-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, T/ZR4lIlkBxbhezPRf/cSRPodIY0rftNYiAaMQPqXKZN+CkI6XhWTq3g+RKBFkXF YeIxrqdul7P+fmSZDeLK4A== 0000890566-98-000351.txt : 19980318 0000890566-98-000351.hdr.sgml : 19980318 ACCESSION NUMBER: 0000890566-98-000351 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 18 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980317 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: POGO PRODUCING CO CENTRAL INDEX KEY: 0000230463 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 741659398 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-07792 FILM NUMBER: 98567317 BUSINESS ADDRESS: STREET 1: 5 GREENWAY PLAZA STE 2700 STREET 2: P O BOX 2504 CITY: HOUSTON STATE: TX ZIP: 77046-0504 BUSINESS PHONE: 7132975017 MAIL ADDRESS: STREET 1: 5 GREENWAY PLAZA SUITE 2700 STREET 2: P O BOX 2504 CITY: HOUSTON STATE: TX ZIP: 77046-0504 FORMER COMPANY: FORMER CONFORMED NAME: PENNZOIL OFFSHORE GAS OPERATORS INC /TX/ DATE OF NAME CHANGE: 19600201 10-K 1 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, 1997 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 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 INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.) 5 GREENWAY PLAZA, P.O. BOX 2504 77252-2504 HOUSTON, TEXAS (ZIP CODE) (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 297-5000 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: NAME OF EACH EXCHANGE TITLE OF EACH CLASS: ON WHICH REGISTERED: Common Stock, $1 par value New York Stock Exchange Pacific Stock Exchange Preferred Stock Purchase Rights New York Stock Exchange Pacific Stock Exchange 5 1/2% Convertible Subordinated New York Stock Exchange Notes due March 15, 2004 SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: 5 1/2% Convertible Subordinated Notes due June 15, 2006 8 3/4% Senior Subordinated Notes due May 15, 2007 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. [ ] 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 $890,078,498 as of March 13, 1998 (based on $30.1875 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange Composite Tape on such date). 37,554,982 shares of the registrant's Common Stock were outstanding as of March 13, 1998. DOCUMENT INCORPORATED BY REFERENCE Portions of the Company's definitive Proxy Statement respecting the annual meeting of shareholders to be held on April 28, 1998 (to be filed not later than 120 days after December 31, 1997) 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, 1997 (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 Company's operations both domestically and in Thailand, 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") including, without limitation, in connection with such forward-looking statements. 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. 2 PART I ITEM 1. BUSINESS. Pogo Producing Company (the "Company"), incorporated in 1970, is engaged in oil and gas exploration, development 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 in the Gulf of Thailand. As of December 31, 1997, the Company had interests in 101 lease blocks offshore Louisiana and Texas, approximately 237,000 gross acres onshore in the United States and approximately 734,000 gross acres offshore in the Kingdom of Thailand. Unless otherwise specifically identified, the information set forth in this Annual Report, including production rates and the number of wells, platforms and blocks, is presented on a gross basis, rather than net to the Company. In recent years, the Company has concentrated its efforts in selected areas where it believes that its expertise, competitive acreage position, or ability to quickly take advantage of new opportunities offer the possibility of superior rates of return. As of January 1, 1998, six significant operating areas, of which three are located in the Gulf of Mexico and one each in South Texas, New Mexico and Thailand, accounted for approximately 82% of the Company's estimated proved natural gas reserves, approximately 90% of the Company's estimated proved oil, condensate and natural gas liquids reserves, approximately 80% of the Company's natural gas production and 89% of the Company's oil, condensate and natural gas liquids production for 1997. Reserves, as estimated by Ryder Scott Petroleum Engineers, Houston Texas ("Ryder Scott"), and production data, as estimated by the Company, for the six significant operating areas are shown in the following table. No other producing area accounted for more than 3% of the Company's estimated proved reserves as of January 1, 1998.
SIGNIFICANT OPERATING AREA 1997 AVERAGE NET NET PROVED RESERVES(A) DAILY PRODUCTION ------------------------------------------ ------------------------------------------ NATURAL GAS LIQUIDS(B) NATURAL GAS LIQUIDS(B) -------------------- -------------------- -------------------- -------------------- MMCF % MBBLS % MCF % BBLS % --------- --------- --------- --------- --------- --------- --------- --------- DOMESTIC OFFSHORE Eugene Island................... 27,182 6.8 7,607 13.1 23,334 13.5 4,673 24.5 Main Pass....................... 14,570 3.6 3,830 6.6 7,104 4.1 2,777 14.6 East Cameron.................... 30,199 7.5 1,006 1.7 53,893 31.2 3,242 17.0 DOMESTIC ONSHORE New Mexico...................... 20,578 5.1 11,287 19.4 9,151 5.3 4,008 21.0 South Texas..................... 52,724 13.1 1 0.0 11,484 6.6 0 0.0 INTERNATIONAL Kingdom of Thailand.. 184,768 46.0 28,783 49.5 37,733 19.0 2,421 14.0
TOTAL NET PROVED RESERVES(A) % ----------- DOMESTIC OFFSHORE Eugene Island................... 10.7 Main Pass....................... 5.0 East Cameron.................... 4.8 DOMESTIC ONSHORE New Mexico...................... 11.8 South Texas..................... 7.0 INTERNATIONAL Kingdom of Thailand.. 47.6 - ------------ (a) Net proved reserves and total net proved reserves are each as of January 1, 1998. Units of measurement used in this table include: thousand cubic feet ("Mcf"), million cubic feet ("MMcf"), barrels ("Bbls") and thousand barrels ("MBbls"). (b) "Liquids," includes oil, condensate and natural gas liquids. DOMESTIC OFFSHORE OPERATIONS Historically, the Company's interests have been concentrated in the Gulf of Mexico, where approximately 59% of the Company's domestic proved reserves and 31% of its total proved reserves are now located. During 1997, approximately 65% of the Company's natural gas production and approximately 59% of its oil and condensate production was from its domestic offshore properties, contributing approximately 62% of the Company's consolidated oil and gas revenues. Three offshore producing areas, Eugene Island, Main Pass and East Cameron, account for approximately 18% of the Company's net proved natural gas 3 reserves and approximately 21% of the Company's proved crude oil, condensate and natural gas liquids reserves. See ";Significant Domestic Offshore Operating Areas during 1997." 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 sales and subsequent activities, as of December 31, 1997, the Company owned interests in 93 federal leases and 8 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 1997, the Company was successful in acquiring interests in 19 lease blocks through federal Outer Continental Shelf oil and gas lease sales and 1 lease block by assignment from a third party. The Department of the Interior has announced its intention to hold two lease sales during 1998 covering federal acreage in the Central and Western portions of the Gulf of Mexico; and it is anticipated that various states will also hold sales covering offshore state acreage from time to time. As in the case of prior sales, the extent to which the Company participates in future bidding 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. 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 1997 were approximately $86,300,000, or 9% lower than the Company's domestic offshore capital and exploration expenditures of approximately $94,400,000 (excluding approximately $2,000,000 of net property acquisitions) for 1996 and 128% higher than the Company's domestic offshore capital and exploration expenditures of approximately $37,800,000 (excluding approximately $650,000 of net property acquisitions) for 1995. The decrease in the Company's domestic offshore capital and exploration expenditures for 1997, compared with 1996, resulted primarily from a decrease in drilling activity and in construction and installation of offshore platforms, pipelines and other facilities, which was partially offset by the increased costs to the Company (and the entire oil and gas industry generally) because of price increases by the oil and gas services, construction and supply industries due to the shortage of skilled workers and the comparative scarcity of certain equipment, such as drilling rigs, and critical materials, such as certain types of steel pipe. The increase in the Company's domestic offshore capital and exploration expenditures for 1997, compared to 1995, resulted primarily from increased drilling activity and increased costs associated with the construction and installation of offshore platforms, pipelines and other facilities and the increase in prices discussed above. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." 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 4 be the operator of a particular lease. The Company was the operator on all or a portion of 30 of the 101 offshore leases in which it has an interest on December 31, 1997. 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. Platforms are used to accommodate both development drilling and additional exploratory drilling. Over the last three years, the gross cost of production platforms and related facilities to the joint ventures in which the Company has varying net interests has ranged from approximately $3,000,000 to approximately $16,500,000. Platform costs vary and more expensive platforms could be required in the future depending on, among other factors, the number of slots, water depth, currents, and sea floor conditions. For example, during 1997, the Company and its joint venture partners approved construction of a platform located on Viosca Knoll Block 823 which will be located in approximately 1200 feet of water. This platform, together with its related pipelines and other facilities, is currently estimated to have a gross cost of approximately $127,000,000 (approximately $13,700,000 net to the Company's current working interest). SIGNIFICANT DOMESTIC OFFSHORE OPERATING AREAS DURING 1997 EUGENE ISLAND A significant portion of the Company's reserves and a substantial part of its production are located in the Eugene Island area off the Louisiana coast in the Gulf of Mexico. The Eugene Island area has been an important part of the Company's operations since the first lease in that area was purchased in 1970 and production began in 1973. The Company currently holds interests in 10 blocks in the Eugene Island area. These blocks comprise eight fields containing 64 oil and gas wells producing from multiple reservoirs and horizons. During 1997, the Company participated in the drilling of eight wells in the Eugene Island operating area. The Eugene Island Block 330 field is one of the Company's most significant producing assets. This field, located in 245 feet of water, contains three drilling and production platforms in which the Company holds a 35% working interest, as well as an additional platform in which the Company holds a 30% working interest. There are currently 12 wells producing primarily natural gas and 34 wells producing primarily oil on the block. The Company and its joint venture partners drilled six new wells which added significant new reserves in this field during 1997. MAIN PASS The Company's 12 lease blocks in the Main Pass area, including two acquired in 1997, are located near the mouth of the Mississippi River in the Gulf of Mexico and include leases in which the Company has held an interest since 1974. The majority of the Company's production from the Main Pass area comes from a field that includes Main Pass Blocks 72, 73 and 72/74 which was unitized in 1982. The Company's working interest in this field is 35%. This field contains 20 producing oil wells and nine producing natural gas wells from three platforms operated by the Company's joint venture partner and is located in 125 feet of water. The Company participated in the drilling of 3 exploratory wells in the Main Pass area during 1997. EAST CAMERON The first leasehold interest acquired by the Company in the East Cameron area off the Texas/Louisiana border in the Gulf of Mexico commenced production in February 1973. Presently, the Company has interests in five offshore blocks in this area which contain two fields and 19 producing gas wells. Two of the five blocks were awarded to the Company and its joint venture partners during 1997 and have yet to be fully evaluated. During 1997, the Company and its partners were active in the East Cameron Block 334/335 field. In February 1997, the Company and one of its joint venture partners completed construction of the East Cameron "E" platform and commenced production from two wells. Following mechanical problems in one of these wells which caused it to be shut in, production was restored in the first week of January 1998. The 5 Company and its joint venture partners completed construction of a sixth platform during 1997, known as the "F" platform. Production from the well served by this platform, in which the Company holds a 42% interest, commenced in December 1997. DOMESTIC ONSHORE OPERATIONS The Company has onshore division staffs in Houston and Midland, Texas. Its onshore activities are concentrated in known oil and gas provinces, principally the Permian Basin area of southeastern New Mexico, West Texas and Northwest Texas, and in the onshore Gulf Coast areas of South Texas, East Texas and South Louisiana. See ";Significant Domestic Onshore Operating Areas During 1997." LEASE ACQUISITIONS Commencing in 1995 and continuing into 1997, the Company has increased its activities in the onshore Gulf Coast areas of East Texas and South Louisiana through its participation in several large proprietary 3-D seismic surveys, in connection with which the Company typically purchases an option to acquire an interest in the acreage covered by the 3-D seismic survey. As it has in recent years, in 1997 the Company also successfully participated in various onshore federal and state lease sales and acquired interests in prospective acreage from private individuals. As of December 31, 1997, the Company held interests in approximately 237,000 gross (113,000 net) acres onshore in the United States, an increase of approximately 12% from year end 1996. EXPLORATION AND DEVELOPMENT The Company's primary drilling objective 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 357 wells in the Permian Basin, West and Northwest Texas areas through December 31, 1997, including 58 wells in 1997. The Company's primary drilling activity in East Texas has been in the Cotton Valley formation reef play. In Southeast Louisiana, the Company participated in drilling 11 wells in 1997 to test various Hackberry formation and Yegua formation prospects, all of which were identified on proprietary 3-D seismic surveys that the Company and its industry partners have acquired since 1995. The Company also actively explores for oil and gas onshore in South Texas. In total, the Company participated in the drilling of 25 wells in the onshore Gulf Coast areas of South Texas, East Texas and South Louisiana, including 14 exploratory wells (principally in East Texas and South Louisiana) and 11 developmental wells (principally in the Lopeno Field in South Texas). See "; Significant Domestic Onshore Operating Areas During 1997; South Texas." Domestic onshore reserves as of December 31, 1997, accounted for approximately 41% of the Company's domestic proved reserves and approximately 21% of its total proved reserves. During 1997, approximately 16% of the Company's natural gas production and 27% of its oil and condensate production was from its domestic onshore properties, contributing approximately 20% of the Company's consolidated oil and gas revenues. 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 domestic onshore capital and exploration expenditures were approximately $60,000,000 (excluding approximately $1,700,000 of net property acquisitions) for 1997, or 28% higher than the Company's domestic onshore capital and exploration expenditures of approximately $47,000,000 (excluding approximately $3,800,000 of net property acquisitions) for 1996 and 82% higher than the Company's domestic onshore capital and exploration expenditures of approximately $33,000,000 (excluding approximately $7,800,000 of net property acquisitions) for 1995. The increase in the Company's domestic onshore capital and exploration expenditures for 1997, compared to 1996 and 1995, resulted primarily from increased drilling activity in South Texas, East Texas and South Louisiana and, to a lesser extent, by the increased costs to the Company (and the entire oil and gas industry generally) because of 6 price increases by the oil and gas services, construction and supply industries due to the shortage of skilled workers and the comparative scarcity of certain equipment, such as drilling rigs and critical materials, such as certain types of steel pipe. SIGNIFICANT DOMESTIC ONSHORE OPERATING AREAS DURING 1997 NEW MEXICO The Company believes that during the past five 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 79,000 gross acres. The Company's primary drilling objective is the Brushy Canyon (Delaware) formation. Fields in the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of the Permian Basin are generally characterized by production from relatively shallow depths (6,000 to 9,000 feet), multiple producing zones in most wells and relatively high initial rates of production (frequently equaling the top field allowables which typically range from 142 Bbls to 230 Bbls per day, depending on the depth of production from the field). 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. Since the Company began exploring in the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of the Permian Basin in October 1989, it has participated through December 31, 1997, in the drilling of, among others, 94 wells in the Sand Dunes field where the Company's working interest ranges from 4% to 100%, 27 wells in the East Loving field where the Company's working interest ranges from 33% to 98%, 60 wells in the Livingston Ridge field where the Company's working interest ranges from 25% to 100%, 61 wells in the Red Tank field where the Company's working interest ranges from 89% to 100%, 31 wells in the Cedar Canyon field where the Company's working interest ranges from 38% to 100% (including 15 during 1997), 15 wells in the Lost Tank field where the Company's working interest ranges from 50% to 100% (including 12 during 1997), and 3 wells in the Poker Lake Field where the Company's working interest ranges from 60% to 100%. The oil fields in this area are generally developed on a 40 acre spacing pattern. The Company anticipates drilling additional locations in certain of these and other fields in southeastern New Mexico during 1998 including, in particular, an aggressive drilling program in the Cedar Canyon and Lost Tank fields. SOUTH TEXAS The Company has increased its activity in South Texas in recent years, where it is currently active in two fields, both of which primarily produce natural gas. The most significant of these two fields is the Lopeno Field, which is located within 40 miles of the border with Mexico. The Company acquired its initial interest in the Lopeno Field in 1983. The Company currently has interests in over 7,800 gross acres containing 29 producing wells, with working interests generally averaging approximately 50%. The Lopeno Field produces from over 20 upper Wilcox sandstone reservoirs ranging in depth up to 12,500 feet. Based in part on a 3-D seismic survey acquired over the field in 1994, the Company and its joint venture partners commenced an active development drilling program in the fourth quarter of 1995. In 1997, the Company drilled seven successful wells in the Lopeno Field and currently plans to drill an additional nine wells in this field during 1998. INTERNATIONAL OPERATIONS The Company has conducted international exploration activities since the late 1970's in numerous oil and gas areas throughout the world. Currently, the Company maintains an office in Bangkok, Thailand from which it directs field operations in the Gulf of Thailand on its Block B8/32 Concession (the "Thailand Concession") through its wholly owned subsidiary Thaipo Limited ("Thaipo"). As a result of its acquisition in 1995 and March 1997 of portions of the original interest of Maersk Oil (Thailand) Ltd., a former joint venture partner that owned a 31.67% interest in the Thailand Concession, the Company has increased its ownership interest in the Thailand Concession so that it currently owns, directly or indirectly, a 46.34% working interest in the entire Thailand Concession. In addition, Thaipo has been elected by its joint 7 venture partners, Thai Romo Ltd., Palang Sophon Limited and B8/32 Partners Ltd, and designated by the government of Thailand, as the operator of the Thailand Concession. As of December 31, 1997, the Company's proved reserves located in the Kingdom of Thailand accounted for approximately 48% of the Company's total proved reserves. During 1997, approximately 19% of the Company's natural gas production and 14% of its oil and condensate production came from its operations on the Thailand Concession, contributing approximately 14% of the Company's consolidated oil and gas revenues. EXPLORATION AND DEVELOPMENT The Company's international capital and exploration expenditures were approximately $88,300,000 (excluding approximately $28,600,000 of net property acquisitions) for 1997, or 37% higher than the Company's international capital and exploration expenditures of approximately $64,400,000 for 1996 and 152% higher than the Company's international capital and exploration expenditures of approximately $35,000,000 (excluding approximately $4,200,000 of net property acquisitions) for 1995. The increase in the Company's international capital and exploration expenditures for 1997, compared to 1996 and 1995, resulted primarily from increased platform and facilities construction costs related to initial development of the Benchamas Field, increased drilling activity and, to a lesser extent, by the increased costs to the Company (and the entire oil and gas industry generally) because of price increases by the oil and gas services, construction and supply industries due to the shortage of skilled workers and the comparative scarcity of certain equipment, such as drilling rigs, and certain critical materials, such as certain types of steel pipe. Substantially all of the Company's international capital and exploration expenditures for 1997 were related to the Company's license in the Kingdom of Thailand. In addition, the Company continues to evaluate other international opportunities that are consistent with the Company's international exploration strategy. 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 Thai government. See "; Contractual Terms Governing the Thailand Concession and Related Production." Platforms are used to accommodate both development drilling and additional exploratory drilling. Over the last three years, the gross cost of the first four production platforms and related facilities in the Tantawan Field has averaged approximately $20,000,000. 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. See "; Significant International Operating Areas During 1997; Tantawan Field." SIGNIFICANT INTERNATIONAL OPERATING AREAS DURING 1997 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. The Tantawan production area has been named the Tantawan Field. Through March 13, 1998, 19 exploration and 29 development wells have been drilled in the Tantawan Field. Initial production from the Tantawan Field commenced on February 1, 1997, from wells located on two platforms. Currently, there are 34 wells producing from four platforms. The Company is currently planning to install a fifth platform in the Tantawan Field from which production is currently expected to commence in the second half of 1999. Additional drilling in order to maintain field delivery capacity is currently planned to commence in the third quarter of 1998 from existing platforms, following which wells will be drilled at the location of the proposed platform. 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 8 other production related equipment is installed. Following processing on board the FPSO, natural gas produced from the field is delivered to the Petroleum Authority of Thailand ("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. The FPSO and its processing equipment is leased from a third party under a bareboat charter by Tantawan Services, LLC, an affiliate of Thaipo. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." Thaipo and its joint venture partners pay a processing fee to Tantawan Services, LLC, to process the production from the Tantawan Field through the FPSO. BENCHAMAS FIELD AND THE MALIWAN PRODUCTION AREA In July 1997, the government of Thailand designated another portion of the Thailand Concession comprising approximately 102,000 acres of the Benchamas and Pakakrong production area as the Benchamas Field. This area currently includes at least two discrete geologic structures which were previously designated as the Benchamas and Pakakrong areas, respectively. In September 1997, the government of Thailand designated an additional 91,000 acres of the Thailand Concession as the Maliwan production area. Through March 13, 1998, 15 exploration wells have been drilled in the Benchamas Field and four exploration wells have been drilled in the Maliwan production area. Current development plans call for the staged development of these fields, with the Benchamas Field to be brought on production first. The Benchamas Field development plan currently contemplates the initial installation of 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 will be processed and separated. The natural gas will then be sold to PTT and delivered into export pipelines for transportation to shore, while the oil and condensate produced from the field will be stored on board a converted oil tanker known as a Floating Storage and Offloading system (an "FSO") for sale and ultimate transfer to shore by oil tanker. The FSO will be moored in the Benchamas Field. Its capacity will be approximately 1,400,000 Bbls of oil, or slightly more than the FPSO. The field's current development plan calls for initial production to commence in the third quarter of 1999. During 1998, Thaipo and its joint venture partners currently plan to continue delineation drilling in the Benchamas Field and to conduct additional exploratory drilling in the Maliwan production area. OTHER AREAS In addition to the above mentioned fields, Thaipo and its joint venture partners have identified other potentially promising areas on the Thailand Concession. Since acquiring their interest in the Thailand Concession, Thaipo and its joint venture partners have acquired 3-D seismic surveys covering approximately 673,650 acres of the Thailand Concession, including 221,650 acres during the fourth quarter of 1997 over what is known as the Jarmjuree area. Interpretation of the Jarmjuree 3-D seismic survey commenced in the first quarter of 1998 and is ongoing. In addition to the ongoing interpretation of this recently acquired 3-D seismic data, Thaipo has proposed to its joint venture partners that the joint venture conduct an exploratory drilling program during 1998 to initially evaluate the Chongko area which is located on trend to the south of the Maliwan production area and to also evaluate prospects developed from the interpretation of the Jarmjuree 3-D seismic survey. CONTRACTUAL TERMS GOVERNING THE THAILAND CONCESSION AND RELATED PRODUCTION The Thailand Concession was granted in August 1991. The original exploratory term of the concession agreement governing those portions of the Thailand Concession not designated as a production area expired on July 31, 1997. However, on application from Thaipo and its joint venture partners, the government of Thailand agreed in a supplemental concession agreement to extend the exploratory term for those portions of the Thailand Concession that have not yet been designated a production area (currently comprising approximately 474,000 acres) until July 31, 2000. In exchange, the Company and its joint venture partners committed to, among other things, an additional work program which includes the drilling of two wells and the acquisition of 148,000 acres of 3-D seismic data during the remainder of the exploratory term.The Company currently believes that this work commitment will be satisfied during the ordinary course of the 9 Company's operations on the Thailand Concession during 1998. 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." Currently, the Tantawan, Maliwan, and Benchamas and Pakakrong 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 income taxes and other similar governmental charges including a Special Remuneratory Benefit tax ("SRB"). On November 7, 1995, Thaipo and its joint venture partners announced the signing of a thirty-year gas sales agreement with PTT, initially governing gas production from the Tantawan Field. On November 12, 1997, Thaipo and its joint venture partners entered into an amendment to the gas sales agreement to include the reserves and anticipated gas production from the Benchamas Field (as so amended, the "Gas Sales Agreement"). The terms of the Gas Sales Agreement currently include a minimum daily contract quantity ("DCQ") of 85 MMcf per day, which the Company currently anticipates will continue until the Benchamas Field commences production at which time the DCQ will, subject to certain exceptions, be based on a percentage of the remaining proved reserves, but in any event, will not be less than 125 MMcf per day. The DCQ is the minimum daily volume that PTT has agreed to take, or pay for if not taken under the agreement. Likewise, 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. For production during the month of February 1998, the Company estimates that the gas sales price under the Gas Sales Agreement formula was approximately 84 Thai Baht per Mcf. This price is subject to automatic semi-annual adjustments based upon a formula which takes into account, among other things, changes in: Singapore fuel oil prices; the U.S. Department of Commerce 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. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Results of Operations; Operating Costs and Expenses; Foreign Currency Transaction Loss, and -- Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues." 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. In addition, the Company owns 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. In 1989, the Company entered into a limited partnership agreement as general partner of Pogo Gulf Coast, Ltd., a Texas limited partnership ("Pogo Gulf Coast"). As of December 31, 1997, Pogo Gulf Coast had interests in 5 federal offshore leases. The Company owns 40% of any interest in properties acquired by the limited partnership. Unless otherwise noted, the statistical data reported in this Annual Report reflect only the Company's share of Pogo Gulf Coast's holdings. 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 10 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 handle the Company's current and projected future production. The Company's Thailand Concession is traversed by two major (34 inches and 36 inches in diameter, respectively) natural gas pipelines that are owned and operated by PTT and which come within approximately 25 miles of the Tantawan Field (and are slightly closer to the Benchamas Field). Thaipo and its joint venture partners in the Tantawan Field signed a long term gas sales contract with PTT in November 1995 which has since been amended to include production from the Benchamas Field. 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 crude oil benchmark price. The buyer is responsible for sending a tanker to off load the oil and condensate it has purchased. It is currently anticipated that crude oil and condensate production from the Benchamas Field, when it commences production, will be initially stored aboard the FSO and sold in the same manner. See "-- International Operations; Contractual Terms Governing the Thailand Concession and Related Production." The marketing of domestic 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 domestic oil and gas production is located in areas where commercial production of economic discoveries can be rapidly effectuated. Most of the Company's domestic natural gas sales are currently made in the "spot market" for no more than one month at a time at then currently available prices. Prices on the spot market fluctuate with demand. Crude oil and condensate production is also generally sold one month at a time at the price that is then currently available. Other than any 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. Enron Corp. and its affiliates and PTT, who purchased $57,965,000 (20% of the Company's consolidated gross revenues) and $30,108,000 (11% of the Company's consolidated gross revenues) of the Company's oil and gas production during 1997, respectively, were the Company's only customers to which sales exceeded 10% of its 1997 revenues. The oil and gas sold to Enron Corp. and its affiliates was sold under a number of short term, generally month to month, contracts. 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 the past, when natural gas prices in the United States were lower than they are currently, the Company at times elected to curtail certain quantities of its production. Should natural gas prices fall in the future, the Company may again elect to curtail certain quantities of its natural gas production. Any significant decline in oil or gas prices could have a material adverse effect on the Company's operations and financial condition and could, under certain circumstances, result in a reduction in funds available under the Company's bank credit facility. Because it is impossible to predict future oil and gas price movements with any certainty, the Company from time to time enters into contracts on a portion of its production to hedge against the volatility in oil and gas prices. 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 11 effect of price declines, such transactions could effectively limit the Company's participation in price increases for the covered period, which increases could be significant. As of March 13, 1998, the Company was not a party to any natural gas futures contracts or crude oil swap agreements. When the Company does engage in such hedging activities, it may satisfy its obligations with its own production or by the purchase (or sale) of third party production. The Company may also 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. The availability of a ready market for the Company's natural gas production depends on a number of factors, including the demand for and supply of natural gas, the proximity of natural gas reserves to pipelines, the capacity of such pipelines and government regulations. 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; Operating Costs and Expenses; Foreign Currency Transaction Loss," and " -- 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. 12 ACREAGE The following table shows the Company's interest in developed and undeveloped oil and gas acreage as of December 31, 1997: DEVELOPED ACREAGE UNDEVELOPED ACREAGE (A) (B) -------------------- -------------------- GROSS NET GROSS NET --------- --------- --------- --------- DOMESTIC ONSHORE Louisiana...................... 2,475 598 36,074 10,895 New Mexico..................... 21,021 12,591 58,410 42,932 Texas.......................... 12,084 4,346 103,100 40,769 Other.......................... 3,200 333 238 55 --------- --------- --------- --------- Total Domestic Onshore.... 38,780 17,868 197,822 94,651 --------- --------- --------- --------- DOMESTIC OFFSHORE Louisiana (State).............. 7,942 3,255 1,508 753 Louisiana (Federal) (c)........ 186,422 61,378 152,879 56,061 Texas (Federal)................ 40,320 10,251 56,905 16,530 --------- --------- --------- --------- Total Domestic Offshore... 234,684 74,854 211,292 73,344 --------- --------- --------- --------- TOTAL DOMESTIC............ 273,464 92,722 409,114 167,995 --------- --------- --------- --------- INTERNATIONAL Kingdom of Thailand............ 260,407 120,682 473,733 219,530 --------- --------- --------- --------- TOTAL COMPANY............. 533,871 213,404 882,847 387,525 ========= ========= ========= ========= - ------------ (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 production area by the Thai government, which currently includes the Tantawan, Maliwan, Benchamas and Pakakrong production areas. (b) "Undeveloped acreage" includes acreage under lease or subject to lease or purchase options that the Company currently expects to exercise. Less than 1% of the Company's total domestic offshore net undeveloped acreage is under leases that have terms expiring in 1998 (unless otherwise extended) and another approximately 1% of total domestic offshore net undeveloped acreage will expire in 1999 (unless otherwise extended). Approximately 7% of the Company's total domestic onshore net undeveloped acreage is under leases that have terms expiring in 1998 (unless otherwise extended) and another approximately 15% of total domestic onshore net undeveloped acreage will expire in 1999 (unless otherwise extended). The Company's total international net undeveloped acreage must be relinquished to the Thai government on July 31, 2000, unless designated as a production area or unless the exploration term is extended. See "-- International Operations; Contractual Terms Governing the Thailand Concession and Related Production." (c) The Company also owns overriding royalty interests in one federal lease offshore Louisiana totaling 5,000 gross acres (1,250 net acres). PRODUCTIVE WELLS AND DRILLING ACTIVITY The following table shows the Company's interest in productive oil and natural gas wells as of December 31, 1997. 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. 13 NATURAL OIL WELLS (A) GAS WELLS (A) ----------------- ----------------- GROSS NET GROSS NET ----- --------- ----- --------- Offshore United States............... 129 33.3 113 33.8 Onshore United States................ 339 214.4 91 33.1 Kingdom of Thailand.................. -- -- 34 15.8 ----- --------- ----- --------- TOTAL........................... 468 247.7 238 82.7 ===== ========= ===== ========= - ------------ (a) One or more completions in the same bore hole are counted as one well. The data in the above table includes five gross (.6 net) oil wells and 45 gross (20.4 net) natural gas wells with multiple completions. 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 commercial 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.
