-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, SPEjzJWqMTiWgknryYitHbhkCKWeYvgyu2MIflpdWIIsvPREHURwDSJ2YhWeWyCF jUsH8THgbJh8SvKCi012Gw== 0000890566-94-000050.txt : 19940302 0000890566-94-000050.hdr.sgml : 19940302 ACCESSION NUMBER: 0000890566-94-000050 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 15 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940228 FILER: COMPANY DATA: COMPANY CONFORMED NAME: POGO PRODUCING CO CENTRAL INDEX KEY: 0000230463 STANDARD INDUSTRIAL CLASSIFICATION: 1311 IRS NUMBER: 741659398 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-07792 FILM NUMBER: 94513478 BUSINESS ADDRESS: STREET 1: 5 GREENWAY PLAZA STE 2700 STREET 2: P O BOX 2504 CITY: HOUSTON STATE: TX ZIP: 77046 BUSINESS PHONE: 7136514300 FORMER COMPANY: FORMER CONFORMED NAME: PENNZOIL OFFSHORE GAS OPERATORS INC /TX/ DATE OF NAME CHANGE: 19600201 10-K 1 ANNUAL REPORT PERIOD ENDING 12/31/93 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, 1993 / / 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 HOUSTON, TEXAS 77252-2504 ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) Registrant's telephone number, including area code: (713) 297-5000 Securities registered pursuant to Section 12(b) of the Act: TITLE OF EACH CLASS: NAME OF EACH EXCHANGE ON WHICH REGISTERED: Common Stock, $1 par value New York Stock Exchange Pacific Stock Exchange 8% Convertible Subordinated New York Stock Exchange Debentures Due December 31, 2005 Securities registered pursuant to Section 12(g) of the Act: None Indicate by checkmark 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 preceeding 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 $561,037,000 as of February 24, 1994 (based on $19.00 per share, the last sale price of the Common Stock as reported on the New York Stock Exchange Composite Tape on such date). 32,542,952 shares of the registrant's Common Stock were outstanding as of February 24, 1994. DOCUMENT INCORPORATED BY REFERENCE Portions of the Company's definitive Proxy Statement respecting the annual meeting of shareholders to be held on April 26, 1994 (to be filed not later than 120 days after December 31, 1993) are incorporated by reference in Part III of this Form 10-K. 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 and onshore in the United States. The Company is also engaged in exploration of its license concession in the Gulf of Thailand, and is evaluating a development program in connection with its recently announced oil and gas discoveries on that concession. The Company has interests in 76 lease blocks offshore Louisiana and Texas, approximately 93,000 gross acres onshore in the United States, approximately 2,635,000 gross acres offshore in the Kingdom of Thailand, and approximately 1,965,000 gross acres in Australia. DOMESTIC OFFSHORE OPERATIONS Historically, the Company's interests have been concentrated in the Gulf of Mexico, where approximately 81% of the Company's domestic proved reserves and 68% of its total proved reserves are now located. During 1993, approximately 75% of the Company's natural gas equivalent production was from its domestic offshore properties, contributing approximately 75% of consolidated oil and gas revenues. Four offshore producing areas, Eugene Island, South Marsh Island, Main Pass and East Cameron, account for approximately 52% of the Company's net proved natural gas reserves and approximately 56% of the Company's proved crude oil, condensate and natural gas liquids reserves. Eugene Island is the Company's largest producing area with 1993 average net revenue interest production (net to the Company's interest and net of royalty burdens) of 24 million cubic feet ('MMcf') per day of natural gas and 4,600 barrels ('Bbls') per day of oil, condensate and natural gas liquids. The table in Item 2 of this Annual Report on Form 10-K for the year ended December 31, 1993 (the 'Annual Report') summarizes the Company's offshore leasehold interests, drilling activity, and platforms set or announced as of December 31, 1993. LEASE ACQUISITIONS The Company has participated with other companies in bidding on and acquiring interests in federal leases offshore in the Gulf of Mexico since December 1970. As a result of such sales and subsequent activities, the Company owns interests in 70 federal leases offshore Louisiana and Texas. Federal leases generally have primary terms of five years, subject to extension by development and production operations. The Company also owns interests in six leases in state waters offshore Louisiana. 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. The Department of the Interior has announced its intention to hold two lease sales during 1994 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 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 properties where additional low-risk drilling or improved production methods by the Company can provide attractive rates of return. During 1993, the Company acquired a 50% working interest in South Pass Block 50 and acquired an additional approximately 17% working interest in Ship Shoal Block 240. In late 1993, the Company effected an exchange of working interests in certain federal offshore lease blocks with another working interest owner in such blocks. As a result of this exchange, the Company increased its working interest 1 in the following five blocks: Eugene Island 256 (from 41.5% to 69.2%), Eugene Island 295 (from 60% to 100% on 3,125 acres above 3,000 feet, from 12% to 20% on 1,875 acres above 3,000 feet and from 12% to 20% on all of the block below 3,000 feet), Eugene Island 261 (from 43.3% to 66.6%) and West Cameron blocks 252 and 253 (from 24% to 80%). In exchange, the Company assigned various working interests in 13 blocks to the other working interest owner. The Company effected the exchange primarily because it believes that this exchange will result in significant increased exploitation and exploration potential in the Eugene Island and West Cameron areas. This exchange of working interests is also consistent with the Company's strategy of increasing its working interest in its core areas. In connection with this exchange, the Company became the operator for the joint venture partners on certain of these blocks. 