3.0 3.0 9.0 4.0 Development.............. 39.0 -- 23.0 1.0 32.0 1.0 Offshore Kingdom of Thailand Exploratory.............. 7.0 3.0 4.0 -- 12.0 -- Development.............. 24.0 -- 42.0 -- 12.0 -- ----- ---- ----- ---- ----- ---- Total.................. 111.0 16.0 87.0 4.0 72.0 6.0 ===== ==== ===== ==== ===== ==== Net Wells: Offshore United States Exploratory.............. 2.16 2.37 1.32 -- 1.07 .25 Development.............. 6.19 1.00 3.37 -- .80 -- Onshore United States and Canada Exploratory.............. 3.81 2.46 1.63 1.65 5.08 2.19 Development.............. 28.09 -- 13.89 .80 22.61 .34 Offshore Kingdom of Thailand Exploratory.............. 3.24 1.39 1.85 -- 5.56 -- Development.............. 11.12 -- 19.46 -- 5.56 -- ----- ---- ----- ---- ----- ---- Total.................. 54.61 7.22 41.52 2.45 40.68 2.78 ===== ==== ===== ==== ===== ====
Average Production (Lifting) Costs 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."
2000 1999 1998 ---- ----- ----- Average Production (lifting) Costs(a): Located in the United States Natural Gas, Crude Oil, Condensate and Natural Gas Liquids (per Mcfe)................................................. $.82 $ .69 $ .61 ==== ===== ===== Located in Canada Natural Gas, Crude Oil, Condensate and Natural Gas Liquids (per Mcfe)................................................. $.88 $1.10 $ .65 ==== ===== ===== Located in the Kingdom of Thailand Natural Gas, Crude Oil and Condensate (per Mcfe)............ $.69 $ .99 $1.10 ==== ===== ===== Total Company............................................. $.77 $ .77 $ .71 ==== ===== =====
-------- (a) Production costs were converted to common units of measure on the basis of relative energy content. Such production costs exclude all depletion and amortization associated with property and equipment. 14 Reserves The following table sets forth information as to the Company's net proved and proved developed reserves as of December 31, 2000, 1999 and 1998, 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, as estimated by Ryder Scott Petroleum Engineers ("Ryder Scott"), the Company's independent petroleum engineers, in accordance with criteria prescribed by the Commission. Due in part to natural gas prices being at or near their historic highs on December 31, 2000, the Company does not currently believe that the calculation of estimated future net revenues using the assumptions prescribed by Commission guidelines and generally described below is representative of the true value of future net revenues from the Company's proved reserves. The future prices received by the Company for the sales of its production may be higher or lower than the prices used in calculating the estimates of future net revenues, and the operating costs and other costs relating to such production may also increase or decrease from existing levels.
As of December 31, ------------------------------ 2000 1999 1998 ---------- ---------- -------- Total Proved Reserves: Oil, condensate, and natural gas liquids (MBbls) Located in the United States and Canada....... 58,257 42,120 33,699 Located in the Kingdom of Thailand............ 37,065 36,656 33,811 ---------- ---------- -------- Total Company............................... 95,322 78,776 67,510 ========== ========== ======== Natural Gas (MMcf) Located in the United States and Canada....... 216,679 221,110 271,780 Located in the Kingdom of Thailand............ 153,304 153,588 168,389 ---------- ---------- -------- Total Company............................... 369,983 374,698 440,169 ========== ========== ======== Present value of estimated future net revenues, before income taxes (in thousands)(a) Located in the United States and Canada....... $1,948,894 $ 585,052 $294,629 Located in the Kingdom of Thailand............ 506,021 569,594 200,597 ---------- ---------- -------- Total Company............................... $2,454,915 $1,154,646 $495,226 ========== ========== ======== Total Proved Developed Reserves: Oil, condensate, and natural gas liquids (MBbls) Located in the United States and Canada....... 35,910 35,487 29,070 Located in the Kingdom of Thailand............ 24,747 18,408 4,298 ---------- ---------- -------- Total Company............................... 60,657 53,895 33,368 ========== ========== ======== Natural Gas (MMcf) Located in the United States and Canada....... 152,742 157,216 184,630 Located in the Kingdom of Thailand............ 87,236 88,041 40,424 ---------- ---------- -------- Total Company............................... 239,978 245,257 225,054 ========== ========== ======== Present value of estimated future net revenues, before income taxes (in thousands)(a) Located in the United States and Canada....... $1,246,068 $ 472,856 $242,574 Located in the Kingdom of Thailand............ 445,033 304,275 28,244 ---------- ---------- -------- Total Company............................... $1,691,101 $ 777,131 $270,818 ========== ========== ========
-------- (a) The Company believes, for the reasons set forth in succeeding paragraphs, that the present value of estimated future net revenues set forth in the Annual Report and calculated in accordance with Commission guidelines are not necessarily indicative of the true present value of the Company's reserves and, due to the fact that essentially all of the Company's domestic natural gas production is currently sold on the spot market, whereas all of the Company's Thai natural gas production is sold pursuant to a long-term gas sales contract, such estimates of future net revenues from the Company's domestic and Thai reserves are, accordingly, not useful for comparative purposes. See the discussion on the following pages for the prices used in making these calculations. 15 Natural gas liquids comprised approximately 7% of the Company's total proved liquids reserves and approximately 7% of the Company's proved developed liquids reserves as of December 31, 2000. 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. As set forth in the following table, in computing future revenues from gas reserves attributable to the Company's domestic interests, prices in effect at December 31, 2000 were used, including current market prices, contract prices and fixed and determinable price escalations where applicable. In accordance with Commission guidelines, 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 somewhat lower than December gas prices. For domestic 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 to depletion of the reserves. In computing future revenues from liquids attributable to the Company's domestic interests, prices in effect at December 31, 2000 were used and these prices were held constant to depletion of the properties. The future revenues are adjusted to reflect the Company's net revenue interest in these reserves as well as any ad valorem and other severance taxes but do not include, unless otherwise noted, any provisions for corporate income taxes. In computing future revenues from the Company's gas reserves attributable to the Company's interests in the Kingdom of Thailand, the current contract price under the Gas Sales Agreement was used, without giving effect to any of the adjustments provided for in the Gas Sales Agreement, due to their indeterminate nature as of December 31, 2000, in accordance with Commission guidelines. In computing future revenues from liquids attributable to the Company's interests in the Kingdom of Thailand, a price was used which the Company believes approximates the price that the Company would have received for its production from the Thailand Concession based upon the world market price for Malaysian Tapis Blend benchmark crude on December 31, 2000, and this price was held constant until depletion of the Company's reserves in the Kingdom of Thailand. The future revenues are adjusted to reflect the Company's net revenue interest in these reserves and the Company's obligations under the Thailand Concession, including the payment of SRB and applicable production bonuses, but does not include any provisions for U.S. or Thai corporate income or other taxes. In accordance with Commission guidelines, 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 were as follows:
As of December 31, -------------------- 2000 1999 1998 ------ ------ ------ Initial Weighted Average Price (in U.S. dollars): Oil, condensate, and natural gas liquids (per Bbl) Located in the United States and Canada.............. $26.10 $25.55 $10.45 ====== ====== ====== Located in the Kingdom of Thailand................... $24.23 $25.08 $12.68 ====== ====== ====== Natural Gas (per Mcf) Located in the United States and Canada.............. $10.14 $ 2.14 $ 2.01 ====== ====== ====== Located in the Kingdom of Thailand................... $ 2.27 $ 1.99 $ 1.81 ====== ====== ======
In accordance with Commission guidelines for calculating future net revenues, the operating costs for the leases and wells include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. Development costs are based on authorization for expenditure for the proposed work or actual costs for similar projects. The current operating and development costs were held constant throughout the life of the properties. For properties located onshore, the estimates of future net 16 revenues and the present value thereof do not consider the salvage value of the lease equipment or the abandonment cost of the lease since both are relatively insignificant and tend to offset each other. The estimated net cost of abandonment after salvage was considered for offshore properties where such costs net of salvage are significant. 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 2000. The future production rates from reservoirs now on production may be more or less than estimated because of, among other reasons, mechanical breakdowns and changes in market demand or allowables set by regulatory bodies. Properties that are not currently producing may start producing earlier or later than anticipated in the estimates of future production rates. There are numerous uncertainties in estimating the quantity of proved reserves and in projecting the future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those of Ryder Scott, the Company's reserve engineers. 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 revisions 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 Federal Energy Regulatory Commission ("FERC") and the Federal Trade Commission; with respect to reserves located in Canada, with the Alberta Energy Utilities Board and, with respect to reserves located in Thailand, the Kingdom of Thailand's Department of Mineral Resources and PTT, which the Company considers a quasi-governmental authority. 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 furnished by Ryder Scott in accordance with Commission guidelines because of the nature of the various reports required. The major differences generally include differences in the time as of which such estimates are made, 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. During 2000, no estimates by the Company of its total proved net oil and gas reserves were filed with or included in reports to any governmental authority or agency other than the Commission; and, with respect to reserves relating to the Company's properties located in Thailand, the Kingdom of Thailand's Department of Mineral Resources and PTT. Government Regulation The Company's operations are affected from time to time in varying degrees by political developments and governmental laws and regulations. Rates of production of oil and gas have for many years been subject to governmental conservation laws and regulations, and the petroleum industry has been subject to federal and state tax laws dealing specifically with it. Federal Income Tax The Company's operations are significantly affected by federal income tax laws. The principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, its domestic "intangible drilling and development costs" and to claim depletion on a portion of its domestic oil and gas properties based on 15% of its oil and gas gross income from such properties (up to an aggregate of 1,000 Bbls per day of domestic crude oil and/or equivalent units of 17 domestic natural gas) even though the Company has little or no basis in such properties. Under certain circumstances, however, a portion of such intangible drilling and development costs and the percentage depletion allowed in excess of basis will be tax preference items that will be taken into account in computing the Company's alternative minimum tax. Environmental Matters Domestic oil and gas operations are subject to extensive federal regulation and, with respect to federal leases, to interruption or termination by governmental authorities on account of environmental and other considerations including the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") also known as the "Superfund Law." The recent trend towards stricter standards in environmental legislation and regulation may continue, and this could increase costs to the Company and others in the industry. Oil and gas lessees are subject to liability for the costs of clean-up of pollution resulting from a lessee's operations, and may also be subject to liability for pollution damages. 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, as it has in the past, also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area. The operators of the Company's properties have numerous applications pending before the Environmental Protection Agency (the "EPA") for National Pollution Discharge Elimination System water discharge permits with respect to offshore drilling and production operations. The issue generally involved is whether effluent discharges from each facility or installation comply with the applicable federal regulations. 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 a federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. 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 must be demonstrated for most Company offshore platforms is $35,000,000. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities at no significant increase in expense over recent prior years. 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. The Company's onshore operations are subject to numerous United States and foreign federal, state, provincial and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment including CERCLA. Such laws and regulations, among other things, impose absolute liability on the lessee under a lease for the cost of clean-up of pollution resulting from a lessee's operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Federal, state, provincial and local initiatives to further regulate the disposal of oil and gas wastes are also pending in certain jurisdictions, and these initiatives could have a similar impact on the Company. 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 18 environmental control facilities would have been incurred absent environmental regulations as prudent, safe oilfield practice. During 2000, the Company incurred capital expenditures of approximately $1,128,000 for environmental control facilities, primarily relating to the cost of converting a well into a salt water disposal well, installation of pit and firewall spill liners, and routine site restoration costs. The Company has budgeted approximately $2,600,000 for expenditures involving environmental control facilities during 2001, including, among other things, the conversion of two wells to salt water disposal wells, 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 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 of the Department of the Interior (the "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 applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. The MMS is currently engaged in developing new oil and gas valuation regulations for royalty purposes. The gas rule was published in final form on December 16, 1997. Industry trade associations challenged portions of the rule and, on March 28, 2000, a district court invalidated the challenged regulations. The MMS has appealed the court's decision, and the appeal remains pending. The oil rule was published in final form on March 15, 2000. Portions of this rule have also been challenged by industry trade associations in court and the case remains pending, with no resolution expected in the near future. We are not in a position to predict the outcome of the litigation, but the Company believes that the impact of the final rules that emerge from the court review will not impact the Company to any greater extent than other similarly situated producers. Recently, the MMS and various state and municipal authorities have attempted to collect alleged underpayment of royalties from various integrated oil companies in connection with sale transactions between exploration and production affiliates and pipeline affiliates of the same company. The Company has not been served in any of these collection efforts, a fact that the Company believes is primarily due to its never having sold any oil or gas production from one of its affiliates to another. The Company does not believe that it has any material liability for underpayment of royalty in connection with affiliate transactions, including those described above. The FERC has recently embarked on wide-ranging regulatory initiatives relating to gas transportation rates and services, including the availability of market-based and other alternative rate mechanisms to pipelines for transmission and storage services. In addition, the FERC has announced and implemented a policy allowing pipelines and transportation customers to negotiate rates above the otherwise applicable maximum lawful cost-based rates on the condition that the pipelines alternatively offer so-called recourse rates equal to the maximum lawful cost-based rates. With respect to gathering services, the FERC has issued orders declaring that certain facilities owned by interstate pipelines primarily perform a gathering function, and may be transferred to affiliated and non-affiliated entities that are not subject to the FERC's rate jurisdiction. The Company cannot predict the ultimate outcome of these developments, nor the effect of these developments on transportation rates. Inasmuch as the rates for these pipeline services can affect the gas prices received by the Company for the sale of its production, the FERC's actions may have an impact on the Company. However, the impact should not be substantially different on the Company than it will on other similarly situated gas producers and sellers. 19 Employees As of December 31, 2000, the Company and its subsidiaries had 161 full-time employees, including seven in its Bangkok, Thailand office and seven in its Calgary, Canada office. None of the Company's employees are presently represented by a union for collective bargaining purposes. The Company considers its relations with its employees to be excellent. 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 covered by insurance or are otherwise immaterial at this time. See "Business--Government Regulation; Other Laws and Regulations." ITEM 4. Submission of Matters to a Vote of Security-Holders. Not Applicable. ITEM S-K 401(b). Executive Officers of Registrant. Executive officers of the Company are appointed annually to serve for the ensuing year or until their successors have been elected or appointed. The executive officers of the Company, their age as of December 31, 2000 and the year each was elected to his present position are as follows:
Year Executive Officer Executive Office Age Elected ----------------- ---------------- --- ------- Paul G. Van Wagenen..... Chairman of the Board, President and Chief Executive Officer 54 1991 Stuart P. Burbach....... Executive Vice President--Exploration 48 1998 Jerry A. Cooper......... Senior Vice President and Western Division Manager 52 1998 R. Phillip Laney........ Senior Vice President and Manager of Worldwide New Ventures 60 1998 John O. McCoy, Jr....... Senior Vice President and Chief Administrative Officer 49 1998 J. D. McGregor.......... Senior Vice President--Sales 56 1998 Barry W. Acomb.......... Vice President and Offshore Division Manager 48 1999 Bruce E. Archinal....... Vice President and Onshore Division Manager 48 1997 David R. Beathard....... Vice President--Engineering 42 1997 Stephen R. Brunner...... Vice President--Operations 42 1997 Frank Davis III......... Vice President--Land 54 1997 Thomas E. Hart.......... Vice President and Chief Accounting Officer 57 1999 Gerald A. Morton........ Vice President--Law and Corporate Secretary 42 1997 S. Clay Robinson, Jr.... Vice President and International Division Manager 46 1999 James P. Ulm, II........ Vice President and Chief Financial Officer 37 1999
Prior to assuming their present positions with the Company, the business experience of each executive officer for more than the last five years was as follows: Mr. Van Wagenen, who joined the Company in 1979, served as President and Chief Operating Officer of the Company since 1990; Mr. Burbach served as Vice President and Offshore Division Manager since rejoining the Company in 1991; Mr. Cooper, who joined the Company in 1979, served as Vice President and Western Division Manager for the Company since 1990; Mr. Laney, who joined the Company in 1977, served as Vice President and International Exploration Manager for the Company since 1991; Mr. McCoy, who joined the Company in 1978, served as Vice President and Chief Administrative Officer of the Company since 1989; Mr. McGregor, who joined the Company in 1981, served as 20 Vice President--Sales since 1988; Mr. Acomb served as Offshore Division Exploration Manager since joining the Company in 1994; Mr. Archinal, who joined the Company in 1982, served as the Company's Onshore Division Manager since 1994; Mr. Beathard, who joined the Company in 1982, served as Manager of Petroleum Engineering for the Company since 1991; Mr. Brunner, who joined the Company in 1994, served as Resident Manager of the Company's Thailand operations since 1995; Mr. Davis, who joined the Company in 1978, served as Land Manager for the Company since 1991; Mr. Hart was Vice President and Controller since 1988 and prior thereto was Controller since joining the Company in 1977; Mr. Morton was Associate General Counsel since joining the Company in 1993; Mr. Robinson served as International Division Exploration Manager since joining the Company in 1996; and Mr. Ulm served as Treasurer of Newfield Exploration Company from 1995 until joining the Company as its Vice President and Chief Financial Officer in August of 1999. PART II ITEM 5. Market for the Registrant's Common Stock and Related Security Matters. 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.
Low High --- ---- 1999 1st Quarter............................................... 8 15/16 14 1/2 2nd Quarter............................................... 11 15/16 21 3/8 3rd Quarter............................................... 18 1/8 23 7/16 4th Quarter............................................... 15 5/8 21 2000 1st Quarter............................................... 18 3/8 28 3/4 2nd Quarter............................................... 21 1/8 29 3/4 3rd Quarter............................................... 18 29 7/16 4th Quarter............................................... 22 1/2 33 3/16
As of March 1, 2001, there were 2,550 holders of record of the Company's Common Stock. In each of 1999 and 2000, the Company paid four quarterly dividends of $0.03 per share on its Common Stock. However, the declaration and payment of future 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 with its banks under which the Company has borrowed funds, and the Indentures relating to the Company's 8 3/4% Senior Subordinated Notes due 2007 (the "2007 Notes") and 10 3/8% Senior Subordinated Notes due 2009 (the "2009 Notes") contain covenants that may restrict the ability of the Company to pay dividends on the Company's Common Stock. The Company does not currently believe that any of these agreements will restrict the Company's ability to pay dividends on its Common Stock at any time in the reasonably foreseeable future. In addition, the 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities, Series A (the "Trust Preferred Securities") issued by the Company's subsidiary, Pogo Trust I, prohibit the Company from paying dividends on the Company's Common Stock if dividends have not been paid on the Trust Preferred Securities. 21 ITEM 6. Selected Financial Data.