1997 1996 1995 --------------------- -------------------- -------------------- SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY ---------- ----- ---------- ---- ---------- ---- GROSS WELLS: Offshore United States Exploratory..................... 4.0 1.0 4.0 2.0 7.0 4.0 Development..................... 12.0 3.0 17.0 3.0 3.0 1.0 Onshore United States Exploratory..................... 18.0 12.0 12.0 4.0 8.0 1.0 Development..................... 50.0 3.0 39.0 1.0 47.0 1.0 Offshore Kingdom of Thailand Exploratory..................... 18.0 1.0 7.0 -- 3.0 -- Development..................... 12.0 -- 16.0 -- 7.0 -- ---------- ----- ---------- ---- ---------- ---- TOTAL...................... 114.0 20.0 95.0 10.0 75.0 7.0 ========== ===== ========== ==== ========== ==== 1997 1996 1995 --------------------- -------------------- -------------------- SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY ---------- ----- ---------- ---- ---------- ---- NET WELLS: Offshore United States Exploratory..................... 1.21 .25 1.7 1.5 3.0 1.6 Development..................... 4.15 1.05 4.9 1.5 1.0 0.4 Onshore United States Exploratory..................... 11.27 7.40 6.5 0.9 4.6 1.0 Development..................... 30.18 1.41 24.4 0.7 31.3 0.1 Offshore Kingdom of Thailand Exploratory..................... 8.34 .46 2.4 -- 1.1 -- Development..................... 5.11 -- 7.4 -- 3.2 -- ---------- ----- ---------- ---- ---------- ---- TOTAL...................... 60.26 10.57 47.3 4.6 44.2 3.1 ========== ===== ========== ==== ========== ====
14 As of December 31, 1997, the Company was participating in the drilling of 3 gross (1.1 net) offshore domestic wells, 6 gross (4.2 net) onshore wells and 1 gross (0.5 net) wells offshore the Kingdom of Thailand. PRODUCTION AND SALES The following table summarizes the Company's average daily production, net of all royalties, overriding royalties and other outstanding interests, for the periods indicated. Natural gas production refers only to marketable production of natural gas on an "as sold" basis. 1997 1996 1995 --------- --------- --------- Located in the United States Natural Gas (Mcf per day).. 147,200 107,700 121,000 ========= ========= ========= Liquid Hydrocarbons (Bbls per day) Crude Oil and Condensate............ 13,712 11,968 11,786 Natural Gas Liquids (a)................... 2,923 2,173 1,998 --------- --------- --------- Total Domestic Liquid Hydrocarbons.... 16,635 14,141 13,784 ========= ========= ========= Located in the Kingdom of Thailand Natural Gas (Mcf per day)....................... 37,700 -- -- ========= ========= ========= Liquid Hydrocarbons (Bbls per day) Crude Oil and Condensate............ 2,421 -- -- ========= ========= ========= - ------------ (a) Natural Gas Liquids includes sales attributable to both the Company's leasehold and plant ownership interests. The following table shows the average sales prices received by the Company for its production and the average production (lifting) costs per unit of production during the periods indicated. See "-- Miscellaneous; Competition and Market Conditions and Sales." 1997 1996 1995 --------- --------- --------- SALES PRICES: Located in the United States Natural Gas (per Mcf)...... $ 2.50 $ 2.40 $ 1.63 Crude Oil and Condensate (per Bbl)............... $ 19.49 $ 22.12 $ 17.80 Natural Gas Liquids (per Bbl).................... $ 12.89 $ 14.92 $ 11.10 Located in the Kingdom of Thailand Natural Gas (per Mcf)...... $ 1.93 -- -- Crude Oil and Condensate (per Bbl)............... $ 18.60 -- -- PRODUCTION (LIFTING) COSTS (A): Located in the United States Natural Gas, Crude Oil, Condensate and Natural Gas Liquids (per Mcf equivalent).... $ .49 $ .53 $ .47 Located in the Kingdom of Thailand Natural Gas, Crude Oil and Condensate (per Mcf equivalent)(b).......... $ 1.12 -- -- - ------------ (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. (b) The major contributing factor to lifting costs are lease operating expenses. A substantial portion of the Company's lease operating expenses in the Kingdom of Thailand relate to lease payments made by a subsidiary of the Company in connection with its bareboat charter of the FPSO, which amounted to $10,200,000 during 1997. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources; Capital Requirements; Other Material Long-Term Commitments." 15 RESERVES The following table sets forth information as to the Company's net proved and proved developed reserves as of December 31, 1997, 1996, and 1995, 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 in accordance with criteria prescribed by the Commission. AS OF DECEMBER 31, ---------------------------------- 1997 1996 1995 ---------- ---------- ---------- TOTAL PROVED RESERVES: Oil, condensate, and natural gas liquids (MBbls) Located in the United States.................. 29,382 28,270 26,185 Located in the Kingdom of Thailand................ 28,783 21,332 18,997 ---------- ---------- ---------- Total Company......... 58,165 49,602 45,182 ========== ========== ========== Natural Gas (MMcf) Located in the United States.................. 216,720 215,946 196,454 Located in the Kingdom of Thailand................ 184,768 144,998 131,607 ---------- ---------- ---------- Total Company......... 401,488 360,944 328,061 ========== ========== ========== Present value of estimated future net revenues, before income taxes (in thousands) (a) Located in the United States.................. $ 406,161 $ 773,127 $ 400,845 Located in the Kingdom of Thailand................ 56,620 181,418 131,630 ---------- ---------- ---------- Total Company......... $ 462,781 $ 954,545 $ 532,475 ========== ========== ========== TOTAL DEVELOPED RESERVES: Oil, condensate, and natural gas liquids (MBbls) Located in the United States.................. 26,168 25,898 22,488 Located in the Kingdom of Thailand................ 6,982 5,192 -- ---------- ---------- ---------- Total Company......... 33,150 31,090 22,488 ========== ========== ========== Natural Gas (MMcf) Located in the United States.................. 179,972 192,034 164,679 Located in the Kingdom of Thailand................ 59,760 45,998 -- ---------- ---------- ---------- Total Company......... 239,732 238,032 164,679 ========== ========== ========== Present value of estimated future net revenues, before income taxes (in thousands) (a) Located in the United States.................. $ 377,530 $ 710,871 $ 359,984 Located in the Kingdom of Thailand................ 36,692 69,062 -- ---------- ---------- ---------- Total Company......... $ 414,222 $ 779,933 $ 359,984 ========== ========== ========== - ------------ (a) The Company believes, for the reasons set forth in succeeding paragraphs, that the present value of estimated future net revenues set forth in this 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. Natural gas liquids comprise approximately 7% of the Company's total proved liquids reserves and approximately 11% of the Company's proved developed liquids reserves. All hydrocarbon liquid reserves 16 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. 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. Reservoirs are considered proved if economic producibility is supported by actual production or formation tests. In certain instances, proved reserves are assigned on the basis of a combination of core analysis and electrical and other type logs which indicate the reservoirs are analogous to reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. The area of a reservoir considered proved includes (i) that portion delineated by drilling and defined by fluid contacts, if any, and (ii) the adjoining portions not yet drilled that can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Proved reserves are estimates of hydrocarbons to be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional data becomes available. Proved natural gas reserves are comprised of non-associated, associated and dissolved gas. An appropriate reduction in gas reserves has been made for the expected removal of liquids, for lease and plant fuel and the exclusion of non-hydrocarbon gases if they occur in significant quantities and are removed prior to sale. Reserves that can be produced economically through the application of established improved recovery techniques are included in the proved classification when these qualifications are met: (i) successful testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based, and (ii) it is reasonably certain the project will proceed. Improved recovery includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir, including, (i) pressure maintenance, (ii) cycling, and (iii) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids. Estimates of proved reserves do not include crude oil, condensate, natural gas, or natural gas liquids being held in underground storage. Depending on the status of development, these proved reserves are further subdivided into: (i) "developed reserves" which are those proved reserves reasonably expected to be recovered through existing wells with existing equipment and operating methods, including (a) "developed producing reserves" which are those proved developed reserves reasonably expected to be produced from existing completion intervals now open for production in existing wells, and (b) "developed non-producing reserves" which are those proved developed reserves which exist behind casing of existing wells which are reasonably expected to be produced through these wells in the predictable future where the cost of making such hydrocarbons available for production should be relatively small compared to the cost of new wells; and (ii) "undeveloped reserves" which are those proved reserves reasonably expected to be recovered from new wells on undrilled acreage, from existing wells where a relatively large expenditure is required and from acreage for which an application of fluid injection or other improved recovery technique is contemplated where the technique has been proved effective by actual tests in the area in the same reservoir. Reserves from undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are included only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. In computing future revenues from gas reserves attributable to the Company's domestic interests, prices in effect at December 31, 1997 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 which 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 17 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, 1997 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, 1997, 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 Tapis benchmark crude on December 31, 1997, 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, unless otherwise noted, any provisions for U.S. or Thai corporate income or other taxes. In accordance with Commission guidelines, the prices used by Ryder Scott to calculate the present value of estimated future net revenues are determined on a well by 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, ------------------------------- 1997 1996 1995 --------- --------- --------- INITIAL WEIGHTED AVERAGE PRICE (in U.S. dollars): Oil, condensate, and natural gas liquids (per Bbl) Located in the United States..................... $ 16.60 $ 24.06 $ 19.10 Located in the Kingdom of Thailand................... $ 16.00 $ 24.56 $ 18.71 Natural Gas (per Mcf) Located in the United States..................... $ 2.30 $ 3.93 $ 2.08 Located in the Kingdom of Thailand................... $ 1.83 $ 2.09 $ 2.02 The estimates of future net revenue from the Company's domestic and Thailand properties are based on existing law where the properties are located and are calculated in accordance with Commission guidelines. 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 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 1997. 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 18 allowables set by regulatory bodies. Properties which are not currently producing may start producing earlier or later than anticipated in the estimates of future production rates. 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 present value thereof as set forth herein, and the operating costs and other costs relating to such production may also increase or decrease from existing levels; however, such possible changes in prices and costs were, in accordance with rules adopted by the Commission, omitted from consideration in arriving at such estimates. 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 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 1997, 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 certain provisions of the federal income tax laws applicable to the petroleum industry. 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 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. 19 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. A "responsible party" includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. 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 regulation. If the party fails to report a spill or cooperate fully in the cleanup, liability limits likewise do not apply. 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. For tank vessels, including mobile offshore drilling rigs, the OPA imposes on owners, operators and charterers of the vessels, an obligation to maintain evidence of financial responsibility of up to $10,000,000 depending on gross tonnage. With respect to offshore facilities, proof of greater levels of financial responsibility may be applicable. For offshore facilities that have a worst case oil spill potential of more than 1,000 barrels (which includes many of the Company's offshore producing facilities), certain amendments to the OPA that were enacted in 1996 provide that the amount of financial responsibility that must be demonstrated for most facilities ranges from $10,000,000 to $35,000,000, depending upon location, with higher amounts, up to $150,000,000 in certain limited circumstances. 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 effect 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 federal, state, 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 and local initiatives to further 20 regulate the disposal of oil and gas wastes are also pending in certain states, 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 environmental control facilities would have been incurred absent environmental regulations as prudent, safe oilfield practice. During 1997, the Company incurred capital expenditures of approximately $610,000 for environmental control facilities, primarily relating to the installation of certain environmental control facilities on two platforms installed in the Gulf of Thailand. The Company currently has budgeted approximately $1,630,000 for expenditures involving environmental control facilities during 1998, including, among other things, two salt water disposal facilities in New Mexico and environmental control equipment for three platforms in the Gulf of Thailand and two platforms in the Gulf of Mexico. 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. In a letter dated May 3, 1993, the MMS announced a reinterpretation of its right to collect royalty payments from producers on certain settlements in which such producers and pipeline companies were involved a number of years ago. The MMS reinterpretation has been challenged in court by various producers and trade groups representing them. On August 27, 1996, in INDEPENDENT PETROLEUM ASSOCIATION OF AMERICA, ET AL. V. BABBIT ET AL., Nos. 95-5210 etc., the United States Court of Appeals for the District of Columbia Circuit held that the May 3, 1993, reinterpretation was invalid and unenforceable. Unless and until this or other similar cases are resolved in favor of the MMS' reinterpretation of its regulations, it is unlikely that the Company or other producers will be legally required to pay royalties on such settlement agreements. The Company was involved in several settlement agreements with pipelines that could be subject to the MMS' new reinterpretation. The MMS has reviewed the Company's and other producers' settlement agreements, to determine whether it believes any additional royalty payments may be due and has asserted that additional royalties may be due in connection with two of the Company's settlement agreements. Based upon existing case law, the Company has asserted through the administrative appeals process, and continues to believe, that it does not owe any additional royalties beyond what it has previously paid. However, in the event that the MMS is able to successfully assert that additional royalty is due from the Company in connection with settlement agreements to which the Company is a party, the Company does not currently believe that such additional assessment will have a material adverse impact on the financial position or results of operations of the Company. 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 named 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. 21 The FERC has recently embarked on regulatory initiatives relating to its jurisdiction over rates for natural gas gathering services provided by interstate pipelines and to the availability of market-based and other alternative rate mechanisms to such pipelines for transmission and storage services. Among the FERC initiatives is the creation of a pilot program to determine the effect on rates of lifting price caps on the rates for interruptible transportation, short-term firm transportation, and for transportation using capacity released by the firm transportation customers of interstate pipelines. 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. This negotiated/recourse rate policy has been challenged in the United States Court of Appeals for the District of Columbia, and the appeal remains pending. 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. These orders have been generally upheld on appeal to the courts. 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. EMPLOYEES As of March 1, 1998, the Company had 137 full-time employees and its subsidiary Thaipo employed an additional 23 individuals. 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 other 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. 22 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 March 13, 1998, 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 52 1991 and Chief Executive Officer Stuart P. Burbach.................... Executive Vice President -- 45 1998 Exploration Kenneth R. Good...................... Executive Vice President 60 1998 Jerry A. Cooper...................... Senior Vice President and 49 1998 Western Division Manager R. Phillip Laney..................... Senior Vice President and Manager 57 1998 of Worldwide New Ventures John O. McCoy, Jr.................... Senior Vice President and 46 1998 Chief Administrative Officer J. D. McGregor....................... Senior Vice President -- Sales 53 1998 Bruce E. Archinal.................... Vice President and Onshore 45 1997 Division Manager David R. Beathard.................... Vice President -- Engineering 39 1997 Stephen R. Brunner................... Vice President -- Operations 39 1997 Frank Davis III...................... Vice President -- Land 51 1997 John W. Elsenhans.................... Vice President and Chief 45 1998 Financial Officer Thomas E. Hart....................... Vice President and Controller 55 1988 Ronald B. Manning.................... Vice President and 44 1995 General Counsel Gerald A. Morton..................... Vice President--Law and 39 1997 Corporate Secretary
23 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. Good, who joined the Company in 1977, served as Corporate Senior Vice President of the Company since 1996 and prior thereto served as the Company's Senior Vice President -- Land and Budgets since 1991; Mr. Cooper, who joined the Company in 1979, served as Vice President and Western Division Manager for the Company since 1991; 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 Vice President -- Sales since 1988; Mr. Archinal, who joined the Company in 1982, served as the Company's Onshore Division Manager since 1994 and prior thereto served as Offshore Division Exploration Manager for the Company since 1991; Mr. Beathard, who joined the Company in 1982, served as Manager of Petroleum Engineering for the Company since 1991; Mr. Brunner served as Resident Manager of the Company's Thailand operations since 1995, prior to which he was an Operations Manager for the Company since joining in 1994 and prior thereto held various positions in the energy industry, the most recent of which was as Operations Manager for Zilkha Energy since 1991; Mr. Davis who joined the Company in 1978, served as Land Manager for the Company since 1991; Mr. Elsenhans, who joined the Company in 1991, served as Vice President -- Finance and Treasurer for the Company since 1995, and prior thereto was Director, Corporate Finance for the Company since 1991; Mr. Hart was Controller for the Company since joining the Company in 1977; Mr. Manning, who joined the Company in 1987, was Corporate Secretary and an Associate General Counsel for the Company since 1990; and Mr. Morton was an Associate General Counsel for the Company since 1993 and prior thereto was an attorney with the law firm of Weil, Gotshal & Manges since 1988. 24 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER 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 Stock Exchange. LOW HIGH ---- ----- 1996 1st Quarter............................. 24 3/8 34 3/4 2nd Quarter............................. 31 3/8 38 1/4 3rd Quarter............................. 32 1/4 38 3/4 4th Quarter............................. 35 3/4 48 3/8 1997 1st Quarter............................. 33 3/8 49 7/8 2nd Quarter............................. 33 1/2 41 3/8 3rd Quarter............................. 37 7/8 45 3/8 4th Quarter............................. 27 44 9/16 As of March 13, 1998, there were 2,891 holders of record of the Company's Common Stock. In each of 1996 and 1997, 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. Pursuant to the Company's revolving credit agreement with its banks under which the Company has borrowed funds, and the Indenture relating to the Company's 8 3/4% Senior Subordinated Notes due 2007 (the "2007 Notes") Company may not, subject to certain exceptions, pay any dividends on its capital stock or make any other distributions on shares of its capital stock (other than dividends or distributions payable solely in shares of such capital stock) or apply any funds, property or assets to the purchase, redemption, sinking fund or other retirement of its capital stock, if the aggregate amount of all such dividends, purchases, and redemptions would exceed an amount determined based on the consolidated income of the Company and its consolidated subsidiaries plus the proceeds of the issuance of capital stock from and after a specified date set forth in each respective agreement or, in the case of the revolving credit agreement, if the net worth of the Company is negative. As of December 31, 1997, $28,657,000 was available for dividends under this limitation in the Indenture relating to the 2007 Notes, the agreement currently having the most restrictive covenant. 25 ITEM 6. SELECTED FINANCIAL DATA.