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 1993 were approximately $39,000,000, or 122% higher than the Company's domestic offshore capital and exploration expenditures of approximately $17,600,000 for 1992 and 23% higher than the Company's domestic offshore capital and exploration expenditures of approximately $31,700,000 for 1991. Development and production related projects represented 86% of the Company's 1993 domestic offshore capital and exploration expenditures. 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 influence decisions regarding development and operations even though it may not be the operator of a particular lease. The Company, which historically has not operated a substantial percentage of its offshore properties, has assumed the operation of certain of its properties where the Company believes that its technical expertise and ability to control overhead and operating costs will enhance its economic interest. Platforms are installed on a 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. In recent years, the gross cost of production platforms to the joint ventures in which the Company has varying net interests has been less than $11,000,000 per platform. 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. During 1993, the Company commenced installation of an additional platform on Eugene Island Block 295 and announced its intention to set a platform on Main Pass Block 123. See 'Properties -- Principal Properties.' 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'), in which the Company agreed to be responsible for investing as much as $60,000,000 on behalf of Pogo Gulf Coast for acquisition and exploration in state and federal waters in the Gulf of Mexico. As of December 31, 1993, Pogo Gulf Coast had interests in 24 federal offshore leases, and had invested a total of $41,750,000 of the aforementioned $60,000,000. 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. 2 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 of southeastern New Mexico and West Texas and the onshore Gulf Coast area. As of December 31, 1993, the Company and its partners had drilled and completed as productive 151 consecutive wells in Lea and Eddy Counties in southeastern New Mexico, including 58 wells in 1993 alone. The Company's primary drilling objective in southeastern New Mexico is the Brushy Canyon (Delaware) formation which produces oil at depths of 6,000 to 9,000 feet. The Company's net revenue interest portion of daily liquid hydrocarbon production in New Mexico averaged approximately 3,700 Bbls during 1993, which represented approximately 32% of the Company's total average daily production of oil, condensate and liquid plant products during 1993. 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 onshore properties using independent contractors. The Company's domestic onshore capital and exploration expenditures were approximately $29,400,000 for 1993, or 44% higher than the Company's domestic onshore capital and exploration expenditures of approximately $20,400,000 for 1992 and 56% higher than the Company's domestic onshore capital and exploration expenditures of approximately $18,800,000 for 1991. Development and production related projects represented 82% of the Company's 1993 domestic onshore capital and exploration expenditures. As of December 31, 1993, the Company held leases on 56,155 net acres onshore in the United States. Onshore reserves as of December 31, 1993, accounted for approximately 19% of the Company's domestic proved reserves and approximately 16% of its total proved reserves. During 1993, approximately 25% of the Company's natural gas equivalent production was from its domestic onshore properties, contributing approximately 25% of consolidated oil and gas revenues. INTERNATIONAL OPERATIONS The Company has conducted international exploration activities since the late 1970's in numerous oil and gas areas in various parts of the world. The Company pursues a strategy of evaluating potentially high return prospects in areas of the world with a stable political and financial climate such as certain European and ASEAN ('Association of Southeast Asian Nations') countries. In 1988, the Company sold its United Kingdom reserves which were located in the North Sea. Since that time, the Company has analyzed several opportunities and has obtained a concession in the Kingdom of Thailand and a concession in Australia. The Company's international capital and exploration expenditures were approximately $6,000,000 for 1993, or 131% higher than the Company's international capital and exploration expenditures of approximately $2,600,000 for 1992. Substantially all of the Company's international capital and exploration expenditures for 1993 were related to the Company's license in the Kingdom of Thailand. However, the Company continues to evaluate other international opportunities that are consistent with the Company's international exploration strategy. In 1990, the