For the Year Ended December 31, ------------------------------------------------ 2000 1999 1998 1997 1996 ---------- -------- -------- -------- -------- (Expressed in thousands, except per share and production data) Financial Data Revenues: Crude oil and condensate.... $ 272,932 $109,803 $ 74,703 $112,603 $ 96,908 Natural gas................. 190,401 111,152 116,148 158,500 94,589 Natural gas liquids......... 15,869 9,544 9,303 13,748 11,867 ---------- -------- -------- -------- -------- Oil and gas revenues........ 479,202 230,499 200,154 284,851 203,364 Pipeline sales and other.... 15,113 7,159 2,741 349 778 Gains (losses) on sales..... 3,676 37,458 (92) 1,100 (165) ---------- -------- -------- -------- -------- Total...................... $ 497,991 $275,116 $202,803 $286,300 $203,977 ========== ======== ======== ======== ======== Income (loss) before cumulative effect of change in accounting principle and extraordinary item.......... $ 89,023 $ 22,134 $(43,098) $ 37,116 $ 33,581 Extraordinary loss........... -- -- -- -- (821) Cumulative effect of change in accounting principle..... (1,768) -- -- -- -- ---------- -------- -------- -------- -------- Net income (loss)............ $ 87,255 $ 22,134 $(43,098) $ 37,116 $ 32,760 ========== ======== ======== ======== ======== Per share data: Income (loss) before cumulative effect of change in accounting principle and extraordinary item-- Basic...................... $ 2.20 $ 0.55 $ (1.14) $ 1.11 $ 1.01 Diluted.................... $ 1.99 $ 0.55 $ (1.14) $ 1.06 $ 0.97 Cash dividends on common stock...................... $ 0.12 $ 0.12 $ 0.12 $ 0.12 $ 0.12 Price range of common stock: High....................... $ 33.19 $ 23.44 $ 34.69 $ 49.88 $ 48.38 Low........................ $ 18.00 $ 8.94 $ 9.81 $ 27.00 $ 24.38 Weighted average number of common shares outstanding... 40,445 40,178 37,902 33,421 33,203 Long-term debt at year end... $ 365,000 $375,000 $434,947 $348,179 $246,230 Minority interest at year end......................... $ 144,913 $144,751 $ -- $ -- $ -- Shareholders' equity at year end......................... $ 358,271 $268,512 $249,660 $146,106 $107,282 Total assets at year end..... $1,083,522 $948,193 $862,396 $676,617 $479,242 Production (Sales) Data Net daily average production and weighted average price: Natural gas (Mcf per day).. 164,600 141,600 159,000 181,700 107,700 Price (per Mcf)............ $ 3.16 $ 2.15 $ 2.00 $ 2.39 $ 2.40 Crude oil-condensate (Bbl per day).................. 25,788 16,036 15,775 15,927 11,968 Price (per Bbl)............ $ 28.92 $ 18.76 $ 12.97 $ 19.37 $ 22.12 Natural gas liquids (Bbl per day).................. 2,141 2,077 2,422 2,923 2,173 Price (per Bbl)............ $ 20.25 $ 12.59 $ 10.52 $ 12.89 $ 14.92 Capital Expenditures Oil and gas: Domestic Offshore-- Exploration................ $ 18,700 $ 12,600 $ 20,200 $ 18,700 $ 16,800 Development................ 43,700 43,200 42,500 59,800 73,900 Purchase of reserves....... -- -- 5,000 900 -- Onshore North America-- Exploration................ 19,700 9,800 16,500 18,100 10,400 Development................ 34,700 19,800 28,100 38,400 27,800 Purchase of reserves....... 8,400 19,500 133,100 1,700 -- International-- Exploration................ 9,400 3,500 11,600 21,700 8,500 Development................ 51,500 106,300 95,500 62,500 54,700 Purchase of reserves....... -- -- -- 29,300 -- ---------- -------- -------- -------- -------- Total oil and gas.......... 186,100 214,700 352,500 251,100 192,100 Other........................ 700 2,200 6,300 4,000 1,600 ---------- -------- -------- -------- -------- Total....................... $ 186,800 $216,900 $358,800 $255,100 $193,700 ========== ======== ======== ======== ========
22 ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. On November 20, 2000, the Company announced that it had entered into an agreement and plan of merger with NORIC and certain NORIC shareholders. The Company has called a special meeting of shareholders for March 13, 2001 to obtain shareholder approval of the Merger. If the Company's shareholders approve the Merger, the Company currently expects that the Merger will be completed within several days after the shareholders' meeting. The Company will account for the Merger using the purchase method of accounting. Because the Merger has not yet been consummated, none of the information set forth in this Management's Discussion and Analysis of Financial Condition and Results of Operations or elsewhere in this Annual Report reflects the impact of the Merger or of the Company's future combined operation, except as expressly noted. On August 17, 1998, a wholly owned subsidiary of the Company merged with and into Arch in a stock-for-stock tax-free merger accounted for as a purchase. In connection with the merger, the Company repaid $51,749,000 of Arch's existing bank debt and production payment obligations. The Company also exchanged $5,000,000 of Arch's existing convertible subordinated notes, 727,273 shares of Arch preferred stock (having a liquidation preference of $20,000,000) and 17,321,804 shares of Arch common stock for approximately 2,500,000 shares of Common Stock. Results of Operations Net Income (Loss) The Company reported net income for 2000 of $87,255,000 or $2.16 per share ($97,704,000 or $1.95 per share on a diluted basis), compared to net income for 1999 of $22,134,000 or $0.55 per share (on both a basic and a diluted basis) and a net loss of $43,098,000 or $1.14 per share (on both a basic and a diluted basis) for 1998. Net income in 2000 was adversely affected by a one time $1,768,000 non-cash charge related to a change in accounting principles required by the Commission. Historically, the Company recorded oil and condensate inventory held for sale (principally in the FPSO and FSO in Thailand) at fair market value as of the close of the accounting period. However, the Commission recently announced that it would require such inventory to be recorded as inventory at cost. The $1,768,000 one-time charge reflects a catch up adjustment for years prior to 2000. The Company does not currently expect to incur any similar charges related to this issue in the future. Among other items affecting net income for 2000 and 1999 were net gains of $3,676,000 and $37,458,000, respectively, related to the Company's sale of certain non- strategic properties as part of its asset maximization plan. Net income for 1998 was affected by non-recurring expenses totaling approximately $2,285,000 ($1,485,000 or $0.04 per share on an after-tax basis) related to the Company's acquisition of Arch and impairments to its oil and gas properties of $30,813,000, primarily resulting from poor reservoir performance and persistent low oil and gas prices. Earnings per common share are based on the weighted average number of common shares outstanding for 2000 of 40,445,000 (50,155,000 on a diluted basis), compared to 40,178,000 (40,390,000 on a diluted basis) for 1999 and 37,902,000 (on both a basic and a diluted basis) for 1998. The increase in the weighted average number of common shares outstanding for 2000, compared to 1999, resulted primarily from the issuance of common stock upon the exercise of stock options pursuant to the Company's stock option plans. The increase in weighted average number of common shares outstanding for 2000, compared to 1998, resulted primarily from the issuance of 3,882,023 shares of its common stock upon the conversion of the Company's 5 1/2% Convertible Subordinated Notes due 2004 (the "2004 Notes") prior to their being redeemed on March 16, 1998, the issuance as of August 17, 1998 of approximately 2,500,000 shares of common stock to former holders of Arch capital stock and convertible debt securities in connection with the Company's acquisition of Arch and, to a lesser extent, the issuance of common stock upon the exercise of stock options pursuant to the Company's stock option plans. The earnings per share computation on a diluted basis in 2000 primarily reflects additional shares of common stock issuable upon the assumed conversion of the Company's 5 1/2% Convertible Subordinated Notes due 2006 (the "2006 Notes") and the Trust Preferred Securities, the elimination of related interest requirements, as adjusted for applicable federal income taxes and, to a lesser extent, the assumed exercise of options to purchase common shares. The earnings per share computation on a diluted basis in 1998 23 is identical to the basic earnings per share computation because there were no securities of the Company that were dilutive during the period. In addition, the number of common shares outstanding in the diluted computation is adjusted to include dilutive shares that are assumed to have been issued by the Company in connection with outstanding options, less treasury shares that are assumed to have been purchased by the Company from the option proceeds. Total Revenues The Company's total revenues for 2000 were $497,991,000, an increase of approximately 81% compared to total revenues of $275,116,000 for 1999, and an increase of approximately 146% from total revenues of $202,803,000 for 1998. The increase in the Company's total revenues for 2000, compared to 1999 and 1998, resulted primarily from increased oil and gas revenues and an increase in pipeline sales, that was partially offset, in comparison with 1999, by a decrease in gains on property sales. Oil and Gas Revenues The Company's oil and gas revenues for 2000 were $479,202,000, an increase of approximately 108% from oil and gas revenues of $230,499,000 for 1999, and an increase of approximately 139% from oil and gas revenues of $200,154,000 for 1998. The following table reflects an analysis of variances in the Company's oil and gas revenues (expressed in thousands) between 2000 and the previous two years:
2000 Compared to ----------------- 1999 1998 -------- -------- Increase (decrease) in oil and gas revenues resulting from variances in: Natural gas-- Price................................................. $ 52,148 $ 67,271 Production............................................ 27,101 6,982 -------- -------- $ 79,249 $ 74,253 ======== ======== Crude oil and condensate-- Price................................................. $ 59,457 $ 91,800 Production............................................ 103,672 106,429 -------- -------- $163,129 $198,229 -------- -------- Natural Gas Liquids.................................... $ 6,325 $ 6,566 -------- -------- Increase (decrease) in oil and gas revenues........... $248,703 $279,048 ======== ========
The increase in the Company's oil and gas revenues in 2000, compared to 1999 and 1998, is related to increases in the Company's crude oil and condensate production volumes, the average prices that the Company received for such production volumes, and, to a lesser extent, increases in the average price that the Company received for its natural gas and NGL production and an increase in natural gas production. The increase in oil and gas revenues for 2000, compared to 1998, was partially offset by a decline in NGL production. 24
% Change % Change 2000 1999 2000 to 1999 1998 2000 to 1998 ------ ------ ------------ ------ ------------ Comparison of Increases (Decreases) in: Natural Gas Average prices North America................. $ 3.69 $ 2.31 60 $ 2.09 77 Kingdom of Thailand (Thai Baht)(a)..................... 79 61 30 70 13 Company-wide average price.. $ 3.16 $ 2.15 47 $ 2.00 58 Average daily production volumes (MMcf per day) North America................. 106.2 102.6 4 122.2 (13) Kingdom of Thailand(a)........ 58.4 39.0 50 36.8 59 ------ ------ ------ Company-wide average daily production................. 164.6 141.6 16 159.0 4 ====== ====== ====== Crude Oil and Condensate Average prices North America................. $27.83 $17.43 60 $12.94 115 Kingdom of Thailand(a)........ $30.10 $23.49 28 $13.17 129 Company-wide average price.. $28.92 $18.76 54 $12.97 123 Average daily production volumes (Bbls per day) North America................. 13,432 12,517 7 13,214 2 Kingdom of Thailand(a)........ 12,356 3,519 251 2,561 382 ------ ------ ------ Company-wide average daily production................. 25,788 16,036 61 15,775 63 ====== ====== ====== Total Liquid Hydrocarbons Company-wide average daily production (Bbls per day)............... 27,929 18,112 54 18,197 53
-------- (a) Production from the Benchamas Field commenced in July 1999. Prices received for the Company's natural gas production during the period from October 1998 through August 1999 when the Company did not meet the contractual DCQ were negatively affected by the contractual provisions of the Gas Sales Agreement. Natural Gas Thailand Prices. The price that the Company receives under the Gas Sales Agreement for its natural gas production from the Thailand Concession normally adjusts on a semi-annual basis. However, the Gas Sales Agreement provides for adjustment on a more frequent basis in the event that certain indices and factors on which the price is based fluctuate outside a given range. During 2000, in addition to the two semi-annual adjustments, there was one additional adjustment resulting primarily from the fluctuation of the Baht against the dollar. In addition, prices received by the Company for its natural gas production during the period from October 1, 1998 through August 1999 were adversely affected by certain penalty provisions in the Gas Sales Agreement. See "Business International Operations; Contractual Terms Governing the Thailand Concession and Related Production." Due to the relative stability of the Baht-U.S. dollar exchange rate throughout much of 1999 and 2000, adjustments to the price that the Company receives under the Gas Sales Agreement have not been as frequent as they were in 1998. See "Foreign Currency Transaction Gain (Loss)," and "Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues." 25 Production. The increase in the Company's natural gas production during 2000, compared to 1999 and 1998, was primarily related to increased production from the Company's Thailand Concession resulting from a successful infill drilling program in the Tantawan Field and commencement of production from the Benchamas Field and production from the Company's Garden Banks Block 367 project, which was partially offset by decreased production from the Company's East Cameron Block 334 "E" platform and natural production declines from other Company properties. The decline in North American natural gas production from 2000 to 1998 primarily related to the sale, in early 1999 of the Company's interest in the Lopeno Field, decreased production from the Company's East Cameron Block 334 "E" platform and natural production declines from other Company properties, that was not entirely offset by increased production from the Company's Garden Banks Block 367 project and other development projects. Crude Oil and Condensate Thailand Prices. Since the inception of production from the Tantawan Field, crude oil and condensate has been stored on the FPSO until an economic quantity was accumulated for offloading and sale. The first such sale of crude oil and condensate from the Tantawan Field occurred in July 1997. Commencing in July 1999 when production began from the Benchamas Field, crude oil and condensate from that field has been stored on the FSO and sold as economic quantities were accumulated. Prices that the Company receives for its crude oil and condensate production from Thailand are based on world benchmark prices, typically as a differential to Malaysian Tapis Blend crude and are denominated in dollars. The differential has varied over the years and is influenced by a number of factors including, among others, tanker availability, world-wide crude oil demand, the size of the lifting and the perceived quality of the production from the Tantawan and Benchamas Fields. Over the last year, the differential has generally ranged anywhere from $0.90 above the Tapis Blend benchmark to $0.92 below. In addition, the Company is generally paid for its crude oil and condensate production from Thailand in U.S. dollars. As discussed previously under "Results of Operations; Net Income (Loss)," the Company records all crude oil held in the FPSO and the FSO at the end of an accounting period as inventory held at cost. When such crude oil is sold, usually during the following month, the difference between the cost of the crude oil and the sales price is recorded as income. Production. The increase in the Company's crude oil and condensate production during 2000, compared to 1999 and 1998, resulted primarily from increased production from the Company's Thailand Concession due to a full year's production from the Benchamas Field, and increased production from the Company's Western Division properties, which was partially offset by a decline in production from certain of the Company's other domestic properties, principally in the offshore Gulf of Mexico. NGL Production. The Company's oil and gas revenues, and its total liquid hydrocarbon production, reflect the production and sale by the Company of NGL, which are liquid products that are extracted from natural gas production. The increase in NGL revenues for 2000, compared with 1999 and 1998, primarily related to an increase in the average price that the Company received for its NGL and, with respect to 1999, a small increase in NGL production. The increase in NGL revenues for 2000, compared to 1999, was partially offset by a decrease in the Company's NGL production volumes. 26 Costs and Expenses
% Change % Change 2000 1999 2000 to 1999 1998 2000 to 1998 ------------ ------------ ------------ ------------ ------------ Comparison of Increases (Decreases) in: Lease Operating Expenses North America........ $ 60,072,000 $ 48,121,000 25 $ 48,158,000 25 Kingdom of Thailand.. 33,568,000 21,815,000 54 20,913,000 61 ------------ ------------ ------------ Total Lease Operating Expenses.......... $ 93,640,000 $ 69,936,000 34 $ 69,071,000 36 ============ ============ ============ General and Administrative Expenses............. $ 34,568,000 $ 29,865,000 16 $ 26,356,000 31 Exploration Expenses.. $ 15,291,000 $ 5,982,000 156 $ 9,802,000 56 Dry Hole and Impairment Expenses.. $ 28,608,000 $ 4,594,000 523 $ 41,736,000 (31) Depreciation, Depletion and Amortization (DD&A) Expenses............. $131,151,000 $104,266,000 26 $110,916,000 18 DD&A rate............ $ 1.08 $ 1.12 (4) $ 1.12 (4) Mcfe produced........ 121,580,000 91,351,000 33 97,894,000 24 Pipeline operating and natural gas purchases............ $ 15,090,000 $ 6,481,000 133 $ 2,142,000 604 Interest Charges.............. $ 34,064,000 $ 35,874,000 (5) $ 24,682,000 38 Capitalized Interest Expense............. $ 20,918,000 $ 17,733,000 18 $ 9,381,000 123 Minority Interest Dividends and costs associated with preferred securities of a subsidiary trust................ $ 9,965,000 $ 5,914,000 68 -- N/A Foreign Currency Transaction Gains (Loss)............... $ (3,174,000) $ 572,000 N/A $ 953,000 N/A Income Tax Benefit (Expense)............ $(66,969,000) $ (9,583,000) 599 $ 27,751,000 N/A
Lease Operating Expenses The increase in North American lease operating expenses for 2000, compared to 1999 and 1998, were primarily attributable to an increase of approximately $6,400,000 in severance taxes resulting from increased oil and gas prices, repair costs related to higher than expected tubing and completion failure rate number of offshore wells and generally increased costs resulting from an industry-wide increase in demand for oil field services and equipment. In addition, lease operating expenses for 1998 were reduced by $1,793,000 in refunds in connection with the Company's audit of a joint venture partner and settlement of a dispute with a vendor. The increase in lease operating expenses in the Kingdom of Thailand for 2000, compared to 1999 and 1998, was primarily related to a full year's operations in Benchamas Field which commenced production in July 1999, increased well maintenance and the presence in 1999 of a special credit related to contract services for which no equivalent benefit was experienced in 2000. A substantial portion of the Company's lease operating expenses in the Kingdom of Thailand relate to lease payments made in connection with the bareboat charter of the FPSO for the Tantawan Field and the FSO for the Benchamas Field. Collectively, these lease payments accounted for $15,109,000, $13,619,000 and $11,122,000 (net to the Company's interest) of the Company's Thailand lease operating expenses for 2000, 1999 and 1998, respectively. The Company currently expects these lease payments to decrease by approximately $526,000 (net to the Company's interest) for 2001 and in future years. See "Liquidity and Capital Resources; Capital Requirements; Other Material Long-Term Commitments." General and Administrative Expenses The increase in general and administrative expenses for 2000, compared with 1999 and 1998, was related to a decrease in the net amount of general and administrative expenses billed to joint venture partners, increased expenses associated with the Company's Thailand operations, as well as normal salary and concomitant benefit expense adjustments and, with respect to 1998, an increase in the Company's work force, 27 that was partially offset by a number of non-recurring expenses in 1998 arising in connection with the Company's acquisition of Arch totaling approximately $2,285,000, that included severance payments to former officers and employees of Arch as well as costs related to closing Arch's office in Ft. Worth, Texas. Exploration Expenses Exploration expenses consist primarily of rental payments required under oil and gas leases to hold non-producing properties ("delay rentals") and geological and geophysical costs which are expensed as incurred. The increase in exploration expenses for 2000, compared to 1999 and 1998, resulted primarily from increased seismic acquisition costs in the offshore Gulf of Mexico, a major seismic data reprocessing project in Thailand and the acquisition of 2-D and 3-D seismic data in Hungary and 3-D seismic data in the North Sea. Dry Hole and Impairment Expenses Dry hole and impairment expenses relate to costs of unsuccessful wells drilled, along with impairments resulting from the application of the Financial Accounting Standards Board's Statement of Financial Accounting Standards ("SFAS") No. 121 due to decreases in expected reserves from producing wells. The increase in dry hole and impairment expenses for 2000, compared with 1999, was principally related to an increased number of dry holes drilled in 2000 that resulted from increased drilling in 2000. The decrease in dry hole and impairment expenses for 2000, compared with 1998, was principally related to expenses charged in 1998 for the dry hole cost of the Company's Mustang Island Block A-51 well, and impairment expenses related to several of the Company's domestic properties as a result of low oil and gas prices and poor reservoir performance, that was partially offset by an increase in dry hole expense in 2000. Depreciation, Depletion and Amortization Expenses The Company accounts for its oil and gas activities using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Proved properties are reviewed whenever events or changes in circumstances indicate that the value of such property on the Company's books may not be recoverable. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Proved oil and gas properties are reviewed when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair value. Estimated fair value includes the estimated present value of all reasonably expected future production, prices and costs. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. The provision for DD&A expense is based on the capitalized costs, as determined in the preceding paragraph, plus future costs to abandon offshore wells and platforms, and is determined on a cost center by cost center basis using the units of production method. The Company generally creates cost centers on a field-by-field basis for oil and gas activities in the Gulf of Mexico and Gulf of Thailand. Generally, the Company establishes cost centers on the basis of an oil or gas trend or play for its oil and gas activities onshore in the United States and Canada. The increase in the Company's DD&A expenses for 2000, compared to 1999 and 1998, resulted primarily from an increase in the Company's natural gas and liquid hydrocarbon production that was only partially offset by a decrease in the Company's composite DD&A rate. The decrease in the composite DD&A rate for all of the Company's producing fields for 2000, compared to 1999 and 1998, resulted primarily from an increased percentage of the Company's production coming from certain of the Company's fields that have DD&A rates that are lower than the Company's recent historical composite rate, including the Benchamas Field, and a corresponding decrease in the percentage of the Company's production coming from fields that have DD&A rates that are higher than the Company's recent historical composite DD&A rate. 28 Pipeline Operating and Natural Gas Purchases The Company acquired primarily all of its pipeline interests as part of its acquisition of Arch on August 17, 1998. The Company purchases natural gas for transportation through the Pogo Onshore Pipeline, which runs from Wichita Falls, Texas to just outside of Fort Worth, Texas. This gas is then resold under firm contracts to its customers. The expense of purchasing the natural gas is reported on the Company's income statement under pipeline operating and natural gas purchases. Revenue from the sale of the natural gas is reported as revenue under pipeline sales and other. The increase in pipeline operating expenses and natural gas purchase costs for 2000, compared to 1999 and 1998, primarily relates to increased purchase costs for natural gas due to higher natural gas prices and, with respect to 1998, the fact that expenses for the pipeline were recorded for all of 2000, whereas expenses for 1998 did not commence until the pipeline was acquired as part of the Arch acquisition on August 17, 1998. Interest Interest Charges. The decrease in the Company's interest charges for 2000, compared to 1999, resulted primarily from a decrease in the debt outstanding, that was only partially offset by an increase in the average interest rates on the debt outstanding and increased commitment fees (due to reduced usage of the revolving credit facility). The increase in the Company's interest charges for 2000, compared to 1998, resulted primarily from an increase in the average interest rates on the debt outstanding (resulting primarily from the issuance of the 2009 Notes on January 15, 1999, which bear interest at a 10 3/8% annual interest rate) and, to a lesser extent, increased debt issuance expense being amortized that was not entirely offset by a decrease in the amount of debt outstanding. Capitalized Interest. The increase in capitalized interest for 2000, compared to 1999 and 1998, resulted primarily from an increase in the amount of capital expenditures subject to interest capitalization during 2000 ($248,344,000) compared to 1999 ($217,183,000) and 1998 ($137,956,000), that was only partially offset by a decrease in the computed rate that the Company uses to apply on such capital expenditures to arrive at the total amount of capitalized interest. The Company currently expects the amount of capital expenditures subject to interest capitalization to increase during 2001 due to fabrication of platforms and facilities to be installed in Thailand and in the offshore Gulf of Mexico. Minority Interest--Dividends and Costs Associated with Preferred Securities of a Subsidiary Trust Pogo Trust I, a subsidiary business trust, issued $150,000,000 of Trust Preferred Securities on June 2, 1999. The amounts recorded for 1999 and 2000 under Minority Interest--Dividends and Costs Associated with Preferred Securities of a Subsidiary Trust principally reflect cumulative dividends and, to a lesser extent, the amortization of issuance expenses related to the offering and sale of the Trust Preferred Securities. The increase in payments in 2000, compared to 1999, primarily reflect the fact that the Trust Preferred Securities were outstanding throughout 2000, but were only outstanding in the second half of 1999. Foreign Currency Transaction Gains (Loss) The foreign currency transaction gain and loss each resulted primarily from the fluctuation against the U.S. dollar of cash and other monetary assets and liabilities denominated in Thai Baht that were on the Company's subsidiary's financial statements during the respective periods. In early July 1997, the government of the Kingdom of Thailand announced that the value of the Baht would be set against the dollar and other currencies under a "managed float" program arrangement. This led to a precipitous decline in the value of the Baht against the dollar, resulting in the foreign currency transaction loss recorded by the Company in 1997. During both 1998 and 1999, the value of the Thai Baht generally strengthened against the dollar resulting in the gains recorded for each year. During 2000, the Thai Baht generally weakened against the dollar. This weakness had been attributed to, among other things, the negative impact on the economy of high crude oil prices, continued weakness in the banking sector, and political uncertainty surrounding the recently completed national elections. 29 The Company cannot predict what the Thai Baht to dollar exchange rate may be in the future. See "--Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues" and "Business--International Operations; Contractual Terms Governing the Thailand Concession." As of February 27, 2001, the Company was not a party to any financial instrument that was intended to constitute a foreign currency hedging arrangement. Income Tax Benefit (Expense) The increase in the Company's income tax expense for 2000, compared to 1999, resulted primarily from increased pre-tax income from North American operations and from pre-tax income from the Company's operations in the Kingdom of Thailand that was only partially offset by tax benefits in the United States for foreign taxes paid and the use, during 1999, of all of the Company's accrued foreign losses from the Company's operations in the Kingdom of Thailand. The Company's income tax benefit for 1998 resulted primarily from a pre-tax loss resulting from substantially lower revenues in the United States and the tax benefit of accrued foreign losses from the Company's operations in the Kingdom of Thailand. Liquidity and Capital Resources Cash Flows The Company's Consolidated Statement of Cash Flows for 2000 reflects net cash provided by operating activities of $239,059,000. In addition to net cash provided by operating activities, the Company received net proceeds of $3,745,000 from the sale of certain non-strategic properties and tubular stock and $6,115,000 from the exercise of stock options. During 2000, the Company repaid a net $10,000,000 under its revolving credit facility and other senior debt agreements, invested $139,062,000 of such cash flow in capital projects, spent $8,393,000 to purchase proved reserves, paid $9,750,000 in cash dividends to holders of its Trust Preferred Securities, paid $4,852,000 ($0.03 per share for each quarter of 2000) in cash dividends to holders of the Company's common stock and, in connection with the Merger, purchased natural gas floor contracts for $24,022,000. See "Quantitative and Qualitative Disclosures About Market Risk--Current Hedging Activity; Natural Gas." As of February 23, 2001, the Company's cash and cash investments were $135,922,000, its long-term debt stood at $365,000,000 and it had $150,000,000 in Trust Preferred Securities outstanding. Future Capital Requirements The Company's capital and exploration budget for 2001, which does not include any amounts that may be expended for the purchase of proved reserves or any interest which may be capitalized resulting from projects in progress, was established by the Company's Board of Directors at $275,000,000. The Company currently anticipates that its available cash and cash investments, cash provided by operating activities and funds available under its new revolving credit facility to be entered into in connection with the Merger and its uncommitted credit line will be sufficient to fund anticipated costs and expenses related to the Merger, the Company's ongoing operating, interest and general and administrative expenses, any currently anticipated costs associated with the Company's projects during 2001, and future dividend and distribution payments at current levels. The declaration of future dividends on the Company's equity securities will depend upon, among other things, the Company's future earnings and financial condition, liquidity and capital requirements, its ability to pay dividends and payments under certain covenants contained in its debt instruments, the general economic and regulatory climate and other factors deemed relevant by the Company's Board of Directors. 30 Other Material Long-Term Commitments Thaipo and its co-venturers in the Tantawan Field (collectively, the "Charterers") are parties to a Charter Agreement (the "Charter") with Tantawan Production B.V. for the charter of the FPSO for use in the Tantawan Field. See "Business--International Operations." The Charter expires on July 31, 2008, subject to extension. In addition, the Charterers have a purchase option on the FPSO throughout the term of the Charter. SBM Marine Services Thailand Ltd., has been contracted to operate the FPSO on a reimbursable basis throughout the initial term of the Charter. Liability on the Charter is full recourse as to each joint venturer, as to performance but the payment obligations are several, meaning that each joint venturer's payment obligations under the Charter are still limited to its percentage interest in the Tantawan Field. Thaipo's performance and payment obligations are fully and unconditionally guaranteed by the Company, but only as to Thaipo's pro rata share of the obligations arising under the Charter. The agreement to operate the FPSO is non-recourse to the Company. The Charter currently provides for a charter hire commitment of $24,000,000 per year ($11,122,000 net to Thaipo through January 31, 2007, and a decreasing amount thereafter. However, as a result of ongoing negotiations with the lessor of the FPSO and pending partner approval, the Company currently anticipates that this amount will be reduced to $22,860,000 per year ($10,600,000 net to Thaipo), effective retroactively to January 1, 2001. As of August 24, 1998, the Charterers entered into a Bareboat Charter Agreement (the "BCA") with Watertight Shipping B.V. for the charter of the FSO. See "Business--International Operations." The term of the BCA is for a period of ten years commencing on May 15, 1999. In addition, the Charterers have a purchase option on the FSO throughout the term of the BCA. The Charterers have also contracted with another company, Tanker Pacific (Thailand) Co. Ltd, to operate the FSO on a fixed fee basis throughout the initial term of the BCA. Performance of both the BCA and the agreement to operate the FSO are non- recourse to the Company. However the obligations of each joint venturer are full recourse to each joint venturer, but the payment obligations under the BCA are several, meaning that each joint venturer's payment obligations are limited to its percentage interest in the Thailand Concession. The BCA currently provides for a charter hire commitment of $8,515,000 per year ($3,946,000 net to Thaipo). Capital Structure Credit Facility and Uncommitted Credit Line. The Company has entered into a reserve-based credit facility (the "Credit Facility"), which was amended most recently as of November 17, 2000. The Credit Facility provides for a $250,000,000 revolving credit facility until July 1, 2002, after which the balance will be due in eight quarterly term loan installments, commencing October 31, 2002. The amount that may be borrowed may not exceed a borrowing base which is determined semi-annually and is calculated based upon substantially all of the Company's proved oil and gas properties. As of March 2, 2001, the Company's borrowing base was set at $225,000,000. The Credit Facility is governed by various financial and other covenants, including requirements to maintain positive working capital (excluding current maturities of debt) and a fixed charge coverage ratio, and limitations on indebtedness (including a total indebtedness limit of $590,000,000), creation of liens, the prepayment of subordinated debt, the payment of dividends, mergers and consolidations, investments and asset dispositions. In addition, the Company is prohibited from pledging borrowing base properties as security for other debt. Borrowings under the Credit Facility bear interest, at the Company's option, at a base (prime) rate plus a variable margin (currently none) or LIBOR plus a variable margin (currently 1.25%). The margin varies as a function of the percentage of the borrowing base being utilized. A commitment fee on the unborrowed amount that is currently available under the Credit Facility is also charged based upon the percentage of the borrowing base that is being utilized. As of March 2, 2001, there were no amounts outstanding under the Credit Facility. In connection with the NORIC Merger, the Company will terminate the Credit Facility and enter into a new revolving credit facility. Based on a term sheet agreed to with the lenders under the proposed new facility, the Company currently expects that the new credit facility will provide for a $515,000,000 revolving loan facility terminating five years after the closing of the Merger. The amount that may be borrowed under the new facility may not exceed a borrowing base which is determined semi-annually and will be calculated based upon 31 substantially all of the Company's proved oil and gas properties, including those of North Central. The Company expects that the initial borrowing base will be set at $475,000,000. The financial and other covenants will be substantially similar to those contained in the Credit Facility, with the following exceptions: there will be no express limitation on indebtedness; there will be a limitation on commodity hedging; and the Company will be obligated to pledge the stock of North Central and an affiliated subsidiary, and its inter-company receivables with North Central as security. The new revolving credit facility will also permit short-term "swing line" loans and the issuance of up to $50,000,000 in letters of credit as a part of the facility. Proceeds of the new facility will be used to fund anticipated costs and expenses related to the Merger, including retiring existing North Central debt and funding the cash portion of the consideration paid to NORIC shareholders and for other general corporate purposes. As of March 2, 2001, the Company also has available an uncommitted money market line of credit with a commercial bank. The line of credit is on an as available or as offered basis. Loans made under the line of credit are reflected as long-term debt on the Company's balance sheet because the Company currently has the ability and intent to reborrow such amounts under its Credit Facility. Under its Credit Facility, the Company is currently limited to incurring a maximum of $20,000,000 of additional senior debt, which would include debt incurred under the line of credit and under the banker's acceptances discussed below. Further, the 2007 Notes and the 2009 Notes also restrict the incurrence of additional senior indebtedness. See "; 2007 Notes" and "; 2009 Notes." The letter agreement permits either party to terminate it at any time. As of March 2, 2001, no amounts were outstanding under this agreement. 2009 Notes. On January 15, 1999, the Company issued $150,000,000 principal amount of 2009 Notes. The 2009 Notes bear interest at a rate of 10 3/8%, payable semi-annually in arrears on February 15 and August 15 of each year. The 2009 Notes are general unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company's senior indebtedness, which currently includes the Company's obligations under the Credit Facility, its unsecured credit line and its banker's acceptances, are equal in right of payment to the 2007 Notes, but are senior in right of payment to the Company's subordinated indebtedness, which currently includes the 2006 Notes. The Company, at its option, may redeem the 2009 Notes in whole or in part, at any time on or after February 15, 2004, at a redemption price of 105.188% of their principal value and decreasing percentages thereafter. The indenture governing the 2009 Notes also imposes certain covenants on the Company that are substantially identical to the covenants contained in the indenture governing the 2007 Notes, including covenants limiting: incurrence of indebtedness including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of asset sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and mergers, consolidations and the sale of assets. 2007 Notes. On May 22, 1997, the Company issued $100,000,000 principal amount of 2007 Notes. The 2007 Notes bear interest at a rate of 8 3/4%, payable semi-annually in arrears on May 15 and November 15 of each year. The 2007 Notes are general unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company's senior indebtedness, are equal in right of payment to the 2009 Notes, but are senior in right of payment to the Company's subordinated indebtedness. The Company, at its option, may redeem the 2007 Notes in whole or in part, at any time on or after May 15, 2002, at a redemption price of 104.375% of their principal value and decreasing percentages thereafter. The indenture governing the 2007 Notes also imposes certain covenants on the Company that are substantially identical to the covenants contained in the indenture governing the 2009 Notes described previously. 2006 Notes. The outstanding principal amount of 2006 Notes was $115,000,000 as of December 31, 2000. The 2006 Notes are convertible into Common Stock at $42.185 per share, subject to adjustment upon the occurrence of certain events. The 2006 Notes bear interest at a rate of 5 1/2%, payable semi-annually in arrears on June 15 and December 15 of each year. The 2006 Notes are currently redeemable at the option of the Company, in whole or in part, at any time, at a redemption price of 103.30% of their principal. The redemption premium will decline over the next several years. 32 Trust Preferred Securities. Pogo Trust I, a business trust in which the Company owns all of the issued common securities (the "Trust"), issued 3,000,000 Trust Preferred Securities having a liquidation preference of $50 per Trust Preferred Security, on June 2, 1999. The proceeds from the issuance of the Trust Preferred Securities were used to purchase $150,000,000 of the Company's 6 1/2% Junior Subordinated Convertible Debentures, due 2029 (the "Debentures"). The Debentures are the sole asset of the Trust. The financial terms of the Debentures are generally the same as those of the Trust Preferred Securities. The Trust Preferred Securities accrue and pay distributions quarterly in arrears at a rate of 6 1/2% per annum on the stated liquidation amount of $50 per Trust Preferred Security on March 1, June 1, September 1, and December 1 of each year to securities holders of record on the business day immediately preceding the distribution payment date. The Company has guaranteed, on a subordinated basis, distributions and other payments due on the Trust Preferred Securities to the extent that there are funds available in the Trust. The Company currently believes that, taken as a whole, the Company's guarantee of the Trust's obligations under the Preferred Securities constitutes a full and unconditional guarantee by the Company of the Trust's performance obligations. The Company may cause the Trust to defer the payment of distributions for successive periods up to 20 consecutive quarterly periods unless an event of default on the Debentures has occurred and is continuing. During such periods, accrued distributions on the Trust Preferred Securities will compound quarterly and the Company will generally not be permitted to declare or pay distributions on its common stock or debt securities that rank equal or junior to the Debentures. The Trust Preferred Securities are convertible at the option of the holder at any time into common stock of the Company at the rate of 2.1053 shares of Company common stock per Trust Preferred Security. This conversion rate will be subject to adjustment to prevent dilution and is currently equivalent to a conversion price of $23.75 per share of Company common stock. The Trust Preferred Securities are mandatorily redeemable upon maturity of the Debentures on June 1, 2029, or to the extent of any earlier redemption of any Debentures by the Company and are callable by the Trust at any time after June 1, 2002. In addition, if certain tax changes occur so that the Trust becomes subject to federal income taxes or interest payments made by the Company to the Trust on the Debentures are no longer deductible for federal income tax purposes, the Trust may liquidate and distribute Debentures to holders of the Trust Preferred Securities and, in certain circumstances, the Company may shorten the stated maturity of the Debentures to as early as June 2, 2014. Other Matters Inflation. Publicly held companies are asked to comment on the effects of inflation on their business. Currently annual inflation in terms of the decrease in the general purchasing power of the U.S. dollar is running much below the general annual inflation rates experienced in the past. While the Company, like other companies, continues to be affected by fluctuations in the purchasing power of the U.S. dollar due to inflation, such effect is not currently considered significant. Southeast Asia Economic Issues. A substantial portion of the Company's oil and gas operations are conducted in Southeast Asia, and a substantial portion of its natural gas and liquid hydrocarbon production is sold there. Southeast Asia in general, and the Kingdom of Thailand in particular, experienced severe economic difficulties in 1997 and 1998 which were characterized by sharply reduced economic activity, illiquidity, highly volatile foreign currency exchange rates and unstable stock markets. Since that time, the economic situation has generally improved, although the recent worldwide rise in crude oil prices, continued weakness in the Thai banking sector and political uncertainty surrounding the recently completed national elections have had a negative impact on the Thai economy, resulting in a slow decline of the value of the Baht against the U.S. dollar. The economic health of the Thai economy and its effect on the volatility of the Thai Baht against the U.S. dollar, will continue to have a material impact on the Company's operations in the Kingdom of Thailand, together with the prices that the company receives for its oil and natural gas production there. See "--Results of Operations; Oil and Gas Revenues" and "--Results of Operations; Foreign Currency Transaction Gain (Loss)." 33 All of the Company's current natural gas production from the Thailand Concession is committed under a long-term Gas Sales Agreement to PTT at a price denominated in Thai Baht which is determined in accordance with a formula that is intended to ameliorate, at least in part, any decline in the purchasing power of the Thai Baht against the U.S. dollar. See "Business International Operations; Contractual Terms Governing the Thailand Concession" and "Business Miscellaneous; Sales." Although the Company currently believes that PTT will honor its commitments under the Gas Sales Agreement, a failure by PTT to honor such commitments could have a material adverse effect on the Company. The Company's crude oil and condensate production from the Thailand Concession is currently sold on a tanker load by tanker load basis. Prices that the Company receives for such production are based on world benchmark prices, which are denominated in U.S. dollars, and are typically paid in U.S. dollars. See "Business--International Operations; Contractual Terms Governing the Thailand Concession and Related Production" and "Business--Miscellaneous; Sales." ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk. The Company is exposed to market risk, including adverse changes in commodity prices, interest rates and foreign currency exchange rates as discussed below. Commodity Price Risk The Company produces, purchases and sells natural gas, crude oil, condensate and NGLs. As a result, the Company's financial results can be significantly affected as these commodity prices fluctuate widely in response to changing market forces. In the past, the Company has made limited use of a variety of derivative financial instruments only for non-trading purposes as a hedging strategy to manage commodity prices associated with oil and gas sales and to reduce the impact of commodity price fluctuations. See "Business Competition and Market Conditions." 34 Interest Rate Risk From time to time, the Company has entered into various financial instruments, such as interest rate swaps, to manage the impact of changes in interest rates. As of February 27, 2001, the Company has no open interest rate swap or interest rate lock agreements. Therefore, the Company's exposure to changes in interest rates primarily results from its short-term and long-term debt with both fixed and floating interest rates. The following table presents principal or notional amounts (stated in thousands) and related average interest rates by year of maturity for the Company's debt obligations and their indicated fair market value at December 31, 2000:
Fair 2000 2001 2002 2003 2004 Thereafter Total Value ---- ---- ---- ---- ---- ---------- -------- -------- Liabilities Long-Term Debt: Variable Rate.......... $ 0 $ 0 $ 0 $ 0 $ 0 $ 0 $ 0 $ 0 Average Interest Rate.. -- -- -- -- -- -- -- -- Fixed Rate............. $ 0 $ 0 $ 0 $ 0 $ 0 $365,000 $365,000 $361,682 Average Interest Rate.. -- -- -- -- -- 8.4% 8.4% --