FOR THE YEAR ENDED DECEMBER 31, ----------------------------------------------------- 1997 1996 1995 1994 1993 --------- --------- --------- --------- --------- FINANCIAL DATA (Expressed in thousands, except per share data) Revenues: Crude oil and condensate........... $ 112,603 $ 96,908 $ 76,557 $ 65,141 $ 64,042 Natural gas........................ 158,500 94,589 72,032 99,093 66,173 Natural gas liquids................ 13,748 11,867 8,097 9,189 7,288 Other, net......................... 349 778 773 133 (950) --------- --------- --------- --------- --------- Oil and gas revenues............... 285,200 204,142 157,459 173,556 136,553 Interest on tax refund............. -- -- -- -- 2,322 Gains (losses) on sales............ 1,100 (165) 100 52 679 --------- --------- --------- --------- --------- Total............................ $ 286,300 $ 203,977 $ 157,559 $ 173,608 $ 139,554 ========= ========= ========= ========= ========= Income before extraordinary item..... $ 37,116 $ 33,581 $ 9,230 $ 27,374 $ 25,061 Extraordinary losses................. -- (821) -- (307) -- --------- --------- --------- --------- --------- Net income........................... $ 37,116 $ 32,760 $ 9,230 $ 27,067 $ 25,061 ========= ========= ========= ========= ========= Per share data: Income before extraordinary item -- Basic (restated for 1996 and prior years).................... $ 1.11 $ 1.01 $ 0.28 $ 0.84 $ 0.78 Diluted (restated for 1996 and prior years).................... $ 1.06 $ 0.97 $ 0.28 $ 0.82 $ 0.76 Cash dividends..................... $ 0.12 $ 0.12 $ 0.12 $ 0.06 $ -- Price range of common stock: High............................. $ 49.88 $ 48.38 $ 29.00 $ 24.25 $ 21.00 Low.............................. $ 27.00 $ 24.38 $ 16.00 $ 15.63 $ 9.75 Weighted average number of common shares outstanding.................. 33,421 33,203 32,893 32,663 32,160 Long-term debt at year end........... $ 348,179 $ 246,230 $ 163,249 $ 149,249 $ 130,539 Shareholders' equity at year end..... $ 146,106 $ 107,282 $ 71,708 $ 64,037 $ 33,803 Total assets at year end............. $ 676,617 $ 479,242 $ 338,177 $ 298,826 $ 239,774 PRODUCTION (SALES) DATA Net daily average and weighted average price: Natural gas (Mcf per day).......... 181,700 107,700 121,000 144,800 91,700 Price (per Mcf).................. $ 2.39 $ 2.40 $ 1.63 $ 1.88 $ 1.98 Crude oil-condensate (Bbl. per day).............................. 15,927 11,968 11,786 11,100 9,851 Price (per Bbl.)................. $ 19.37 $ 22.12 $ 17.80 $ 16.08 $ 17.81 Natural gas liquids (Bbl. per day).............................. 2,923 2,173 1,998 2,222 1,678 Price (per Bbl.)................. $ 12.89 $ 14.92 $ 11.10 $ 11.33 $ 11.90 CAPITAL EXPENDITURES (Expressed in thousands) Oil and gas: Domestic Offshore -- Exploration...................... $ 18,700 $ 16,800 $ 13,300 $ 2,800 $ 4,600 Development...................... 59,800 73,900 17,800 44,100 33,700 Purchase of reserves............. 900 -- -- 32,600 -- Domestic Onshore -- Exploration...................... 18,100 10,400 8,800 6,800 5,200 Development...................... 38,400 27,800 22,400 23,700 24,300 Purchase of reserves............. 1,700 -- 7,900 -- -- International -- Exploration...................... 21,700 8,500 5,500 5,100 4,600 Development...................... 62,500 54,700 24,400 -- -- Purchase of reserves............. 29,300 -- 4,200 -- -- --------- --------- --------- --------- --------- Total oil and gas.................. 251,100 192,100 104,300 115,100 72,400 Other................................ 4,000 1,600 500 1,200 200 --------- --------- --------- --------- --------- Total.............................. $ 255,100 $ 193,700 $ 104,800 $ 116,300 $ 72,600 ========= ========= ========= ========= =========
26 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. RESULTS OF OPERATIONS INCOME AND REVENUE DATA NET INCOME The Company reported net income for 1997 of $37,116,000 or $1.11 per share ($40,198,000 or $1.06 per share on a diluted basis) compared to net income for 1996 of $32,760,000 or $0.99 per share ($35,843,000 or $0.95 per share on a diluted basis) and net income for 1995 of $9,230,000 or $0.28 per share (on both a basic and a diluted basis). The Company recorded an extraordinary loss of $821,000 during the second quarter of 1996 related to the early retirement of the Company's 8% Convertible Subordinated Debentures, due 2005 (the "8% Debentures") with the proceeds from the Company's issuance on June 18, 1996, of its 5 1/2% Convertible Subordinated Notes, due 2006 (the "2006 Notes"). Earnings per common share are based on the weighted average number of common and common equivalent shares outstanding for 1997 of 33,421,000 (38,064,000 on a diluted basis), compared to 33,203,000 (37,920,000 on a diluted basis) for 1996 and 32,893,000 (33,490,000 on a diluted basis) for 1995. The yearly increases in the weighted average number of common shares outstanding resulted primarily from the issuance of shares of Common Stock upon the exercise of stock options pursuant to the Company's stock option plans. Earnings per common share computations on a diluted basis primarily reflect additional common shares issuable upon the assumed conversion of the Company's 5 1/2% Convertible Subordinated Notes, due 2004 (the "2004 Notes") in 1996 and 1997 (the only convertible securities of the Company that were dilutive during the applicable periods) and the elimination of related interest requirements, as adjusted for applicable federal income taxes. In addition, the number of common shares outstanding in the diluted computation is also adjusted, in accordance with the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 128 ("SFAS 128"), to include dilutive shares that are assumed to have been issued by the Company in connection with options exercised during the year, less treasury shares that are assumed to have been purchased by the Company from the option proceeds. SFAS 128 was adopted by the Company in 1997, resulting in a restatement of the earnings per share calculations for 1996, 1995, and all preceding years. REVENUES TOTAL REVENUES The Company's total revenues for 1997 were $286,300,000, an increase of approximately 40% from total revenues of $203,977,000 for 1996, and an increase of approximately 82% from total revenues of $157,559,000 for 1995. The increase in the Company's total revenues for 1997, compared to 1996, resulted primarily from the substantial increase in the Company's natural gas and liquid hydrocarbon (including crude oil, condensate and natural gas liquid ("NGL")) production, which was only partially offset by a decline in the average price that the Company received for its liquid hydrocarbon production and, to a much lesser extent, the average price that the Company received for its natural gas production. The increase in the Company's total revenues for 1997, compared to 1995, resulted primarily from the substantial increases in the Company's natural gas production, the average price that the Company received for its natural gas production, the Company's liquid hydrocarbon production and, to a lesser extent, the average price that the Company received for its liquid hydrocarbon production. 27 OIL AND GAS REVENUES The Company's oil and gas revenues for 1997 were $285,200,000, an increase of approximately 40% from oil and gas revenues of $204,142,000 for 1996, and an increase of approximately 81% from oil and gas revenues of $157,459,000 for 1995. The following table reflects an analysis of variances in the Company's oil and gas revenues between 1997 and the previous two years: 1997 COMPARED TO --------------------- 1996 1995 --------- ---------- (IN THOUSANDS) Increase (decrease) in oil and gas revenues resulting from variances in: Natural Gas Price........................... $ (394) $ 33,466 Production...................... 64,305 53,002 --------- ---------- 63,911 86,468 --------- ---------- Crude oil and condensate Price........................... (12,064) 6,767 Production...................... 27,759 29,279 --------- ---------- 15,695 36,046 --------- ---------- NGL and other, net................... 1,452 5,227 --------- ---------- Increase (decrease) in oil and gas revenues........................... $ 81,058 $ 127,741 ========= ========== NATURAL GAS PRICES. Prices per Mcf that the Company received for its natural gas production during 1997 averaged $2.39 per Mcf. The average price that the Company received for its natural gas production in 1997 was approximately equal to the average price that the Company had received during 1996 of $2.40 per Mcf, but was a substantial increase (of approximately 47%) from the average price of $1.63 that it received during 1995. DOMESTIC PRICES. Prices that the Company received for its domestic natural gas production during 1997 averaged $2.50 per Mcf, an increase of approximately 4% from an average price of $2.40 per Mcf that the Company received for its domestic natural gas production during 1996, and an increase of approximately 53% from an average price of $1.63 that the Company received for its natural gas production during 1995. THAILAND PRICES. The Company's Tantawan Field located in the Kingdom of Thailand commenced production of natural gas and liquid hydrocarbons in February 1997. During 1997, the price that the Company received under the Gas Sales Agreement averaged approximately 60 Thai Baht per Mcf. The price that the Company receives under the Gas Sales Agreement would normally adjust 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. See "Business -- International Operations; Contractual Terms Governing the Thailand Concession and Related Production." Due to the volatility of the Thai Baht and the current economic difficulties in the Kingdom of Thailand and throughout Southeast Asia, the price that the Company receives under the Gas Sales Agreement has been adjusted on almost a monthly basis since July 1997. As a result of these adjustments, during December 1997 the price that the Company received under the Gas Sales Agreement for its production from the Thailand Concession averaged approximately 68 Thai Baht per Mcf. However, the increases that the Company has received in the Thai Baht price for its natural gas production from the Thailand Concession have not been sufficient to completely ameliorate, in U.S. dollar terms, the decline of the Thai Baht against the U.S. dollar. The Company cannot predict when, if ever, the adjustments provided for in the Gas Sales Agreement will completely recompense the Company for the decline of the Thai Baht against the U.S. dollar. However, the Company anticipates that should the Thai economy stabilize and recover, the volatility of the value of the Thai Baht against the U.S. dollar will decline and the adjustments to the gas sales price under the Gas Sales 28 Agreement resulting from changes to the indices and other factors will gradually restore, at least in part, the gas sales price (in U. S. dollar terms) to the relative value it had prior to the devaluation of the Thai Baht which commenced in July 1997. See "Operating Costs and Expenses; Foreign Currency Transaction Loss", "-- Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues" and "Business -- International Operations; Contractual Terms Governing the Thailand Concession." NATURAL GAS PRODUCTION. The Company's natural gas production for 1997 averaged 181.7 MMcf per day, an increase of approximately 69% from average production of 107.7 MMcf per day during 1996, and an increase of approximately 50% from average production of 121 MMcf per day during 1995. DOMESTIC PRODUCTION. The Company's domestic natural gas production for 1997 averaged 147.2 MMcf per day, an increase of approximately 37% from average production of 107.7 MMcf per day during 1996, and an increase of approximately 22% from average production of 121 MMcf per day during 1995. The increase in the Company's average domestic natural gas production for 1997, compared to 1996 and 1995, was related in large measure to production from the Company's East Cameron Block 334 "E" platform, which commenced production in April 1997, and, to a lesser extent, the results of successful drilling in the Company's Lopeno Field in South Texas and its Eugene Island Block 261 field, that was only partially offset by the anticipated natural decline in deliverability from certain of the Company's properties. As of March 13, 1998, the Company was not a party to any future natural gas sales contracts. THAILAND PRODUCTION. The Company commenced production from its Tantawan Field early in February 1997. Following a field startup phase which ended on March 15, 1997, production from the Tantawan Field stabilized. During 1997, the Company's share of natural gas production from the Tantawan Field averaged approximately 37.7 MMcf per day. CRUDE OIL AND CONDENSATE PRICES. Prices received by the Company for its crude oil and condensate production averaged $19.37 per Bbl during 1997, a decrease of approximately 12% compared to an average of $22.12 per Bbl during 1996, and an increase of approximately 9% compared to an average price of $17.80 per Bbl that the Company received during 1995. DOMESTIC PRICES. Prices that the Company received for its domestic crude oil and condensate production during 1997 averaged $19.49 per Bbl, a decrease of approximately 12% from an average price of $22.12 per Bbl that the Company received for its domestic crude oil and condensate production during 1996, and an increase of approximately 9% from an average price of $17.80 per Bbl that the Company received for its crude oil and condensate production during 1995. 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. The average price that the Company recorded for its crude oil and condensate production stored on the FPSO during 1997 was $18.60 per Bbl. Prices that the Company receives for such production are based on world benchmark prices, which are denominated in U.S. dollars, and are currently expected on future crude oil sales to be paid in U.S. dollars. CRUDE OIL AND CONDENSATE PRODUCTION. The Company's crude oil and condensate production for 1997 averaged 15,927 Bbls per day, an increase of approximately 33% from 11,968 Bbls per day for 1996, and an increase of approximately 35% from 11,786 Bbls per day for 1995. DOMESTIC PRODUCTION. The Company's domestic crude oil and condensate production for 1997 averaged 13,711 Bbls per day, an increase of approximately 15% from 11,968 Bbls per day for 1996, and an increase of approximately 16% from 11,786 Bbls per day for 1995. The increase in the Company's crude oil and condensate production for 1997, compared to 1996 and 1995, resulted primarily from increased condensate production from wells located in the Gulf of Mexico and, to a lesser extent, increased crude oil production from certain of the Company's onshore properties, which was only partially offset by the natural decline in deliverability from certain of the Company's more mature properties. As of March 13, 1998, the Company was not a party to any crude oil swap agreements. 29 THAILAND PRODUCTION. The Company commenced production from its Tantawan Field early in February 1997. Following a field startup phase which ended on March 15, 1997, production from the Tantawan Field stabilized. During 1997, the Company's share of crude oil and condensate production from the Tantawan Field averaged approximately 2,421 Bbls per day. NGL PRODUCTION AND "OTHER" NET REVENUE ITEMS. 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. In addition, the Company's oil and gas revenues for 1997, 1996 and 1995 also reflect adjustments for various miscellaneous items. The Company's NGL and other, net revenues for 1997 increased $1,452,000 from those reported in 1996, and $5,227,000 from those reported in 1995. The increase in NGL and other, net revenues in 1997, compared with 1996, primarily related to an increase in the Company's NGL production that was partially offset by a decrease in the average price that the Company received for such NGL production. The increase in NGL and other, net revenues in 1997, compared with 1995, primarily related to an increase in the Company's NGL production and, to a lesser extent, an increase in the price that the Company received for its NGL production. TOTAL LIQUID HYDROCARBON PRODUCTION. The Company's average liquid hydrocarbon (including crude oil, condensate and NGL) production during 1997 was 18,851 Bbls per day, an increase of approximately 33% from an average total liquids production of 14,141 Bbls per day for 1996, and an increase of approximately 37% from an average total liquids production of 13,784 Bbls per day for 1995. OPERATING COSTS AND EXPENSES LEASE OPERATING EXPENSES Lease operating expenses for 1997 were $63,501,000, an increase of approximately 69% from lease operating expenses of $37,628,000 for 1996, and an increase of approximately 81% from lease operating expenses of $35,071,000 for 1995. DOMESTIC LEASE OPERATING EXPENSES. The Company's domestic lease operating expenses for 1997 were $43,934,000, an increase of approximately 17% from domestic lease operating expenses of $37,628,000 for 1996, and an increase of approximately 25% from domestic lease operating expenses of $35,071,000 for 1995. The increase in domestic lease operating expenses for 1997, compared to 1996 and 1995, resulted primarily from increased costs to the Company (and the entire offshore oil industry) because of an increasing shortage of qualified offshore service contractors, which has permitted such contractors to increase the costs of their services significantly in the last year, increased expenses related to the leasing of certain equipment in the Gulf of Mexico, a year to year increase in the level of the Company's operating activities, including increased operating costs related to additional properties brought on production and an increased ownership interest in certain properties as a result of the acquisition of such interests. THAILAND LEASE OPERATING EXPENSES. The Company's lease operating expenses in Thailand for 1997 were $19,567,000. Prior to the commencement of production in the Tantawan Field on February 1, 1997, there were no lease operating expenses incurred by the Company in Thailand as defined by generally accepted accounting principles. A substantial portion of the Company's lease operating expenses in the Kingdom of Thailand relate to lease payments made by a subsidiary of the Company in connection with its bareboat charter of the FPSO, which amounted to $10,200,000 during 1997. See "-- Liquidity and Capital Resources; Capital Requirements; Other Material Long-Term Commitments." GENERAL AND ADMINISTRATIVE EXPENSES General and administrative expenses for 1997 were $21,412,000, an increase of approximately 19% from general and administrative expenses of $18,028,000 for 1996, and an increase of approximately 31% from general and administrative expenses of $16,400,000 for 1995. The increase in general and administrative expenses for 1997, compared to 1996 and 1995, was primarily related to salary and benefit expenses incurred in connection with the increase in the Company's work force in its Bangkok, Thailand office as a result of the Company's increased activities there. 30 EXPLORATION EXPENSES Exploration expenses consist primarily of delay rentals and geological and geophysical costs which are expensed as incurred. Exploration expenses for 1997 were $10,530,000, a decrease of approximately 37% from exploration expenses of $16,777,000 for 1996, and an increase of approximately 41% from exploration expenses of $7,468,000 for 1995. The decrease in exploration expenses for 1997, compared to 1996, resulted primarily from the incurrence of costs associated with conducting several 3-D seismic surveys by the Company on its leases in South Louisiana, East Texas and the Permian Basin during 1996 for which no similar costs of their magnitude were incurred during the comparative periods, although such costs were partially offset in 1997 by the costs associated with conducting the Jarmjuree 3-D seismic survey in the Gulf of Thailand and by increased seismic data acquisition in the Gulf of Mexico. The increase in exploration expenses for 1997, compared to 1995, resulted primarily from increased geophysical activity by the Company, including the costs of conducting and processing the Jarmjuree 3-D seismic survey. In addition, exploration expenses attributable to increased delay rental expense resulting from the Company's acquisition of additional prospective oil and gas acreage during 1997, as compared to 1996 and 1995, served to offset the decrease in exploration expenses for 1997, compared to 1996, and to increase the exploration expenses incurred during 1997, compared to 1995. The Company does not currently expect its exploration expenses in 1998 to increase significantly over those incurred during 1997. DRY HOLE AND IMPAIRMENT EXPENSES Dry hole and impairment expenses relate to costs of unsuccessful wells drilled along with impairments due to decreases in expected reserves from producing wells. The Company's dry hole and impairment expenses for 1997 were $9,631,000, an increase of approximately 12% from dry hole and impairment costs of $8,579,000 for 1996, and an increase of approximately 44% from dry hole and impairment costs of $6,703,000 for 1995. 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. 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 ("DD&A") is based on 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 the Gulf of Thailand. Generally, the Company established cost centers on the basis of an oil or gas trend or play for its oil and gas activities onshore in the United States. The Company's DD&A expense for 1997 was $103,157,000, an increase of approximately 67% from DD&A expenses of $61,857,000 for 1996, and an increase of approximately 51% from DD&A expenses of $68,489,000 for 1995. The increase in the Company's DD&A expenses for 1997, compared to 1996 and 1995, resulted primarily from an increase in the Company's natural gas and liquid hydrocarbon production and, to a lesser extent, an increase in the Company's composite DD&A rate. The composite DD&A rate for all of the Company's producing fields for 1997 was $0.95 per equivalent Mcf ($5.68 per equivalent barrel), an increase of approximately 9% from a composite DD&A rate of $0.87 per equivalent Mcf ($5.20 per equivalent barrel) for 1996, and an increase of approximately 3% from a composite DD&A rate of $0.91 per equivalent Mcf ($5.47 per equivalent barrel) for 1995. The increase in the composite DD&A rate for all of the Company's producing fields for 1997, compared to 1996 and 1995, resulted primarily from an increased percentage of the Company's production coming from 31 certain of the Company's fields that have DD&A rates that are higher than the Company's recent historical composite rate and a corresponding decrease in the percentage of the Company's production coming from fields that have DD&A rates that are lower than the Company's recent historical composite DD&A rate. Management currently anticipates that this trend will continue for the foreseeable future, resulting in generally increasing DD&A rates. The Company produced 107,605,000 equivalent Mcf (17,934,000 equivalent Bbls) in 1997, an increase of approximately 53% from the 70,472,000 equivalent Mcf (11,745,000 equivalent Bbls) produced in 1996, and an increase of approximately 45% from the 74,337,000 equivalent Mcf (12,389,000 equivalent Bbls) produced in 1995. INTEREST INTEREST CHARGES. The Company incurred interest charges for 1997 of $21,886,000, an increase of approximately 66% from interest charges of $13,203,000 for 1996, and an increase of approximately 96% from interest charges of $11,167,000 for 1995. The increase in the Company's interest charges for 1997, compared to 1996 and 1995, resulted primarily from an increase in the average amount of the Company's outstanding debt and, to a lesser extent, increased average interest rates on the debt outstanding (resulting primarily from the issuance of the 2007 Notes on May 22, 1997, which bear interest at an 8 3/4% annual interest rate) and increased expenses related to amortization of debt issuance expenses resulting from the issuance of the 2006 Notes in 1996. CAPITALIZED INTEREST EXPENSE. Capitalized interest for 1997 was $6,175,000 an increase of approximately 46% from capitalized interest of $4,244,000 for 1996, and an increase of approximately 237% from capitalized interest of $1,834,000 for 1995. The increase in capitalized interest for 1997, compared to 1996 and 1995, resulted primarily from the requirement to capitalize interest expense attributable to capital expenditures on non-producing properties, principally capital expenditures related to the Company's development of the Tantawan Field and the East Cameron Block 334 "E" platform during the first quarter of 1997 and its development of the Benchamas Field commencing in 1997, which substantially exceeded the Company's capital expenditures on non-producing properties (principally the Tantawan Field) during 1996 and 1995. To a lesser extent, the increase in capitalized interest expense is also attributable to an increase in the rate used to compute the interest that was capitalized. The Company expects its capitalized interest costs to increase in the future, primarily as a result of the requirement to capitalize interest expense attributable to capital expenditures incurred in connection with its development of the Benchamas Field in the Gulf of Thailand. See "Business -- International Operations; Significant International Operating Areas During 1997; Benchamas Field and the Maliwan Production Area". FOREIGN CURRENCY TRANSACTION LOSS The Company incurred a foreign currency transaction loss of $7,604,000 during 1997. No comparable losses were incurred in 1996 or 1995. The foreign currency transaction loss resulted from the devaluation 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 1997. In early July 1997, the government of the Kingdom of Thailand announced that the value of the Thai Baht would be set against the U.S. dollar and other currencies under a "managed float" program arrangement. Since that time the value of the Thai Baht has generally declined, although in recent weeks it has shown some sign of stabilizing. During the last two weeks of the month of February 1998, the Thai Baht traded in a range of approximately 43 to 48 Thai Baht to the U.S. dollar. The Company cannot predict what the Thai Baht to U.S. dollar exchange rate may be in the future. Moreover, it is anticipated that this exchange rate will remain volatile. INCOME TAX EXPENSE Income tax expense for 1997 was $18,091,000, a decrease of approximately 4% from income tax expense of $18,800,000 for 1996, and an increase of approximately 270% from income tax expense of $4,891,000 for 1995. The decrease in income tax expense for 1997, compared to 1996, resulted primarily from the foreign currency transaction loss discussed in the preceding paragraph, which was partially offset by increased taxable income. The increase in income tax expense for 1997, compared to 1995, resulted primarily from increased taxable income. 32 LIQUIDITY AND CAPITAL RESOURCES CASH FLOWS The Company's Consolidated Statement of Cash Flows for the year ended December 31, 1997, reflects net cash provided by operating activities of $150,732,000. In addition to the net cash provided by operating activities, the Company received net proceeds of $96,835,000 from the issuance of the 2007 Notes on May 22, 1997, $3,874,000 from the exercise of stock options and $387,000 from the sale of certain non-strategic properties and had net borrowings of $2,000,000 under its revolving credit agreement and uncommitted money market credit lines with certain banks. During 1997, the Company invested $197,326,000 of such cash flow in capital projects during 1997, purchased certain oil and gas properties for $31,234,000 and paid $4,012,000 ($0.03 per share for four quarters) in cash dividends to holders of the Company's Common Stock. Of the $197,326,000 invested in capital projects, $56,961,000 was applicable to 1996 projects and $140,365,000 was applicable to 1997 capital projects. As of December 31, 1997, the Company had $19,646,000 in cash and cash investments. FUTURE CAPITAL REQUIREMENTS The Company's capital and exploration budget for 1998, which does not include any amounts which may be expended for the purchase of proved reserves or any interest which may be capitalized resulting from projects in progress, has been established by the Company's Board of Directors at $230,000,000, an increase of approximately 6% from the Company's capital and exploration expenditures (excluding purchased reserves and interest capitalized) of $217,729,000 for 1997, an increase of approximately 12% over capital and exploration expenditures (excluding purchased reserves and interest capitalized) of $206,207,000 for 1996, and an increase of approximately 135% over capital and exploration expenditures (excluding purchased reserves and interest capitalized) of approximately $97,910,000 for 1995. In addition to anticipated capital and exploration expenses, other material 1998 cash requirements that the Company currently anticipates include ongoing operating, general and administrative, income tax, interest expense and the payment of dividends on its Common Stock, including a $0.03 per share dividend on its Common Stock paid on February 27, 1998, to stockholders of record on February 13, 1998. The Company currently anticipates that cash provided by operating activities and funds available under its Credit Agreement and uncommitted money market credit lines will be sufficient to fund the Company's ongoing expenses, its 1998 capital and exploration budget and anticipated future dividend payments. 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. OTHER MATERIAL LONG-TERM COMMITMENTS As of February 9, 1996, Tantawan Services, LLC ("TS"), a company that is currently a wholly owned subsidiary of the Company, entered into a Bareboat 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 term of the Charter is for a period ending July 31, 2008, subject to extension. In addition, TS has a purchase option on the FPSO throughout the term of the Charter. TS has also contracted with another company, SBM Marine Services Thailand Ltd., to operate the FPSO on a reimbursable basis throughout the initial term of the Charter. Performance of both the Charter and the agreement to operate the FPSO are non-recourse to TS and the Company. However, performance is secured by a negative pledge on any hydrocarbons stored on the FPSO and is guaranteed by each of the working interest holders in the Tantawan Field, including Thaipo. Thaipo's guarantee is limited to its percentage interest in the Tantawan Field (currently 46.34%). The Charter currently provides for an estimated charter hire commitment of $24,000,000 per year ($11,122,000 net to Thaipo). 33 CAPITAL STRUCTURE CREDIT AGREEMENT AND UNCOMMITTED CREDIT LINES Effective August 1, 1997, the Company entered into an amended and restated credit agreement (as so amended and restated, "Credit Agreement"). The Credit Agreement provides for an unsecured $250,000,000 revolving/term credit facility which will be fully revolving until July 1, 2000, after which the balance will be due in eight quarterly term loan installments, commencing October 31, 2000. The amount that may be borrowed under the Credit Agreement may not exceed a borrowing base which is composed of both domestic and Thai properties less, in certain circumstances, the present value of interest payments on the 2007 Notes. The domestic borrowing base is determined semi-annually by the lenders in accordance with the Credit Agreement, based primarily on the discounted present value of future net revenues from the Company's domestic oil and gas reserves. The portion of the borrowing base which is composed of properties located in the Kingdom of Thailand is also determined semi-annually, but may, at the lenders' discretion, be redetermined once more during each semi-annual period. As of March 13, 1998, the Company's total borrowing base, including both domestic and Thai properties, exceeded $250,000,000. The Credit Agreement 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, creation of liens, the prepayment of subordinated debt, the payment of dividends, mergers and consolidations, investments and asset dispositions. See "Market for the Registrant's Common Stock and Related Security Holder Matters." In addition, the Company is prohibited from pledging borrowing base properties as security for other debt. Borrowings under the Credit Agreement currently bear interest at a base (prime) rate or LIBOR plus 5/8%, at the Company's option. A commitment fee on the unborrowed amount under the Credit Agreement is also charged. The commitment fee is currently 0.25% per annum on the unborrowed amount under the Credit Agreement that is designated as "active" and 0.10% per annum on the unborrowed amount under the Credit Agreement that is designated as "inactive." Of the $250,000,000 that is currently available under the Credit Agreement (subject to borrowing base limitations), $125,000,000 is designated as "active" and $125,000,000 is designated as "inactive." As of March 13, 1998, the Company had also entered into separate letter agreements with two banks under which one of the banks may provide a $10,000,000 uncommitted money market line of credit and the other bank may provide a $20,000,000 uncommitted money market line of credit. Each line of credit is on an as available or offered basis and neither bank has an obligation to make any advances under its respective line of credit. Although loans made under these letter agreements are for a maximum term of 30 days, they 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 Agreement. Both letter agreements permit either party to terminate such letter agreement at any time. Under its Credit Agreement, the Company is currently limited to incurring a maximum of $20,000,000 of additional senior debt, which would include debt incurred under these lines of credit. Further, the 2007 Notes also restrict the incurrence of additional senior indebtedness. See "; 2007 Notes." As of March 1, 1998, indebtedness in the amount of $56,000,000 was outstanding under the Credit Agreement and the two letter agreements. 2007 NOTES On May 22, 1997, the Company issued $100,000,000 principal amount of 2007 Notes. The proceeds from the issuance of the 2007 Notes were used to repay amounts outstanding under the Credit Agreement, and to purchase short-term cash investments. 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, commencing November 15, 1997. 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, which currently includes the Company's obligations under its bank revolving credit agreement and its unsecured credit lines, but are senior in right of payment to its subordinated indebtedness, which currently includes the 2006 Notes and the 2004 Notes. 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. No 34 sinking fund payments are required on the 2007 Notes. The 2007 Notes are redeemable at the option of any holder, upon the occurrence of a change of control (as defined in the indenture governing the 2007 Notes), at 101% of their principal amount. The indenture governing the 2007 Notes also imposes certain covenants on the Company that are customary for senior subordinated indebtedness generally, 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. 