Company invited Rutherford/Moran Oil Company ('Rutherford/Moran'), Maersk Olie og Gas A/S ('Maersk') and Sophonpanich Co., Ltd. ('Sophonpanich') to join it in bidding for a concession license on Block B8/32, a 2.6 million acre tract in the Gulf of Thailand. In August 1991, the Company, Rutherford/Moran, Maersk and Sophonpanich were awarded a license from the Kingdom of Thailand to explore for and produce oil and gas on the tract. The Company's working interest in the concession is 31.67%. Maersk is the operator with a similar 31.67% interest. Exploration activities in Thailand are consistent with the Company's objectives of expanding its international operations in areas that have geological features which the Company believes may be favorable for hydrocarbon accumulation, low entry costs, an acceptable political risk profile and operational or other similarities with the Company's existing activities. Thailand is expected to be a 3 net importer of hydrocarbons at least through the year 2000, which should provide an attractive market for hydrocarbons produced locally. The Company's acreage is located 150 miles south southeast of Bangkok in 250 feet of water and is on trend with several producing oil and gas fields including, among others, the Erawan, Surat and Satun fields. The tract is traversed by a major natural gas pipeline. The Company understands that a contract has been entered into for construction of a second, parallel pipeline owned by an entity controlled by the government of the Kingdom of Thailand, with completion scheduled for early 1996. The Company anticipates that by the time production can commence from this concession, there should be ample transportation capacity available on these pipelines. Following an initial evaluation of the Thailand concession area, the Company and its joint venture partners drilled five exploratory wells on three separately identified seismic structures. In October 1992, the first well drilled, the Tantawan No. 1, successfully tested a large, complexly faulted, anticlinal structure with production tests from five intervals in that well resulting in calculated cumulative flow rates of 6,260 Bbls of oil and condensate and 25,750 thousand cubic feet ('Mcf') of natural gas per day. During 1993, the Company and its joint venture partners shot, processed and evaluated approximately 9,000 kilometers of new 3-D seismic data over and around the Tantawan No. 1 well. In late 1993, the Company drilled the Tantawan No. 2 and the Tantawan No. 3 exploratory wells on the Tantawan structure. The Tantawan No. 2 well successfully delineated a previously untested fault block to the east of the Tantawan No. 1 well with production tests from six intervals resulting in calculated cumulative flow rates of 70,300 Mcf of natural gas and 1,720 Bbls of condensate per day. The Tantawan No. 3 well successfully delineated a third untested fault block on the Tantawan structure located approximately two miles north of the Tantawan No. 1 and No. 2 wells. Production tests from this third Tantawan well were reported in January 1994, with production tests from five intervals resulting in calculated cumulative flow rates of 40,660 Mcf of natural gas and 8,684 Bbls of oil and condensate per day. As a result of its successful exploration drilling program, the Company's Thailand concession now accounts for approximately 14% of the Company's total estimated net proved reserves of natural gas, approximately 19% of the Company's total estimated net proved reserves of oil, condensate and natural gas liquids and approximately 16% of the Company's total net proved oil and gas equivalent reserves. Additional delineation wells on the Tantawan structure are planned during 1994. Based upon the results of such drilling, the Company and its partners will agree upon the type of development plan needed to commence production in this area. In addition, in late 1993, the Company and its joint venture partners began shooting and processing additional new 3-D seismic data in a different portion of Block B8/32. Following evaluation of this seismic data, additional exploratory wells are expected to be drilled by the Company and its joint venture partners on as yet untested seismic structures identified on Block B8/32. Production from the concession will be subject to a royalty ranging from 5% to 15% of oil and gas sales, plus certain fixed dollar amounts payable at specified cumulative production levels. Revenue from production in Thailand will also be subject to income taxes and other governmental charges. As set forth in the August 1991 concession, the exploratory term of the concession is for a period of up to six years; provided, however, that after the expiration of four years, a portion of the acreage in Block B8/32 must be relinquished by the Company and its joint venture partners and removed from the concession license. The Company must identify and release this acreage no later than August 1, 1995. During the remainder of the concession's exploratory period, the Company and its joint venture partners have certain work commitments involving the drilling of four more exploratory wells or the expenditure of certain sums of money on exploration activities. The Company anticipates, based on the joint venture's current exploration budget and capital spending plans, that it and its joint venture partners will satisfy the remainder of the concession's work commitments by the middle of 1995. Following the commencement of production, the initial production period of the concession is 20 years, subject to extension. 