Foreign Currency Exchange Rate Risk The Company conducts business in Thai Baht, Hungarian Forint and the Canadian dollar and is therefore subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investing transactions. The Company conducts a substantial portion of its oil and gas production and sales in Southeast Asia. Southeast Asia in general, and the Kingdom of Thailand in particular, have experienced severe economic difficulties, including sharply reduced economic activity, illiquidity, highly volatile foreign currency exchange rates and unstable stock markets. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Results of Operations; Foreign Currency Transaction Gain (Loss)" and "Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues." However, the economic difficulties in Thailand and the volatility of the Thai Baht against the U.S. dollar will continue to have a material impact on the Company's Thailand operations and prices that the Company receives for its oil and gas production there. Although the Company's sales to PTT under the Gas Sales Agreement are denominated in Baht, because predominantly all of the Company's crude oil sales and its capital and most other expenditures in the Kingdom of Thailand are denominated in dollars, the dollar is the functional currency for the Company's operations in the Kingdom of Thailand. As of March 2, 2001, the Company is not a party to any foreign currency exchange agreement. Exposure from market rate fluctuations related to activities in Canada, where the Company's functional currency is the Canadian dollar, and Hungary, where the Company's functional currency is the Forint, is not material at this time. Current Hedging Activity From time to time, the Company has used and expects to continue to use hedging transactions with respect to a portion of its oil and gas production to achieve a more predictable cash flow, as well as to reduce its exposure to price fluctuations. While the use of these hedging arrangements limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counter-parties will be unable to meet the financial terms of such transactions. All of the Company's recent historical hedging transactions have been carried out in the over-the-counter market with investment grade institutions. During 2000, approximately 21% of the Company's equivalent production was subject to commodity price hedging arrangements. In January 2001, the Company began to account for its hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific 35 hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that we must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Based on the nature of the Company's derivative instruments currently outstanding and the historical volatility of oil and gas commodity prices, we expect that SFAS 133 could increase volatility in our earnings and other comprehensive income in future periods. Natural Gas In anticipation of the NORIC Merger, in late November and early December of 2000, the Company purchased options to sell 70 million cubic feet of natural gas production per day for the period from April 2001 through December 2002. These contracts give the Company the right, but not the obligation, to sell natural gas at a sales price of $4.25 per MMBtu for the period from April 2001 through March 2002 and $4.00 per MMBtu for the period from April 2002 through December 2002. These contracts are designed to guarantee a minimum "floor" price for the contracted volumes of production without limiting the Company's participation in price increases during the covered period. The Company paid approximately $24 million in cash to enter into these option contracts. As of December 31, 2000, and March 2, 2001, the Company was a party to the following hedging arrangements:
NYMEX Contract Price per MMBtu(a) --------------------------------- Volume Collars in --------------- Fair Market Period MMBtu(a) Swaps Floors Ceilings Value(b) ------ -------- ----- ------ -------- ----------- Floor Contracts: April 2001-March 2002.............. 25,550 -- $4.25 -- $ 6,930,000 April 2002-December 2002........... 19,250 -- $4.00 -- $13,342,000
-------- (a) "MMBtu" means million British Thermal Units. (b) Fair Market Value is calculated using prices derived from NYMEX futures contract prices existing at December 31, 2000. These hedging transactions are settled based upon the average of the reported settlement prices on the NYMEX for the last three trading days or, occasionally, the penultimate trading day of a particular contract month. For any particular floor transaction, the counter-party is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction. The Company is not required to make any payment in connection with the settlement of a floor transaction. However, in accordance with SFAS 133, the Company is required to record changes in the fair value of these floor contracts' premium (the contracts' time value) currently in earnings with no offset. Based on existing implementation guidelines issued by the Financial Accounting Standards Board staff, we recorded a non-cash after-tax charge to earnings of approximately $2,400,000 as the cumulative effect of adopting SFAS 133 effective January 1, 2001. The pre- tax cumulative effect represents the difference between the unamortized premium paid for the floor contracts and the fair value of the contracts' time value as of January 1, 2001. This charge will be reflected on the Company's first quarter 2001 financial statements. Crude Oil As of December 31, 2000 and March 2, 2001, the Company was not a party to any commodity price hedging contracts with respect to any of its current or future crude oil and condensate production. 36 ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2000 POGO PRODUCING COMPANY AND SUBSIDIARIES HOUSTON, TEXAS 37 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Pogo Producing Company: We have audited the accompanying consolidated balance sheets of Pogo Producing Company (a Delaware corporation) and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Pogo Producing Company and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the financial statements, effective January 1, 2000, the Company changed its method of accounting for product inventory. ARTHUR ANDERSEN LLP Houston, Texas February 9, 2001 38 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31, ---------------------------- 2000 1999 1998 -------- -------- -------- (Expressed in thousands, except per share amounts) Revenues: Oil and gas.................................... $479,202 $230,499 $200,154 Pipeline sales and other....................... 15,113 7,159 2,741 Gains (losses) on sales........................ 3,676 37,458 (92) -------- -------- -------- Total........................................ 497,991 275,116 202,803 -------- -------- -------- Operating Costs and Expenses: Lease operating................................ 93,640 70,349 69,071 Pipeline operating and natural gas purchases... 15,090 6,481 2,142 General and administrative..................... 34,568 29,452 26,356 Exploration.................................... 15,291 5,982 9,802 Dry hole and impairment........................ 28,608 4,594 41,736 Depreciation, depletion and amortization....... 131,151 104,266 110,916 -------- -------- -------- Total........................................ 318,348 221,124 260,023 -------- -------- -------- Operating Income (Loss).......................... 179,643 53,992 (57,220) Interest: Charges........................................ (34,064) (35,874) (24,682) Income......................................... 2,634 1,208 719 Capitalized.................................... 20,918 17,733 9,381 Minority Interest--Dividends and costs associated with mandatorily redeemable convertible preferred securities of a subsidiary trust...... (9,965) (5,914) -- Foreign Currency Transaction Gains (Loss)........ (3,174) 572 953 -------- -------- -------- Income (Loss) Before Taxes and Cumulative Effect of Change in Accounting Principle............... 155,992 31,717 (70,849) Income Tax Benefit (Expense)..................... (66,969) (9,583) 27,751 -------- -------- -------- Income (Loss) Before Cumulative Effect of Change in Accounting Principle......................... 89,023 22,134 (43,098) Cumulative Effect of Change in Accounting Principle....................................... (1,768) -- -- -------- -------- -------- Net Income (Loss)................................ $ 87,255 $ 22,134 $(43,098) ======== ======== ======== Earnings (Loss) per Common Share: Basic Income (loss) before cumulative effect of change in accounting principle................ $ 2.20 $ 0.55 $ (1.14) Cumulative effect of change in accounting principle..................................... (0.04) -- -- -------- -------- -------- Net income (loss).............................. $ 2.16 $ 0.55 $ (1.14) ======== ======== ======== Diluted Income (loss) before cumulative effect of change in accounting principle................ $ 1.99 $ 0.55 $ (1.14) Cumulative effect of change in accounting principle..................................... (0.04) -- -- -------- -------- -------- Net income (loss).............................. $ 1.95 $ 0.55 $ (1.14) ======== ======== ======== Dividends per Common Share....................... $ 0.12 $ 0.12 $ 0.12 ======== ======== ========
The accompanying notes to consolidated financial statements are an integral part hereof. 39 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
December 31, -------------------------- 2000 1999 ------------ ------------ (Expressed in thousands) ASSETS Current Assets: Cash and cash equivalents........................ $ 81,510 $ 6,267 Accounts receivable.............................. 84,381 37,321 Other receivables................................ 27,242 35,870 Inventory--product............................... 3,054 7,209 Inventories--tubulars............................ 8,056 10,352 Price hedge contracts............................ 9,153 -- Other............................................ 1,276 2,370 ------------ ------------ Total current assets........................... 214,672 99,389 ------------ ------------ Property and Equipment: Oil and gas, on the basis of successful efforts accounting Proved properties being amortized 1,698,404 1,638,321 Unevaluated properties and properties under development, not being amortized.............. 154,914 144,357 Pipelines, at cost............................... 7,095 6,984 Other, at cost................................... 15,257 13,103 ------------ ------------ 1,875,670 1,802,765 ------------ ------------ Accumulated depreciation, depletion, and amortization Oil and gas.................................... (1,053,478) (1,006,542) Pipelines...................................... (1,780) (1,534) Other.......................................... (8,758) (7,329) ------------ ------------ (1,064,016) (1,015,405) ------------ ------------ Property and equipment, net...................... 811,654 787,360 ------------ ------------ Other Assets: Price hedge contracts............................ 14,869 -- Debt issue expenses.............................. 10,718 12,686 Foreign value added taxes receivable............. 7,262 12,025 Foreign tax net operating losses................. 3,695 16,237 Other............................................ 20,652 20,496 ------------ ------------ 57,196 61,444 ------------ ------------ $ 1,083,522 $ 948,193 ============ ============
The accompanying notes to consolidated financial statements are an integral part hereof. 40 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
December 31, --------------------------- 2000 1999 ------------- ------------ (Expressed in thousands) LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable--operating activities........... $ 27,334 $ 21,724 Accounts payable--investing activities........... 67,703 62,878 Accrued interest payable......................... 7,443 7,457 Accrued dividends associated with preferred securities of a subsidiary trust................ 813 813 Accrued payroll and related benefits............. 2,285 2,149 Other............................................ 851 208 ------------- ----------- Total current liabilities...................... 106,429 95,229 Long-Term Debt..................................... 365,000 375,000 Deferred Income Tax................................ 95,453 51,177 Deferred Credits................................... 13,456 13,524 ------------- ----------- Total liabilities.............................. 580,338 534,930 ------------- ----------- Commitments and Contingencies (Note 1)............. -- -- Minority Interests: Company-obligated mandatorily redeemable convertible preferred securities of a subsidiary trust, net of unamortized issue expenses........ 144,913 144,751 ------------- ----------- Shareholders' Equity: Preferred stock, $1 par; 2,000,000 shares authorized...................................... -- -- Common stock, $1 par; 100,000,000 shares authorized, and 40,659,591 and 40,279,661 shares issued, respectively............................ 40,660 40,279 Additional capital............................... 298,885 291,909 Retained earnings (deficit)...................... 20,112 (62,291) Accumulated other comprehensive loss............. (1,062) (1,061) Treasury stock (15,575 shares), at cost.......... (324) (324) ------------- ----------- Total shareholders' equity..................... 358,271 268,512 ------------- ----------- $ 1,083,522 $ 948,193 ============= ===========
The accompanying notes to consolidated financial statements are an integral part hereof. 41 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, ---------------------------- 2000 1999 1998 -------- -------- -------- (Expressed in thousands) Cash flows from operating activities: Cash received from customers.................. $446,184 $218,936 $222,433 Federal income taxes received................. 6,000 6,446 -- Operating, exploration and general and administrative expenses paid................. (152,979) (105,924) (116,272) Interest paid................................. (32,028) (29,606) (26,221) Purchase of price hedge contracts............. (24,022) -- -- Federal income taxes paid..................... (9,444) (21,000) -- Value added taxes received (paid)............. 4,763 101 (6,161) Other......................................... 585 (196) (2,850) -------- -------- -------- Net cash provided by operating activities.... 239,059 68,757 70,929 -------- -------- -------- Cash flows from investing activities: Capital expenditures.......................... (139,062) (201,323) (201,946) Purchase of proved reserves................... (8,393) (20,000) (2,961) Proceeds from the sale of property and tubular stock........................................ 3,745 81,944 7,164 -------- -------- -------- Net cash used in investing activities........ (143,710) (139,379) (197,743) -------- -------- -------- Cash flows from financing activities: Borrowings under senior debt agreements....... 67,000 260,053 449,947 Payments under senior debt agreements......... (77,000) (470,000) (313,500) Proceeds from issuance of new debt............ -- 150,000 -- Proceeds from issuance of new financing....... -- 150,000 -- Proceeds from exercise of stock options....... 6,115 1,115 1,034 Payment of preferred dividends of a subsidiary trust........................................ (9,750) (4,999) -- Payment of cash dividends on common stock..... (4,852) (4,825) (4,531) Payment of financing issue expenses........... (135) (12,347) (2,635) Principal payment of production payment obligation................................... -- -- (15,246) Other......................................... -- -- (621) -------- -------- -------- Net cash provided by (used in) financing activities.................................. (18,622) 68,997 114,448 -------- -------- -------- Effect of exchange rate changes on cash......... (1,484) (67) 679 -------- -------- -------- Net increase (decrease) in cash and cash equivalents.................................... 75,243 (1,692) (11,687) Cash and cash equivalents at the beginning of the year....................................... 6,267 7,959 19,646 -------- -------- -------- Cash and cash equivalents at the end of the year........................................... $ 81,510 $ 6,267 $ 7,959 ======== ======== ======== Reconciliation of net income to net cash provided by operating activities: Net income (loss)............................. $ 87,255 $ 22,134 $(43,098) Adjustments to reconcile net income to net cash provided by operating activities Cumulative effect of change in accounting principle................................... 1,768 -- -- Minority interest............................ 9,965 5,914 -- Foreign currency transaction (gain) loss..... 3,174 (572) (953) (Gains) losses on sales...................... (3,676) (37,458) 92 Depreciation, depletion and amortization..... 131,151 104,266 110,916 Dry hole and impairment...................... 28,608 4,594 41,736 Interest capitalized......................... (20,918) (17,733) (9,381) Increase (decrease) in deferred income taxes....................................... 63,495 (5,337) (31,251) Change in assets and liabilities: (Increase) decrease in accounts receivable................................ (48,425) (13,006) 15,307 (Increase) decrease in inventory--product.. 601 (6,117) (259) Increase in price hedge contracts.......... (24,022) -- -- Decrease in other current assets........... 1,062 453 1,258 (Increase) decrease in other assets........ 2,902 41 (13,550) Increase (decrease) in accounts payable.... 5,447 9,714 (1,122) Increase (decrease) in accrued interest payable................................... (14) 4,314 95 Increase in accrued payroll and related benefits.................................. 132 201 14 Increase (decrease) in other current liabilities............................... 624 210 (637) Increase (decrease) in deferred credits.... (70) (2,861) 1,762 -------- -------- -------- Net cash provided by operating activities....... $239,059 $ 68,757 $ 70,929 ======== ======== ========
The accompanying notes to consolidated financial statements are an integral part hereof. 42 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Accumulated Retained Other Common Additional Earnings Comprehensive Treasury Shareholders' Comprehensive Stock Capital (Deficit) Income (Loss) Stock Equity Income (Loss) ------- ---------- --------- ------------- -------- ------------- ------------- Balance at December 31, 1997................... $33,553 $144,848 $(31,971) $ -- $(324) $146,106 Net loss................ -- -- (43,098) -- -- (43,098) $(43,098) Exercise of stock options................ 147 1,835 -- -- -- 1,982 Shares issued in connection with the conversion of 2004 Notes.................. 3,880 80,712 -- -- -- 84,592 Shares issued for stock and debt of acquired company................ 2,539 62,944 -- (1,253) -- 64,230 Shares issued as compensation........... 17 316 -- -- -- 333 Dividends ($0.12 per common share).......... -- -- (4,531) -- -- (4,531) Exchange gain on Canadian currency...... -- -- -- 46 46 46 -------- Comprehensive loss...... -- -- -- -- -- -- $(43,052) ------- -------- -------- ------- ----- -------- ======== Balance at December 31, 1998................... 40,136 290,655 (79,600) (1,207) (324) 249,660 Net income.............. -- -- 22,134 -- -- 22,134 $ 22,134 Exercise of stock options................ 130 1,267 -- -- -- 1,397 Adjustment for fractional shares and other.................. 13 (13) -- -- -- -- Dividends ($0.12 per common share).......... -- -- (4,825) -- -- (4,825) Exchange gain on Canadian currency...... -- -- -- 146 146 146 -------- Comprehensive income.... -- -- -- -- -- -- $ 22,280 ------- -------- -------- ------- ----- -------- ======== Balance at December 31, 1999................... 40,279 291,909 (62,291) (1,061) (324) 268,512 Net income.............. -- -- 87,255 -- -- 87,255 $ 87,255 Exercise of stock options................ 315 5,754 -- -- -- 6,069 Shares issued as compensation........... 66 1,222 -- -- -- 1,288 Dividends ($0.12 per common share).......... -- -- (4,852) -- -- (4,852) Exchange loss on Canadian currency...... -- -- -- (1) -- (1) (1) -------- Comprehensive income.... -- -- -- -- -- -- $ 87,254 ------- -------- -------- ------- ----- -------- ======== Balance at December 31, 2000................... $40,660 $298,885 $ 20,112 $(1,062) $(324) $358,271 ======= ======== ======== ======= ===== ========
The accompanying notes to consolidated financial statements are an integral part hereof. 43 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Summary of Significant Accounting Policies Nature of Operations-- Pogo Producing Company was incorporated in 1970. Pogo Producing Company and its subsidiaries (the "Company") are engaged in oil and gas exploration, development, production and acquisition activities in the United States both offshore in the Gulf of Mexico (primarily in federal waters offshore Louisiana and Texas) and onshore principally in the states of New Mexico, Texas and Louisiana. The Company also conducts exploration, development and production activities internationally in the Kingdom of Thailand (offshore in the Gulf of Thailand) and Canada (primarily in the provinces of Alberta, British Columbia and Saskatchewan) and exploration activities in Hungary and the British and Danish sectors of the North Sea. Use of Estimates-- The preparation of these financial statements requires the use of certain estimates by management in determining the Company's assets, liabilities, revenues and expenses. Depreciation, depletion and amortization of oil and gas properties and the impairment of oil and gas properties are determined using estimates of proved oil and gas reserves. 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. Proved reserves of crude oil, condensate, natural gas and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions. Principles of Consolidation-- The consolidated financial statements include the accounts of Pogo Producing Company and its subsidiary and affiliated companies, after elimination of all significant intercompany transactions. Majority owned subsidiaries are fully consolidated. Minority owned oil and gas subsidiaries or affiliates are pro rata consolidated in the same manner as the Company, and the oil and gas industry generally, accounts for its operating or working interest in oil and gas joint ventures. See note 4 of the notes to consolidated financial statements for a discussion of the Company's accounting for its minority interest in Pogo Trust I. Prior-Year Reclassifications-- Certain prior-year amounts have been reclassified to conform with the current year presentation. Foreign Currency-- The U. S. dollar is the functional currency for all areas of operations of the Company except Canada. Accordingly, monetary assets and liabilities and items of income and expense denominated in a foreign currency are remeasured to U.S. dollars at the rate of exchange in effect at the end of each month or the average for the month and the resulting gains or losses on foreign currency transactions are included in the consolidated statements of income for the period. The Canadian dollar is the functional currency for the Company's Canadian operations. Accordingly, monetary assets and liabilities and items of income and expense denominated in Canadian dollars are translated to U. S. dollars at the rate of exchange in effect at the end of each month (or the average exchange rate for the month with respect to items of income and expense) and the resulting gains or losses on Canadian currency transactions are included in the consolidated statement of shareholders' equity for the period through accumulated other comprehensive income. 44 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Production Imbalances-- Owners of an oil and gas property often take more or less production from a property than entitled based on their ownership percentages in the property. This results in a condition known in the industry as a production imbalance. The Company follows the "sales" (takes or cash) method of accounting for production imbalances whereby the Company recognizes revenues on production as it is taken and delivered to its purchasers not withstanding its ownership percentage. The Company's crude oil imbalances are not significant. At December 31, 2000, the Company had taken approximately 2,268 MMcf of natural gas less than it was entitled to based on its interest in those properties, and approximately 1,600 MMcf more than its entitlement on other properties placing the Company at year-end in a net under-delivered position of approximately 668 MMcf of natural gas based on its working interest ownership in the properties. Inventory--Product Crude oil and condensate from the Company's producing fields located in the Kingdom of Thailand are produced into storage vessels and sold periodically as economic quantities are accumulated. The product inventory at December 31, 1999 consists of approximately 287,000 barrels of crude oil and condensate, net to the Company's interest, and was carried at its estimated net realizable value of $25.09 per barrel. Effective January 1, 2000, the Company adopted the provisions of the Securities and Exchange Commission's (the "SEC") Staff Accounting Bulletin No. 101, Revenue Recognition. As a result, the oil and gas exploration and production industry's long-standing practice of recording such product inventories at their net realizable value will no longer be accepted by the SEC. The product inventory at December 31, 2000 consists of approximately 350,000 barrels of crude oil and condensate, net to the Company's interest, and is carried at its estimated average cost of $8.73 per barrel. The cumulative effect of this change in accounting principle through December 31, 1999 ($1,768,000, net of tax benefits of $1,768,000) has been charged to earnings effective January 1, 2000 and the first three quarters of 2000 have been restated. The following summary presents the proforma consolidated results of operations as if the accounting change had occurred as of the beginning of 1998. The proforma results are expressed in thousands of dollars, except for per share amounts.