2004 NOTES The Company's 2004 Notes were called for redemption on March 16, 1998, at a price equal to 103.30% of their principal amount. Prior thereto, holders of all but $95,000 principal amount of the 2004 Notes chose to convert their 2004 Notes into Common Stock at a conversion price of $22.188 per common share, rather than receive cash for their 2004 Notes resulting in the issuance of 3,879,726 shares of Common Stock. 2006 NOTES The outstanding principal amount of 2006 Notes was $115,000,000 as of December 31, 1997. 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 will be redeemable at the option of the Company, in whole or in part, at any time on or after June 15, 1999, at a redemption price of 103.85% of their principal amount and decreasing percentages thereafter. No sinking fund payments are required on the 2006 Notes. The 2006 Notes are redeemable at the option of the holder, upon the occurrence of a repurchase event (a change of control and other circumstances as defined in the indenture governing the 2006 Notes), at 100% of the principal amount. 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, 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 are sold there. In recent months, 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 oil and natural gas production there. See "-- Results of Operations; Income and Revenue Data" and "-- Results of Operations; Operating Costs and Expenses; Foreign Currency Transaction Loss." 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 35 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 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 currently expected on future crude oil sales to be paid in U.S. dollars. See "Business -- International Operations; Contractual Terms Governing the Thailand Concession and Related Production" and "Business -- Miscellaneous; Sales." The Company believes that the current economic difficulties in Southeast Asia have resulted in a decreased demand for petroleum products in the region, which has contributed to the recent general decline in crude oil and condensate prices throughout the world. This price decline has had an adverse effect on all oil and gas companies that sell their production on the world spot markets, including the Company, without regard to where their respective production is located. YEAR 2000 ISSUE Many computer software systems, as well as certain hardware, were structured to utilize a two-digit date field meaning that they may not be able to properly recognize dates in the year 2000. This could result in significant system failures. The Company has a process in place to identify potential year 2000 problems and implement solutions. The Company has addressed the year 2000 issue in those areas where replacement systems have been installed for other business reasons. Where existing systems are expected to remain in place beyond 1999, the Company is implementing systems changes utilizing a combination of internal and external resources. In addition, the Company intends to communicate with its major suppliers and others with whom it conducts business to determine that they will be able to resolve the year 2000 issue. While the Company believes it will be able to resolve the year 2000 issue, if it is unable to complete the required systems changes or if those with whom the Company conducts business are unsuccessful in implementing solutions, the year 2000 issue could have an adverse impact on the Company's operations and revenues. Based upon current estimates, the Company believes that it will not incur material costs during 1998 and 1999 to implement the necessary changes to existing systems. These costs are being expensed as they are incurred. 36 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1997 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, 1997 and 1996, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1997. 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 generally accepted auditing standards. 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, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Houston, Texas February 13, 1998 38 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME YEAR ENDED DECEMBER 31, ---------------------------------- 1997 1996 1995 ---------- ---------- ---------- (EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Oil and gas..................... $ 285,200 $ 204,142 $ 157,459 Gains (losses) on sales......... 1,100 (165) 100 ---------- ---------- ---------- Total...................... 286,300 203,977 157,559 ---------- ---------- ---------- Operating Costs and Expenses: Lease operating................. 63,501 37,628 35,071 General and administrative...... 21,412 18,028 16,400 Exploration..................... 10,530 16,777 7,468 Dry hole and impairment......... 9,631 8,579 6,703 Depreciation, depletion and amortization.................. 103,157 61,857 68,489 ---------- ---------- ---------- Total...................... 208,231 142,869 134,131 ---------- ---------- ---------- Operating Income..................... 78,069 61,108 23,428 Interest: Charges......................... (21,886) (13,203) (11,167) Income.......................... 453 232 26 Capitalized..................... 6,175 4,244 1,834 Foreign Currency Transaction Loss.... (7,604) -- -- ---------- ---------- ---------- Income Before Taxes and Extraordinary Item............................... 55,207 52,381 14,121 ---------- ---------- ---------- Income Tax Expense................... (18,091) (18,800) (4,891) ---------- ---------- ---------- Income Before Extraordinary Item..... 37,116 33,581 9,230 Extraordinary Loss on Early Extinguishment of Debt, net of taxes.............................. -- (821) -- ---------- ---------- ---------- Net Income........................... $ 37,116 $ 32,760 $ 9,230 ========== ========== ========== Earnings per Share (restated for 1996 and 1995): Basic Before extraordinary item.................... $ 1.11 $ 1.01 $ 0.28 Extraordinary item......... -- (0.02) -- ---------- ---------- ---------- Net income................. $ 1.11 $ 0.99 $ 0.28 ========== ========== ========== Diluted Before extraordinary item.................... $ 1.06 $ 0.97 $ 0.28 Extraordinary item......... -- (0.02) -- ---------- ---------- ---------- Net income................. $ 1.06 $ 0.95 $ 0.28 ========== ========== ========== 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, -------------------------- 1997 1996 ------------ ------------ (EXPRESSED IN THOUSANDS) ASSETS Current Assets: Cash and cash investments....... $ 19,646 $ 3,054 Accounts receivable............. 39,540 30,031 Other receivables............... 46,951 35,027 Inventory -- product............ 713 -- Inventories -- tubulars......... 8,334 6,165 Other........................... 4,087 641 ------------ ------------ Total current assets....... 119,271 74,918 ------------ ------------ Property and Equipment: Oil and gas, on the basis of successful efforts accounting Proved properties being amortized.............. 1,321,817 1,079,523 Unevaluated properties and properties under development, not being amortized.............. 110,231 111,192 Other, at cost.................. 12,619 8,773 ------------ ------------ 1,444,667 1,199,488 Less -- accumulated depreciation, depletion, and amortization, including $6,004 and $4,822 respectively, applicable to other property... 917,363 814,623 ------------ ------------ 527,304 384,865 ------------ ------------ Other................................ 30,042 19,459 ------------ ------------ $ 676,617 $ 479,242 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable -- operating activities..................... $ 13,639 $ 7,676 Accounts payable -- investing activities..................... 90,833 56,961 Accrued interest payable........ 3,130 1,957 Accrued payroll and related benefits....................... 1,938 1,490 Other........................... 632 163 ------------ ------------ Total current liabilities............ 110,172 68,247 Long-Term Debt....................... 348,179 246,230 Deferred Federal Income Tax.......... 57,502 46,321 Deferred Credits..................... 14,658 11,162 ------------ ------------ Total liabilities.......... 530,511 371,960 ------------ ------------ Shareholders' Equity: Preferred stock, $1 par; 2,000,000 shares authorized.... -- -- Common stock, $1 par; 100,000,000 shares authorized, and 33,552,702 and 33,321,381 shares issued, respectively.... 33,553 33,321 Additional capital.............. 144,848 139,337 Retained earnings (deficit)..... (31,971) (65,075) Treasury stock and other, at cost........................... (324) (301) ------------ ------------ Total shareholders' equity................. 146,106 107,282 ------------ ------------ $ 676,617 $ 479,242 ============ ============ The accompanying notes to consolidated financial statements are an integral part hereof. 40 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS YEAR ENDED DECEMBER 31, ------------------------------- 1997 1996 1995 --------- --------- --------- (EXPRESSED IN THOUSANDS) Cash flows from operating activities: Cash received from customers..... $ 272,004 $ 195,931 $ 164,065 Federal income taxes received.... 7,037 -- 6,000 Operating, exploration, and general and administrative expenses paid.................. (86,445) (74,512) (56,997) Interest paid.................... (20,713) (12,960) (11,036) Federal income taxes paid........ (19,500) 12,500) (6,000) Other............................ (1,651) (3,061) 301 --------- --------- --------- Net cash provided by operating activities...... 150,732 92,898 96,333 --------- --------- --------- Cash flows from investing activities: Capital expenditures............. (197,326) (172,032) (96,403) Purchase of proved reserves...... (31,234) -- (11,921) Proceeds from the sale of property and tubular stock..... 387 100 100 --------- --------- --------- Net cash used in investing activities................ (228,173) (171,932) (108,224) --------- --------- --------- Cash flows from financing activities: Proceeds from issuance of new debt........................... 100,000 115,000 -- Borrowings under senior debt agreements..................... 502,000 208,000 199,000 Payments under senior debt agreements..................... (500,000) (201,000) (182,000) Proceeds from exercise of stock options........................ 3,874 3,378 1,717 Payment of cash dividends on common stock................... (4,012) (3,979) (3,946) Debt issue expenses paid......... (3,165) (3,116) -- Purchase of 8% debentures due 2005........................... -- (40,699) (450) Principal payments of other long-term debt obligations..... -- -- (871) --------- --------- --------- Net cash provided by financing activities...... 98,697 77,584 13,450 --------- --------- --------- Effect of exchange rate changes on cash............................... (4,664) 23 -- --------- --------- --------- Net increase (decrease) in cash and cash investments................... 16,592 (1,427) 1,559 Cash and cash investments at the beginning of the year.............. 3,054 4,481 2,922 --------- --------- --------- Cash and cash investments at the end of the year........................ $ 19,646 $ 3,054 $ 4,481 ========= ========= ========= Reconciliation of net income to net cash provided by operating activities: Net income....................... $ 37,116 $ 32,760 $ 9,230 Adjustments to reconcile net income to net cash provided by operating activities Extraordinary losses on early extinguishments of debt, net of taxes........ -- 821 -- Foreign currency transaction loss...................... 7,604 -- -- (Gains) losses on sales..... (1,100) 165 (100) Depreciation, depletion and amortization.............. 103,157 61,857 68,489 Dry hole and impairment..... 9,631 8,579 6,703 Interest capitalized........ (6,175) (4,244) (1,834) Increase in deferred income tax....................... 12,999 7,175 5,592 Change in assets and liabilities: (Increase) decrease in accounts receivable... (12,483) (8,211) 7,095 Increase in inventory -- product... (713) -- -- (Increase) decrease in other current assets................ (6,470) 81 23 Increase in other assets................ (7,418) (5,228) (1,187) Increase (decrease) in accounts payable...... 8,998 (2,079) 1,942 Increase in accrued interest payable...... 1,173 243 131 Increase in accrued payroll and related benefits.............. 448 251 2 Increase in other current liability..... 469 60 63 Increase in deferred credits............... 3,496 668 184 --------- --------- --------- Net cash provided by operating activities......................... $ 150,732 $ 92,898 $ 96,333 ========= ========= ========= The accompanying notes to consolidated financial statements are an integral part hereof. 41 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
TREASURY RETAINED STOCK SHARE- SHARES COMMON ADDITIONAL EARNINGS AND HOLDERS' OUTSTANDING STOCK CAPITAL (DEFICIT) OTHER EQUITY ----------- ------- ---------- --------- -------- --------- (DOLLARS EXPRESSED IN THOUSANDS) BALANCE AT DECEMBER 31, 1994......... 32,810,261 $32,826 $ 130,675 $ (99,140) $ (324) $ 64,037 Net income........................... -- -- -- 9,230 -- 9,230 Exercise of stock options............ 181,136 181 2,206 -- -- 2,387 Dividends ($0.12 per common share)... -- -- -- (3,946) -- (3,946) ----------- ------- ---------- --------- -------- --------- BALANCE AT DECEMBER 31, 1995......... 32,991,397 33,007 132,881 (93,856) (324) 71,708 Net income........................... -- -- -- 32,760 -- 32,760 Foreign currency translation gain.... -- -- -- -- 23 23 Exercise of stock options............ 274,714 274 4,924 -- -- 5,198 Shares issued in connection with the Long-Term Incentive Plan........... 5,896 6 246 -- -- 252 Shares issued in connection with the conversion of -- 8% Debentures................... 32,898 33 1,267 -- -- 1,300 2004 Notes...................... 901 1 19 -- -- 20 Dividends ($0.12 per common share)... -- -- -- (3,979) -- (3,979) ----------- ------- ---------- --------- -------- --------- BALANCE AT DECEMBER 31, 1996......... 33,305,806 33,321 139,337 (65,075) (301) 107,282 Net income........................... -- -- -- 37,116 -- 37,116 Foreign currency translation loss.... -- -- -- -- (23) (23) Exercise of stock options............ 229,024 230 5,461 -- -- 5,691 Shares issued in connection with the conversion of 2004 Notes........... 2,297 2 50 -- -- 52 Dividends ($0.12 per common share)... -- -- -- (4,012) -- (4,012) ----------- ------- ---------- --------- -------- --------- BALANCE AT DECEMBER 31, 1997......... 33,537,127 $33,553 $ 144,848 $ (31,971) $ (324) $ 146,106 =========== ======= ========== ========= ======== =========
The accompanying notes to consolidated financial statements are an integral part hereof. 42 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 and production activities on its properties located offshore in the Gulf of Mexico and onshore in the United States and internationally in the Gulf of Thailand. The Company has interests in 101 lease blocks offshore Louisiana and Texas, approximately 237,000 gross acres onshore in the United States and approximately 734,000 gross acres offshore in the Kingdom of Thailand. USE OF ESTIMATES -- The preparation of these financial statements require 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 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. 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. 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 and the resulting gains or losses on foreign currency transactions are included in the consolidated statements of income for the period. INVENTORY -- PRODUCT Crude oil and condensate from the Company's Tantawan field located in the Kingdom of Thailand is produced into a floating production, storage and off loading ("FPSO") system and sold periodically as an economic barge quantity is accumulated. The product inventory at December 31, 1997 consists of approximately 43,000 barrels of crude oil and condensate, net to the Company's interest, and is carried at its estimated net realizable value of $16.67 per barrel. INVENTORY -- 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. 43 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. EARNINGS PER SHARE -- In 1997, the Company adopted the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 128, Earnings Per Share ("SFAS 128"). Prior years have been restated in conformity with the provisions of SFAS 128. Earnings per common share (basic earnings per share) are based on the weighted average number of shares of common stock outstanding during the periods. Earnings 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, 1997 ------------------------------ INCOME SHARES PER SHARE ------- ------ --------- BASIC EARNINGS PER SHARE............. $37,116 33,421 $ 1.11 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................ -- 758 -- Interest expense avoided, net of taxes, and shares issued from the assumed conversion at $22.188 per share of the 2004 Notes......................... 3,082 3,885 ------- ------ --------- DILUTED EARNINGS PER SHARE........... $40,198 38,064 $ 1.06 ======= ====== ========= Antidilutive securities: Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period.......... -- 471 $ 40.82 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 44 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FOR THE YEAR ENDED DECEMBER 31, 1996 -------------------------------- INCOME(A) SHARES PER SHARE --------- ------ --------- BASIC EARNINGS PER SHARE............. $33,581 33,203 $ 1.01 Effect of potential dilutive securities: Shares issued from the assumed exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period................ -- 831 -- Interest expense avoided, net of taxes, and shares issued from the assumed conversion at $22.188 per share of the 2004 Notes......................... 3,083 3,886 --------- ------ --------- DILUTED EARNINGS PER SHARE........... $36,664 37,920 $ 0.97 ========= ====== ========= (a) Computed on income before extraordinary item 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.......... -- 20 $ 40.94 Interest expense incurred, net of taxes, and shares not issued related to the assumed non-conversion at $39.50 per share of the 8% Debentures, retired on June 28, 1996................. $ 1,179 521 $ 2.26 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.................. $ 2,238 1,472 $ 1.52 FOR THE YEAR ENDED DECEMBER 31, 1995 ------------------------------ INCOME SHARES PER SHARE ------- ------ --------- BASIC EARNINGS PER SHARE............. $ 9,230 32,893 $ 0.28 Effect of potential dilutive securities: Shares issued from the assumed exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period................ -- 597 -- ------- ------ --------- DILUTED EARNINGS PER SHARE........... $ 9,230 33,490 $ 0.28 ======= ====== ========= 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.......... -- 598 $ 22.13 Interest expense incurred, net of taxes, and shares not issued related to the assumed non-conversion at $39.50 per share of the 8% Debentures.... $ 2,229 1,085 $ 2.05 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....... $ 3,083 3,887 $ 0.79 45 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 to 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 "take" (cash) method of accounting for production imbalances. Under this method, the Company recognizes revenues on production as it is taken and delivered to its purchasers. The Company's crude oil imbalances are not significant. At December 31, 1997, the Company had taken approximately 3,751 MMcf of natural gas less than it was entitled to based on its interest in those properties, and approximately 1,757 MMcf more than its entitlement on other properties placing the Company at year end in a net under-delivered position of approximately 1,994 MMcf of natural gas based on its working interest ownership in the properties. 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 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. 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 costs to abandon offshore wells and platforms, and is 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 the 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. Other properties 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 Long-Term Incentive Plan and the conversion of debentures into Common Stock in 1996 and 1997. COMMITMENTS AND CONTINGENCIES -- The Company has commitments for operating leases for office space in Houston, Midland and Bangkok and commitments for an operating lease and operating expenses related to a floating production, storage and off-loading vessel (FPSO) in the Gulf of Thailand. Rental expense for office space was $1,440,000 in 1997, $1,054,000 in 1996, and $861,000 in 1995. Expenses for the FPSO lease and related 46 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) operating costs were $14,809,000 in 1997. Future minimum office and FPSO lease expenses and related FPSO operating expense payments (in thousands of dollars) at December 31, 1997 are as follows: 1998................................. $ 17,826 1999................................. 17,830 2000................................. 17,758 2001................................. 17,758 2002................................. 16,611 Thereafter........................... 91,352 (2) INCOME TAXES The components of income (loss) before income taxes for each of the three years in the period ended December 31, 1997, are as follows (expressed in thousands): 1997 1996 1995 --------- --------- --------- United States........................ $ 62,953 $ 56,380 $ 16,899 Foreign.............................. (7,746) (3,999) (2,778) --------- --------- --------- Total........................... $ 55,207 $ 52,381 $ 14,121 ========= ========= ========= The components of federal income tax expense (benefit) for each of the three years in the period ended December 31, 1997, are as follows (expressed in thousands): 1997 1996 1995 --------- --------- --------- United States, current............... $ 16,000 $ 12,500 $ -- United States, deferred(a)........... 5,964 7,162 5,602 Foreign, deferred.................... (3,873) (862) (711) --------- --------- --------- Total........................... $ 18,091 $ 18,800 $ 4,891 ========= ========= ========= - ------------ (a) Excludes $443,000 of deferred tax benefit on extraordinary loss of $1,264,000 in 1996. Total federal income tax expense (benefit) for each of the three years in the period ended December 31, 1997, 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): 1997 1996 1995 --------- --------- --------- Federal statutory income tax rate.... 35.0% 35.0% 35.0% Increases (reductions) resulting from: Statutory depletion in excess of tax basis....................... (0.2) (0.2) (2.2) Foreign taxes................... (2.1) 1.1 1.6 Other........................... 0.1 -- 0.2 --------- --------- --------- 32.8% 35.9% 34.6% ========= ========= ========= 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 47 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) future tax benefit will be realized. The principal components of the Company's deferred income tax assets and liabilities include the following at December 31, 1997 and 1996 (expressed in thousands): DECEMBER 31, -------------------------- 1997 1996 ------------ ------------ Deferred tax liabilities: Intangible drilling costs, capitalized and amortized for financial statement purposes and deducted for income tax purposes...................... $ 204,218 $ 184,981 Charges to property and equipment, expensed for financial statement purposes, and capitalized and amortized for income tax purposes....... 12,203 8,089 Interest charges, capitalized and amortized for financial statement purposes and deducted for income tax purposes...................... 19,762 21,046 ------------ ------------ 236,183 214,116 Deferred tax asset: Differences in depletion and depreciation rates used for tangible assets for financial and income tax purposes....... (178,681) (167,795) ------------ ------------ Net deferred tax liability........... $ 57,502 $ 46,321 ============ ============ (3) LONG-TERM DEBT Long-term debt and the amount due within one year at December 31, 1997 and 1996, consists of the following (dollars expressed in thousands): DECEMBER 31, ---------------------- 1997 1996 ---------- ---------- Senior debt -- Bank revolving credit agreement debt: LIBO Rate based loans, borrowings at December 31, 1997 and 1996 at average interest rates of 6.52% and 6.59%, respectively............ $ 47,000 $ 22,000 Prime rate based loans, borrowing at December 31, 1996 at an interest rate of 8.25%........... -- 13,000 ---------- ---------- Total bank revolving credit agreement debt............... 47,000 35,000 Uncommitted credit lines with banks, borrowing at December 31, 1996 at an average interest rate of 7.0%.................... -- 10,000 ---------- ---------- Total senior debt.................... 47,000 45,000 ---------- ---------- Subordinated debt -- 8 3/4% Senior subordinated notes, due 2007 (issued May 22, 1997)................. 100,000 -- 5 1/2% Convertible subordinated notes, due 2004............... 86,179 86,230 5 1/2% Convertible subordinated notes, due 2006............... 115,000 115,000 ---------- ---------- Total subordinated debt.............. 301,179 201,230 ---------- ---------- Total debt........................... 348,179 246,230 ---------- ---------- Amount due within one year -- ....... -- -- ---------- ---------- Long-term debt....................... $ 348,179 $ 246,230 ========== ========== 48 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Effective August 1, 1997, the Company entered into an amended and restated credit agreement (as so amended and restated, the "Credit Agreement"). The Credit Agreement provides for an unsecured $250,000,000 revolving/term credit facility which will be fully revolving until July 1, 2000, after which the balance will be due in eight quarterly term loan installments, commencing October 31, 2000. The amount that may be borrowed under the Credit Agreement may not exceed a borrowing base which is composed of both domestic and Thai properties less, in certain circumstances, the present value of interest payments on the 2007 Notes. The domestic borrowing base is determined semiannually by the lenders in accordance with the Credit Agreement, based primarily on the discounted present value of future net revenues from the Company's domestic oil and gas reserves. The portion of the borrowing base which composed of properties located in the Kingdom of Thailand is also determined semiannually, but may, at the lenders' discretion, be redetermined once more during each semiannual period. The value of this portion of the borrowing base is determined by the lenders applying their usual and customary criteria for oil and gas evaluation. As of January 1, 1998, the Company's total borrowing base, including both domestic and Thai properties, exceeded $250,000,000. The Credit Agreement is governed by various financial and other covenants, including requirements to maintain positive working capital (excluding current maturities of debt) and fixed charge coverage ratio, and limitations on indebtedness, creation of liens, the prepayment of subordinated debt, the payment of dividends, mergers and consolidation, investments and asset dispositions. In addition, the Company is prohibited from pledging borrowing base properties as security for other debt. Borrowings under the Credit Agreement currently bear interest at a base (prime) rate or LIBOR plus 5/8%, at the Company's option. A commitment fee on the unborrowed amount under the Credit Agreement is also charged. The commitment fee is currently 0.25% per annum on the unborrowed amount under the Credit Agreement that is designated as "active" and 0.10% per annum on the unborrowed amount under the Credit Agreement that is designated as "inactive." Of the $250,000,000 that is currently available under the Credit Agreement (subject to borrowing base limitations), $125,000,000 is designated as "active" and $125,000,000 is designated as "inactive". The Company has also entered into separate letter agreements with two banks under which one of the banks may provide a $10,000,000 uncommitted money market line of credit and the other bank may provide a $20,000,000 uncommitted money market line of credit. Each line of credit is on an as available or offered basis and neither bank has an obligation to make any advances under its respective line of credit. Although loans made under these letter agreements are for a maximum term of 30 days, they will be reflected as long-term on the Company's balance sheet because the Company has the ability and intent to reborrow such amounts under its Credit Agreement. Both letter agreements permit either party to terminate such letter agreement at any time. On May 22, 1997, the Company issued $100,000,000 of 8 3/4% Senior Subordinated Notes due 2007 (the "2007 Notes"). The proceeds from the issuance of the 2007 Notes were used to repay amounts outstanding under the Company's bank revolving credit agreement, and to purchase short-term cash investments. The 2007 Notes bear interest at a rate of 8 3/4%, payable semiannually in arrears on May 15 and November 15 of each year, commencing November 15, 1997. 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, which currently includes the Company's obligations under its bank revolving credit agreement and its unsecured credit lines, but are senior in right of payment to its subordinated indebtedness, which currently includes the 2006 Notes and the 2004 Notes. 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. No sinking fund payments are required on the 2007 Notes. The 2007 Notes are redeemable at the option of any holder, upon the occurrence of a change of control (as defined in the indenture governing the 2007 Notes), at 101% of their principal amount. The indenture governing the 2007 Notes also imposes certain covenants on the Company that are customary for senior subordinated indebtedness generally, including covenants limiting: incurrence of indebtedness 49 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. As of December 31, 1997, $28,657,000 was available for dividends under this limitation, which is currently the Company's most restrictive such covenant. The 5 1/2% Convertible Subordinated Notes, due 2004 (the "2004 Notes") are convertible into Common Stock at $22.188 per share subject to adjustment upon the occurrence of certain events. The 2004 Notes will be redeemable at the option of the Company, in whole or in part, at any time on or after March 15, 1998, at a redemption price of 103.3% and decreasing percentages thereafter. No sinking fund is provided. The 2004 Notes are redeemable at the option of the holder, upon the occurrence of a repurchase event (a change in control and other circumstances, as defined), at 100% of the principal amount. On February 12, 1998, the Company announced its intent to redeem the 2004 Notes on March 16, 1998 at an amount equal to 103.3% of their principal amount plus accrued interest. Holders may elect to convert the principal or any integral multiple of a 2004 Note into common stock at $22.188 per share until close of business on March 13, 1998. The 5 1/2% Convertible Subordinated Notes, due 2006 (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 will be redeemable at the option of the Company, in whole or in part, at any time on or after June 15, 1999, at a redemption price of 103.85% and decreasing percentages thereafter. No sinking fund is provided. The 2006 Notes are redeemable at the option of the holder, upon the occurrence of a repurchase event (a change in control and other circumstances, as defined), at 100% of the principal amount. Current maturities and sinking fund requirements during the next five years in connection with the above long-term debt are none in 1998 and 1999, $7,050,000 in 2000, $25,850,000 in 2001 and $14,100,000 in 2002. All of the current maturities reflected above are related to the retirement of the Company's bank debt. The Company has established a history of refinancing its bank debt before scheduled maturity payments commence and expects to do so again before the amortization of bank debt commences in 2000. 50 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (4) GEOGRAPHIC SEGMENT REPORTING During 1997, the Company adopted the Financial and Accounting Standard's Board's Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information ("SFAS 131"). Information concerning the Company's revenues and long-lived assets as required by SFAS 131 is as follows (in thousands of dollars): LONG-LIVED REVENUES ASSETS ---------- ----------- AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1997 United States................... $ 245,458 $ 366,638 Kingdom of Thailand............. 39,393 160,666 ---------- ----------- $ 284,851 $ 527,304 ========== =========== AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1996 United States................... $ 203,364 $ 295,108 Kingdom of Thailand............. -- 89,757 ---------- ----------- $ 203,364 $ 384,865 ========== =========== AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1995 United States................... $ 156,729 $ 232,527 Kingdom of Thailand............. -- 29,306 ---------- ----------- $ 156,729 $ 261,833 ========== =========== (5) 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. Sales to the following customers exceeded 10% of revenues during any one of the three years indicated (expressed in thousands): 1997 1996 1995 --------- --------- --------- Enron Corp. and affiliates........... $ 57,965 $ 58,101 $ 42,895 Petroleum Authority of Thailand (PTT).............................. $ 30,108 $ -- $ -- Coastal Gas Marketing Company........ $ -- $ 18,376 $ 18,117 (6) CREDIT RISK Substantially all of the Company's accounts receivable at December 31, 1997 and 1996, 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 generally have not been material. No known material credit losses were experienced during 1997 or 1996. 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 are sold there. In recent months, 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 51 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. All of the Company's current natural gas production from its Thailand operations 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 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 currently expected on future crude oil sales to be paid in U.S. dollars. The Company believes that the current economic difficulties in Southeast Asia have resulted in a decreased demand for petroleum products in the region, which has contributed to the recent general decline in crude oil and condensate prices throughout the world. (7) EMPLOYEE BENEFITS As permitted by SFAS No. 123, the Company applies APB Opinion No. 25 and related interpretations in accounting for its stock option plans. Since the exercise price of the options granted is equal to the quoted market price of the Company's stock at the date of grant, no compensation cost has been recognized for its stock option plans. Had compensation costs been determined based on the fair value at the grant dates for awards made in 1997, 1996, and 1995 consistent with the methods of SFAS No. 123, the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below (in thousands, except for per share amounts): 1997 1996 1995 --------- --------- --------- Net income: As reported..................... $ 37,116 $ 32,760 $ 9,230 Pro forma....................... $ 34,220 $ 31,194 $ 8,619 Earnings per share: As reported (restated for 1996 and 1995) -- Basic............ $ 1.11 $ 0.99 $ 0.28 As reported (restated for 1996 and 1995) -- Diluted.......... $ 1.06 $ 0.95 $ 0.28 Pro forma -- Basic.............. $ 1.04 $ 0.94 $ 0.26 Pro forma -- Diluted............ $ 0.99 $ 0.91 $ 0.26 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 1997, 1996, and 1995, respectively: risk-free interest rates of 6.10%, 6.25%, and 6.00%, expected volatility of 34.63%, 39.15%, and 41.78%, dividend yields of 0.29%, 0.34%, and 0.54%, and an expected life of the options of 4 years in each of the years 1997, 1996, and 1995. The Company has a tax-advantaged savings plan in which all 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 ($10,000 for 1998), 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 separate 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 $588,000 to the savings plan in 1997, $471,000 in 1996, and $277,000 in 1995. 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, 52 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) expire 10 years from the date of grant. In 1996, the Company adopted the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation ("SFAS No. 123"). As permitted by SFAS No. 123, the Company elected to continue to account for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Accordingly, the adoption of SFAS No. 123 had no effect on the Company's results of operations in 1996 and 1997. A summary of the status of the Company's plans as of December 31, 1997, 1996, and 1995, and changes during the years ended on those dates is presented below: WEIGHTED AVERAGE NUMBER OF EXERCISE OPTIONS PRICE --------- -------- Outstanding, December 31, 1994 1,387,537 $11.72 Granted......................... 389,000 $22.34 Exercised....................... (181,136) $ 9.48 Forfeited or expired............ (20,000) $14.88 --------- Outstanding, December 31, 1995....... 1,575,401 $14.56 ========= Exercisable, December 31, 1995....... 1,006,686 $10.87 ========= Available for grant, December 31, 1995............................... 1,719,893 ========= Weighted-average fair value of options granted during 1995........ $ 8.77 Outstanding, December 31, 1995....... 1,575,401 $14.56 Granted......................... 406,500 $34.59 Exercised....................... (274,714) $12.30 --------- Outstanding, December 31, 1996....... 1,707,187 $19.70 ========= Exercisable, December 31, 1996....... 1,077,658 $14.31 ========= Available for grant, December 31, 1996............................... 1,313,393 ========= Weighted-average fair value of options granted during 1996........ $13.56 Outstanding, December 31, 1996....... 1,707,187 $19.70 Granted......................... 480,400 $40.49 Exercised....................... (229,024) $16.83 --------- Outstanding, December 31, 1997....... 1,958,563 $25.13 ========= Exercisable, December 31, 1997....... 1,196,803 $18.15 ========= Available for grant, December 31, 1997............................... 832,993 ========= Weighted-average fair value of options granted during 1997........ $14.63 53 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table summarizes information about stock options outstanding at December 31, 1997:
OPTIONS OUTSTANDING --------------------------------------- WEIGHTED OPTIONS EXERCISABLE AVERAGE ----------------------- REMAINING WEIGHTED WEIGHTED CONTRACTUAL AVERAGE AVERAGE RANGE OF NUMBER LIFE EXERCISE NUMBER EXERCISE OPTION PRICES OUTSTANDING (DAYS) PRICE EXERCISABLE PRICE - ------------------------------------- ------------ ----------- -------- ----------- -------- $4.38........................... 92,750 12 $ 4.38 92,750 $ 4.38 $5.56 to $8.06.................. 349,361 1,107 $ 6.83 349,361 $ 6.83 $15.13 to $19.13................ 156,046 2,014 $16.46 156,046 $16.46 $20.31 to $23.88................ 484,838 2,620 $22.15 381,827 $22.17 $30.56 to $34.88................ 325,001 3,143 $33.91 102,319 $33.93 $35.13 to $38.94................ 82,667 3,150 $36.18 56,000 $36.03 $40.56 to $44.38................ 465,900 3,483 $40.80 58,500 $41.20 $48.75.......................... 2,000 3,306 $48.75 -- -- ------------ ----------- Total........................... 1,958,563 2,493 $25.13 1,196,803 $18.15 ============ ===========
54 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A trusteed retirement plan has been adopted by the Company for its 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 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. The following table sets forth the plan's funded status (in thousands of dollars) as of December 31, 1997, 1996, and 1995. 1997 1996 1995 ---------- --------- --------- Actuarial present value (discounted at 7%, 7 1/4%, and 7 1/4%, respectively) of benefit obligations: Accumulated benefit obligations -- Vested..................... $ 7,355 $ 6,408 $ 5,488 Non-vested................. 1,536 1,138 1,173 ---------- --------- --------- Total accumulated benefit obligations................ 8,891 7,546 6,661 Projected salary increases (escalated at 5 1/2%, 5% and 5%, respectively) and other changes....................... 2,329 1,804 1,734 ---------- --------- --------- Projected benefit obligations for service rendered to date.......................... 11,220 9,350 8,395 Plan assets at fair value, primarily listed securities with an expected long-term rate of return of 9 1/2%, 8 1/2% and 8 1/2%, respectively.... 31,312 24,181 19,089 ---------- --------- --------- Plan assets in excess of projected benefit obligations................ 20,092 14,831 10,694 Unrecognized: Net overfunding being recognized over 15 years................. (336) (440) (543) Net gain arising from the difference between actual experience and that assumed... (13,134) (9,335) (5,989) Prior service cost.............. (300) (343) (387) ---------- --------- --------- Accrued retirement plan asset........ $ 6,322 $ 4,713 $ 3,775 ========== ========= ========= Retirement plan cost (benefit) for 1997, 1996, and 1995 included the following components: Service cost, benefits accruing each year with proration for future salary increases....... $ 746 $ 621 $ 480 Interest cost on projected benefit obligations..... 707 604 535 Actual return on plan assets..................... (2,286) (1,615) (1,182) Net amortization and deferral................... (775) (548) (333) ---------- --------- --------- Accrued retirement plan cost (benefit)..................... $ (1,608) $ (938) $ (500) ========== ========= ========= Although the Company has no obligation to do so, the Company currently provides full medical benefits to its retired 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. 55 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following is an analysis (in thousands of dollars) of the annual expense and activity in the deferred cost and benefits obligation accounts for 1995, 1996 and 1997. The computation assumes that future increases in medical costs will trend down from 8.1% to 5% per year over the next 7 years for purposes of estimating future costs. The medical cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed medical cost trend rate by one percent in each year would increase the aggregate of service and interest cost components of net periodic post retirement benefit cost for 1997 by $170,000 and the accumulated post retirement benefit obligation as of December 31, 1997 by $1,104,000. ANNUAL DEFERRED BENEFIT EXPENSE COSTS OBLIGATION ------- -------- ---------- Balance at January 1, 1995.............. $3,349 $ (5,487) Amortization of transition costs over 14 years representing the average remaining service period of eligible employees............................. $ 304 (304) 304 Amortization of net gain from earlier periods............................... (69) (69) Service cost, including interest........ 241 Interest cost on transition obligation............................ 399 ------- 1995 expense............................ $ 875 (875) ======= Current benefits paid................... 145 Unrecognized net gain................... 541 -------- ---------- Balance at December 31, 1995............ 3,045 (5,441) Amortization of transition costs over 14 years................................. $ 304 (304) 304 Amortization of net gain from earlier periods............................... (41) (41) Service cost, including interest........ 268 Interest cost on transition obligation............................ 387 ------- 1996 expense............................ $ 918 (918) ======= Current benefits paid................... 94 Unrecognized net gain................... 107 -------- ---------- Balance at December 31, 1996............ 2,741 (5,895) Amortization of transition costs over 14 years................................. $ 305 (305) 305 Amortization of net gain from earlier periods............................... (26) (26) Service cost, including interest........ 459 Interest cost on transition obligation............................ 427 ------- 1997 expense............................ $ 1,165 (1,165) ======= Current benefits paid................... 99 Unrecognized net loss................... (224) -------- Balance at December 31, 1997............ $2,436 ======== Plan assets at fair value............... ---------- Funded status at December 31, 1997 (discounted at 7%).................... $ (6,906) ========== The accumulated postretirement benefit obligation (in thousands of dollars) at December 31, 1997 is attributable to the following groups: Retirees and beneficiaries.............. $1,951 Dependents of retirees.................. 978 Fully eligible active employees......... 802 Active employees, not fully eligible.... 3,175 ---------- $6,906 ========== 56 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (8) 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 INVESTMENTS Fair value is carrying value as no cash equivalents or cash investments are included in the balances as of December 31, 1997 and 1996. DEBT INSTRUMENT BASIS OF FAIR VALUE ESTIMATE - -------------------------------------------------------------------------- Bank revolving credit agreement...... Fair value is carrying value as of December 31, 1997 and 1996 based on the market value interest rates. Uncommitted credit lines with banks.............................. Fair value is carrying value as of December 31, 1997 and 1996 based on the market value interest rates. 2007 Notes........................... Fair value is 102.5% of carrying value as of December 31, 1997 based on a quoted market value. 2004 Notes........................... Fair value is 140.38% and 166%, of carrying value as of December 31, 1997 and 1996, respectively, based on quoted market values. 2006 Notes........................... Fair value is 93.5% and 120%, of carrying value as of December 31, 1997 and 1996, respectively, based on quoted market values. The carrying value and estimated fair value of the Company's financial instruments at December 31, 1997 and 1996 (in thousands of dollars) are as follows:
1997 1996 -------------------------- -------------------------- CARRYING FAIR CARRYING FAIR VALUE VALUE VALUE VALUE ------------ ------------ ------------ ------------ Cash and cash investments............ $ 19,646 $ 19,646 $ 3,054 $ 3,054 Debt: Bank revolving credit agreement..................... (47,000) (47,000) (35,000) (35,000) Uncommitted credit lines with banks......................... -- -- (10,000) (10,000) 2007 Notes...................... (100,000) (102,500) -- -- 2004 Notes...................... (86,179) (120,978) (86,230) (143,142) 2006 Notes...................... (115,000) (107,525) (115,000) (138,000)
The Company occasionally enters into forward and futures contracts to minimize the impact of oil and gas price fluctuations. However, the Company does not consider its forward and futures contracts to be financial instruments since these contracts require or permit settlement by the delivery of the underlying commodity. Gains and losses on these activities are recognized in revenues when the hedged production occurs. No such contracts were outstanding as of December 31, 1997 or 1996. 57 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. United States income tax expense was determined by applying the statutory rates to pretax operating results with adjustments for permanent differences. Kingdom of Thailand tax expense was determined by applying the statutory tax rate to Thailand taxable income. UNITED KINGDOM OF TOTAL STATES THAILAND --------- -------- ---------- (EXPRESSED IN THOUSANDS) 1997 ----------------------------------- Revenues............................. $ 284,851 $245,458 $ 39,393 Lease operating expense.............. (63,501) (43,934) (19,567) Exploration expense.................. (10,530) (6,242) (4,288) Dry hole and impairment expense...... (9,631) (9,631) -- Depreciation, depletion and amortization expense............... (101,273) (84,443) (16,830) --------- -------- ---------- Pretax operating results............. 99,916 101,208 (1,292) Income tax (expense) benefit......... (30,353) (32,390) 2,037 --------- -------- ---------- Operating results.................... $ 69,563 $ 68,818 $ 745 ========= ======== ========== 1996 ----------------------------------- Revenues............................. $ 204,142 $204,131 $ 11 Lease operating expense.............. (37,628) (37,628) -- Exploration expense.................. (16,777) (14,247) (2,530) Dry hole and impairment expense...... (8,579) (8,834) 255 Depreciation, depletion and amortization expense............... (61,033) (60,932) (101) --------- -------- ---------- Pretax operating results............. 80,125 82,490 (2,365) Income tax (expense) benefit......... (27,905) (28,767) 862 --------- -------- ---------- Operating results.................... $ 52,220 $ 53,723 $ (1,503) ========= ======== ========== 1995 ----------------------------------- Revenues............................. $ 157,459 $157,536 $ (77) Lease operating expense.............. (35,071) (35,071) -- Exploration expense.................. (7,468) (6,111) (1,357) Dry hole and impairment expense...... (6,703) (6,703) -- Depreciation, depletion and amortization expense............... (67,831) (67,798) (33) --------- -------- ---------- Pretax operating results............. 40,386 41,853 (1,467) Income tax (expense) benefit......... (13,623) (14,334) 711 --------- -------- ---------- Operating results.................... $ 26,763 $ 27,519 $ (756) ========= ======== ========== 58 UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED) The following table sets forth the Company's capitalized costs (expressed in thousands) incurred for oil and gas producing activities during the years indicated. 1997 1996 1995 ---------- ---------- ---------- Capitalized costs incurred: Property acquisition -- United States........................ $ 14,492 $ 5,927 $ 14,864 Property acquisition -- Kingdom of Thailand................... 28,617 -- 4,171 Exploration -- United States.... 24,016 20,651 14,562 Exploration -- Kingdom of Thailand...................... 21,187 8,317 5,418 Development -- United States.... 95,768 99,464 39,461 Development -- Kingdom of Thailand...................... 60,996 53,564 23,994 Interest capitalized -- United States........................ 3,331 4,244 1,834 Interest capitalized -- Kingdom of Thailand................... 2,748 -- -- ---------- ---------- ---------- $ 251,155 $ 192,167 $ 104,304 ========== ========== ========== Provision for depreciation, depletion and amortization: United States................... $ 85,104 $ 61,033 $ 67,798 Kingdom of Thailand............. 16,830 101 33 ---------- ---------- ---------- $ 101,934 $ 61,134 $ 67,831 ========== ========== ========== 59 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 offshore in the Kingdom of Thailand is based on reports prepared by Ryder Scott Company Petroleum Engineers. The definitions and assumptions that served 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
TOTAL COMPANY UNITED STATES KINGDOM OF THAILAND ----------------------- ----------------------- ----------------------- OIL OIL OIL CONDENSATE CONDENSATE CONDENSATE & NATURAL NATURAL & NATURAL NATURAL & NATURAL NATURAL GAS LIQUIDS GAS GAS LIQUIDS GAS GAS LIQUIDS GAS (BBLS.) (MMCF) (BBLS.) (MMCF) (BBLS.) (MMCF) ----------- -------- ----------- -------- ----------- -------- Proved Reserves as of December 31, 1994................................. 33,861,612 242,890 26,187,240 186,151 7,674,372 56,739 Revisions of previous estimates...................... 496,849 21,800 363,213 16,592 133,636 5,208 Extensions, discoveries and other additions...................... 11,901,880 78,434 4,267,871 35,058 7,634,009 43,376 Purchase of properties........... 4,015,131 30,054 460,156 3,770 3,554,975 26,284 Sale of properties............... (15,144) (748) (15,144) (748) -- -- Estimated 1995 production........ (5,078,326) (44,369) (5,078,326) (44,369) -- -- ----------- -------- ----------- -------- ----------- -------- Proved Reserves as of December 31, 1995............................... 45,182,002 328,061 26,185,010 196,454 18,996,992 131,607 Revisions of previous estimates...................... (499,595) (30,034) 3,374,647 3,022 (3,874,242) (33,056) Extensions, discoveries and other additions...................... 9,810,363 102,039 3,601,333 55,592 6,209,030 46,447 Purchase of properties........... -- -- -- -- -- -- Sale of properties............... -- -- -- -- -- -- Estimated 1996 production........ (4,890,588) (39,122) (4,890,588) (39,122) -- -- ----------- -------- ----------- -------- ----------- -------- Proved Reserves as of December 31, 1996............................... 49,602,182 360,944 28,270,402 215,946 21,331,780 144,998 Revisions of previous estimates...................... 1,033,664 (16,860) 2,194,936 (5,582) (1,161,272) (11,278) Extensions, discoveries and other additions...................... 9,316,407 92,063 4,649,856 49,651 4,666,551 42,412 Purchase of properties........... 5,175,501 30,319 409,428 8,919 4,766,073 21,400 Sale of properties............... (6,155) (1,864) (6,155) (1,864) -- -- Estimated 1997 production........ (6,957,246) (63,114) (6,136,957) (50,350) (820,289) (12,764) ----------- -------- ----------- -------- ----------- -------- Proved Reserves as of December 31, 1997............................... 58,164,353 401,488 29,381,510 216,720 28,782,843 184,768 =========== ======== =========== ======== =========== ======== Proved developed reserves as of: December 31, 1994................ 24,669,755 178,518 24,669,755 178,518 -- -- December 31, 1995................ 22,487,608 164,679 22,487,608 164,679 -- -- December 31, 1996................ 31,090,407 238,032 25,898,414 192,034 5,191,993 45,998 December 31, 1997................ 33,149,612 239,732 26,167,519 179,972 6,982,093 59,760
60 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND --------- --------- ----------- (EXPRESSED IN THOUSANDS) 1997 --------------------------------------- Future gross revenues................ $1,801,254 $1,002,609 $ 798,645 Future production costs: Lease operating expense......... (604,665) (269,505) (335,160) Future development and abandonment costs.............................. (401,970) (155,179) (246,791) --------- --------- ----------- Future net cash flows before income taxes.............................. 794,619 577,925 216,694 Discount at 10% per annum............ (331,838) (171,764) (160,074) --------- --------- ----------- Discounted future net cash flow before income taxes................ 462,781 406,161 56,620 Future income taxes, net of discount at 10% per annum................... (113,316) (93,386) (19,930) --------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves........ $ 349,465 $ 312,775 $ 36,690 ========= ========= =========== 1996 --------------------------------------- Future gross revenues................ $2,318,113 $1,491,057 $ 827,056 Future production costs: Lease operating expense......... (504,899) (259,501) (245,398) Future development and abandonment costs.............................. (310,839) (126,086) (184,753) --------- --------- ----------- Future net cash flows before income taxes.............................. 1,502,375 1,105,470 396,905 Discount at 10% per annum............ (547,830) (332,343) (215,487) --------- --------- ----------- Discounted future net cash flow before income taxes................ 954,545 773,127 181,418 Future income taxes, net of discount at 10% per annum................... (268,505) (212,906) (55,599) --------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves........ $ 686,040 $ 560,221 $ 125,819 ========= ========= =========== 1995 --------------------------------------- Future gross revenues................ $1,495,320 $ 873,578 $ 621,742 Future production costs: Lease operating expense......... (415,829) (208,477) (207,352) Future development and abandonment costs.............................. (247,019) (119,821) (127,198) --------- --------- ----------- Future net cash flows before income taxes.............................. 832,472 545,280 287,192 Discount at 10% per annum............ (299,997) (144,435) (155,562) --------- --------- ----------- Discounted future net cash flow before income taxes................ 532,475 400,845 131,630 Future income taxes, net of discount at 10% per annum................... (155,330) (104,864) (50,466) --------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves........ $ 377,145 $ 295,981 $ 81,164 ========= ========= =========== 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. 61 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED -- (CONTINUED) 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 escalations 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 and the Kingdom of Thailand, as noted. YEAR ENDED DECEMBER 31, 1997 ------------------------------------ TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND --------- --------- ---------- (EXPRESSED IN THOUSANDS) Beginning balance.................... $ 686,040 $ 560,221 $ 125,819 Revisions to prior years' proved reserves: Net changes in prices and production costs.............. (473,086) (344,493) (128,593) Net changes due to revisions in quantity estimates............ (18,624) 9,619 (28,243) Net changes in estimates of future development costs...... (83,170) (75,649) (7,521) Accretion of discount........... 95,455 77,313 18,142 Changes in production rate...... (2,907) 8,568 (11,475) Other........................... (28,225) (13,086) (15,139) --------- --------- ---------- Total revisions............ (510,557) (337,728) (172,829) New field discoveries and extensions, net of future production and development costs.................. 79,258 76,687 2,571 Purchases of properties.............. 10,189 5,899 4,290 Sales of properties.................. (6,069) (6,069) -- Sales of oil and gas produced, net of production costs................... (221,350) (201,524) (19,826) Previously estimated development costs incurred..................... 156,764 95,768 60,996 Net change in income taxes........... 155,190 119,521 35,669 --------- --------- ---------- Net change in standardized measure of discounted future net cash flows.... (336,575) (247,446) (89,129) --------- --------- ---------- Ending balance....................... $ 349,465 $ 312,775 $ 36,690 ========= ========= ========== 62 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED -- (CONTINUED) YEAR ENDED DECEMBER 31, 1996 ------------------------------------ TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND --------- --------- ---------- (EXPRESSED IN THOUSANDS) Beginning balance....................... $ 377,145 $ 295,981 $ 81,164 Revisions to prior years' proved reserves: Net changes in prices and production costs.............................. 304,233 289,182 15,051 Net changes due to revisions in quantity estimates................. 6,717 53,708 (46,991) Net changes in estimates of future development costs.................. (132,685) (79,791) (52,894) Accretion of discount................. 53,248 40,085 13,163 Changes in production rate............ (59,714) (35,762) (23,952) Other................................. (12,760) (2,831) (9,929) --------- --------- ---------- Total revisions.................... 159,039 264,591 (105,552) New field discoveries and extensions, net of future production and development costs..................... 275,738 173,962 101,776 Sales of oil and gas produced, net of production costs...................... (165,736) (165,736) -- Previously estimated development costs incurred.............................. 153,028 99,464 53,564 Net change in income taxes.............. (113,174) (108,041) (5,133) --------- --------- ---------- Net change in standardized measure of discounted future net cash flows................ 308,895 264,240 44,655 --------- --------- ---------- Ending balance.......................... $ 686,040 $ 560,221 $ 125,819 ========= ========= ========== YEAR ENDED DECEMBER 31, 1995 ------------------------------------ TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND --------- --------- ---------- (EXPRESSED IN THOUSANDS) Beginning balance....................... $ 290,069 $ 257,266 $ 32,803 Revisions to prior years' proved reserves: Net changes in prices and production costs.............................. 34,004 69,988 (35,984) Net changes due to revisions in quantity estimates................. 29,630 26,109 3,521 Net changes in estimates of future development costs.................. (8,632) (36,721) 28,089 Accretion of discount................. 38,298 33,087 5,211 Changes in production rate............ (14,754) (15,792) 1,038 Other................................. (4,393) (432) (3,961) --------- --------- ---------- Total revisions.................... 74,153 76,239 (2,086) New field discoveries and extensions, net of future production and development costs..................... 105,172 71,701 33,471 Purchases of properties................. 29,299 5,160 24,139 Sales of properties..................... (969) (969) -- Sales of oil and gas produced, net of production costs...................... (121,615) (121,615) -- Previously estimated development costs incurred.............................. 63,455 39,461 23,994 Net change in income taxes.............. (62,419) (31,262) (31,157) --------- --------- ---------- Net change in standardized measure of discounted future net cash flows................ 87,076 38,715 48,361 --------- --------- ---------- Ending balance.......................... $ 377,145 $ 295,981 $ 81,164 ========= ========= ========== 63 QUARTERLY RESULTS -- UNAUDITED Summaries of the Company's results of operations by quarter for the years 1997 and 1996 are as follows: QUARTER ENDED ------------------------------------------ MAR. 31 JUNE 30 SEPT. 30 DEC. 31 --------- --------- --------- --------- (EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1997 Revenues............................. $ 61,314 $ 76,740 $ 77,177 $ 71,069 Gross profit(a)...................... $ 27,776 $ 23,953 $ 27,648 $ 20,104 Net income........................... $ 12,818 $ 9,174 $ 7,386 $ 7,738 Earnings per share(b): Basic........................... $ 0.38 $ 0.27 $ 0.22 $ 0.23 Diluted......................... $ 0.36 $ 0.26 $ 0.21 $ 0.22 1996 Revenues............................. $ 48,052 $ 51,543 $ 48,233 $ 56,149 Gross profit(a)...................... $ 17,004 $ 20,011 $ 16,845 $ 25,276 Income before extraordinary loss..... $ 6,265 $ 8,937 $ 6,971 $ 11,408 Extraordinary loss on early extinguishment of debt............. -- $ (821) -- -- Net income........................... $ 6,265 $ 8,116 $ 6,971 $ 11,408 Earnings per share(b): Basic -- Income before extraordinary loss..................... $ 0.19 $ 0.27 $ 0.21 $ 0.34 Extraordinary loss......... -- $ (0.02) -- -- Net income................. $ 0.19 $ 0.25 $ 0.21 $ 0.34 Diluted -- Income before extraordinary loss..................... $ 0.19 $ 0.26 $ 0.20 $ 0.32 Extraordinary loss......... -- $ (0.02) -- -- Net income................. $ 0.19 $ 0.24 $ 0.20 $ 0.32 - ------------ (a) Represents revenues less lease operating, exploration, dry hole and impairment, and depreciation depletion and amortization expenses. (b) Restated for September 30, 1997, and all prior periods ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES. Not applicable. 64 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 28, 1998, to be filed within 120 days of December 31, 1997 pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the Company's "1998 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 1998 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 1998 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 1998 Proxy Statement is 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 1. Financial Statements and Supplementary Data: PAGE ---- Report of Independent Public Accountants.................... 38 Consolidated statements of income....................... 39 Consolidated balance sheets... 40 Consolidated statements of cash flows..................... 41 Consolidated statements of shareholders' equity........... 42 Notes to consolidated financial statements........... 43 Unaudited supplementary financial data................. 58 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. 3. Exhibits:
*3(a) -- Restated Certificate of Incorporation of Pogo Producing Company. (Exhibit e(a), Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-7792). *3(a)(i) -- 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(b) -- Bylaws of Pogo Producing Company, as amended and restated through January 27, 1998. 65 *4(a) -- 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(b) -- 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(c) -- 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(d) -- 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(e) -- 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). *4(f) -- Registration Rights Agreement, dated as of June 18, 1996, by and among the Company, Goldman, Sachs & Co., Merrill Lynch & Co. and Merrill Lynch, Pierce, Fenner & Smith Incorporated. (Exhibit 4(c), Registration Statement on Form S-3 filed September 13, 1996, File No. 333-11927.) *4(g) -- Registration Rights Agreement, dated May 22, 1997, among Pogo Producing Company, Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Goldman, Sachs & Co. (Exhibit 4.4, Registration Statement on Form S-4 filed July 2, 1997, File No. 333-30613.) Pogo Producing Company agrees to furnish to the Commission upon request a copy of any agreement defining the rights of holders of long-term debt of Pogo Producing Company and all its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed under which the total amount of securities authorized does not exceed 10% of the total assets of Pogo Producing Company and its subsidiaries on a consolidated basis. EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (comprising Exhibits 10(a) through 10(d)(ii), inclusive) *10(a) -- 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(a)(1) -- 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(a)(2) -- 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(b) -- 1995 Long-Term Incentive Plan. (Exhibit 4(c), Registration Statement on Form S-8 filed May 22, 1996, File No. 333-04233). *10(c)(1)(i) -- 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(c)(1)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated effective February 1, 1997. (Exhibit 10(g)(1)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No. 001-7792). 66 10(c)(1)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated effective February 1, 1998. *10(c)(2)(i) -- 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(c)(2)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated effective February 1, 1997. (Exhibit 10(g)(2)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No. 001-7792). 10(c)(2)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated effective February 1, 1998. *10(c)(3)(i) -- Executive Employment Agreement by and between Pogo Producing Company and Kenneth R. Good, dated February 1, 1996.(Exhibit 10(f)(3), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792). *10(c)(3)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Kenneth R. Good, dated effective February 1, 1997. (Exhibit 10(g)(3)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No. 001-7792). 10(c)(3)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Kenneth R. Good, dated effective February 1, 1998. *10(c)(4)(i) -- 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(c)(4)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and R. Phillip Laney, dated effective February 1, 1997. (Exhibit 10(g)(4)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No. 001-7792). 10(c)(4)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and R. Phillip Laney, dated effective February 1, 1998. *10(c)(5)(i) -- 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(c)(5)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and John O. McCoy, Jr., dated effective February 1, 1997. (Exhibit 10(g)(5)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No. 001-7792). 10(c)(5)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and John O. McCoy, Jr., dated effective February 1, 1998. *10(c)(6)(i) -- Executive Employment Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated February 1, 1996. (Exhibit 10(f)(6), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792). 67 *10(c)(6)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated effective February 1, 1997. (Exhibit 10(g)(6)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No. 001-7792). 10(c)(6)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated effective February 1, 1998. 10(c)(7)(i) -- Executive Employment Agreement by and between Pogo Producing Company and Bruce E. Archinal, dated as of February 1, 1998. *10(d)(1) -- Excess Benefits Letter Agreement by and between Pogo Producing Company and Kenneth R. Good, dated March 2, 1995. (Exhibit 10(g)(1), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792). *10(d)(2) -- 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(e) -- Limited partnership agreement of Pogo Gulf Coast, Ltd. (Exhibit 19, Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 0-5468). *10(f) -- Bareboat Charter Agreement by and between Tantawan Services, LLC and Tantawan Production B.V., dated as of February 9, 1996. (Exhibit 10(j), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792). *10(g)(i) -- 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(g)(ii) -- 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. *21 -- List of Subsidiaries of Pogo Producing Company (Exhibit 21, Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792). 23(a) -- Consent of Independent Public Accountants. 23(b) -- 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, 1997. 27.1 -- Financial Data Schedule. 27.2 -- Restated Financial Data Schedules for the 1997 Interim periods. 27.3 -- Restated Financial Data Schedules for the 1996 Annual period. 27.4 -- Restated Financial Data Schedule for the 1996 Interim periods. 27.5 -- Restated Financial Data Schedule for the 1995 Annual period.