4 The Company also holds interests in three Authority to Prospect ('ATP') licenses in Australia. One ATP, in which the Company holds a 7.5% interest, covers 480,000 acres and expires in February 1995 unless certain expenditures are made. The Company has farmed out the other two ATP's to a third party and retained a small carried interest. None of the ATP's requires material expenditures by the Company. MISCELLANEOUS OTHER ASSETS The Company and a subsidiary, Pogo Offshore Pipeline Co., own minority interests in three pipelines through which offshore oil production is transported ashore. In addition, the Company owns an approximately 22% interest in a cryogenic gas processing plant near Erath, Louisiana, which entitles it to process up to 159,000 Mcf of gas per day. The plant is not operating at full capacity. 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 must await the construction or expansion of pipeline capacity before production from that area can be marketed. The marketing of onshore oil and gas production is also subject to the availability of pipelines, crude oil hauling and other transportation, processing and refining facilities as well as the existence of adequate markets. Generally, the Company's onshore domestic oil and gas production is located in areas where commercial production of economic discoveries can be rapidly effectuated. Most of the Company's 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 currently available prices. Other than any futures contracts referred to in ' -- Miscellaneous; Competition and Market Conditions,' 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. See also 'Financial Statements and Supplementary Data -- Note 4 to Notes to Consolidated Financial Statements and -- Unaudited Supplementary Financial Data.' 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 capacity. Should natural gas prices fall in the future, the Company may again elect to curtail certain quantities of its natural gas production capacity. 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 not exceeded 50% of the Company's total oil and gas production on an energy equivalent basis for any given period. While intended to limit the negative effect of price declines, such transactions could effectively limit the 5 Company's participation in price increases for the covered period, which increases could be significant. The Company has entered into a contract with another party for 1,000 Bbls per day of its crude oil production. The agreement expires July 31, 1994, but may be extended through January 31, 1995 at such party's option, for a contract price of $16.00 per barrel. At present, the Company has no futures contracts or forward sales of natural gas in effect. When the Company does engage in 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 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 is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. 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 other areas outside the United States are subject to the various risks inherent in foreign operations. These risks include, among others, 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, and renegotiation of contracts with governmental entities, as well as changes in laws and policies governing operations of foreign-based companies. 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. The Company believes that the Kingdom of Thailand currently presents favorable conditions in which to conduct international operations. 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. 6 ACREAGE The following table shows the Company's interest in developed and undeveloped oil and gas acreage as of December 31, 1993:
DEVELOPED ACREAGE (A) UNDEVELOPED ACREAGE (B) GROSS NET GROSS NET ONSHORE Arkansas------------------------- -- -- 118 20 Colorado------------------------- -- -- 7,963 7,963 Louisiana------------------------ 869 258 -- -- New Mexico----------------------- 14,013 6,950 36,317 29,161 Oklahoma------------------------- 3,840 374 -- -- Texas---------------------------- 11,677 4,541 17,849 6,853 Wyoming-------------------------- -- -- 120 35 Total Onshore---------------- 30,399 12,123 62,367 44,032 OFFSHORE Louisiana (State)---------------- 7,804 2,964 -- -- Louisiana (Federal)(c)----------- 169,193 51,734 89,989 19,765 Texas (Federal)------------------ 46,080 7,971 17,280 3,340 Total Offshore--------------- 223,077 62,669 107,269 23,105 TOTAL DOMESTIC------------------- 253,476 74,792 169,636 67,137 INTERNATIONAL Thailand (Offshore)-------------- -- -- 2,635,116 878,372 Australia (Onshore)-------------- -- -- 1,964,800 42,960 TOTAL INTERNATIONAL-------------- -- -- 4,599,916 921,332 TOTAL COMPANY------------------------ 253,476 74,792 4,769,552 988,469 (a) 'Developed acreage' consists of lease acres spaced or assignable to production on which wells have been drilled or completed to a point that would permit production of commercial quantities of oil and natural gas. (b) Approximately 38% of the Company's total offshore net undeveloped acreage is under leases that have terms expiring in 1994, if not held by production, and another approximately 21% of offshore net undeveloped acreage will expire in 1995 if not also held by production. Approximately 16% of onshore net undeveloped acreage is under leases that have terms expiring in 1994, if not held by production, and another approximately 39% of onshore net undeveloped acreage will expire in 1995 if not also held by production. (c) The Company also owns overriding royalty interests in one federal lease offshore Louisiana totaling 5,000 gross and 1,250 net acres.