2000 1999 1998 -------- -------- -------- Proforma: Revenues.......................................... $497,991 $268,876 $202,547 Operating income (loss)........................... $179,643 $ 50,456 $(57,055) Net income (loss)................................. $ 89,023 $ 20,366 $(43,016) Earnings (loss) per share: Basic........................................... $ 2.20 $ 0.51 $ (1.14) Diluted......................................... $ 1.99 $ 0.50 $ (1.14) As reported: Earnings (loss) per share: Basic........................................... $ 2.16 $ 0.55 $ (1.14) Diluted......................................... $ 1.95 $ 0.55 $ (1.14)
Inventories--Tubulars Tubular inventories consist primarily of goods used in the Company's operations and are stated at the lower of average cost or market value. Interest Capitalized-- Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until production commences if the projects are evaluated as successful. 45 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Earnings per Share-- Earnings (loss) per common share (basic earnings per share) are based on the weighted average number of shares of common stock outstanding during the periods. Earnings (loss) per common share and potential common share (diluted earnings per share) consider the effect of dilutive securities as set out below in thousands, except per share amounts.
For the Year Ended December 31, 2000 ----------------------------------------- Income(a) Shares Per Share ------------- ----------- ------------- Basic earnings per share............. $ 89,023 40,445 $ 2.20 Effect of potential dilutive securities: Shares assumed issued from the exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period.............. 668 Interest expense incurred, net of taxes, and shares issued related to the assumed conversion at $42.185 per share of the 2006 Notes............................. 4,111 2,726 Minority interest expense incurred, net of taxes, and shares issued related to the assumed conversion at $23.75 per share of the Trust Preferred Securities.............. 6,338 6,316 ------------- ----------- ----------- Diluted earnings per share........... $ 99,472 50,155 $ 1.99 ============= =========== =========== -------- (a) Represents income before cumulative effect of change in accounting principle Antidilutive securities: Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period or the effect of the assumed exercise would be antidilutive...................... $ -- 219 $ 34.93 For the Year Ended December 31, 1999 ----------------------------------------- Income Shares Per Share ------------- ----------- ------------- Basic earnings per share............. $ 22,134 40,178 $ 0.55 Effect of potential dilutive securities: Shares assumed issued from the exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period.............. -- 212 -- ------------- ----------- ----------- Diluted earnings per share........... $ 22,134 40,390 $ 0.55 ============= =========== =========== Antidilutive securities: Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period or the effect of the assumed exercise would be antidilutive...................... $ -- 2,388 $ 21.46 Interest expense incurred, net of taxes, and shares not issued related to the assumed non- conversion at $42.185 per share of the 2006 Notes.................... $ 4,111 2,726 $ 1.51 Minority interest expense incurred, net of taxes, and shares not issued related to the assumed non- conversion at $23.75 per share of the Trust Preferred Securities, issued on June 2, 1999............ $ 3,681 3,668 $ 1.00 For the Year Ended December 31, 1998 ----------------------------------------- Income Shares Per Share ------------- ----------- ------------- Basic and diluted earnings (loss) per share............................... $ (43,098) 37,902 $ (1.14) ============= =========== =========== Antidilutive securities: Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period or the effect of the assumed exercise would be antidilutive...................... $ -- 2,464 $ 19.37 Interest expense incurred, net of taxes, and shares not issued related to the assumed non- conversion at $42.185 per share of the 2006 Notes.................... $ 4,111 2,726 $ 1.51 Interest expense incurred, net of taxes, and shares not issued related to the assumed non- conversion at $22.188 per share of the 2004 Notes.................... $ 478 594 $ 0.80
46 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Oil and Gas Activities and Depreciation, Depletion and Amortization -- The Company follows the successful efforts method of accounting for its oil and gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Proved oil and gas properties are reviewed when circumstances suggest the need for such a review and, if required, the proved properties are written down to their estimated fair value. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Estimated fair value includes the estimated present value of all reasonably expected future production, prices, and costs. As a result of poor reservoir performance and persistent low oil and gas prices, the Company performed such a review in 1998 and expensed $30,813,000 related to its domestic oil and gas properties which is included in the Consolidated Statements of Income as dry hole and impairment expense. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above, plus future cost to abandon offshore wells and platforms, and is on a cost center by cost center basis using the units of production method with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves. The Company generally creates cost centers on a field by field basis for oil and gas activities in the Gulf of Mexico and the Gulf of Thailand. Generally, the Company establishes cost centers on the basis of an oil or gas trend or play for its onshore oil and gas activities. In connection with an ongoing asset maximization process, the Company had designated certain non-strategic and/or under performing properties to be disposed of to generate cash and maximize its focus on properties with greater exploration potential. These properties, including the previously announced sale of the Lopeno Field in South Texas were sold in the first quarter of 1999 at an aggregate gain of $37,344,000. Other properties and equipment are depreciated using a straight-line method in amounts which in the opinion of management are adequate to allocate the cost of the properties over their estimated useful lives. Consolidated Statements of Cash Flows-- For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less to be cash equivalents. Significant transactions may occur which do not directly affect cash balances and as such will not be disclosed in the Consolidated Statements of Cash Flows. Certain such noncash transactions are disclosed in the Consolidated Statements of Shareholders' Equity relating to shares issued in connection with the conversion of notes into common stock, shares issued as compensation, and shares issued for stock and debt of an acquired company. The shares issued for stock and debt of an acquired company is also discussed in the following Acquisition section of this note. Commitments and Contingencies-- The Company has commitments for operating leases (primarily for office space) in Houston, Midland, Fort Worth, Calgary and Bangkok and commitments for operating leases related to an FPSO and FSO in the Gulf of Thailand. Rental expense for office space was $1,911,000 in 2000, $1,855,000 in 1999, and $1,545,000 in 1998. Expenses for the FPSO lease were approximately $11,100,000 in each of the years 2000, 1999 and 1998. Expenses for the floating storage and offloading system ("FSO") (which commenced in May 1999) were approximately $4,000,000 in 2000 and $2,500,000 in 1999. Future minimum lease expenses at December 31, 2000 are $17,500,000 in 2001; $17,900,000 in 2002; $17,800,000 in 2003; $17,900,000 in 2004; $17,800,000 in 2005; and $53,600,000 in years thereafter. 47 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Acquisitions-- On November 19, 2000, the Company entered into an agreement and plan of merger with NORIC and certain shareholders of NORIC signatories thereto, which provided for the Merger of the Company and NORIC. The Company expects the Merger to occur in mid-March following satisfaction of all conditions precedent including approval by the Company's shareholders on March 13, 2001. The principal asset of NORIC is North Central, a privately held company that explores for and produces oil and natural gas principally in onshore and offshore Gulf Coast areas and Wyoming. Except where expressly noted, the information in this Annual Report relates only to the Company and does not include either historical information regarding North Central or the future impact of the Merger on the Company. The aggregate merger consideration including assumption of North Central's debt, is approximately $750,000,000. The merger agreement provides for consideration to NORIC stockholders of approximately $630,000,000, subject to a purchase price adjustment, in a combination of 50% cash and 50% Pogo common stock. The number of shares of stock is determined based on the market price of Pogo common stock over a 20-trading day period ending five days prior to the effective time of the merger, subject to a minimum of 11,559,633 shares of Pogo common stock if the price per share exceeds $27.25 and a maximum of 14,157,303 shares if the price per share is less than $22.25. Adding the approximately $120,000,000 of North Central's net debt that was assumed would exist at the closing results in the $750,000,000 total consideration. In August 1998, a wholly owned subsidiary of the Company merged with Arch Petroleum Inc. ("Arch") in a tax-free, stock for stock transaction accounted for as a purchase through which Arch became a wholly owned subsidiary of the Company. As a result, approximately 2,500,000 shares of the Company's common stock (valued at approximately $64.8 million) were issued in exchange for Arch preferred and common stock and its convertible debt. The value of the Company's common stock in excess of the book value of the net assets acquired (approximately $52.9 million) has been allocated to oil and gas properties and is being amortized using the units of production method over the life of the oil and gas reserves acquired. The unaudited proforma consolidated revenues, net loss and loss per share, as if the acquisition had occurred at the beginning of 1998 are $217,915,000; ($48,369,000) and ($1.22); respectively. These unaudited proforma results are presented for illustrative purposes only and are not necessarily indicative of the operating results that would have occurred had the acquisition been consummated at that date, nor are they necessarily indicative of future operating results. Price Risk Management-- The Company from time to time enters into commodity price hedging contracts with respect to its oil and gas production to limit the volatility of price movements. Such contracts are accounted for as hedges, in accordance with Statement of Financial Accounting Standard No. 80 ("SFAS 80"). Gains and losses on these contracts are recognized in revenue in the period in which the underlying production is delivered. In 2000, the Company hedged 16,910 MMcf of gas and 1,509,500 barrels of crude oil (25,967 equivalent MMcf) or approximately 21% of its equivalent 2000 production and recorded hedge losses of $11,549,000 in connection with its natural gas contracts and hedge losses of $9,976,000 in connection with its crude oil contracts. In 1999, the Company hedged 3,175 MMcf of natural gas and 514,500 barrels of crude oil (6,262 equivalent MMcf) or approximately 7% of its equivalent 1999 production and recorded hedge gains of $933,000 in connection with its natural gas contracts and hedge gains of $1,947,000 in connection with its crude oil contracts. No significant amount of hedge positions were held by the Company in earlier years. These instruments are measured for correlation at both the inception of the contract and on an ongoing basis. If these instruments cease to meet certain criteria for deferral accounting, any subsequent gains or losses are recognized in revenue. If these instruments are terminated prior to maturity, resulting gains and losses continue to be deferred until the hedged item is recognized in revenue. Neither the hedging contracts nor the unrealized gains or losses on these contracts are recognized in the financial statements. The Company has currently hedged 44,800 MMcf of its 48 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) forecasted natural gas production using purchased put options or floors. Prior to January 1, 2001, changes in the value of such contracts were recognized in earnings when the hedged production occurred. Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133") which requires that that changes in the fair value of the option premium (the option's time value) be reported currently in earnings with no offset. See Note 11. (2) Income Taxes The components of income (loss) before income taxes for each of the three years in the period ended December 31, 2000, are as follows (expressed in thousands):
2000 1999 1998 -------- ------- -------- United States....................................... $ 67,967 $40,472 $(57,112) Foreign............................................. 88,025 (8,755) (13,737) -------- ------- -------- Income (loss) before income taxes and cumulative effect of change in accounting principle......... $155,992 $31,717 $(70,849) ======== ======= ========
The components of income tax expense (benefit) for each of the three years in the period ended December 31, 2000, are as follows (expressed in thousands):
2000 1999 1998 ------- ------- -------- United States, current.............................. $ 9,000 $21,000 $ -- United States, deferred............................. 12,392 (6,978) (20,750) Foreign, deferred................................... 45,577 (4,439) (7,001) ------- ------- -------- Income tax expense (benefit)...................... $66,969 $ 9,583 $(27,751) ======= ======= ========
Total income tax expense (benefit) for each of the three years in the period ended December 31, 2000, differs from the amounts computed by applying the statutory federal income tax rate to income before taxes as follows (expressed as a percent of pretax income):
2000 1999 1998 ---- ---- ------ Federal statutory income tax rate........................... 35.0% 35.0% (35.0)% Increases (reductions) resulting from: Statutory depletion in excess of tax basis.................. (0.8) (0.8) (0.4) Foreign taxes............................................. 8.7 (4.1) (3.8) Other..................................................... -- 0.1 -- ---- ---- ------ 42.9% 30.2% (39.2)% ==== ==== ======
49 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (2) Income Taxes (Continued) Deferred income taxes are determined based upon the differences between the financial statement and tax basis of the Company's assets and liabilities using enacted tax rates in effect for the years in which the differences are expected to reverse. Deferred tax assets are recognized if it is more likely than not that the future tax benefit will be realized. The presentation in the consolidated balance sheets and the principal components of the Company's deferred income tax assets and liabilities at December 31, 2000 and 1999 (expressed in thousands) are as follows:
December 31, -------------------- 2000 1999 --------- --------- Deferred United States federal income tax liability...... $ (67,881) $ (51,177) Deferred foreign income tax liability.................... (27,572) -- Other assets--foreign tax net operating losses........... 3,695 16,237 --------- --------- Net deferred tax liability............................... $ (91,758) $ (34,940) ========= ========= Deferred tax liabilities: Domestic-- Intangible drilling costs, capitalized and amortized for financial statement purposes and deducted for income tax purposes................................... $(224,389) $(162,526) Charges to property and equipment, expensed for financial statement purposes, and capitalized and amortized for income tax purposes..................... (9,157) (24,254) Interest charges, capitalized and amortized for financial statement purposes and deducted for income tax purposes.......................................... (30,281) (15,037) Thailand-- Differences in depletion and depreciation rates used for tangible and intangibles assets for financial and tax purposes.......................................... (58,699) -- --------- --------- (322,526) (201,817) --------- --------- Deferred tax asset: Differences in depletion and depreciation rates used for tangible assets for financial and income tax purposes.............................................. 194,915 145,630 Foreign net operating loss carryforwards............... 65,302 16,237 Valuation allowance.................................... (30,480) -- Domestic net operating loss carryforwards.............. -- 3,979 Tax credits and other.................................. 1,031 1,031 --------- --------- 230,768 166,877 --------- --------- Net deferred tax liability............................... $ (91,758) $ (34,940) ========= =========
As of December 31, 2000, the Company has a net operating loss carryforward applicable to non-U.S. subsidiaries of approximately $126,900,000, which will begin to expire in 2007. A valuation allowance has been provided for certain of the deferred tax assets attributable to these loss carryforwards as it is currently deemed more likely than not that these assets will not be fully realized. 50 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (3) Long-Term Debt Long-term debt and the amount due within one year at December 31, 2000 and 1999, consists of the following (dollars expressed in thousands):
December 31, ----------------- 2000 1999 -------- -------- Senior debt-- Bank revolving credit agreement: LIBOR based loans, borrowings at an average interest rate of 7.8%................................................... $ -- $ 5,000 Uncommitted credit lines with banks, borrowings at an average interest rate of 5.9%.................................................... -- 5,000 -------- -------- Total senior debt............................................. -- 10,000 -------- -------- Subordinated debt-- 8 3/4% Senior subordinated notes, due 2007.................. 100,000 100,000 10 3/8% Senior subordinated notes, due 2009................. 150,000 150,000 5 1/2% Convertible subordinated notes, due 2006............. 115,000 115,000 -------- -------- Total subordinated debt....................................... 365,000 365,000 -------- -------- Total debt.................................................... 365,000 375,000 -------- -------- Amount due within one year--.................................. -- -- -------- -------- Long-term debt................................................ $365,000 $375,000 ======== ========
The Company entered into a reserve-based credit facility (the "Credit Facility"), which was amended most recently in November 2000. The Credit Facility provides for a $250,000,000 revolving credit facility until July 1, 2002, after which the balance will be due in eight quarterly term loan installments, commencing on October 31, 2002. The amount that may be borrowed may not exceed a borrowing base which determined semi-annually and is calculated based upon substantially all of the Company's proved oil and gas properties. As of December 31, 2000, the Company's borrowing base was set at $225,000,000. The Credit Facility is governed by various financial and other covenants, including requirements to maintain positive working capital (excluding current maturities of debt) and a fixed charge coverage ratio, and limitations on indebtedness (including a total indebtedness limit of $590,000,000), creation of liens, the prepayment of subordinated debt, the payment of dividends, mergers and consolidations, investments and asset dispositions. In addition, the Company is prohibited from pledging borrowing base properties as security for other debt. Borrowings under the Credit Facility bear interest, at the Company's option, at a base (prime) rate plus a variable margin (currently none) or LIBOR plus a variable margin (currently 1.25%). The margin varies as a function of the percentage of the borrowing base utilized. A commitment fee on the unborrowed amount at a base rate or LIBOR plus 1.75%, at the Company's option. A commitment fee on the unborrowed amount that is currently available under the Credit Facility is also charged based upon the percentage of the borrowing base that is being utilized. In connection with the NORIC Merger, the Company plans to terminate the above Credit Facility and enter into a new revolving credit facility. Based on a term sheet agreed to with the lenders under the proposed new facility, the Company currently expects that the new credit facility will provide for a $515,000,000 revolving loan facility terminating five years after the closing of the Merger. The amount that may be borrowed under the new facility may not exceed a borrowing base which is to be determined semi-annually and will be calculated based upon substantially all of the Company's proved oil and gas properties, including those of North Central. The Company expects that the initial borrowing base will be set at $475,000,000. The Company expects the financial and other covenants will be substantially similar to those contained in the Credit Facility, 51 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) with the following exceptions: there will be no express limitation on indebtedness; there will be a limitation on commodity hedging; and the Company will be obligated to pledge the stock of North Central and an affiliated subsidiary, and its inter-company receivables with North Central as security. The new revolving credit facility will also permit short-term "swing line" loans and the issuance of up to $50,000,000 in letters of credit as a part of the facility. Proceeds of the new facility will be used to fund the cash portion of the consideration paid to NORIC shareholders, retire existing North Central debt and for other general corporate purposes. As of December 31, 2000, the Company also has available an uncommitted money market line of credit with a commercial bank. The line of credit is on an as available or as offered basis. Loans made under the line of credit are reflected as long-term debt on the Company's balance sheet because the Company currently has the ability and intent to reborrow such amounts under its Credit Facility. Under its Credit Facility, the Company is currently limited to incurring a maximum of $20,000,000 of additional senior debt, which would include debt incurred under the line of credit and under the banker's acceptances discussed below. Further, the 2007 Notes and the 2009 Notes also restrict the incurrence of additional senior indebtedness. The letter agreement permits either party to terminate it at any time. On May 22, 1997, the Company issued $100,000,000 of principal amount of 2007 Notes. The 2007 Notes bear interest at a rate of 8 3/4%, payable semi-annually in arrears on May 15 and November 15 of each year. The 2007 Notes are general unsecured senior subordinated obligations of the Company and are subordinated in right of payment to the Company's senior indebtedness, are equal in right of payment to the 2009 Notes, but are senior in right of payment to the Company's subordinated indebtedness. The Company, at its option, may redeem the 2007 Notes in whole or in part, at any time on or after May 15, 2002, at a redemption price of 104.375% of their principal value and decreasing percentages thereafter. The indenture governing the 2007 Notes also imposes certain covenants on the Company that are substantially identical to the covenants contained in the indenture governing the 2009 Notes described below. On January 15, 1999, the Company issued $150,000,000 principal amount of 2009 Notes. The 2009 Notes bear interest at a rate of 10 3/8%, payable semi- annually in arrears on February 15 and August 15 of each year. The 2009 Notes are generally unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company's senior indebtedness, which currently includes the Company's obligations under the Credit Facility, its unsecured credit lines and its bankers acceptances, are equal in right of payment to the 2007 Notes, but are senior in right of payment to its subordinated indebtedness, which currently includes the 2006 Notes. The Company, at its option, may redeem the 2009 Notes in whole or in part, at any time on or after February 15, 2004, at a redemption price of 105.188% of their principal value and decreasing percentages thereafter. The indenture governing the 2009 Notes also imposes certain covenants on the Company that are substantially identical to the covenants contained in the indenture governing the 2007 Notes, including covenants limiting: incurrence of indebtedness including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of assets sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and mergers, consolidations and the sale of assets. As of December 31, 2000, $75,370,000 was available for dividends under this limitation, which is currently the Company's most restrictive convenant. The outstanding principal amount of 2006 Notes was $115,000,000 as of December 31, 2000. The 2006 Notes bear interest at a rate of 5 1/2%, payable semi-annually in arrears on June 15 and December 15 of each year. The 2006 Notes are convertible into Common Stock at $42.185 per share subject to adjustment upon the occurrence of certain events. The 2006 Notes are currently redeemable at the option of the Company, in whole or in part, at any time, at a redemption price of 103.3% of their principal. The redemption premium will decline over the next several years. The Company currently has no maturities or sinking fund requirements during the next five years in connection with the above long-term debt. 52 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (4) Minority Interest Pogo Trust I, a business trust in which the Company owns all of the issued common securities (the "Trust"), issued $150,000,000 (3,000,000 securities having a liquidation preference of $50 each) of 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities, Series A (the "Trust Preferred Securities") on June 2, 1999. The proceeds of the issuance of the Trust Preferred Securities were used to purchase $150,000,000 of the Company's 6 1/2% Junior Subordinated Convertible Debentures, due June 1, 2029 (the "Debentures"). The Debentures are the sole asset of Pogo Trust I. The financial terms of the Debentures are generally the same as those of the Trust Preferred Securities. The Trust Preferred Securities accrue and pay distributions quarterly in arrears at a rate of 6 1/2% per annum on the stated liquidation amount of $50 per Trust Preferred Security on March 1, June 1, September 1, and December 1 of each year to security holders of record on the business day immediately preceding the distribution payment date. The Company has guaranteed, on a subordinated basis, distributions and other payments due on the Trust Preferred Securities to the extent that there are funds available in the Trust. The Company currently believes that, taken as a whole, the Company guarantee of Pogo Trust I's obligation under the Preferred Securities constitutes a full and unconditional quarantee by the Company of Pogo Trust I's performance obligation. The Company may cause the Trust to defer the payment of distributions for successive periods up to 20 consecutive periods unless an event of default on the Debentures has occurred and is continuing. During such periods, accrued distributions on the Trust Preferred Securities will compound quarterly and the Company will generally not be permitted to declare or pay distributions on its common stock or debt securities that rank equal or junior to the Debentures. The Trust Preferred Securities are convertible at the option of the holder at any time into common stock of the Company at the rate of 2.1053 shares of Company common stock per Trust Preferred Security. This conversion rate will be subject to adjustment to prevent dilution and is currently equivalent to a conversion price of $23.75 per share of Company stock. The Trust Preferred Securities are mandatorily redeemable upon maturity of the Debentures on June 1, 2029, or to the extent of any earlier redemption of any Debenture by the Company and are callable by the Trust at any time after June 1, 2002. In addition, if certain tax changes occur so that the Trust becomes subject to federal income taxes or if interest payments made by the Company to the Trust or the Debentures are no longer deductible for federal income tax purposes, the Trust may liquidate and distribute Debentures to holders of the Trust Preferred Securities and, in certain circumstances, the Company may shorten the stated maturity of the Debentures to as early as June 2, 2014. The amounts recorded in 2000 and 1999 under Minority Interests--Dividends and costs associated with preferred securities of a subsidiary trust principally reflect cumulative dividends and, to a lesser extent, the amortization of issuance expenses related to the offering and sale of the Trust Preferred Securities. 53 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (5) Business Segment Information At December 31, 1998, the Company adopted the Financial Accounting Standard Board's Statement of Financial Accounting Standards No. 131 ("SFAS 131"), Disclosures About Segments of an Enterprise and Related Information, which established Standards for the way enterprises report information about operating segments and related information. The Company has three reportable segments, which are primarily in the business of natural gas and crude oil exploration and production. The accounting policies of the segments are the same as those described in the summary of significant policies. The Company evaluates performance based on profit or loss from operations before income and expense items incidental to oil and gas operations and income taxes. The Company's reportable segments are managed separately because of their geographical locations. Financial information by operating segment is presented below:
Gains Total Oil (Losses) Company and Gas Pipelines & Other -------- -------- --------- -------- (Expressed in thousands) Long-Lived Assets: As of December 31, 2000: United States........................ $462,530 $454,246 $ 5,315 $ 2,969 Kingdom of Thailand.................. 337,317 334,018 -- 3,299 Canada............................... 11,807 11,576 -- 231 -------- -------- ------- ------- Total................................ $811,654 $799,840 $ 5,315 $ 6,499 ======== ======== ======= ======= As of December 31, 1999: United States........................ $440,914 $432,034 $ 5,450 $ 3,430 Kingdom of Thailand.................. 340,204 338,084 -- 2,120 Canada............................... 6,242 6,018 -- 224 -------- -------- ------- ------- Total................................ $787,360 $776,136 $ 5,450 $ 5,774 ======== ======== ======= ======= Revenues: For the year ended December 31, 2000 United States........................ $309,602 $291,266 $15,277 $ 3,059 Kingdom of Thailand.................. 182,965 183,060 -- (95) Canada............................... 5,424 4,876 -- 548 -------- -------- ------- ------- Total................................ $497,991 $479,202 $15,277 $ 3,512 ======== ======== ======= ======= For the year ended December 31, 1999 United States........................ $217,339 $172,683 $ 7,462 $37,194 Kingdom of Thailand.................. 54,444 54,480 -- (36) Canada............................... 3,333 3,336 -- (3) -------- -------- ------- ------- Total................................ $275,116 $230,499 $ 7,462 $37,155 ======== ======== ======= ======= For the year ended December 31, 1998 United States........................ $165,873 $163,438 $ 2,431 $ 4 Kingdom of Thailand.................. 35,649 35,445 -- 204 Canada............................... 1,281 1,271 -- 10 -------- -------- ------- ------- Total................................ $202,803 $200,154 $ 2,431 $ 218 ======== ======== ======= ======= Operating income (loss): For the year ended December 31, 2000 United States........................ $ 86,996 $ 84,491 $ (554) $ 3,059 Kingdom of Thailand.................. 92,735 92,830 -- (95) Canada............................... (88) (636) -- 548 -------- -------- ------- ------- Total................................ $179,643 $176,685 $ (554) $ 3,512 ======== ======== ======= ======= For the year ended December 31, 1999 United States........................ $ 59,130 $ 21,564 $ 372 $37,194 Kingdom of Thailand.................. (3,491) (3,455) -- (36) Canada............................... (1,647) (1,644) -- (3) -------- -------- ------- ------- Total................................ $ 53,992 $ 16,465 $ 372 $37,155 ======== ======== ======= ======= For the year ended December 31, 1998 United States........................ $(42,743) $(43,036) $ 289 $ 4 Kingdom of Thailand.................. (13,050) (13,254) -- 204 Canada............................... (1,427) (1,437) -- 10 -------- -------- ------- ------- Total................................ $(57,220) $(57,727) $ 289 $ 218 ======== ======== ======= =======
54 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (6) Sales to Major Customers The Company is an oil and gas exploration and production company that generally sells its oil and gas to numerous customers on a month-to-month basis. For purposes of comparison, 2000 sales have been presented for those customers who have in either of the previous two years exceeded 10% of revenues (expressed in thousands):
2000 1999 1998 ------- ------- ------- Petroleum Authority of Thailand (PTT).................. $46,930 $24,315 $23,137 Enron Corp. and affiliates............................. $66,083 $10,911 $29,539
(7) Credit Risk Substantially all of the Company's accounts receivable at December 31, 2000 and 1999, result from oil and gas sales and joint interest billings to other companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. Such receivables are generally not collateralized. Historically, credit losses incurred by the Company on receivables have not been material. No material credit losses were experienced during 2000 or 1999. A substantial portion of the Company's oil and gas operations are conducted in Southeast Asia, and a substantial portion of its natural gas and liquids hydrocarbon production are sold there. In the last two years, Southeast Asia in general, and the Kingdom of Thailand in particular, have experienced severe economic difficulties which have been characterized by sharply reduced economic activity, illiquidity, highly volatile foreign currency exchange rates and unstable stock markets. The government of the Kingdom of Thailand and other governments in the region are currently acting to address these issues. However, the economic difficulties currently being experienced in Thailand, together with the volatility of the Thai Baht against the U.S. dollar, will continue to have a material impact on the Company's operations in the Kingdom of Thailand together with the prices that the Company receives for its production there. All of the Company's current natural gas production from its Thailand operations are committed under a long-term Gas Sales Agreement to PTT at a price denominated in Thai Baht. The Company's crude oil and condensate production from its Thailand operations is currently sold on a tanker load by tanker load basis. Prices that the Company receives for such crude oil production are based on world benchmark prices, which are denominated in U.S. dollars and are generally expected on future crude oil sales to be paid in U.S. dollars. (8) Employee Benefits The Company has a tax-advantaged savings plan in which all U.S. salaried employees may participate. Under such plan, a participating employee may allocate up to 10% of his salary, up to a maximum allowed by law ($10,500 for 2001), and the Company will then match the employee's contribution on a dollar for dollar basis up to 6% of the employee's salary. Funds contributed by the employee and the matching funds contributed by the Company are held in trust by a bank trustee in six seperate funds. Amounts contributed by the employee and earnings and accretions thereon may be used to purchase shares of common stock, invest in a money market fund or invest in four stock, bond, or blended stock and bond mutual funds according to instructions from the employee. Matching funds contributed to the savings plan by the Company are invested only in common stock. The Company contributed $886,000 to the savings plan in 2000, $963,000 in 1999, and $701,000 in 1998. A trusteed retirement plan has been adopted by the Company for its U.S. salaried employees. The benefits are based on years of service and the employee's average compensation for five consecutive years within the final ten years of service which produce the highest average compensation. The Company makes annual 55 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (8) Employee Benefits--(Continued) contributions to the plan in the amount of retirement plan cost accrued or the maximum amount which can be deducted for federal income tax purposes. Although the Company has no obligation to do so, the Company currently provides full medical benefits to its retired U.S. employees and dependents. For current employees, the Company assumes all or a portion of post-retirement medical and term life insurance costs based on the employee's age and length of service with the Company. The post-retirement medical plan has no assets and is currently funded by the Company on a pay-as-you-go basis. The following table sets forth the plans' status (in thousands of dollars) as of December 31, 2000 and 1999.
Post-Retirement Retirement Plan Medical Plan ---------------- ---------------- 2000 1999 2000 1999 ------- ------- ------- ------- Change in benefit obligation Benefit obligation at beginning of year.. $11,469 $13,849 $ 7,087 $ 6,284 Service cost............................ 1,012 1,177 441 489 Interest cost........................... 920 840 535 418 Participant contributions............... -- -- -- 5 Benefits paid........................... (1,568) (903) (105) (213) Actuarial (gain) or loss................ 3,146 (3,494) 44 104 ------- ------- ------- ------- Benefit obligation at end of year........ $14,979 $11,469 $ 8,002 $ 7,087 ======= ======= ======= ======= Change in plan assets Fair value of plan assets at beginning of year.................................... $37,299 $37,404 $ -- $ -- Actual return on plan assets............ 2,967 1,075 -- -- Employer contributions.................. -- -- 105 208 Participant contributions............... -- -- -- 5 Benefits paid........................... (1,568) (903) (105) (213) Administrative expenses................. (361) (277) -- -- ------- ------- ------- ------- Fair value of plan assets at end of year.................................... $38,337 $37,299 $ -- $ -- ======= ======= ======= ======= Reconciliation of funded status Funded status............................ $23,358 $25,830 $(8,002) $(7,087) Unrecognized actuarial gain.............. (9,239) (14,307) (1,429) (1,544) Unrecognized transition (asset) or obligation.............................. (26) (129) 1,522 1,826 Unrecognized past service cost........... (170) (214) -- -- ------- ------- ------- ------- Prepaid (accrued) benefit cost at year- end..................................... $13,923 $11,180 $(7,909) $(6,805) ======= ======= ======= ======= Discount rate............................ 7.50% 7.75% 7.50% 7.75% Expected return on plan assets........... 9.50% 9.50% -- -- Rate of compensation increase............ 4.75% 4.75% -- -- Components of net periodic benefit cost Service cost............................. $ 1,012 $ 1,177 $ 441 $ 489 Interest cost............................ 920 840 535 418 Expected return on plan assets........... (3,534) (3,544) -- -- Amortization of prior service cost....... (43) (43) -- -- Amortization of transition (asset) obligation.............................. (104) (103) 305 305 Recognized actuarial gain................ (994) (1,112) (72) (93) ------- ------- ------- ------- $(2,743) $(2,785) $ 1,209 $ 1,119 ======= ======= ======= =======
56 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (8) Employee Benefits--(Continued) For measurement purposes, a 10.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2001. The rate is assumed to decrease gradually to 5% for 2005 and remain at that level thereafter. Assumed health care cost trends have a significant effect on the amount reported for the health care plan. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in thousands):
One Percentage Point ----------------- Increase Decrease -------- -------- Effect on total of service and interest cost components for 2000................................. $ 178 $(142) Effect on year-end 2000 postretirement benefit obligation.......................................... $1,200 $(985)
57 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (9) Stock Option Plans The Company's stock option plans authorize the granting of options to key employees and non-employee directors at prices equivalent to the market value at the date of grant. Options generally become exercisable in three annual installments commencing one year after the date of grant and, if not exercised, expire 10 years from the date of grant. The Company accounts for employee stock-based compensation using the intrinsic value method and since the exercise price of the options granted is equal to the quoted market price of the Company's stock at the grant date, no compensation cost has been recognized for its stock option plans. Had compensation costs been determined based on fair value at the grant dates for awards made in 2000, 1999, and 1998, the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below (in thousands of dollars, except per share amounts):
2000 1999 1998 ------- ------- -------- Income (loss) before cumulative effect of change in accounting principle As reported....................................... $89,023 $22,134 $(43,098) Pro forma......................................... $86,091 $20,118 $(44,602) Net income (loss) As reported....................................... $87,255 $22,134 $(43,098) Pro forma......................................... $86,091 $20,118 $(44,602) Earnings (loss) per share: Income (loss) before the cumulative effect of change in accounting principle As reported--Basic................................ $ 2.20 $ 0.55 $ (1.14) Pro forma--Basic.................................. $ 2.16 $ 0.51 $ (1.19) As reported--Diluted.............................. $ 2.16 $ 0.55 $ (1.14) Pro forma--Diluted................................ $ 1.94 $ 0.51 $ (1.20) Net income (loss) As reported--Basic................................ $ 2.16 $ 0.55 $ (1.14) Pro forma--Basic.................................. $ 2.12 $ 0.51 $ (1.19) As reported--Diluted.............................. $ 1.95 $ 0.55 $ (1.14) Pro forma--Diluted................................ $ 1.91 $ 0.51 $ (1.20)
The fair value of grants was estimated on the date of grant using the Black Scholes option pricing model with the following weighted-average assumptions used in 2000, 1999 and 1998, respectively: risk free interest rates of 6.03%, 5.92% and 5.31%, expected volatility of 42.85%, 42.73% and 35.58%, dividend yields of 0.59%, 0.63% and 0.64%, and an expected life of the options of 5 years in 2000, 5 years in 1999, and 4 years in 1998. 58 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (9) Stock Option Plans--(Continued) A summary of the status of the Company's plans as of December 31, 2000, 1999 and 1998, and changes during the years ended on those dates is presented below:
Weighted Average Number of Exercise Options Price --------- -------- Outstanding, December 31, 1997............................ 1,958,563 $25.13 Granted in 1998......................................... 985,659 $19.62 Exercised in 1998....................................... (145,317) $ 6.87 Canceled in 1998........................................ (334,748) $37.13 --------- Outstanding, December 31, 1998............................ 2,464,157 $19.37 ========= Exercisable, December 31, 1998............................ 1,223,484 $19.00 ========= Available for grant, December 31, 1998.................... 682,082 ========= Weighted-average fair value of options granted during 1998..................................................... $ 5.35 Outstanding, December 31, 1998............................ 2,464,157 $19.37 Granted in 1999......................................... 676,900 $19.03 Exercised in 1999....................................... (130,275) $ 8.57 Canceled in 1999........................................ (5,167) $ 7.31 --------- Outstanding, December 31, 1999............................ 3,005,615 $19.78 ========= Exercisable, December 31, 1999............................ 1,607,395 $20.11 ========= Available for grant, December 31, 1999.................... 205,182 ========= Weighted-average fair value of options granted during 1999..................................................... $ 8.31 Outstanding, December 31, 1999............................ 3,005,615 $19.78 Granted in 2000......................................... 722,800 $20.58 Exercised in 2000....................................... (314,850) $15.33 Canceled in 2000........................................ (5,942) $13.32 --------- Outstanding, December 31, 2000............................ 3,407,623 $20.37 ========= Exercisable, December 31, 2000............................ 2,026,517 $20.72 ========= Available for grant, December 31, 2000.................... 932,677 ========= Weighted-average fair value of options granted during 2000..................................................... $ 9.58
The following table summarizes information about stock options outstanding at December 31, 2000:
Options Outstanding Options Exercisable -------------------------------- -------------------- Weighted Average Weighted Weighted Remaining Average Average Number Contractual Exercise Number Exercise Range of Option Prices Outstanding Life (days) Price Exercisable Price ---------------------- ----------- ----------- -------- ----------- -------- $ 5.63 to $ 7.81........ 106,835 358 $ 6.47 106,835 $ 6.47 $ 12.31 to $ 12.72........ 6,001 2,879 $12.54 1,334 $12.31 $ 15.13 to $ 19.56........ 1,523,961 2,648 $18.64 956,624 $18.32 $ 20.28 to $ 24.81........ 1,555,735 2,660 $21.01 752,966 $21.72 $ 25.38 to $ 29.06........ 49,962 2,725 $25.73 43,629 $25.66 $ 30.23 to $ 33.94........ 30,962 1,979 $33.75 30,962 $33.75 $ 35.13 to $ 36.00........ 51,667 1,982 $35.97 51,667 $35.97 $ 40.62 to $ 44.00........ 82,500 2,354 $41.00 82,500 $41.00 --------- --------- Total..................... 3,407,623 2,560 $20.37 2,026,517 $20.72 ========= =========
59 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (10) Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value. Cash and Cash Equivalents Fair value is carrying value. Debt and Other
Instrument Basis of Fair Value Estimate ------------------------- ----------------------------------------------- Bank revolving credit Fair value is carrying value as of December 31, agreement 1999 based on the market value interest rates. Uncommitted credit lines Fair value is carrying value as of December 31, with banks and banker's 1999 based on the market value interest rates. acceptance loans 2007 Notes Fair value is 97% and 97.5%, of carrying value as of December 31, 2000 and 1999, respectively, based on quoted market values. 2009 Notes Fair value is 104.25% and 106%, of carrying value as of December 31, 2000 and 1999, respectively, based on quoted market values. 2006 Notes Fair value is 94.188% and 78.375%, of carrying value as of December 31, 2000 and 1999, respectively, based on quoted market values. Minority interest in Fair value is 140.88% and 101.25%, of carrying company obligated value as of December 31, 2000 and 1999, preferred securities respectively, based on quoted market values. of a subsidiary trust
The carrying value and estimated fair value of the Company's financial instruments at December 31, 2000 and 1999 (in thousands of dollars) are as follows:
2000 1999 -------------------- -------------------- Carrying Fair Carrying Fair Value Value Value Value --------- --------- --------- --------- Cash and cash equivalents...... $ 81,510 $ 81,510 $ 6,267 $ 6,267 Debt: Bank revolving credit agreement................... -- -- $ (5,000) $ (5,000) Uncommitted credit lines with banks....................... -- -- $ (5,000) $ (5,000) 2007 Notes................... $(100,000) $ (97,000) $(100,000) $ (97,500) 2009 Notes $(150,000) $(156,375) $(150,000) $(159,000) 2006 Notes................... $(115,000) $(108,316) $(115,000) $ (90,131) Minority interest in company obligated mandatorily redeemable preferred securities of a subsidiary trust, net of unamortized $(150,000) $(211,320) $(150,000) $(151,875) issue expenses of............. $ 5,087 $ 5,087 $ 5,249 $ 5,249
The Company occasionally enters into hedging contracts to minimize the impact of oil and gas price fluctuations. See Note 11 for a further discussion of these contracts. 60 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) (11) Hedging Activities Impact of SFAS 133-- In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). In June 1999, the FASB issued SFAS 137, Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133. In June 2000, the FASB issued SFAS 138, Accounting for Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133. SFAS 133, as amended, establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The Company adopted SFAS 133 effective January 1, 2001. Based on the nature of the Company's derivative instruments currently outstanding and the historical volatility of oil and gas commodity prices, the Company expects that SFAS 133 could increase volatility in the Company's earnings and other comprehensive income for future periods. SFAS 133, in part, allows special hedge accounting. SFAS 133 provides that the effective portion of the gain or loss on a loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. Currently, the Company has hedged a portion of its forecasted production using purchased put options. Under generally accepted accounting principles in effect prior to SFAS 133, changes in the intrinsic value of such options are recognized in earnings when the hedged production occurs and the premium paid for the options is amortized into earnings over the option period on a straight-line basis. In contrast, SFAS 133 effectively requires that changes in the fair value of the option premium (the option's time value) be reported currently in earnings with no offset. Based on existing implementation guidelines issued by the FASB staff and the fair market value of the Company's purchased options, the Company recorded a non-cash after-tax charge to earnings of approximately $2,400,000 as the cumulative effect of adopting SFAS 133 effective January 1, 2001. The pre-tax cumulative effect represents the difference between the unamortized premium paid for the options and the fair value of the option's time value as of January 1, 2001. Price Hedge Contracts-- As of December 31, 2000, the Company purchased options to sell 70 million cubic feet of natural gas production per day for the period from April 1, 2001 through December 2002. These contracts give the Company the right, but not the obligation, to sell natural gas at a sales price of $4.25 per MMBtu for the period from April 2001 through March 2002 and $4.00 per MMBtu for the period from April 2002 through December 2002. These contracts are designed to guarantee the Company a minimum "floor" price for the contracted volumes of production without limiting the Company's participation in price increases during the covered period. The Company paid $24,022,000 in cash to enter into these contracts. As of December 31, 2000, the Company was a party to the following hedging arrangements: 61 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
NYMEX Contract Volume Price in per Fair Market Contract Period MMBtu(a) MMBtu(a) Value(b) --------------- -------- -------- ----------- April 2001--March 2002........................ 25,550 $4.25 $ 6,930,000 April 2002--December 2002..................... 19,250 $4.00 $13,342,000
-------- (a) MMBtu means million British Thermal Units. (b) Fair Market value is calculated using prices derived from NYMEX futures contract prices existing at December 31, 2000. These hedging transactions are settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days or occasionally, the penultimate trading day of a particular contract month. For any particular floor transaction, the counter-party is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction. The Company is not required to make any payment in connection with the settlement of a floor transaction. As of December 31, 2000 the Company was not a party to any commodity price hedging contracts with respect to any of its current or future crude oil and condensate production. 62 POGO PRODUCING COMPANY & SUBSIDIARIES UNAUDITED SUPPLEMENTARY FINANCIAL DATA Oil and Gas Producing Activities The results of operations from oil and gas producing activities excludes non-oil and gas revenues, general and administrative expenses, interest charges, interest income and interest capitalized. Income tax (expense) or benefit was determined by applying the statutory rates to pretax operating results with adjustments for permanent differences.