- ------------ * Asterisk indicates exhibits incorporated by reference as shown. (b) Reports on Form 8-K None 68 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) By: /s/ PAUL G. VAN WAGENEN PAUL G. VAN WAGENEN CHAIRMAN OF THE BOARD, PRESIDENT AND CHIEF EXECUTIVE OFFICER Date: March 17, 1998 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 17, 1998. SIGNATURE TITLE - ------------------------------------- ------------------------------------ /s/PAUL G. VAN WAGENEN Principal Executive PAUL G. VAN WAGENEN Officer and Director CHAIRMAN OF THE BOARD, PRESIDENT AND CHIEF EXECUTIVE OFFICER /s/JOHN W. ELSENHANS Principal Financial JOHN W. ELSENHANS Officer VICE PRESIDENT AND CHIEF FINANCIAL OFFICER /s/THOMAS E. HART Principal Accounting THOMAS E. HART Officer VICE PRESIDENT AND CONTROLLER /s/TOBIN ARMSTRONG* Director TOBIN ARMSTRONG /s/JACK S. BLANTON* Director JACK S. BLANTON /s/W. M. BRUMLEY, JR.* Director W. M. BRUMLEY, JR. /s/JOHN B. CARTER, JR.* Director JOHN B. CARTER, JR. /s/WILLIAM L. FISHER* Director WILLIAM L. FISHER /s/WILLIAM E. GIPSON* Director WILLIAM E. GIPSON 69 SIGNATURES -- (CONTINUED) /s/GERRIT W. GONG* Director GERRIT W. GONG /s/J. STUART HUNT* Director J. STUART HUNT /s/FREDERICK A. KLINGENSTEIN* Director FREDERICK A. KLINGENSTEIN /s/NICHOLAS R. PETRY* Director NICHOLAS R. PETRY /s/JACK A. VICKERS* Director JACK A. VICKERS *By: /s/THOMAS E. HART THOMAS E. HART ATTORNEY-IN-FACT 70 EX-3.B 2 POGO PRODUCING COMPANY BYLAWS (As Amended and Restated) ARTICLE I Meetings of Stockholders Section 1. The annual meeting of the stockholders of this Corporation shall be held on such date and at such time as the Board of Directors shall designate by resolution, or any subsequent day or days to which such meeting may be adjourned, for the purposes of electing directors and of transacting such other business as may properly come before the meeting. The Board of Directors shall fix by resolution the city and the place within such city for the holding of such meeting, and at least ten days notice shall be given to the stockholders of the city and place so fixed. Section 2. Special meetings of the stockholders may be called at any time by the Board of Directors, the Chairman of the Board, the Executive Committee (if any), or the President. Upon written request of any person or persons who have duly called a special meeting, it shall be the duty of the Secretary of the Corporation to fix the date of the meeting to be held not less than ten nor more than sixty days after the receipt of the request and to give due notice thereof. If the Secretary shall neglect or refuse to fix the date of the meeting and give notice thereof, the person or persons calling the meeting may do so. Section 3. Every special meeting of the stockholders shall be held at such place within or without the State of Delaware as the Board of Directors may designate, or, in the absence of such designation, at the registered office of the Corporation in the State of Delaware. Section 4. Written notice of every meeting of the stockholders shall be given by the Secretary of the Corporation to each stockholder of record entitled to vote at the meeting, by placing such notice in the mail at least ten days, but not more than fifty days, prior to the day named for the meeting addressed to each stockholder at his address appearing on the books of the Corporation or supplied by him to the Corporation for the purpose of notice. Section 5. The Board of Directors may fix a date, not less than ten nor more than sixty days preceding the date of any meeting of stockholders, as a record date for the determination of stockholders entitled to notice of, or to vote at, any such meeting. The Board of Directors shall not close the books of the Corporation against transfer of shares during the whole or any part of such period. Section 6. The notice of every meeting of stockholders may be accompanied by a form of proxy approved by the Board of Directors in favor of such person or persons as the Board of Directors may select. Section 7. Except as otherwise provided by law or by the Certificate of Incorporation of the Corporation, as from time to time amended, or by these Bylaws, the presence in person or by proxy of stockholders of the Corporation entitled to cast at least a majority of the votes to be cast thereat shall constitute a quorum at each meeting of the stockholders and all questions shall be decided by majority vote of the shares so presented in person or by proxy at the meeting and entitled to vote thereat. The stockholders present at any duly organized meeting may continue to do business until adjournment, notwithstanding the withdrawal of enough stockholders to leave less than a quorum. Section 8. Any meeting of the stockholders may be adjourned from time to time, without notice other than by announcement at the meeting at which such adjournment is taken, and at any such adjourned meeting at which a quorum shall be present any action may be taken that could have been taken at the meeting originally called; provided that if the adjournment is for more than thirty days, or if after the adjournment a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each stockholder of record entitled to vote at the adjourned meeting. Section 9. Subject to the rights of holders of any class or series of stock having a preference over the Common Stock of the Corporation as to dividends or upon liquidation to elect directors under specified circumstances, nominations of persons for election to the Board of Directors may be made only (a) by the Board of Directors or a committee appointed by the Board of Directors or (b) by any stockholder of the Corporation who is a stockholder of record at the time of giving of the stockholder's notice provided for in this Section 9, who shall be entitled to vote at such meeting and who complies with the notice procedures set forth in this Section 9. For a nomination to be properly made by a stockholder, the stockholder shall have given timely notice of his intention to make such nomination or nominations in writing to the Secretary of the Corporation. To be timely, a stockholder's notice shall be delivered to or mailed and received at the principal executive offices of the Corporation not less than eighty days nor more than one hundred and ten days prior to the date of the meeting of stockholders at which such nomination is to be made; provided, however, that in the event that less than ninety days notice or prior public disclosure of the date of the meeting is given or made to stockholders, notice by the stockholder to be timely received by the Corporation must be so received not later than the close of business on the tenth day following the day on which such notice of the date of the meeting was mailed to stockholders or such public disclosure was made, whichever first occurs. Such stockholder's notice to the Secretary shall set forth: (i) the name and address, as they appear on the Corporation's books, of the stockholder proposing to make 2 such nomination or nominations; (ii) a representation of the stockholder as to the class and number of shares of capital stock of the Corporation which are beneficially owned by such stockholder, and the stockholder's intent to appear in person or by proxy at the meeting to nominate the person or persons specified in the notice; (iii) a description of all arrangements or understandings between the stockholder and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by the stockholder; (iv) the name, age, business address and residence address, business experience or other qualifications of the person or persons to be nominated; (v) the principal occupation or employment of such person or persons; (vi) the class and number of shares of capital stock of the Corporation which are beneficially owned by such person or persons; (vii) such other information regarding each nominee proposed by such stockholder as would be required to be included in a proxy statement filed pursuant to the proxy rules of the Securities and Exchange Commission, had the nominee been nominated, or intended to be nominated, by the Board of Directors; and (viii) the consent of each nominee to serve as a director of the Corporation if so elected. No stockholder nomination shall be effective unless made in accordance with the procedures set forth in this Section 9. The Chairman of the meeting shall, if the facts warrant, determine and declare to the meeting that a stockholder nomination was not made in accordance with the provisions of the Bylaws, and if he should so determine, he shall so declare to the meeting and the defective nomination shall be disregarded. Section 10. At any meeting of stockholders, only such business shall be conducted as shall have been brought before the meeting (a) by or at the direction of the Board of Directors or (b) by any stockholder of the Corporation who is a stockholder of record at the time of giving of the stockholder's notice provided for in this Section 10, who shall be entitled to vote at such meeting and who complies with the notice procedures set forth in this Section 10. For business to be properly brought before a meeting of stockholders by a stockholder, the stockholder shall have given timely notice thereof in writing to the Secretary of the Corporation. To be timely, a stockholder's notice shall be delivered to or mailed and received at the principal executive offices of the Corporation not less than eighty days nor more than one hundred and ten days prior to the date of the meeting at which such business is to be considered; provided, however that in the event that less than ninety days notice or prior public disclosure of the date of the meeting is given or made to stockholders, notice by the stockholder to be timely received by the Corporation must be so received not later than the close of business on the tenth day following the day on which such notice of the date of the meeting was mailed to stockholders or such public disclosure was made, whichever first occurs. Such stockholder's notice to the Secretary shall set forth as to each matter the stockholder proposes to bring before the meeting: (i) a brief description of the business desired to be brought before the meeting: the reasons for conducting such business at the meeting and, in the event that such business includes a proposal to amend either the Certificate of Incorporation or Bylaws of the Corporation, the language of the proposed amendment, (ii) the name and address, as they appear on the Corporation's books, of the stockholder proposing such business, (iii) a representation of the stockholder as to the class and number of shares of capital stock of the Corporation which are beneficially owned by such 3 stockholder, and the stockholder's intent to appear in person or by proxy at the meeting to propose such business and (iv) any material interest of such stockholder in such business. Notwithstanding anything in the Bylaws to the contrary, no business shall be conducted at a stockholders meeting unless brought before the meeting in accordance with the procedures set forth in this Section 10. The Chairman of the meeting shall, if the facts warrant, determine and declare to the meeting that business was not properly brought before the meeting and in accordance with the provisions of the Bylaws, and if he should so determine, he shall so declare to the meeting and any such business not properly brought before the meeting shall not be transacted. Section 11. For purposes of Sections 9 and 10 of these Bylaws, notice of the date of any stockholders' meeting may be included in any (i) report or other communication mailed to stockholders generally or (ii) press release issued by the Corporation. Public disclosure of such date shall be deemed sufficient for such purpose if made in any report filed by the Corporation with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder. Notwithstanding the foregoing provisions of Sections 9 and 10, a stockholder shall also comply with all applicable requirements of the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder with respect to the matters set forth in Sections 9 and 10. ARTICLE II Board of Directors Section 1. The business, affairs and property of the Corporation shall be managed by the Board of Directors. The number of directors shall be no more than twelve, divided into three classes as provided in the Certificate of Incorporation of the Corporation. The directors shall be elected by the stockholders as provided in the Certificate of Incorporation of the Corporation. A director need not be a resident of the State of Delaware or a stockholder of the Corporation. Section 2. Any vacancy in the Board of Directors, including vacancies resulting from an increase in the number of directors, shall be filled by a majority of the remaining members of the Board though less than a quorum, and the person so chosen shall be a director until the next election by the stockholders of the class for which such director shall have been chosen, and until his successor is elected and qualified. Section 3. Regular meetings of the Board of Directors shall be held at such place or places within or without the State of Delaware, at such hour and on such day as may be fixed by resolution of the Board of Directors, without further notice of such meetings. The time or place of holding regular meetings of the Board of Directors may be changed by the Chairman of the Board or the President by giving written notice thereof as provided in Section 5 of this Article II. 4 Section 4. Special meetings of the Board of Directors shall be held, whenever called by the Chairman of the Board, the President, or by a resolution of a majority of the members of the Board of Directors that are then in office, at such place or places within or without the State of Delaware as may be stated in the notice of the meeting. Section 5. Notice of the time and place of all special meetings of the Board of Directors, and notice of any change in the time or place of holding the regular meetings of the Board of Directors, shall be given to each director either personally or by mail, telephone, telegraph or facsimile, at least one day before the day of the meeting; provided, however, that notice of any meeting need not be given to any director if such director signs a written waiver of such notice at any time, or if such director shall be present at such meeting. Section 6. A majority of the directors in office shall constitute a quorum of the Board of Directors for the transaction of business; but a lesser number may adjourn from day to day until a quorum is present. Except as otherwise provided by law or in these Bylaws, all questions shall be decided by the vote of a majority of the directors present. Section 7. Any action which may be taken at a meeting of the directors or members of the Executive Committee may be taken without a meeting if consent in writing setting forth the action so taken shall be signed by all the directors or members of the Executive Committee, as the case may be, and shall be filed with the Secretary of the Corporation. Section 8. No currently sitting member of the Board of Directors may stand for re-election, nor may any other individual stand for election or be appointed to the Board of Directors, if on the date of election or appointment, such individual has reached 71 years of age or older; provided, however, that any properly elected or appointed member of the Board of Directors shall be entitled to serve out the full term to which he was elected or appointed, regardless of the age he reaches during the course of his term. 5 ARTICLE III Executive Committee The Board of Directors may, by resolution adopted by a majority of the whole Board, designate three or more of its number to constitute an Executive Committee which committee, during intervals between meetings of the Board, shall have and exercise the authority of the Board of Directors in the management of the business of the Corporation to the extent permitted by law, including without limitation the power and authority to declare dividends and authorize the issuance of capital stock. ARTICLE IV Officers Section 1. The officers of the Corporation shall consist of a Chairman of the Board, President, Secretary, Treasurer and such Vice Presidents and other officers as may be elected or appointed by the Board of Directors. Any number of offices may be held by the same person. All officers shall hold office until their successors are elected or appointed, except that the Board of Directors may remove any officer at any time at its discretion. Section 2. The officers of the Corporation shall have such powers and duties as generally pertain to their offices, except as modified herein or by the Board of Directors, as well as such powers and duties as from time to time may be conferred by the Board of Directors. The Chairman of the Board shall be the chief executive officer of the Corporation and shall have general supervision of the business, affairs and property of the Corporation and over its several officers, and shall preside at meetings of the Board and at meetings of the stockholders. The President shall be the chief operating officer of the Corporation and shall have such other duties as may be assigned to him by the Board of Directors. ARTICLE V Seal The seal of the Corporation shall be in such form as the Board of Directors shall prescribe. ARTICLE VI Certificates of Stock The shares of the Corporation shall be represented by certificates of stock, signed by the President or such Vice President or other officer designated by the Board of Directors and countersigned by the Treasurer or the Secretary; and if such certificates of stock are signed or countersigned by a transfer agent other than the Corporation, or, by a registrar other than the Corporation, such signature of the President, Vice President, or other officer and such countersignature of the Treasurer or Secretary, or either of them, may be executed in facsimile, engraved or printed. In case any officer who has signed or whose facsimile signature has been placed upon any share certificate shall have ceased to be such officer because of death, resignation or otherwise before the certificate is issued, it may be issued by the Corporation with the same effect as if the officer had not 6 ceased to be such at the date of its issue. Said certificates of stock shall be in such form as the Board of Directors may from time to time prescribe. ARTICLE VII Indemnification Section 1. Right to Indemnification. The Corporation shall indemnify and hold harmless, to the fullest extent permitted by applicable law as it presently exists or may hereafter be amended, any person who was or is made or is threatened to be made a party or is otherwise involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative (a "proceeding") by reason of the fact that he, or a person for whom he is the legal representative, is or was a director, officer, employee or agent of the Corporation or is or was serving at the request of the Corporation as a director, officer, employee, fiduciary or agent of another corporation or of a partnership, joint venture, trust, enterprise or non-profit entity including service with respect to employee benefit plans, against all liability and loss suffered and expenses reasonably incurred by such person. The Corporation shall indemnify a person in connection with a proceeding initiated by such person only if the proceeding was authorized by the Board of Directors of the Corporation. Section 2. Prepayment of Expenses. The Corporation shall pay the expenses incurred in defending any proceeding in advance of its final disposition, provided, however, that the payment of expenses incurred by a director or officer in his capacity as a director or officer (except with regard to service to an employee benefit plan or non-profit organizations in advance of the final disposition of the proceeding) shall be made only upon receipt of an undertaking by the director or officer to repay all amounts advanced if it should be ultimately determined that the director or officer is not entitled to be indemnified under this Article or otherwise. Section 3. Claims. If a claim for indemnification or payment of expenses under this Article is not paid in full within ninety days after a written claim therefor has been received by the Corporation the claimant may file suit to recover the unpaid amount of such claim and, if successful in whole or in part, shall be entitled to be paid the expense of prosecuting such claim. In any such action the Corporation shall have the burden of proving that the claimant was not entitled to the requested indemnification or payment of expenses under applicable law. Section 4. Non-Exclusivity of Rights. The rights conferred on any person by this Article shall not be exclusive of any other rights which such person may have or hereafter acquire under any statute, provision of the Certificate of Incorporation, these Bylaws, agreement, vote of stockholders or disinterested directors or otherwise. 7 Section 5. Amendment or Repeal. Any repeal or modification of the foregoing provisions of this Article VII shall not adversely affect any right or protection hereunder of any person in respect of any act or omission occurring prior to the time of such repeal or modification. ARTICLE VIII Amendments These Bylaws may be altered, amended, added to or repealed by the stockholders at any annual or special meeting, by the vote of stockholders entitled to cast at least a majority of the vote which all stockholders are entitled to cast, and, except as may be otherwise required by law, the power to alter, amend, add to or repeal these Bylaws is also vested in the Board of Directors, acting by a majority vote of the members of the Board of Directors in office (subject always to the power of the stockholders to change such action); provided, however, that notice of the general nature of any such action proposed to be taken shall be included in the notice of the meeting of stockholders or of the Board of Directors at which such action is taken. Amended and restated in full: 04/22/97 Article II amended by adding Section 8: 01/27/98 8 EX-10.C.1.III 3 EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT BETWEEN STUART P. BURBACH ("EXECUTIVE") AND POGO PRODUCING COMPANY, A DELAWARE CORPORATION ("COMPANY"), DATED EFFECTIVE FEBRUARY 1, 1998 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1996; and WHEREAS, February 1, 1998, (even date herewith) is hereby deemed to be the "Renewal Date" in that Employment Agreement; and WHEREAS, Executive and Company each wish to extend said Employment Agreement for an additional one-year period so as to terminate (unless further extended) two years thereafter, (to-wit January 31, 2000); and WHEREAS, Company desires to retain the services of Executive for the benefit of Company and its shareholders, and desires to induce Executive to remain in its employ for that extended time period; and WHEREAS, Executive has agreed to continue to serve as an employee of Company for the period specified herein from and after the date of this Extension Agreement; an WHEREAS, Company and Executive desire to enter into this Extension Agreement in order to formally secure for Company the benefit of the experience and abilities of Executive, and to set forth the agreements and understandings of Company and Executive; and WHEREAS, Company has advised Executive that execution and performance of this Extension Agreement by Company has been duly authorized and approved by all requisite corporate action on the part of the Company. NOW, THEREFORE, in consideration of the foregoing and the mutual promises and agreements herein contained, and in consideration of the sum of $10 paid by Company to Executive, receipt whereof is hereby acknowledged by Executive, Executive and Company do hereby agree as follows: 1. The Employment Agreement between Executive and Company bearing an "Effective Date" of February 1, 1996 and a "Renewal Date" which is deemed herein to be February 1, 1998, is hereby extended for an additional one-year period commencing February 1, 1998 and ending January 31, 2000, unless such employ ment period is hereafter further extended for an additional period by both Executive and Company. 2. All provisions of the Employment Agreement between Executive and Company dated as of February 1, 1996, and as it is herein amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1998. POGO PRODUCING COMPANY By: /s/ JOHN O. MCCOY, JR. ----------------------------- Senior Vice President and Chief Administrative Officer ATTEST: /s/ JOE ANN KINGDON - ---------------------------- Assistant Corporate Secretary EMPLOYEE: /s/ STUART P. BURBACH ---------------------------- EX-10.C.2.III 4 EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT BETWEEN JERRY A. COOPER ("EXECUTIVE") AND POGO PRODUCING COMPANY, A DELAWARE CORPORATION ("COMPANY"), DATED EFFECTIVE FEBRUARY 1, 1998 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1996; and WHEREAS, February 1, 1998, (even date herewith) is hereby deemed to be the "Renewal Date" in that Employment Agreement; and WHEREAS, Executive and Company each wish to extend said Employment Agreement for an additional one-year period so as to terminate (unless further extended) two years thereafter, (to-wit January 31, 2000); and WHEREAS, Company desires to retain the services of Executive for the benefit of Company and its shareholders, and desires to induce Executive to remain in its employ for that extended time period; and WHEREAS, Executive has agreed to continue to serve as an employee of Company for the period specified herein from and after the date of this Extension Agreement; ad WHEREAS, Company and Executive desire to enter into this Extension Agreement in order to formally secure for Company the benefit of the experience and abilities of Executive, and to set forth the agreements and understandings of Company and Executive; and WHEREAS, Company has advised Executive that execution and performance of this Extension Agreement by Company has been duly authorized and approved by all requisite corporate action on the part of the Company. NOW, THEREFORE, in consideration of the foregoing and the mutual promises and agreements herein contained, and in consideration of the sum of $10 paid by Company to Executive, receipt whereof is hereby acknowledged by Executive, Executive and Company do hereby agree as follows: 1. The Employment Agreement between Executive and Company bearing an "Effective Date" of February 1, 1996 and a "Renewal Date" which is deemed herein to be February 1, 1998, is hereby extended for an additional one-year period commencing February 1, 1998 and ending January 31, 2000, unless such employ ment period is hereafter further extended for an additional period by both Executive and Company. 2. All provisions of the Employment Agreement between Executive and Company dated as of February 1, 1996, and as it is herein amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1998. POGO PRODUCING COMPANY By: /s/ JOHN O. MCCOY, JR. ----------------------------- Senior Vice President and Chief Administrative Officer ATTEST: /s/ JOE ANN KINGDON - ---------------------------- Assistant Corporate Secretary EMPLOYEE: /s/ JERRY A. COOPER ---------------------------- EX-10.C.3.III 5 EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT BETWEEN KENNETH R. GOOD ("EXECUTIVE") AND POGO PRODUCING COMPANY, A DELAWARE CORPORATION ("COMPANY"), DATED EFFECTIVE FEBRUARY 1, 1998 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1996; and WHEREAS, February 1, 1998, (even date herewith) is hereby deemed to be the "Renewal Date" in that Employment Agreement; and WHEREAS, Executive and Company each wish to extend said Employment Agreement for an additional one-year period so as to terminate (unless further extended) two years thereafter, (to-wit January 31, 2000); and WHEREAS, Company desires to retain the services of Executive for the benefit of Company and its shareholders, and desires to induce Executive to remain in its employ for that extended time period; and WHEREAS, Executive has agreed to continue to serve as an employee of Company for the period specified herein from and after the date of this Extension Agreement; ad WHEREAS, Company and Executive desire to enter into this Extension Agreement in order to formally secure for Company the benefit of the experience and abilities of Executive, and to set forth the agreements and understandings of Company and Executive; and WHEREAS, Company has advised Executive that execution and performance of this Extension Agreement by Company has been duly authorized and approved by all requisite corporate action on the part of the Company. NOW, THEREFORE, in consideration of the foregoing and the mutual promises and agreements herein contained, and in consideration of the sum of $10 paid by Company to Executive, receipt whereof is hereby acknowledged by Executive, Executive and Company do hereby agree as follows: 1. The Employment Agreement between Executive and Company bearing an "Effective Date" of February 1, 1996 and a "Renewal Date" which is deemed herein to be February 1, 1998, is hereby extended for an additional one-year period commencing February 1, 1998 and ending January 31, 2000, unless such employ ment period is hereafter further extended for an additional period by both Executive and Company. 2. All provisions of the Employment Agreement between Executive and Company dated as of February 1, 1996, and as it is herein amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1998. POGO PRODUCING COMPANY By: /s/ JOHN O. MCCOY, JR. ----------------------------- Senior Vice President and Chief Administrative Officer ATTEST: /s/ JOE ANN KINGDON - ---------------------------- Assistant Corporate Secretary EMPLOYEE: /s/ KENNETH R. GOOD ---------------------------- EX-10.C.4.III 6 EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT BETWEEN R. PHILLIP LANEY ("EXECUTIVE") AND POGO PRODUCING COMPANY, A DELAWARE CORPORATION ("COMPANY"), DATED EFFECTIVE FEBRUARY 1, 1998 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1996; and WHEREAS, February 1, 1998, (even date herewith) is hereby deemed to be the "Renewal Date" in that Employment Agreement; and WHEREAS, Executive and Company each wish to extend said Employment Agreement for an additional one-year period so as to terminate (unless further extended) two years thereafter, (to-wit January 31, 2000); and WHEREAS, Company desires to retain the services of Executive for the benefit of Company and its shareholders, and desires to induce Executive to remain in its employ for that extended time period; and WHEREAS, Executive has agreed to continue to serve as an employee of Company for the period specified herein from and after the date of this Extension Agreement; ad WHEREAS, Company and Executive desire to enter into this Extension Agreement in order to formally secure for Company the benefit of the experience and abilities of Executive, and to set forth the agreements and understandings of Company and Executive; and WHEREAS, Company has advised Executive that execution and performance of this Extension Agreement by Company has been duly authorized and approved by all requisite corporate action on the part of the Company. NOW, THEREFORE, in consideration of the foregoing and the mutual promises and agreements herein contained, and in consideration of the sum of $10 paid by Company to Executive, receipt whereof is hereby acknowledged by Executive, Executive and Company do hereby agree as follows: 1. The Employment Agreement between Executive and Company bearing an "Effective Date" of February 1, 1996 and a "Renewal Date" which is deemed herein to be February 1, 1998, is hereby extended for an additional one-year period commencing February 1, 1998 and ending January 31, 2000, unless such employ ment period is hereafter further extended for an additional period by both Executive and Company. 2. All provisions of the Employment Agreement between Executive and Company dated as of February 1, 1996, and as it is herein amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1998. POGO PRODUCING COMPANY By: /s/ JOHN O. MCCOY, JR. ----------------------------- Senior Vice President and Chief Administrative Officer ATTEST: /s/ JOE ANN KINGDON - ---------------------------- Assistant Corporate Secretary EMPLOYEE: /s/ R. PHILLIP LANEY ---------------------------- EX-10.C.5.III 7 EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT BETWEEN JOHN O. MCCOY, JR. ("EXECUTIVE") AND POGO PRODUCING COMPANY, A DELAWARE CORPORATION ("COMPANY"), DATED EFFECTIVE FEBRUARY 1, 1998 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1998; and WHEREAS, February 1, 1998, (even date herewith) is hereby deemed to be the "Renewal Date" in that Employment Agreement; and WHEREAS, Executive and Company each wish to extend said Employment Agreement for an additional one-year period so as to terminate (unless further extended) two years thereafter, (to-wit January 31, 2000); and WHEREAS, Company desires to retain the services of Executive for the benefit of Company and its shareholders, and desires to induce Executive to remain in its employ for that extended time period; and WHEREAS, Executive has agreed to continue to serve as an employee of Company for the period specified herein from and after the date of this Extension Agreement; and WHEREAS, Company and Executive desire to enter into this Extension Agreement in order to formally secure for Company the benefit of the experience and abilities of Executive, and to set forth the agreements and understandings of Company and Executive; and WHEREAS, Company has advised Executive that execution and performance of this Extension Agreement by Company has been duly authorized and approved by all requisite corporate action on the part of the Company. NOW, THEREFORE, in consideration of the foregoing and the mutual promises and agreements herein contained, and in consideration of the sum of $10 paid by Company to Executive, receipt whereof is hereby acknowledged by Executive, Executive and Company do hereby agree as follows: 1. The Employment Agreement between Executive and Company bearing an "Effective Date" of February 1, 1996 and a "Renewal Date" which is deemed herein to be February 1, 1998, is hereby extended for an additional one-year period commencing February 1, 1998 and ending January 31, 2000, unless such employ ment period is hereafter further extended for an additional period by both Executive and Company. 