Total United Kingdom of Company States Thailand Canada Other(a) --------- -------- ---------- ------- -------- (Expressed in thousands) 2000 ------------------------------------------------- Revenues.................... $ 479,202 $291,266 $183,060 $ 4,876 $ -- Lease operating expense..... (93,368) (58,916) (33,568) (884) -- Exploration expense......... (15,291) (6,532) (3,507) (856) (4,396) Dry hole and impairment expense.................... (28,608) (28,142) -- (466) -- Depreciation, depletion and amortization expense....... (129,476) (76,516) (50,968) (1,992) -- --------- -------- -------- ------- ------- Pretax operating results.... 212,459 121,160 95,017 678 (4,396) Income tax (expense) benefit.................... (87,307) (41,059) (47,509) (278) 1,539 --------- -------- -------- ------- ------- Operating results........... $ 125,152 $ 80,101 $ 47,508 $ 400 $(2,857) ========= ======== ======== ======= ======= -------- (a) Included in Other are costs associated with initial activities related to Hungary of $3,396, the British sector of the North Sea of $836, and the Danish sector of the North Sea of $164. 1999 ------------------------------------------------- Revenues.................... $ 230,499 $172,683 $ 54,480 $ 3,336 $ -- Lease operating expense..... (69,816) (46,341) (21,815) (1,660) -- Exploration expense......... (5,982) (4,147) (1,682) (153) -- Dry hole and impairment expense.................... (4,594) (4,259) -- (335) -- Depreciation, depletion and amortization expense....... (102,265) (73,886) (27,174) (1,205) -- --------- -------- -------- ------- ------- Pretax operating results.... 47,842 44,050 3,809 (17) -- Income tax (expense) benefit.................... (16,315) (14,418) (1,905) 8 -- --------- -------- -------- ------- ------- Operating results........... $ 31,527 $ 29,632 $ 1,904 $ (9) $ -- ========= ======== ======== ======= ======= 1998 ------------------------------------------------- Revenues.................... $ 200,154 $163,438 $ 35,445 $ 1,271 $ -- Lease operating expense..... (68,883) (47,294) (20,913) (676) -- Exploration expense......... (9,802) (8,831) (293) (678) -- Dry hole and impairment expense.................... (41,736) (41,736) -- -- -- Depreciation, depletion and amortization expense....... (109,288) (85,969) (22,753) (566) -- --------- -------- -------- ------- ------- Pretax operating results.... (29,555) (20,392) (8,514) (649) -- Income tax benefit.......... 11,916 7,399 4,257 260 -- --------- -------- -------- ------- ------- Operating results........... $ (17,639) $(12,993) $ (4,257) $ (389) $ -- ========= ======== ======== ======= =======
63 POGO PRODUCING COMPANY & SUBSIDIARIES UNAUDITED SUPPLEMENTARY FINANCIAL DATA--(Continued) The following table sets forth the Company's costs incurred (expressed in thousands) for oil and gas producing activities during the years indicated.
Total United Kingdom of Company States Thailand Canada Other(a) -------- -------- ---------- ------- -------- Costs incurred (capitalized unless otherwise indicated): 2000: Property acquisition Proved.................... $ 8,393 $ 8,393 -- -- -- Unproved.................. 11,213 7,602 1,882 1,729 -- Exploration Capitalized............... 36,588 23,978 7,518 5,092 -- Expensed.................. 15,291 6,532 3,507 856 4,396 Development................. 108,991 71,621 36,034 1,336 -- Interest.................... 20,918 5,446 15,472 -- -- -------- -------- -------- ------- ------ Total oil and gas costs incurred................... $201,394 $123,572 $ 64,413 $ 9,013 $4,396 ======== ======== ======== ======= ====== Provision for depreciation, depletion and amortization..... $129,476 $ 76,516 $ 50,968 $ 1,992 $ -- ======== ======== ======== ======= ====== -------- (a) Included in the expensed exploration costs reflected in Other are costs associated with initial activities related to Hungary of $3,396, the British sector of the North Sea of $836, and the Danish sector of the North Sea of $164. 1999: Property acquisition Proved.................... $ 19,532 $ 19,532 $ -- $ -- $ -- Unproved.................. 7,129 6,506 -- 623 -- Exploration Capitalized............... 20,263 15,448 3,500 1,315 -- Expensed.................. 5,982 4,147 1,682 153 -- Development................. 150,096 54,204 95,163 729 -- Interest.................... 17,733 6,599 11,134 -- -- -------- -------- -------- ------- ------ Total oil and gas costs incurred................... $220,735 $106,436 $111,479 $ 2,820 $ -- ======== ======== ======== ======= ====== Provision for depreciation, depletion and amortization..... $102,265 $ 73,886 $ 27,174 $ 1,205 $ -- ======== ======== ======== ======= ====== 1998: Property acquisition Proved.................... $139,346 $133,474 $ -- $ 5,872 $ -- Unproved.................. 10,557 10,557 -- -- -- Exploration Capitalized............... 36,465 24,685 11,631 149 -- Expensed.................. 9,802 8,831 293 678 -- Development................. 156,718 64,052 89,365 3,301 -- Interest.................... 9,381 3,209 6,172 -- -- -------- -------- -------- ------- ------ Total oil and gas costs incurred................... $362,269 $244,808 $107,461 $10,000 $ -- ======== ======== ======== ======= ====== Provision for depreciation, depletion and amortization..... $109,288 $ 85,969 $ 22,753 $ 566 $ -- ======== ======== ======== ======= ======
64 POGO PRODUCING COMPANY & SUBSIDIARIES UNAUDITED SUPPLEMENTARY FINANCIAL DATA--(Continued) The following information regarding estimates of the Company's proved oil and gas reserves, which are located offshore in United States waters of the Gulf of Mexico, onshore in the United States and Canada and offshore in the Kingdom of Thailand is based on reports prepared by Ryder Scott Company Petroleum Engineers. The definitions and assumptions that serve as the basis for the discussions under the caption "Item 1, Business--Exploration and Production Data--Reserves" should be referred to in connection with the following information. Estimates of Proved Reserves
Oil, Condensate and Natural Gas Liquids (Bbls.) Total United Kingdom of Company States Thailand Canada ----------- ---------- ---------- -------- Proved Reserves as of December 31, 1997....................... 58,164,353 29,381,510 28,782,843 -- Revisions of previous estimates.................... (263,410) 1,316,467 (1,417,472) (162,405) Extensions, discoveries and other additions.............. 10,111,879 2,767,537 7,341,791 2,551 Purchase of properties........ 6,226,804 5,496,985 -- 729,819 Sale of properties............ (28,024) (28,024) -- -- Estimated 1998 production..... (6,702,038) (5,724,933) (896,200) (80,905) ----------- ---------- ---------- -------- Proved Reserves as of December 31, 1998....................... 67,509,564 33,209,542 33,810,962 489,060 Revisions of previous estimates.................... 7,274,136 8,922,125 (1,634,802) (13,187) Extensions, discoveries and other additions.............. 8,673,230 2,647,306 5,797,988 227,936 Purchase of properties........ 3,698,016 3,698,016 -- -- Sale of properties............ (1,690,467) (1,690,467) -- -- Estimated 1999 production..... (6,688,062) (5,232,860) (1,318,451) (136,751) ----------- ---------- ---------- -------- Proved Reserves as of December 31, 1999....................... 78,776,417 41,553,662 36,655,697 567,058 Revisions of previous estimates.................... 2,335,209 2,561,793 (480,335) 253,751 Extensions, discoveries and other additions.............. 24,741,720 19,115,830 5,546,923 78,967 Purchase of properties........ 23,657 23,657 -- -- Sale of properties............ (205,506) (205,506) -- -- Estimated 2000 production..... (10,350,000) (5,571,000) (4,657,000) (122,000) ----------- ---------- ---------- -------- Proved Reserves as of December 31, 2000....................... 95,321,497 57,478,436 37,065,285 777,776 =========== ========== ========== ======== Proved Developed Reserves as of: December 31, 1997............. 33,149,612 26,167,519 6,982,093 -- December 31, 1998............. 33,368,347 28,581,175 4,298,112 489,060 December 31, 1999............. 53,894,653 35,136,156 18,407,852 350,645 December 31, 2000............. 60,656,634 35,132,295 24,746,563 777,776
65 POGO PRODUCING COMPANY & SUBSIDIARIES UNAUDITED SUPPLEMENTARY FINANCIAL DATA--(Continued) Estimates of Proved Reserves
Natural Gas (MMcf) Total United Kingdom of Company States Thailand Canada ------- ------- ---------- ------ Proved Reserves as of December 31, 1997... 401,488 216,720 184,768 -- Revisions of previous estimates......... (13,376) 7,391 (17,943) (2,824) Extensions, discoveries and other additions.............................. 70,649 55,859 14,418 372 Purchase of properties.................. 38,689 32,259 -- 6,430 Sale of properties...................... (2,738) (2,738) -- -- Estimated 1998 production............... (54,543) (41,136) (12,854) (553) ------- ------- ------- ------ Proved Reserves as of December 31, 1998... 440,169 268,355 168,389 3,425 Revisions of previous estimates......... 7,704 27,327 (17,617) (2,006) Extensions, discoveries and other additions.............................. 61,717 44,563 16,991 163 Purchase of properties.................. 7,060 7,060 -- -- Sale of properties...................... (90,164) (90,164) -- -- Estimated 1999 production............... (51,788) (37,012) (14,175) (601) ------- ------- ------- ------ Proved Reserves as of December 31, 1999... 374,698 220,129 153,588 981 Revisions of previous estimates......... (2,245) 3,110 (5,518) 163 Extensions, discoveries and other additions.............................. 56,372 28,623 26,605 1,144 Purchase of properties.................. 2,601 2,601 -- -- Sale of properties...................... (1,195) (1,195) -- -- Estimated 2000 production............... (60,248) (38,647) (21,371) (230) ------- ------- ------- ------ Proved Reserves as of December 31, 2000... 369,983 214,621 153,304 2,058 ======= ======= ======= ====== Proved Developed Reserves as of: December 31, 1997....................... 239,732 179,972 59,760 -- December 31, 1998....................... 225,054 181,205 40,424 3,425 December 31, 1999....................... 245,257 156,398 88,041 818 December 31, 2000....................... 239,978 150,684 87,236 2,058
66 POGO PRODUCING COMPANY & SUBSIDIARIES STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES--Unaudited
Total United Kingdom of Company States Thailand Canada ----------- ---------- ---------- -------- (Expressed in thousands) 2000 --------------------------------------------- Future gross revenues........... $ 4,926,262 $3,624,205 $1,250,223 $ 51,834 Future production costs: Lease operating expense....... (1,043,108) (550,020) (473,022) (20,066) Future development and abandonment costs.............. (316,467) (196,308) (119,476) (683) ----------- ---------- ---------- -------- Future net cash flows before income taxes................... 3,566,687 2,877,877 657,725 31,085 Discount at 10% per annum....... (1,111,771) (952,332) (151,704) (7,735) ----------- ---------- ---------- -------- Discounted future net cash flow before income taxes............ 2,454,916 1,925,545 506,021 23,350 Future income taxes, net of discount at 10% per annum...... (739,740) (597,811) (135,391) (6,538) ----------- ---------- ---------- -------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves............... $ 1,715,176 $1,327,734 $ 370,630 $ 16,812 =========== ========== ========== ======== 1999 --------------------------------------------- Future gross revenues........... $ 2,752,682 $1,511,517 $1,225,327 $ 15,838 Future production costs: Lease operating expense....... (744,848) (408,533) (332,786) (3,529) Future development and abandonment costs.............. (301,148) (163,862) (136,684) (602) ----------- ---------- ---------- -------- Future net cash flows before income taxes................... 1,706,686 939,122 755,857 11,707 Discount at 10% per annum....... (552,040) (363,286) (186,263) (2,491) ----------- ---------- ---------- -------- Discounted future net cash flow before income taxes............ 1,154,646 575,836 569,594 9,216 Future income taxes, net of discount at 10% per annum...... (285,963) (127,207) (159,126) 370 ----------- ---------- ---------- -------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves............... $ 868,683 $ 448,629 $ 410,468 $ 9,586 =========== ========== ========== ======== 1998 --------------------------------------------- Future gross revenues........... $ 1,624,242 $ 880,743 $ 732,942 $ 10,557 Future production costs: Lease operating expense....... (540,332) (281,421) (255,252) (3,659) Future development and abandonment costs.............. (331,607) (167,724) (163,680) (203) ----------- ---------- ---------- -------- Future net cash flows before income taxes................... 752,303 431,598 314,010 6,695 Discount at 10% per annum....... (257,077) (142,293) (113,413) (1,371) ----------- ---------- ---------- -------- Discounted future net cash flow before income taxes............ 495,226 289,305 200,597 5,324 Future income taxes, net of discount at 10% per annum...... (72,505) (22,494) (52,132) 2,121 ----------- ---------- ---------- -------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves............... $ 422,721 $ 266,811 $ 148,465 $ 7,445 =========== ========== ========== ========
67 POGO PRODUCING COMPANY & SUBSIDIARIES STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES--Unaudited--(Continued) The standardized measure of discounted future net cash flows from the production of proved reserves is developed as follows: 1. Estimates are made of quantities of proved reserves and the future periods in which they are expected to be produced based on year end economic conditions. 2. The estimated future gross revenues from proved reserves are priced on the basis of year end prices, except in those instances where fixed and determinable natural gas price escalation's are covered by contracts. 3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as certain abandonment costs based on year end cost estimates, and the estimated effect of future income taxes. These cost estimates are subject to some uncertainty, particularly those estimates relating to the Company's properties located in the Kingdom of Thailand. The standardized measure of discounted future net cash flows does not purport to present the fair market value of the Company's oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and the risks inherent in reserve estimates. The following are the principal sources of change in the standardized measure of discounted future net cash flows. All amounts are related to changes in reserves located in the United States,the Kingdom of Thailand, and Canada, as noted.