2. All provisions of the Employment Agreement between Executive and Company dated as of February 1, 1996, and as it is herein amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1998. POGO PRODUCING COMPANY By: /s/ PAUL G. VAN WAGENEN ----------------------------- Chairman of the Board, President and Chief Executive Officer ATTEST: /s/ JOE ANN KINGDON - ---------------------------- Assistant Corporate Secretary EMPLOYEE: /s/ JOHN O. MCCOY, JR. ------------------------- EX-10.C.6.III 8 EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT BETWEEN PAUL G. VAN WAGENEN ("EXECUTIVE") AND POGO PRODUCING COMPANY, A DELAWARE CORPORATION ("COMPANY"), DATED EFFECTIVE FEBRUARY 1, 1998 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1996; and WHEREAS, February 1, 1998, (even date herewith) is hereby deemed to be the "Renewal Date" in that Employment Agreement; and WHEREAS, Executive and Company each wish to extend said Employment Agreement for an additional one-year period so as to terminate (unless further extended) two years thereafter, (to-wit January 31, 2000); and WHEREAS, Company desires to retain the services of Executive for the benefit of Company and its shareholders, and desires to induce Executive to remain in its employ for that extended time period; and WHEREAS, Executive has agreed to continue to serve as an employee of Company for the period specified herein from and after the date of this Extension Agreement; ad WHEREAS, Company and Executive desire to enter into this Extension Agreement in order to formally secure for Company the benefit of the experience and abilities of Executive, and to set forth the agreements and understandings of Company and Executive; and WHEREAS, Company has advised Executive that execution and performance of this Extension Agreement by Company has been duly authorized and approved by all requisite corporate action on the part of the Company. NOW, THEREFORE, in consideration of the foregoing and the mutual promises and agreements herein contained, and in consideration of the sum of $10 paid by Company to Executive, receipt whereof is hereby acknowledged by Executive, Executive and Company do hereby agree as follows: 1. The Employment Agreement between Executive and Company bearing an "Effective Date" of February 1, 1996 and a "Renewal Date" which is deemed herein to be February 1, 1998, is hereby extended for an additional one-year period commencing February 1, 1998 and ending January 31, 2000, unless such employ ment period is hereafter further extended for an additional period by both Executive and Company. 2. All provisions of the Employment Agreement between Executive and Company dated as of February 1, 1996, and as it is herein amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1998. POGO PRODUCING COMPANY By: /s/ JOHN O. MCCOY, JR. ----------------------------- Senior Vice President and Chief Administrative Officer ATTEST: /s/ JOE ANN KINGDON - ---------------------------- Assistant Corporate Secretary EMPLOYEE: /s/ PAUL G. VAN WAGENEN -------------------------------- EX-10.C.7.I 9 EXECUTIVE EMPLOYMENT AGREEMENT AGREEMENT by and between POGO PRODUCING COMPANY, a Delaware corporation (the "Company") and BRUCE E. ARCHINAL (the "Executive"), dated as of the 1st day of February, 1998. The Board of Directors of the Company (the "Board"), has determined that it is in the best interests of the Company and its shareholders to assure that the Company will have the continued dedication of the Executive, and to provide the Executive with compensation and benefits arrangements which are competitive with those of other corporations and which ensure that the compensation and benefits expectations of the Executive will be satisfied. The Board also believes it is imperative to diminish the inevitable distraction of the Executive by virtue of the personal uncertainties and risks created by a pending or threatened Change of Control and to encourage the Executive's full attention and dedication to the Company currently and in the event of any threatened or pending Change of Control, and to insure the continuation of favorable compensation and benefits upon a Change of Control. Therefore, in order to accomplish these objectives, the Board has caused the Company to enter into this Agreement. NOW, THEREFORE, IT IS HEREBY AGREED AS FOLLOWS; 1. CERTAIN DEFINITIONS. (a) The "Effective Date" shall mean the date of this Agreement. (b) The "Employment Period" shall mean the period commencing on the Effective Date and ending on the second anniversary of such date; provided, however, that on each annual anniversary of the Effective Date (the "Renewal Date"), the Employment Period shall be reviewed, to determine whether, in the discretion of the Company, it should be extended for one additional year so as to terminate two years from such Renewal Date. Any such one year extension shall be effective only if, prior to the Renewal Date, the Company shall give notice to the Executive that the Employment Period shall be so extended. 2. CHANGE OF CONTROL. For the purpose of this Agreement, a "Change of Control" shall mean: (a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act") (a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (i) the then outstanding shares of common stock of the Company (the "Outstanding Company Common Stock") or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Outstanding Company Voting Securities"). Notwithstanding anything in this Agreement to the contrary, the following shall not constitute a Change of Control: (i) any acquisition directly from the Company (excluding an acquisition by virtue of the exercise of a conversion privilege), (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company, or (iv) any acquisition by State Farm Mutual Automobile Insurance Company and certain affiliates ("State Farm") or Klingenstein, Fields & Co., L.P. ("Klingenstein") ("Specified Stockholders") of beneficial ownership of Outstanding Company Voting Securities resulting in an accumulation of said securities up to and including the following amounts: A. In the case of State Farm, 30% of Outstanding Voting Securities, and B. In the case of Klingenstein, 30% of Outstanding Voting Securities, or (v) any acquisition by any corporation pursuant to a reorganization, merger or consolidation, if, following such reorganization, merger or consolidation, the conditions described in clauses (i), (ii) and (iii) of subsection (c) of this Section 2 are satisfied; or (b) Individuals who, as of the date hereof, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company's shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of either an actual or threatened election contest (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or (c) Approval by the shareholders of the Company of a reorganization, merger or consolidation, in each case, unless, following such reorganization, merger or consolidation, i) more than 60% of, respectively, the then outstanding shares of common stock of the corporation resulting from such reorganization, merger or consolidation and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially -2- all of the individuals and entities who where the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such reorganization, merger or consolidation in substantially the same proportions as their ownership, immediately prior to such reorganization, merger or consolidation, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) no Person [excluding the Company, any Specified Stockholder, any employee benefit plan (or related trust) of the Company or such corporation resulting from such reorganization, merger or consolidation and any Person beneficially owning, immediately prior to such reorganization, merger or consolidation, directly or indirectly, 20% or more of the Outstanding Company Common Stock or Outstanding Voting Securities, as the case may be] beneficially owns, directly or indirectly, 20% or more, respectively, of the then outstanding shares of common stock of the corporation resulting from such reorganization, merger or consolidation or the combined voting power of the then outstanding voting securities of such corporation, entitled to vote generally in the election of directors and (iii) at least a majority of the members of the board of directors of the corporation resulting from such reorganization, merger or consolidation were members of the Incumbent Board at the time of the execution of the initial agreement providing for such reorganization, merger or consolidation; or (d) Approval by the shareholders of the Company of (i) a complete liquidation or dissolution of the Company or (ii) the sale or other disposition of all or substantially all of the assets of the Company, other than to a corporation with respect to which following such sale or other disposition (A) more than 60% of, respectively, the then outstanding shares of common stock of such corporation and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such sale or other disposition in substantially the same proportion as their ownership, immediately prior to such sale or other disposition, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (B) no Person [excluding the Company, any Specified Stockholder, any employee benefit plan (or related trust) of the Company or such corporation and any Person beneficially owning, immediately prior to such sale or other disposition, directly or indirectly, 20% or more of the Outstanding Company Common Stock or Outstanding Company Voting Securities, as the case may be] beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of such corporation and the combined voting power of the then outstanding voting securities of such corporation entitled to vote generally in the election of directors and (C) at least a majority of the members of the board of directors of such corporation where members of the Incumbent Board at the time of the execution of the initial agreement or action of the Board providing for such sale or other disposition of assets of the Company. -3- 3. EMPLOYMENT AGREEMENT. The Company hereby agrees to continue the Executive in its employ in accordance with the terms and provisions of this Agreement, for the Employment Period. 4. TERMS OF EMPLOYMENT. (a) POSITION AND DUTIES. (i) During the Employment Period, (A) the Executive's position (including status, offices, titles and reporting requirements), authority, duties and responsibilities shall be at least commensurate in all material respects with the most significant of those held, exercised and assigned at any time during the 90- day period immediately preceding the later of the Effective Date, the most recent Renewal Date or a Change of Control, if any, (the "Applicable Date") and (B) the Executive's services shall be performed at the location where the Executive was employed immediately preceding the Applicable Date or any office which is the headquarters of the Company and is less than 35 miles from such location. (ii) During the Employment Period, and excluding any periods of vacation and sick leave to which the Executive is entitled, the Executive agrees to devote reasonable attention and time during normal business hours to the business and affairs of the Company. During the Employment Period it shall not be a violation of this Agreement for the Executive to (A) serve on corporate, civic or charitable boards or committees, (B) deliver lectures, fulfill speaking engagements or teach at educational institutions and (C) manage personal investments, so long as such activities do not significantly interfere with the performance of the Executive's responsibilities as an employee of the Company in accordance with this Agreement; provided Executive may not serve on the board of a publicly traded for profit corporation or similar body of a publicly traded for profit business organized in other than corporate form without the consent of the Compensation Committee of the Board of Directors of the Company. It is expressly understood and agreed that to the extent that any such activities have been conducted by the Executive prior to the Applicable Date, the continued conduct of such activities (or the conduct of activities similar in nature and scope thereto) subsequent to the Applicable Date shall not thereafter be deemed to interfere with the performance of the Executive's responsibilities to the Company. (b) COMPENSATION. (i) BASE SALARY. During the Employment Period, the Executive shall receive an annual base salary ("Annual Base Salary"), which shall be paid on a monthly basis, at least equal to twelve times the highest monthly base salary paid or payable to the Executive by the Company and its affiliated companies in respect of the twelve-month period immediately preceding the month in which the Applicable Date occurs. During the Employment Period, the Annual Base Salary shall be reviewed at least annually and may be increased at any time and from time to time as shall be substantially consistent with increases in base salary generally awarded in the ordinary course of business to other executives of the Company and its affiliated companies. Any increase in Annual Base Salary shall not serve to limit or reduce any other obligation to the Executive under this Agreement. As used in this Agreement, the term "affiliated companies" shall include any company controlled by, controlling or under common control with the Company. -4- (ii) ANNUAL BONUS. In addition to Annual Base Salary, the Executive may be awarded at the discretion of the Company for any fiscal year ending during the Employment Period, a bonus. (iii) INCENTIVE, SAVINGS AND RETIREMENT PLANS. During the Employment Period, the Executive shall be entitled to participate in all incentive, savings and retirement plans, practices, policies and programs applicable generally to other executives of the Company and its affiliated companies. Such plans, practices, policies and programs shall provide the Executive with incentive opportunities (measured with respect to both regular and special incentive opportunities, to the extent, if any, that such distinction is applicable), savings opportunities and retirement benefit opportunities, in each case, equal to the most favorable of those provided by the Company and its affiliated companies for the Executive under such plans, practices, policies and programs as in effect at any time during the 90-day period immediately preceding the Applicable Date. (iv) WELFARE BENEFIT PLANS. During the Employment Period, the Executive and/or the Executive's family, as the case may be, shall be eligible for participation in and shall receive all benefits under welfare benefit plans, practices, policies and programs provided by the Company and its affiliated companies (including, without limitation, medical, prescription, dental, disability, salary continuance, employee life, group life, accidental death and travel accident insurance plans and programs) to the extent applicable generally to other executives of the Company and its affiliated companies. Such plans, practices, policies and programs shall provide the Executive with benefits which are equal, in the aggregate, to the most favorable of such plans, practices, policies and programs in effect for the Executive at any time during the 90-day period immediately preceding the Applicable Date. (v) EXPENSES. During the Employment Period, the Executive shall be entitled to receive prompt reimbursement for all reasonable expenses incurred by the Executive in accordance with the most favorable policies, practices and procedures of the Company and its affiliated companies in effect for the Executive at any time during the 90-day period immediately preceding the Applicable Date. (vi) FRINGE BENEFITS. During the Employment Period, the Executive shall be entitled to fringe benefits in accordance with the most favorable plans, practices, programs and policies of the Company and its affiliated companies in effect for the Executive at any time during the 90-day period immediately preceding the Applicable Date. (vii) OFFICE AND SUPPORT STAFF. During the Employment Period, the Executive shall be entitled to an office or offices of a size and with furnishings and other appointments, and to personal secretarial and other assistance, at least equal to the most favorable of the foregoing provided to the Executive by the Company and its affiliated companies at any time during the 90-day period immediately preceding the Applicable Date. -5- (viii) VACATION. During the Employment Period, the Executive shall be entitled to paid vacation in accordance with the most favorable plans, policies, programs and practices of the Company and its affiliated companies as in effect for the Executive at any time during the 90-day period immediately preceding the Applicable Date. 5. TERMINATION OF EMPLOYMENT. (a) DEATH OR DISABILITY. The Executive's employment shall terminate automatically upon the Executive's death during the Employment Period. If the Company determines in good faith that the Disability of the Executive has occurred during the Employment Period (pursuant to the definition of Disability set forth below), it may give to the Executive written notice in accordance with Section 12(c) of this Agreement of its intention to terminate the Executive's employment. In such event, the Executive's employment with the Company shall terminate effective on the 30th day after receipt of such notice by the Executive (the "Disability Effective Date"), provided that, within the 30 days after such receipt, the Executive shall not have returned to full-time performance of the Executive's duties. For purposes of this Agreement, "Disability" shall mean the absence of the Executive from the Executive's duties with the Company on a full-time basis for 180 consecutive business days as a result of incapacity due to mental or physical illness which is determined to be total and permanent by a physician selected by the Company or its insurers and acceptable to the Executive or the Executive's legal representative (such agreement as to acceptability not to be withheld unreasonably). (b) CAUSE. The Company may terminate the Executive's employment during the Employment Period for Cause. For purposes of this Agreement, "Cause" shall mean (i) a material violation by the Executive of the Executive's obligations under Section 4(a) of this Agreement (other than as a result of incapacity due to physical or mental illness) which is willful and deliberate on the Executive's part, which is committed in bad faith or without reasonable belief that such violation is in the best interests of the Company and which is not remedied in a reasonable period of time after receipt of written notice from the Company specifying such violation or (ii) the conviction of the Executive of a felony involving moral turpitude. (c) GOOD REASON; WINDOW PERIOD; OTHER TERMINATIONS. The Executive's employment may be terminated (i) during the Employment Period by the Executive for Good Reason, (ii) during the Window Period by the Executive without any reason or (iii) by Executive other than (A) for Good Reason or (B) during a Window Period. For purposes of this Agreement, the "Window Period" shall mean the 180-day period immediately following the date a Change of Control occurs. Anything in this Agreement to the contrary notwithstanding, if a Change of Control occurs and if the Executive's employment with the Company is terminated prior to the date on which the Change of Control occurs, and if it is reasonably demonstrated by the Executive that such termination of employment or cessation of status as an officer (i) was at the request of a third party who has taken steps reasonably calculated to effect the Change of Control or (ii) otherwise arose in connection with or anticipation of the Change of Control, then for all purposes of this Agreement the "date a Change -6- of Control occurs" shall mean the date immediately prior to the date of such termination of employment or cessation of status as an officer. For purposes of this Agreement, "Good Reason" shall mean (i) the assignment to the Executive of any duties inconsistent with the Executive's position (including status, offices, titles and reporting requirements), authority, duties or responsibilities as contemplated by Section 4(a) of this Agreement, or any other action by the Company which results in a diminution in such position, authority, duties or responsibilities excluding for this purpose an insubstantial or inadvertent action which is remedied by the Company promptly after receipt of notice thereof given by the Executive; (ii) any failure by the Company to comply with any of the provisions of Section 4(b) of this Agreement, other than an insubstantial or inadvertent failure which is remedied by the Company promptly after receipt of notice thereof given by the Executive; (iii) the Company's requiring the Executive to be based at any office or location other than that described in Section 4(a)(i)(B) hereof; (iv) any purported termination by the Company of the Executive's employment otherwise than as expressly permitted by this Agreement; or (v) any failure by the Company to comply with and satisfy Section 11(c) of this Agreement. (d) NOTICE OF TERMINATION. Any termination by the Company for Cause, or by the Executive without any reason during the Window Period or for Good Reason, shall be communicated by Notice of Termination to the other party hereto given in accordance with Section 12(c) of this Agreement. For purposes of this Agreement, a "Notice of Termination" means a written notice which (i) indicates the specific termination provision in this Agreement relied upon, (ii) to the extent applicable, sets forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Executive's employment under the provision so indicated and (iii) if the Date of Termination (as defined below) is other than the date of receipt of such notice, specifies the termination date (which date shall be not more than fifteen days after the giving of such notice). The failure by the Executive or the Company to set forth in the Notice of Termination any fact or circumstance which contributes to a showing of Good Reason or Cause shall not waive any right of the Executive or the Company hereunder or preclude the Executive or the Company from asserting such fact or circumstance in enforcing the Executive's or the Company's right hereunder. (e) DATE OF TERMINATION. "Date of Termination" means (i) if the Executive's employment is terminated by the Company for Cause, or by the Executive during the Window Period or for Good Reason, the date of receipt of the Notice of Termination or any later date -7- specified therein, as the case may be, (ii) if the Executive's employment is terminated by the Company other than for Cause or Disability, the Date of Termination shall be the date on which the Company notifies the Executive of such termination, (iii) if the Executive's employment is terminated by reason of death or Disability, the Date of Termination shall be the date of death of the Executive or the Disability Effective Date, as the case may be, and (iv) if the Executive's employment is terminated by the Executive other than for Good Reason or during a Window Period, the date of the receipt of the Notice of Termination or any later date specified therein. 6. OBLIGATIONS OF THE COMPANY UPON TERMINATION. (a) GOOD REASON OR DURING THE WINDOW PERIOD; OTHER THAN FOR CAUSE, DEATH OR DISABILITY. If, during the Employment Period, the Company shall terminate the Executive's employment other than for Cause or Disability or the Executive shall terminate employment either for Good Reason or without any reason during the Window Period: (i) the Company shall pay to the Executive in a lump sum in cash within 30 days after the Date of Termination the aggregate of the following amounts: A. the sum of (1) the Executive's Annual Base Salary through the Date of Termination to the extent not theretofore paid and (2) any compensation previously deferred by the Executive (together with any accrued interest or earnings thereon) and any accrued vacation pay, in each case to the extent not theretofore paid (the sum of the amounts described in clauses (1) and (2) shall be hereinafter referred to as the "Accrued Obligations"); and B. the amount (such amount shall be hereinafter referred to as the "Severance Amount") equal to the product of (1) three and (2) the sum of (x) the Executive's Annual Base Salary and (y) any bonus described in Section 4(b)(ii) paid or payable in respect of the most recently completed fiscal year of the Company; and, provided further, that such amount shall be reduced by the present value (determined as provided in Section 280G(d)(4) of the Internal Revenue Code of 1986, as amended (the "Code")) of any other amount of severance relating to salary or bonus continuation to be received by the Executive upon termination of employment of the Executive under any severance plan, severance policy or severance arrangement of the Company; and C. a separate lump sum supplemental retirement benefit equal to the difference between (1) the actuarial equivalent (utilizing for this purpose the actuarial assumptions utilized with respect to the Employees Retirement Plan for Pogo Producing Company (or any successor plan thereto) (the "Retirement Plan") during the 90-day period immediately preceding the Applicable Date) of the benefit payable under the Retirement Plan and any supplemental and/or excess retirement plan of the Company and its affiliated companies providing benefits for the Executive (the "SERP") which the Executive would receive if the Executive's employment continued at the compensation level provided for in Sections 4(b)(i) and 4(b)(ii) of this Agreement for the remainder of the Employment Period, assuming for this -8- purpose that all accrued benefits are fully vested and that benefit accrual formulas are no less advantageous to the Executive than those in effect during the 90- day period immediately preceding the Applicable Date, and (2) the actuarial equivalent (utilizing for this purpose the actuarial assumptions utilized with respect to the Retirement Plan during the 90-day period immediately preceding the Applicable Date) of the Executive's actual benefit (paid or payable), if any, under the Retirement Plan and the SERP (the amount of such benefit shall be hereinafter referred to as the "Supplemental Retirement Amount"); and (ii) for the remainder of the Employment Period, or such longer period as any plan, program, practice or policy may provide, the Company shall continue benefits to the Executive and/or the Executive's family at least equal to those which would have been provided to them in accordance with the plans, programs, practices and policies described in Section 4(b)(iv) of this Agreement if the Executive's employment had not been terminated in accordance with the most favorable plans, practices, programs or policies of the Company and its affiliated companies as in effect and applicable generally to other executives and their families during the 90-day period immediately preceding the Applicable Date, provided, however, that if the Executive becomes reemployed with another employer and is eligible to receive medical or other welfare benefits under another employer provided plan, the medical and other welfare benefits described herein shall be secondary to those provided under such other plan during such applicable period of eligibility (such continuation of such benefits for the applicable period herein set forth shall be hereinafter referred to as "Welfare Benefit Continuation"). For purposes of determining eligibility of the Executive for retiree benefits pursuant to such plans, practices, programs and policies, the Executive shall be considered to have remained employed until the end of the Employment Period and to have retired on the last day of such period; and (iii) to the extent not theretofore paid or provided, the Company shall timely pay or provide to the Executive and/or the Executive's family any other amounts or benefits required to be paid or provided or which the Executive and/or the Executive's family is eligible to receive pursuant to this Agreement and under any plan, program, policy or practice or contract or agreement of the Company and its affiliated companies as in effect and applicable generally to other executives and their families during the 90-day period immediately preceding the Applicable Date (such other amounts and benefits shall be hereinafter referred to as the "Other Benefits"). (b) DEATH. If the Executive's employment is terminated by reason of the Executive's death during the Employment Period, this Agreement shall terminate without further obligations to the Executive's legal representatives under this Agreement, other than for (i) payment of Accrued Obligations (which shall be paid to the Executive's estate or beneficiary, as applicable, in a lump sum in cash within 30 days of the Date of Termination) and the timely payment or provision of the Welfare Benefit Continuation and Other Benefits and (ii) payment to the Executive's estate or beneficiary, as applicable, in a lump sum in cash within 30 days of the Date of Termination of an amount equal to the sum of the Severance Amount and the Supplemental Retirement Amount. -9- (c) DISABILITY. If the Executive's employment is terminated by reason of the Executive's Disability during the Employment Period, this Agreement shall terminate without further obligations to the Executive, other than for (i) payment of Accrued Obligations (which shall be paid to the Executive in a lump sum in cash within 30 days of the Date of Termination) and the timely payment or provision of the Welfare Benefit Continuation and Other Benefits (excluding, in each case, Disability Benefits (as defined below)) and (ii) payment to the Executive in a lump sum in cash within 30 days of the Date of Termination of an amount equal to the greater of (A) the sum of the Severance Amount and the Supplemental Retirement Amount and (B) the present value (determined as provided in Section 280G(d)(4) of the Code) of any cash amount to be received by the Executive as a disability benefit pursuant to the terms of any long term disability plan, policy or arrangement of the Company and its affiliated companies, but not including any proceeds of disability insurance covering the Executive to the extent paid for on a contributory basis by the Executive (which shall be paid in any event as an Other Benefit) (the benefits included in this clause (B) shall be hereinafter referred to as the "Disability Benefits"). (d) Cause; By Executive Other than for Good Reason And Other Than During a Window Period. If the Executive's employment shall be terminated for Cause during the Employment Period, this Agreement shall terminate without further obligations to the Executive other than the obligation to pay to the Executive Annual Base Salary through the Date of Termination plus the amount of any compensation previously deferred by the Executive, in each case to the extent theretofore unpaid. If the Executive terminates employment during the Employment Period, excluding a termination either for Good Reason or without any reason during the Window Period, this Agreement shall terminate without further obligations to the Executive, other than for Accrued Obligations and the timely payment or provision of Other Benefits. In such case, all Accrued Obligations shall be paid to the Executive in a lump sum in cash within 30 days of the Date of Termination. 7. NON-EXCLUSIVITY OF RIGHTS. Except as provided in Section 6(a)(ii), 6(b) and 6(c) of this Agreement, nothing in this Agreement shall prevent or limit the Executive's continuing or future participation in any plan, program, policy or practice provided by the Company or any of its affiliated companies and for which the Executive may qualify, nor shall anything herein limit or otherwise affect such rights as the Executive may have under any contract or agreement with the Company or any of its affiliated companies. Amounts which are vested benefits or which the Executive is otherwise entitled to receive under any plan, policy, practice or program of or any contract or agreement with the Company or any of its affiliated companies at or subsequent to the Date of Termination shall be payable in accordance with such plan, policy, practice or program or contract or agreement except as explicitly modified by this Agreement. 8. FULL SETTLEMENT; RESOLUTION OF DISPUTES. (a) The Company's obligation to make payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Company may have against the Executive or others. In no event shall the Executive be obligated to seek other employment or take any other action by way of mitigation of the amounts -10- payable to the Executive under any of the provisions of this Agreement and, except as provided in Section 6(a)(ii) of this Agreement, such amounts shall not be reduced whether or not the Executive obtains other employment. If there is any contest by the Company concerning the Payments or benefits to be provided to the Executive hereunder whether through litigation, arbitration or mediation, or with respect to the validity or enforceability of, or liability under, any provision of this Agreement or any guarantee of performance thereof, and the Executive is the prevailing party, the Company agrees to pay promptly upon conclusion of the contest all legal fees and expenses which the Executive may reasonably have incurred. (b) If there shall be any dispute between the Company and the Executive (i) in the event of any termination of the Executive's employment by the Company, whether such termination was for Cause, or (ii) in the event of any termination of employment by the Executive, whether Good Reason existed, then, unless and until there is a final, nonappealable judgment by a court of competent jurisdiction declaring that such termination was for Cause or that Good Reason did not exist, the Company shall pay all amounts, and provide all benefits, to the Executive and/or the Executive's family or other beneficiaries, as the case may be, that the Company would be required to pay or provide pursuant to Section 6(a) hereof as though such termination were by the Company without Cause or by the Executive with Good Reason; provided, however, that the Company shall not be required to pay any disputed amounts pursuant to this paragraph except upon receipt of an undertaking (which need not be secured) by or on behalf of the Executive to repay all such amounts to which the Executive is ultimately adjudged by such court not to be entitled. 9. CERTAIN ADDITIONAL PAYMENTS BY THE COMPANY. (a) Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any payment or distribution by the Company to or for the benefit of the Executive (whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise, but determined without regard to any additional payments required under this Section 9) (a "Payment") would be subject to the excise tax imposed by Section 4999 of the Code or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then the Executive shall be entitled to receive an additional payment (a "Gross-Up Payment") in an amount such that after payment by the Executive of all taxes (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Gross-Up Payment, the Executive retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments. (b) Subject to the provisions of Section 9(c), all determinations required to be made under this Section 9, including whether and when Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at such determination, shall be made by Arthur Andersen LLP (the "Accounting Firm") which shall provide detailed supporting calculations both to the Company and the Executive within 15 -11- business days of the receipt of notice from the Executive that there has been a Payment, or such earlier time as is requested by the Company. In the event that the Accounting Firm is serving as accountant or auditor for the individual, entity or group effecting the Change of Control, the Executive shall appoint another nationally recognized accounting firm to make the determinations required hereunder (which accounting firm shall then be referred to as the Accounting Firm hereunder). All fees and expenses of the Accounting Firm shall be borne solely by the Company. Any Gross-Up Payment, as determined pursuant to this Section 9, shall be paid by the Company to the Executive within five days of the receipt of the Accounting Firm's determination. If the Accounting Firm determines that no Excise Tax is payable by the Executive, it shall furnish the Executive with a written opinion that failure to report the Excise Tax on the Executive's applicable federal income tax return would not result in the imposition of a negligence or similar penalty. Any determination by the Accounting Firm shall be binding upon the Company and the Executive. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that Gross-Up Payments which will not have been made by the Company should have been made ("Underpayment"), consistent with the calculations required to be made hereunder. In the event that the Company exhausts its remedies pursuant to Section 9(c) and the Executive thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Executive. (c) The Executive shall notify the Company in writing of any claims by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than ten business days after the Executive is informed in writing of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Executive shall not pay such claim prior to the expiration of the 30-day period following the date on which it gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Executive in writing prior to the expiration of such period that it desires to contest such claim, the Executive shall: (i) give the Company any information reasonably requested by the Company relating to such claim, (ii) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company, (iii) cooperate with the Company in good faith in order effectively to contest such claim, and -12- (iv) permit the Company to participate in any proceedings relating to such claim; provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Executive harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of costs and expenses. Without limitation on the foregoing provisions of this Section 9(c), the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forego any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Executive to pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and the Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Executive to pay such claim and sue for a refund, the Company shall advance the amount of such payment to the Executive, on an interest-free basis and shall indemnify and hold the Executive harmless, on an after-tax basis, from any Excise Tax or income tax (including interest or penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Executive with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company's control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority. (d) If, after the receipt by the Executive of an amount advanced by the Company pursuant to Section (c), the Executive becomes entitled to receive any refund with respect to such claim, the Executive shall (subject to the Company's complying with the requirements of Section 9(c)) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Executive of an amount advanced by the Company pursuant to Section 9(c), a determination is made that the Executive shall not be entitled to any refund with respect to such claim and the Company does not notify the Executive in writing of its intent to contest such denial of refund prior to the expiration of 30 days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall be offset, to the extent thereof, the amount of Gross-Up Payment required to be paid. 10. CONFIDENTIAL INFORMATION. The Executive shall hold in a fiduciary capacity for the benefit of the Company all secret or confidential information, knowledge or data relating to the Company or any of its affiliated companies, and their respective businesses, which shall have been obtained by the Executive during the Executive's employment by the Company or any of its affiliated companies and which shall not be or become public knowledge (other than by acts by -13- the Executive or representatives of the Executive in violation of this Agreement). After termination of the Executive's employment with the Company, the Executive shall not, without the prior written consent of the Company or as may otherwise be required by law or legal process, communicate or divulge any such information, knowledge or data to anyone other than the Company and those designated by it. In no event shall an asserted violation of the provisions of this Section 10 constitute a basis for deferring or withholding any amounts otherwise payable to the Executive under this Agreement. 11. SUCCESSORS. (a) This Agreement is personal to the Executive and without the prior written consent of the Company shall not be assignable by the Executive otherwise than by will or the laws of descent and distribution. This Agreement shall inure to the benefit of and be enforceable by the Executive's legal representatives. (b) This Agreement shall inure to the benefit of and be binding upon the Company and its successors and assigns. (c) The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to assume expressly and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. As used in this Agreement, "Company" shall mean the Company as hereinbefore defined and any successor to its business and/or assets as aforesaid which assumes and agrees to perform this Agreement by operation of law, or otherwise. 12. MISCELLANEOUS. (a) This Agreement shall be an unfunded obligation of the Company. (b) THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, WITHOUT REFERENCE TO PRINCIPLES OF CONFLICT OF LAWS. The captions of this Agreement are not part of the provisions hereof and shall have no force or effect. This Agreement may not be amended or modified otherwise than by a written agreement executed by the parties hereto or their respective successors and legal representatives. (c) All notices and other communications hereunder shall be in writing and shall be given by hand delivery to the other party or by registered or certified mail, return receipt requested, postage prepaid, addressed as follows: IF TO THE EXECUTIVE: Bruce E. Archinal 4 Coralvine Court Woodlands, Texas 77380 -14- IF TO THE COMPANY: Pogo Producing Company P.O. Box 2504 Houston, Texas 77252-2504 Attention: Chief Administrative Officer or to such other address as either party shall have furnished to the other in writing in accordance herewith. Notice and communications shall be effective when actually received by the addressee. (d) The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement. (e) The Company may withhold from any amounts payable under this Agreement such Federal, state or local taxes as shall be required to be withheld pursuant to any applicable law or regulation. (f) The Executive's or the Company's failure to insist upon strict compliance with any provision hereof or any other provision of this Agreement or the failure to assert any right the Executive or the Company may have hereunder, including, without limitation, the right of the Executive to terminate employment for Good Reason pursuant to Section 5(c)(i)-(v) of this Agreement, shall not be deemed to be a waiver of such provision or right or any other provision or right of this Agreement. -15- IN WITNESS WHEREOF, the Executive has hereunto set the Executive's hand and, pursuant to the authorization from its Board of Directors, the Company has caused these presents to be executed in its name on its behalf, all as of the day and year first above written. EMPLOYEE By /s/ BRUCE E. ARCHINAL ------------------------------ POGO PRODUCING COMPANY By /s/ JOHN O. MCCOY, JR. ------------------------------ -16- EX-10.G.II 10 THE FIRST AMENDMENT TO THE GAS SALES AGREEMENT BETWEEN PETROLEUM AUTHORITY OF THAILAND AND B8/32 PARTNERS LIMITED THAIPO LIMITED THAI ROMO LIMITED PALANG SOPHON LIMITED NOVEMBER 12, 1997 THE FIRST AMENDMENT TO THE GAS SALES AGREEMENT (the GSA) dated November 7th, 1995, is hereby made this November 12th, 1997. BETWEEN (1) PETROLEUM AUTHORITY OF THAILAND, having its principal office at 555 Vibhavadi Rangsit Road, Bangkok 10900 (hereinafter called "PTT"); (2) THAIPO LIMITED, a company duly incorporated and existing under the laws of Thailand and having its registered office at 18th Floor, B.B. Building, 54 Asoke Road, Sukhumvit 21, Bangkok 10110 (hereinafter called "THAIPO"); (3) THAI ROMO LIMITED, a company duly incorporated and existing under the laws of Thailand and having its registered office at 19th floor, B.B. Building, 54 Asoke Road, Sukhumvit 21, Bangkok 10110 (hereinafter called "THAI ROMO"); (4) PALANG SOPHON LIMITED, a company duly incorporated and existing under the laws of Thailand and having its registered office at 19th floor, B.B. Building, 54 Asoke Road, Sukhumvit 21, Bangkok 10110 (hereinafter called "SOPHON"); and (5) B8/32 PARTNERS LIMITED, a company duly incorporated and existing under the laws of Thailand and having its registered office at 19th floor, B.B. Building, 54 Asoke Road, Sukhumvit 21, Bangkok 10110 (hereafter called "B8/32 PARTNERS"). THAIPO, THAI ROMO AND SOPHON hereinafter all collectively called "Original Concessionaire" WHEREAS: (A) The Original Concessionaire has indicated to PTT that additional Natural Gas has been found in the Concession Area at the Benchamas/Pakakrong Fields as defined in the First Schedule, Part II, as hereinafter amended, and that such Natural Gas can be developed in conjunction with the Natural Gas being developed in the Tantawan Field in the GSA Area; (B) The parties involved at the Benchamas/Pakakrong Fields include B8/32 PARTNERS who is not and Original Concessionaire under the GAS; (C) The Original Concessionaire has indicated to PTT that they and the B8/32 Partners wish to sell the Natural Gas from the Benchamas/Pakakrong Fields to PTT and PTT has indicated its willingness to purchase Natural Gas from the Benchamas/Pakakrong Fields. -2- NOW IT IS HEREBY AGREED AS FOLLOWS THAT THE GSA SHALL BE AMENDED BY THIS FIRST AMENDMENT TO REFLECT: 1. That the Concessionaire under the GSA shall include, as of the effective date of this First Amendment, B8/32 Partners. 2. That recital (A) of the GSA shall be amended by the addition of the following words: "and on the fourth (4th day of September, 1995, the Supplementary Petroleum Concession No. 2 to Petroleum Concession 1/2534/36;" 3. That Clause 1.5 of the GSA shall be amended by the addition of the following words; "and Supplementary Petroleum Concession No. 2 to Petroleum Concession No. 1/2534/36, dated September 4, 1995." 4. That Clause 1.19 of the GSA shall be amended by the addition of the following words: "Delivery Point shall include either Delivery Points described in the amended Fourth Schedule or both Delivery Points as the context requires." 5. That Clause 1.25 shall be amended to read "GSA Area means that part of the Concessionaire Area described in the First Schedule, as amended by the First Amendment Part II, and dedicated to the service of the GSA." 6. That Clause 4.1 (line 1) the "Delivery Point" shall be amended to read the "Delivery Points." 7. That Clause 5.1 the "Delivery Point" (lines 1 and 4) shall be amended to read the "Delivery Points." 8. That Clause 6.3 shall be amended to read as follows; "An initial Run-In Period shall follow the Date of Commencement of Delivery (DCD) and a run-in Period shall also commence the effective date of each increase in the DCQ pursuant to Subclause 6.6(iv); and such Run-In Period shall terminate at the earlier of the completion of the seventy-two (72) hour test or three (3) months. The first day following the initial Run-In Period shall be referred to as the Contractual Delivery Date (CDD). The Run-In Period shall be for the purpose of proving the facilities required for the performance of the initial obligations of both the Concessionaire and PTT and during such Run-In Period both the Concessionaire and PTT shall use reasonable endeavours respectively to deliver and take Sales Gas." 9. That Clause 6.3(I) shall be amended by the deletion of the first paragraph and the addition of the following paragraph: -3- "The Concessionaire shall, during the run in period, complete a test of seventy-two (72) consecutive hours. During the run-in period, concessionaire shall notify PTT that the Concessionaire is ready to attempt a seventy-two (72) hour test and PTT shall nominate the rate of delivery in accordance with Clause 6.12 and the Concessionaire shall offer continuously to PTT Sales Gas of quality and at pressure consistent with the PTT nomination. If the Concessionaire is unable, for whatever reason other than PTT's inability to take, to complete the continuous seventy-two (72) hour period, the test shall be restarted after the Concessionaire notifies PTT of its desire to restart the seventy-two (72) hour test: 10. That Subclause 6.3(I) shall be amended the last paragraph to read as follows: "During the initial run in period, sales gas shall be paid for at a price of seventy-five (75) percent of current price as calculated. During all other run-in periods sales gas delivered in excess of the DCQ immediately preceding the increased DCQ referred to in Subclause 6.6(iv) shall be paid for at a price of seventy-five (75) percent of Current Price as calculated." 11. That subclause 6.6(ii) shall be amended by the addition of the following sentence; "In no event, shall the DCQ be less than 125 million cubic feet." 12. That Subclause 6.6(iii) shall be amended to change "one hundred and twenty-five (125) to three hundred (300). 13. That subclause 6.6(iv) shall be amended by the addition of the following paragraph: "Notwithstanding the above paragraph, the date of commencement for the run in period for the DCQ, including the reserves from Benchamas/Pakakrong Fields, shall be the date of completion of the facilities necessary for Concessionaire to produce gas from the Benchamas/Pakakrong Fields, which date shall be August 1, 1999. Such date may be adjusted by up to 60 days by Concessionaire informing PTT twelve (12) months in advance of the date of commencement for the run in period. The DCQ, as determined under Clause 6.6 (ii) above, shall become effective the date following the day the Concessionaire successfully completes the seventy-two (72) hour test or two (2) months from the date of commencement of the run-in period, whichever is earlier." 14. That Clause 6.17 shall be amended to change "eighty-five (85)" to "one hundred twenty-five (125)." -4- 15. That Article VII shall be amended by the addition of the following paragraph: . "The Concessionaire or PTT, as mutually agreed, shall be responsible for the building and testing of the pipeline for the delivery of Benchamas/Pakakrong Field Sales Gas to the PTT 24-inch pipeline. The cost and expense incurred in the design, procurement, fabrication, installation, testing and commissioning of the pipeline shall be shared by the Concessionaire and PTT on a 65/35 basis respectively." 16. That Clause 10.3, the last word of second paragraph shall be amended to change "earlier" to "later." 17. That Clause 14.3 shall be amended to include the words "at the relevant Delivery Point" immediately after the words "delivery Sales Gas" and the word "relevant" added ahead of "Delivery Point." 18. That subject to confirmation and acceptance by PTT that the combined Field Reserves of the Tantawan and Benchamas/Pakakrong Fields equals or exceed file hundred (500) billion cubic feet, Clauses 15.7 and 18.5 shall no longer have any cause or effect. 19. That Clause 25.4 shall be amended by changing "The Sophonpalnich Co., Ltd." To read "Palang Sophon Limited," with the following change of address: Palang Sophon Limited 19th floor, B.B. Building Asoke Road, Sukhumvit 21 Bangkok 10110, Thailand Fax No. 662-260-7247 Tel. No. 662-260-7310 20. That Clause 25.4 shall be amended to include: B8/32 PARTNERS LIMITED 18th Floor, B.B. Building Asoke Road Bangkok 10110 Thailand Fax No. 662-260-7150 Tel No. 662-260-7151 21. That the First Schedule Part II shall be amended to include those parts of the Concession Area containing the Benchamas/Pakakrong Field. Such amended schedule is attached to this First Amendment as First Schedule Part II GSA Area (First Amendment). -5- 22. That the Second Schedule: MERCURY: NIL shall be amended to read "MERCURY: contain not more than 50 micrograms per cubic meter (by weight) with 12 months to rectify any excess amount." 23. That the Fourth Schedule shall be amended by changing "single delivery point" to "two delivery points" in the first paragraph and in the second paragraph changing "Delivery Point" to "Tantawan Delivery Point." 24. That at the end of the Fourth Schedule a new paragraph will be added to state: "The Benchamas/Pakakrong Delivery Point shall be agreed between Concessionaire and PTT within 120 days of the Effective Date of this First Amendment. If additional time is required to agree and confirm a mutually acceptable location, both parties agree to use reasonable endeavours to promptly achieve and confirm an acceptable location." 25. That the Fifth Schedule (Parental Guarantee) attached to this First Amendment is a Parental Guarantee of performance under the GSA for B8/32 Partners. 26. The provisions of this Amendment shall constitute a supplement to the GSA. To the extent that there is any conflict or inconsistency between the terms of the GSA and the terms of this First Amendment, the terms of this First Amendment shall prevail. 27. Except as amended hereby the GSA shall remain in full force and effect. 28. This First Amendment shall be governed by and construed in accordance with the laws of Thailand. 29. This First Amendment shall be effective from the execution date. -6- IN WITNESS WHEREOF this First Amendment has been signed by the duly authorized representatives of the parties on the day and year first above written. /s/ P. SOOHAWERT /s/ ILLEGIBLE - -------------------------------- ------------------------------- Signed for and on behalf of Witness PETROLEUM AUTHORITY OF THAILAND /s/ JEFF SEVERIN /s/ ILLEGIBLE - -------------------------------- ------------------------------- Signed for and on behalf of Witness THAIPO LIMITED /s/ THOMAS E. RANKIN /s/ ILLEGIBLE - -------------------------------- ------------------------------- Signed for and on behalf of Witness THAI ROMO LIMITED /s/ ILLEGIBLE /s/ SUNEE P. - -------------------------------- ------------------------------- Signed for and on behalf of Witness PALANG SOPHON LIMITED /s/ JEFF SEVERIN /s/ RATTIKAN C. - -------------------------------- ------------------------------- Signed for and on behalf of Witness B8/32 PARTNERS LTD. -7- ATTACHMENTS: First Schedule Part II Fifth Schedule -8- POINT LATITUDE LONGITUDE CODE DEG MINS SEC DEG MINS SEC - ---- ------------- ------------- A 10 18 00.00"N 101 24 00.0"E B 10 18 00.00"N Intersecting with the Declared Cambodian Continental Shelf (1972) C 10 16 50.00"N 101 29 30.0"E D 10 09 00.00"N 101 30 00.0"E E 10 09 00.00"N 101 27 00.0"E F 10 00 00.00"N 101 28 20.0"E G 10 00 00.00"N 101 24 00.0"E BENCHAMAS/PAKAKRONG FIELD: POINT LATITUDE LONGITUDE CODE DEG MINS SEC DEG MINS SEC A 10 39 00.00"N 101 14 00.0"E B 10 31 00.00"N 101 14 00.0"E C 10 31 00.00"N 101 12 00.0"E D 10 28 00.00"N 101 12 00.0"E E 10 28 00.00"N 101 11 30.0"E F 10 21 30.00"N 101 11 30.0"E G 10 21 30.00"N 101 14 00.0"E H 10 22 00.00"N 101 14 00.0"E I 10 22 00.00"N 101 16 00.0"E J 10 22 30.00"N 101 16 00.0"E K 10 22 30.00"N 101 20 00.0"E L 10 39 00.00"N 101 20 00.0"E PARENTAL GUARANTEE November 7, 1997 TO PETROLEUM AUTHORITY OF THAILAND Dear Sirs: In consideration of your entering into an Agreement with B8/32 Partners Limited and others for the purchase from them of natural gas on the terms and conditions therein mentioned, we guarantee the due performance by B8/32 Partners Limited of all its obligations under the said Agreement. Yours faithfully, THAI ROMO HOLDINGS, INC. /s/ DAVID F. CHAVENSON By: David F. Chavenson Vice President POGO PRODUCING COMPANY /s/ RONALD B. MANNING By: Ronald B. Manning Vice President PALANG SOPHON LTD. /s/ SIRITAS PRASERT-MANUKITCH /s/ CHOTE S. By: Siritas Prasert-Manukitch Chote Sophonpanich President Director EX-23.A 11 EXHIBIT 23(a) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 13, 1998 included in this Annual Report on Form 10-K, into Pogo Producing Company's previously filed Registration Statement File Nos. 33-54969, 333- 04233, 333-11927 and 333-30613. /s/ ARTHUR ANDERSEN LLP ------------------------------- ARTHUR ANDERSEN LLP Houston, Texas March 17, 1998 EX-23.B 12 EXHIBIT 23(b) CONSENT OF INDEPENDENT PETROLEUM ENGINEERS As independent petroleum engineers, we hereby consent to the use of our name in the Annual Report of Form 10-K for the year ended December 31, 1997. We further consent to the inclusion of our estimate of reserves and present value of future net reserves in such Annual Report. /s/ RYDER SCOTT COMPANY PETROLEUM ENGINEERS RYDER SCOTT COMPANY PETROLEUM ENGINEERS Houston, Texas March 17, 1998 EX-24 13 POWER OF ATTORNEY I TOBIN ARMSTRONG, in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ TOBIN ARMSTRONG ------------------------- Tobin Armstrong POWER OF ATTORNEY I JACK S. BLANTON, in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ JACK S. BLANTON ------------------------- Jack S. Blanton POWER OF ATTORNEY I W. M. BRUMLEY, JR., in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ W. M. BRUMLEY, JR. ------------------------- W. M. Brumley, Jr. POWER OF ATTORNEY I JOHN B. CARTER, JR., in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ JOHN B. CARTER, JR. ------------------------- John B. Carter, Jr. POWER OF ATTORNEY I WILLIAM L. FISHER, in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ WILLIAM L. FISHER ------------------------- William L. Fisher POWER OF ATTORNEY I WILLIAM E. GIPSON, in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ WILLIAM E. GIPSON ------------------------- William E. Gipson POWER OF ATTORNEY I GERRIT W. GONG, in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ GERRIT W. GONG ------------------------- Gerrit W. Gong POWER OF ATTORNEY I J. STUART HUNT, in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ J. STUART HUNT ------------------------- J. Stuart Hunt POWER OF ATTORNEY I FREDERICK A. KLINGENSTEIN, in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ FREDERICK A. KLINGENSTEIN ------------------------- Frederick A. Klingenstein POWER OF ATTORNEY I NICHOLAS R. PETRY, in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ NICHOLAS R. PETRY ------------------------- Nicholas R. Petry POWER OF ATTORNEY I JACK A. VICKERS, in my individual capacity and as a director of Pogo Producing Company (the "Company"), do hereby appoint PAUL G. VAN WAGENEN and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the other, and with full power of substitution and resubstitution, to prepare, execute and file, in my name, place and stead in my individual capacity and as a director of the Company, such documents, reports and filings as may be necessary or advisable under the Securities Exchange Act of 1934, as amended (the "Act"), the Securities Act of 1933, as amended (the "Securities Act") or any other federal, state or local law regulating the Company including, without limitation, the Company's Annual Report of Form 10-K for the fiscal year ended December 31, 1997, as prescribed by the Securities and Exchange Commission (the "Commission") pursuant to the Act, and the rules and regulations promulgated thereunder, with any and all exhibits and other documents relating thereto, any and all amendments to said Annual Report and all instruments as said attorneys or any of them shall deem necessary or incidental in connection therewith and to file the same with the Commission. Each of said attorneys shall have full power and authority to do and perform in my name and on my behalf any act whatsoever to accomplish the purpose and intent of the forgoing that said attorneys deem may be necessary or desirable to be done in the premises as fully and to all intents and purposes as I might or could do in person, and by my signature hereto, I hereby ratify and approve any and all of such acts of said attorneys and each of them. IN WITNESS WHEREOF, I have executed this instrument on this 27TH day of JANUARY, 1998. /s/ JACK A. VICKERS ------------------------- Jack A. Vickers EX-27.1 14
5 THIS FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENTS OF POGO PRODUCING COMPANY, INCLUDING THE CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 1997 AND THE CONSOLIDATED STATEMENTS OF INCOME FOR THE TWELVE MONTHS ENEDED DECEMBER 31, 1997, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH CONSOLIDATED FINANCIAL STATEMENTS. 1,000 12-MOS DEC-31-1997 DEC-31-1997 19,646 0 86,491 0 9,047 119,271 1,444,667 917,363 676,617 110,172 348,179 0 0 33,553 112,553 676,617 285,200 286,300 63,501 63,501 144,730 0 21,886 55,207 18,091 37,116 0 0 0 37,116 1.11 1.06 This amount is not disclosed on the face of the Consolidated Financial Statements due to the lack of materiality, but is included as a contra-asset in Accounts Recievable. Does not include Gains or Losses on Property Sales. Includes Lease Operating Expense, but excludes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. Includes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. This amount is not disclosed on the face of the Consolidated Financial Statements due to a lack of materiality, but is included in Oil and Gas Revenues.
EX-27.2 15
5 THIS FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) OF POGO PRODUCING COMPANY, INCLUDING THE CONSOLIDATED BALANCE SHEETS AS OF THE END OF EACH OF THE PERIODS INDICATED AND THE CONSOLIDATED STATEMENTS OF INCOME FOR EACH OF THE PERIODS INDICATED, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH CONSOLIDATED FINANCIAL STATEMENTS. 1,000 3-MOS 6-MOS 9-MOS DEC-31-1996 DEC-31-1996 DEC-31-1996 MAR-31-1997 JUN-30-1997 SEP-30-1997 9,586 23,505 12,444 0 0 0 77,105 76,791 91,215 0 0 0 8,725 14,145 14,006 95,630 115,542 118,715 1,268,236 1,304,047 1,352,568 832,826 861,875 889,752 552,832 585,022 608,088 55,056 46,336 61,210 306,230 338,205 340,199 0 0 0 0 0 0 33,379 33,396 33,544 86,859 95,217 105,662 552,832 585,022 608,088 61,314 136,595 213,913 61,314 138,054 215,231 12,297 28,488 45,116 12,297 28,488 45,116 27,077 68,794 106,484 0 0 0 4,295 9,831 15,771 19,571 33,700 45,072 6,753 11,708 15,694 12,818 21,992 29,378 0 0 0 0 0 0 0 0 0 12,818 21,992 29,378 0.38 0.66 0.88 0.36 0.62 0.83 This amount is not disclosed on the face of the Consolidated Financial Statements due to the lack of materiality, but is included as a contra-asset in Accounts Recievable. Does not include Gains or Losses on Property Sales. Includes Lease Operating Expense, but excludes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. Includes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. This amount is not disclosed on the face of the Consolidated Financial Statements due to a lack of materiality, but is included in Oil and Gas Revenues.
EX-27.3 16
5 THIS FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENTS OF POGO PRODUCING COMPANY, INCLUDING THE CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 1996 AND THE CONSOLIDATED STATEMENTS OF INCOME FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1996, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH CONSOLIDATED FINANCIAL STATEMENTS. 1,000 12-MOS DEC-31-1996 DEC-31-1996 3,054 0 65,058 0 6,165 74,918 1,199,488 814,623 479,242 68,247 246,230 0 0 33,321 73,961 479,242 204,142 203,977 37,628 37,628 105,241 0 13,203 52,381 18,800 33,581 0 (821) 0 32,760 0.99 0.95 This amount is not disclosed on the face of the Consolidated Financial Statements due to the lack of materiality, but is included as a contra-asset in Accounts Recievable. Does not include Gains or Losses on Property Sales. Includes Lease Operating Expense, but excludes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. Includes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. This amount is not disclosed on the face of the Consolidated Financial Statements due to a lack of materiality, but is included in Oil and Gas Revenues.
EX-27.4 17
5 THIS FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) OF POGO PRODUCING COMPANY, INCLUDING THE CONSOLIDATED BALANCE SHEETS AS OF THE END OF EACH OF THE PERIODS INDICATED CONSOLIDATED STATEMENTS OF INCOME FOR EACH OF THE PERIODS INDICATED, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH CONSOLIDATED FINANCIAL STATEMENTS. 1,000 3-MOS 6-MOS 9-MOS DEC-31-1995 DEC-31-1995 DEC-31-1995 MAR-31-1996 JUN-30-1996 SEP-30-1996 12,369 18,835 5,512 0 0 0 44,130 52,224 46,398 0 0 0 8,040 8,074 9,007 64,805 80,598 61,986 1,030,107 1,062,407 1,110,753 771,078 787,674 803,154 338,137 372,604 388,057 35,626 29,399 35,712 171,249 202,550 206,230 0 0 0 0 0 0 33,143 33,214 33,276 46,384 54,668 62,548 338,137 372,604 388,057 48,217 99,760 147,993 48,052 99,595 147,828 8,875 18,080 27,756 8,875 18,080 27,756 27,594 54,304 79,946 0 0 0 3,012 6,184 9,491 9,412 22,996 33,733 3,147 7,794 11,560 6,265 15,202 22,173 0 0 0 0 (821) (821) 0 0 0 6,265 14,381 21,352 0.19 0.44 0.65 0.19 0.42 0.63 This amount is not disclosed on the face of the Consolidated Financial Statements due to the lack of materiality, but is included as a contra-asset in Accounts Recievable. Does not include Gains or Losses on Property Sales. Includes Lease Operating Expense, but excludes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. Includes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. This amount is not disclosed on the face of the Consolidated Financial Statements due to a lack of materiality, but is included in Oil and Gas Revenues.
EX-27.5 18
5 THIS FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENTS OF POGO PRODUCING COMPANY, INCLUDING THE CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 1995 AND THE CONSOLIDATED STATEMENTS OF INCOME FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1995, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH CONSOLIDATED FINANCIAL STATEMENTS. 1,000 12-MOS DEC-31-1995 DEC-31-1995 4,481 0 52,324 0 6,438 63,965 1,019,572 757,739 338,177 51,317 163,249 0 0 33,007 38,701 338,177 157,459 157,559 35,071 35,071 99,060 0 11,167 14,121 4,891 9,230 0 0 0 9,230 0.28 0.28 This amount is not disclosed on the face of the Consolidated Financial Statements due to the lack of materiality, but is included as a contra-asset in Accounts Recievable. Does not include Gains or Losses on Property Sales. Includes Lease Operating Expense, but excludes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. Includes General and Administrative, Exploration, Dry Hole and Impairment and Depreciation, Depletion and Amortization Expenses. This amount is not disclosed on the face of the Consolidated Financial Statements due to a lack of materiality, but is included in Oil and Gas Revenues.
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