Year Ended December 31, 2000 ------------------------------------------- Total United Kingdom of Company States Thailand Canada ---------- ---------- ---------- ------- (Expressed in thousands) Beginning balance................ $ 868,683 $ 448,629 $ 410,468 $ 9,586 Revisions to prior years' proved reserves: Net changes in prices and production costs.............. 817,201 839,536 (26,592) 4,257 Net changes due to revisions in quantity estimates............ 55,574 63,945 (13,759) 5,388 Net changes in estimates of future development costs...... (22,657) (43,119) 21,527 (1,065) Accretion of discount.......... 115,465 57,584 56,959 922 Changes in production rate and other......................... 110,717 125,761 (13,029) (2,015) ---------- ---------- --------- ------- Total revisions.............. 1,076,300 1,043,707 25,106 7,487 New field discoveries and extensions, net of future production and development costs........................... 494,689 460,239 25,147 9,303 Purchases of properties.......... 11,135 11,135 -- -- Sales of properties.............. (5,712) (5,712) -- -- Sales of oil and gas produced, net of production costs......... (385,834) (232,350) (149,492) (3,992) Previously estimated development costs incurred.................. 109,692 72,690 35,666 1,336 Net change in income taxes....... (453,777) (470,604) 23,735 (6,908) ---------- ---------- --------- ------- Net change in standardized measure of discounted future net cash flows..... 846,493 879,105 (39,838) 7,226 ---------- ---------- --------- ------- Ending balance................... $1,715,176 $1,327,734 $ 370,630 $16,812 ========== ========== ========= =======
68 POGO PRODUCING COMPANY & SUBSIDIARIES STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES--Unaudited--(Continued)
Year Ended December 31, 1999 ----------------------------------------- Total United Kingdom of Company States Thailand Canada --------- --------- ---------- ------- (Expressed in thousands) Beginning balance.................. $ 422,721 $ 266,811 $ 148,465 $ 7,445 Revisions to prior years' proved reserves: Net changes in prices and production costs................ 481,570 246,516 228,424 6,630 Net changes due to revisions in quantity estimates.............. 82,304 127,719 (40,328) (5,087) Net changes in estimates of future development costs........ (61,267) (19,920) (40,470) (877) Accretion of discount............ 49,523 28,931 20,060 532 Changes in production rate and other........................... 37,017 5,429 30,583 1,005 --------- --------- --------- ------- Total revisions................ 589,147 388,675 198,269 2,203 New field discoveries and extensions, net of future production and development costs.. 177,822 66,956 108,230 2,636 Purchases of properties............ 29,421 29,421 -- -- Sales of properties................ (128,555) (128,555) -- -- Sales of oil and gas produced, net of production costs............... (160,683) (126,342) (32,665) (1,676) Previously estimated development costs incurred.................... 152,268 56,376 95,163 729 Net change in income taxes......... (213,458) (104,713) (106,994) (1,751) --------- --------- --------- ------- Net change in standardized measure of discounted future net cash flows.............. 445,962 181,818 262,003 2,141 --------- --------- --------- ------- Ending balance..................... $ 868,683 $ 448,629 $ 410,468 $ 9,586 ========= ========= ========= ======= Year Ended December 31, 1998 ----------------------------------------- Total United Kingdom of Company States Thailand Canada --------- --------- ---------- ------- (Expressed in thousands) Beginning balance.................. $ 349,465 $ 312,775 $ 36,690 $ -- Revisions to prior years' proved reserves: Net changes in prices and production costs................ (165,355) (151,407) (13,948) -- Net changes due to revisions in quantity estimates.............. 5,592 13,681 (8,089) -- Net changes in estimates of future development costs........ (10,777) (43,419) 32,642 -- Accretion of discount............ 46,278 40,616 5,662 -- Changes in production rate and other........................... 1,649 (6,485) 7,539 595 --------- --------- --------- ------- Total revisions................ (122,613) (147,014) 23,806 595 New field discoveries and extensions, net of future production and development costs.. 101,142 55,418 45,338 386 Purchases of properties............ 46,907 41,969 -- 4,938 Sales of properties................ (17,158) (17,158) -- -- Sales of oil and gas produced, net of production costs............... (131,271) (116,144) (14,532) (595) Previously estimated development costs incurred.................... 155,438 66,073 89,365 -- Net change in income taxes......... 40,811 70,892 (32,202) 2,121 --------- --------- --------- ------- Net change in standardized measure of discounted future net cash flows.............. 73,256 (45,964) 111,775 7,445 --------- --------- --------- ------- Ending balance..................... $ 422,721 $ 266,811 $ 148,465 $ 7,445 ========= ========= ========= =======
69 Quarterly Results--Unaudited Summaries of the Company's results of operations by quarter for the years 2000 and 1999 are as follows:
Quarter Ended ---------------------------------------- Mar. 31 June 30 Sept. 30 Dec. 31 -------- -------- -------- -------- (Expressed in thousands, except per share amounts) 2000, As Restated (a): Revenues.............................. $100,918 $108,020 $129,082 $159,971 Gross profit (b)...................... $ 35,092 $ 44,274 $ 60,716 $ 74,223 Income before cumulative effect of change in accounting principle....... $ 10,151 $ 16,791 $ 26,182 $ 35,899 Cumulative effect of change in accounting principle................. $ (1,768) $ -- $ -- $ -- Net income............................ $ 8,383 $ 16,791 $ 26,182 $ 35,899 Earnings (loss) per share (c): Basic Income before cumulative effect of change in accounting principle... $ 0.25 $ 0.42 $ 0.65 $ 0.88 Cumulative effect of change in accounting principle............. $ (0.04) -- -- -- Net income........................ $ 0.21 $ 0.42 $ 0.65 $ 0.88 Diluted Income before cumulative effect of change in accounting principle... $ 0.25 $ 0.39 $ 0.58 $ 0.76 Cumulative effect of change in accounting principle............. $ (0.04) -- -- -- Net income........................ $ 0.21 $ 0.39 $ 0.58 $ 0.76 2000, As Reported (a): Revenues.............................. $105,499 $111,997 $129,834 Gross profit (b)...................... $ 38,703 $ 47,310 $ 62,142 Net income............................ $ 11,956 $ 18,309 $ 26,895 Earnings per share (c): Basic............................... $ 0.30 $ 0.45 $ 0.67 Diluted............................. $ 0.29 $ 0.42 $ 0.59 1999 Revenues.............................. $ 76,046 (d) $ 44,828 $ 69,138 $ 85,104 Gross profit (b)...................... $ 33,987 $ 5,116 $ 18,912 $ 25,842 Net income (loss)..................... $ 14,313 $ (3,006) $ 2,737 $ 8,090 Earnings (loss) per share (c): Basic............................... $ 0.36 $ (0.07) $ 0.07 $ 0.20 Diluted............................. $ 0.36 $ (0.07) $ 0.07 $ 0.20
-------- (a) The first three quarters of 2000 have been restated to give effect to the change in accounting for the evaluation of the company's crude oil inventories from net realizable value to the lower of cost or net realizable value. Refer to footnote 1, Summary of Significant Accounting Policies, Inventory--Product for additional information. (b) Represents revenues less lease operating, pipeline operating and natural gas purchases, exploration, dry hole, and impairment, and depreciation, depletion and amortization expenses. (c) The sum of the individual quarterly earnings (loss) per share may not agree with year-to-date earnings (loss) per share as each quarterly computation is based on the income or loss for that quarter and the weighted average number of common shares outstanding during that period. (d) Revenues for the first quarter of 1999 include $37,344,000 related to gains on the sales of properties. 70 ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. None PART III ITEM 10. Directors and Executive Officers of the Registrant. The information regarding nominees and continuing directors in the Company's definitive Proxy Statement for its annual meeting to be held on April 24, 2001, to be filed within 120 days of December 31, 2000 pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the Company's "2001 Proxy Statement"), is incorporated herein by reference. See also Item S-K 401(b) appearing in Part I of this Form 10-K. ITEM 11. Executive Compensation. The information regarding executive compensation in the Company's 2001 Proxy Statement, other than the information regarding the Compensation Committee Report on Executive Compensation, is incorporated herein by reference. ITEM 12. Security Ownership of Certain Beneficial Owners and Management. The information regarding ownership of the Company securities by management and certain other beneficial owners in the Company's 2001 Proxy Statement is incorporated herein by reference. ITEM 13. Certain Relationships and Related Transactions. The information regarding certain relationships and related transactions with management in the Company's 2001 Proxy Statement in incorporated herein by reference. PART IV ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a) Financial Statements and Supplementary Data, Financial Statement Schedules and Exhibits
Page ---- 1.Financial Statements and Supplementary Data: Report of Independent Public Accountants................................. 38 Consolidated statements of income........................................ 39 Consolidated balance sheets.............................................. 40 Consolidated statements of cash flows.................................... 42 Consolidated statements of shareholders' equity.......................... 43 Notes to consolidated financial statements............................... 44 Unaudited supplementary financial data................................... 63
2. Financial Statement Schedules: All Financial Statement Schedules have been omitted because they are not required, are not applicable or the information required has been included elsewhere herein. 71 3. Exhibits: *2.1 Agreement and Plan of Merger dated as of November 19, 2000 among Pogo Producing Company, NORIC Corporation, and the shareholders signatory thereto (Exhibit 99.1, Current Report on Form 8-K filed November 21, 2000, File No. 1-7792). *3.1 Restated Certificate of Incorporation of Pogo Producing Company (Exhibit 3(a), Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-7792). *3.2 Certificate of Designation, Preferences and Rights of Preferred Stock of Pogo Producing Company, dated March 25, 1987 (Exhibit 3(a)(1), Annual Report on Form 10-K for the year ended December 31, 1987, File No. 0-5468). *3.3 Bylaws of Pogo Producing Company, as amended and restated through January 27, 1998 (Exhibit 3(b), Annual Report on Form 10-K for the year ended December 31, 1998, File No. 1-7792). *4.1 Amended and Restated Credit Agreement dated as of August 1, 1997 among Pogo Producing Company, certain commercial lending institutions, Bank of Montreal as the Agent and Banque Paribas as the Co-Agent (Exhibit 4(a), Quarterly Report on Form 10-Q for the quarter ended, June 30, 1997, File No. 1-7792). *4.2 First Amendment dated as of December 21, 1998, to Amended and Restated Credit Agreement dated as of August 1, 1997 among Pogo Producing Company, certain commercial lending institutions, Bank of Montreal as the Agent and Banque Paribas as the Co-Agent (Exhibit 4.1, Amendment No. 1 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, File No. 1-7792). *4.3 Second Amendment dated July 16, 1999, to Amended and Restated Credit Agreement dated as of August 1, 1997 among Pogo Producing Company, certain commercial lending institutions, Bank of Montreal as the Agent and Banque Paribas as the Co-Agent (Exhibit 4.1, Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, File No. 1-7792). *4.4 Fourth Amendment dated May 3, 2000, to Amended and Restated Credit Agreement dated as of August 1, 1997 among Pogo Producing Company, certain commercial lending institutions, Bank of Montreal as the Agent and Banque Paribas as the Co-Agent (Exhibit 4.1, Quarterly Report on Form 10-Q for the quarter ended June 30, 2000, File No. 1-7792). *4.5 Indenture dated as of June 15, 1996 to Fleet National Bank, as Trustee (Exhibit 4(f), Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 001-7792). *4.6 Indenture dated as of May 15, 1997 between Pogo Producing Company and Fleet National Bank (now State Street Bank & Trust Company as successor in interest under the Indenture) as Trustee (Exhibit 4.3, Registration Statement on Form S-4, filed July 2, 1997, File No. 333-30613). *4.7 Indenture dated as of January 15, 1999 between Pogo Producing Company and State Street Bank & Trust Company as Trustee (Exhibit 4.2, Registration Statement on Form S-4, filed February 10, 1999, File No. 333-72129). *4.8 Amended and Restated Declaration of Trust of Pogo Trust I dated as of June 2, 1999 (Exhibit 4.1, Current Report on Form 8-K, filed June 2, 1999, File No. 1-7792). *4.9 Junior Subordinated Indenture dated as of June 1, 1999, between Pogo Producing Company and Wilmington Trust Company, as Trustee (Exhibit 4.3, Current Report on Form 8-K, filed June 2, 1999, File No. 1-7792). *4.10 Supplemental Indenture No. 1 dated as of June 1, 1999 to Junior Subordinated Indenture dated as of June 1, 1999, between Pogo Producing Company and Wilmington Trust Company, as Trustee (Exhibit 4.4, Current Report on Form 8-K, filed June 2, 1999, File No. 1-7792). *4.11 Rights Agreement dated as of April 26, 1994 between Pogo Producing Company and Harris Trust Company of New York, as Rights Agent (Exhibit 4, Current Report on Form 8-K filed April 26, 1994, File No. 1-7792). *4.12 Certificate of Designations of Series A Junior Participating Preferred Stock of Pogo Producing Company dated April 26, 1994 (Exhibit 4(d), Registration Statement on Form S-8 filed August 9, 1994, File No. 33-54969). Other instruments defining the rights of holders of long-term debt of Pogo Producing Company and its subsidiaries are not being filed because the total amount of securities authorized by such instruments does not exceed 10% of the total assets of Pogo Producing Company and its subsidiaries on a consolidated basis as of December 31, 2000. Pogo Producing Company hereby agrees to furnish to the Commission a copy of any such debt instrument upon request.
72 Executive Compensation Plans and Arrangements (comprising Exhibits 10.1 through 10.42, inclusive) *10.1 1989 Incentive and Nonqualified Stock Option Plan of Pogo Producing Company, as amended and restated effective January 25, 1994 (Exhibit 99, Definitive Proxy Statement on Schedule 14A, filed March 22, 1994, File No. 1-7792). *10.2 Form of Stock Option Agreement under 1989 Incentive and Nonqualified Stock Option Plan, as amended and restated effective January 22, 1991 (Exhibit 10(d)(1), Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-5468). *10.3 Form of Director Stock Option Agreement under 1989 Incentive and Nonqualified Stock Option Plan as amended and restated effective January 22, 1991 (Exhibit 10(d)(2), Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-5468). *10.4 1995 Long-Term Incentive Plan (Exhibit 4(c), Registration Statement on Form S-8 filed May 22, 1996, File No. 333-04233). *10.5 1998 Long-Term Incentive Plan (Exhibit 10.5, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.6 2000 Incentive Plan (Exhibit B) to the Company's Definitive Proxy Statement filed on Schedule 14A, March 27, 2000, File No. 001-7792). *10.7 Executive Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated February 1, 1996 (Exhibit 10(f)(1), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001- 7792). *10.8 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated effective February 1, 1999 (Exhibit 10.7, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.9 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated effective February 1, 2000 (Exhibit 10.8, Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-7792). 10.10 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated effective February 1, 2001. *10.11 Executive Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated February 1, 1996 (Exhibit 10(f)(2), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001- 7792). *10.12 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated effective February 1, 1999 (Exhibit 10.9, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.13 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated effective February 1, 2000 (Exhibit 10.11, Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-7792). 10.14 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated effective February 1, 2001. *10.15 Executive Employment Agreement by and between Pogo Producing Company and R. Phillip Laney, dated February 1, 1996 (Exhibit 10(f)(4), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001- 7792). *10.16 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and R. Phillip Laney, dated effective February 1, 1999 (Exhibit 10.12, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.17 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and R. Phillip Laney, dated effective February 1, 2000 (Exhibit 10.17, Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-7792).
73 10.18 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and R. Phillip Laney, dated effective February 1, 2001. *10.19 Executive Employment Agreement by and between Pogo Producing Company and John O. McCoy, Jr., dated February 1, 1996 (Exhibit 10(f)(5), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792). *10.20 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and John O. McCoy, Jr., dated effective February 1, 1999 (Exhibit 10.15, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.21 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and John O. McCoy, dated effective February 1, 2000 (Exhibit 10.20, Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-7792). 10.22 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and John O. McCoy, dated effective February 1, 2001. 10.23 Executive Employment Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated February 1, 2001. *10.24 Executive Employment Agreement by and between Pogo Producing Company and Bruce E. Archinal, dated as of February 1, 1998 (Exhibit 10(c)(7)(i), Annual Report on Form 10-K for the year ended December 31, 1997, File No. 001-7792). *10.25 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Bruce E. Archinal, dated effective February 1, 1999 (Exhibit 10.19, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.26 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Bruce E. Archinal, dated effective February 1, 2000 (Exhibit 10.26, Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-7792). 10.27 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Bruce E. Archinal, dated effective February 1, 2001. *10.28 Executive Employment Agreement by and between Pogo Producing Company and David R. Beathard, dated as of February 1, 1999 (Exhibit 10.20, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.29 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and David R. Beathard, dated effective February 1, 2000 (Exhibit 10.28, Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-7792). 10.30 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and David R. Beathard, dated effective February 1, 2001. *10.31 Executive Employment Agreement by and between Pogo Producing Company and Stephen R. Brunner, dated as of February 1, 1999 (Exhibit 10.21, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.32 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Stephen R. Brunner, dated effective February 1, 2000 (Exhibit 10.30, Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-7792). 10.33 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Stephen R. Brunner, dated effective February 1, 2001. *10.34 Executive Employment Agreement by and between Pogo Producing Company and J. D. McGregor, dated as of February 1, 1999 (Exhibit 10.22, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001- 7792).
74 *10.35 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and J. D. McGregor, dated effective February 1, 2000 (Exhibit 10.32, Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-7792). 10.36 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and J. D. McGregor, dated effective February 1, 2001. *10.37 Executive Employment Agreement by and between Pogo Producing Company and Gerald A. Morton, dated as of February 1, 1999 (Exhibit 10.23, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.38 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Gerald A. Morton, dated effective February 1, 2000 (Exhibit 10.34, Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-7792). 10.39 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Gerald A. Morton, dated effective February 1, 2001. *10.40 Executive Employment Agreement by and between Pogo Producing Company and James P. Ulm, II, dated as of February 1, 2000 (Exhibit 10.35, Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-7792). 10.41 Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and James P. Ulm II, dated effective February 1, 2001. *10.42 Excess Benefits Letter Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated March 2, 1995 (Exhibit 10(g)(2), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001- 7792). *10.43 Amended and Restated Bareboat Charter Agreement by and between Tantawan Services, L.L.C. and Tantawan Production B.V., dated as of February 9, 1996 (Exhibit 10.26, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.44 Bareboat Charter Agreement by and between Thaipo Limited, Thai Romo Limited, Palang Sophon Limited, B8/32 Partners Limited and Watertight Shipping B.V. dated as of August 24, 1998 (Exhibit 10.27, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-7792). *10.45 Gas Sales Agreement dated November 7, 1995, among The Petroleum Authority of Thailand, Thaipo, Limited, Thai Romo Ltd. and The Sophonpanich Co., Ltd. (Exhibit 10(k), Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 001-7792). *10.46 The First Amendment to the Gas Sales Agreement dated November 12, 1997, among The Petroleum Authority of Thailand, B8/32 Partners Limited, Thaipo, Limited, Thai Romo Limited and Palang Sophon Limited (Exhibit 10(g)(ii), Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-7792). *21 List of Subsidiaries of Pogo Producing Company (Exhibit 21, Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001- 7792). 23.1 Consent of Independent Public Accountants. 23.2 Consent of Independent Petroleum Engineers. 24 Powers of Attorney from each Director of Pogo Producing Company whose signature is affixed to this Form 10-K for the year ended December 31, 2000.
-------- * Asterisk indicates exhibits incorporated by reference as shown. (b) Reports on Form 8-K (1) Current Report on Form 8-K filed on November 20, 2000, regarding Item 9. Regulation FD Disclosure. (2) Current Report on Form 8-K filed on November 20, 2000, regarding Item 5. Other Events. (3) Current Report on Form 8-K filed on November 21, 2000, regarding Item 7. Financial Statements and Exhibits. (4) Current Report on Form 8-K filed on November 27, 2000, regarding Item 5. Other Events. 75 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Pogo Producing Company (Registrant) /s/ Paul G. Van Wagenen By:__________________________________ Paul G. Van Wagenen Chairman of the Board, President and Chief Executive Officer Date: March 2, 2001 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on March 2, 2001.
Signatures Title ---------- ----- /s/ Paul G. Van Wagenen Principal Executive Officer and ______________________________________ Director Paul G. Van Wagenen Chairman of the Board, President and Chief Executive Officer /s/ James P. Ulm, II Principal Financial Officer ______________________________________ James P. Ulm, II Vice President and Chief Financial Officer /s/ Thomas E. Hart Principal Accounting Officer ______________________________________ Thomas E. Hart Vice President and Chief Accounting Officer * Director ______________________________________ Jerry M. Armstrong * Director ______________________________________ Jack S. Blanton * Director ______________________________________ W. M. Brumley, Jr. * Director ______________________________________ Robert H. Campbell * Director ______________________________________ William L. Fisher * Director ______________________________________ Gerrit W. Gong * Director ______________________________________ Frederick A. Klingenstein * Director ______________________________________ Stephen A. Wells
/s/ Thomas E. Hart *By:_____________________________ Thomas E. Hart Attorney-in-Fact 76