7 PRODUCTIVE WELLS AND DRILLING ACTIVITY The following table shows the Company's interest in productive oil and natural gas wells as of December 31, 1993. Productive wells are producing wells plus 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 production facilities). NATURAL GAS OIL WELLS(A) WELLS(A) GROSS NET GROSS NET Offshore United States--------------- 199 36.6 170 46.8 Onshore United States---------------- 163 92.2 65 24.6 Total-------------------- 362 128.8 235 71.4 (a) One or more completions in the same bore hole are counted as one well. The data in the above table includes 30 gross (5.8 net) oil wells and 16 gross (5.8 net) 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. 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.
1993 1992 1991 SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY GROSS WELLS Offshore United States Exploratory---------------------- 5.0 1.0 -- 2.0 2.0 3.0 Development---------------------- 15.0 0 5.0 -- 13.0 -- Onshore United States Exploratory---------------------- 3.0 4.0 4.0 2.0 2.0 4.0 Development---------------------- 61.0 1.0 34.0 -- 32.0 -- Offshore Kingdom of Thailand Exploratory---------------------- 2.0 2.0 1.0 -- -- -- Total-------------------- 86.0 8.0 44.0 4.0 49.0 7.0 NET WELLS Offshore United States Exploratory---------------------- 1.7 0.1 -- 0.7 0.2 0.4 Development---------------------- 7.7 -- 1.5 -- 4.0 -- Onshore United States Exploratory---------------------- 2.0 3.2 2.8 0.9 1.0 2.3 Development---------------------- 33.1 0.4 23.2 -- 18.2 -- Offshore Kingdom of Thailand Exploratory---------------------- 0.6 0.6 0.3 -- -- -- Total-------------------- 45.1 4.3 27.8 1.6 23.4 2.7 As of December 31, 1993, the Company was participating in the drilling of 4 gross (0.9 net) offshore domestic wells and 4 gross (2.7 net) onshore wells.
8 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. 1993 1992 1991 Production Sales: Natural Gas (Mcf per day)-------- 91,700 105,200 104,200 Crude Oil and Condensate (Bbls per day)----------------------- 9,851 8,699 7,108 Natural Gas Liquids (Bbls per day): Leasehold Ownership-------------- 1,538 1,037 609 Plant Ownership------------------ 140 144 54 Total------------------------ 1,678 1,181 663 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.' 1993 1992 1991 Sales Prices: Natural Gas (per Mcf)------------------------------ $ 1.98 $ 1.75 $ 1.66 Crude Oil and Condensate (per Bbl)----------------- $17.81 $20.17 $20.98 Natural Gas Liquids (per Bbl)---------------------- $11.90 $13.50 $14.21 Production (Lifting) Costs(a) Natural Gas, Crude Oil, Condensate and Natural Gas Liquids (per equivalent Mcf of Natural Gas)------- $ 0.45 $ 0.43 $ 0.51 (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. RESERVES The following table sets forth information as to the Company's net proved and proved developed reserves as of December 31, 1993, 1992, and 1991, 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 Company Petroleum Engineers, Houston, Texas ('Ryder Scott') in accordance with criteria prescribed by the Securities and Exchange Commission (the 'Commission'). The summary report of Ryder Scott on the reserve estimates, which includes definitions and assumptions, is set forth as an exhibit to this Annual Report and definitions, assumptions and descriptions of methodology following the tables are based upon the Ryder Scott report.
AS OF DECEMBER 31, 1993 1992 1991 Total Proved Reserves: Oil, condensate, and natural gas liquids (thousands of Bbls) -- Located in the United States---------------------------------------- 22,843 19,979 18,818 Located in the Kingdom of Thailand-------------------------------------- 5,425 2,577 -- Total Company----------------------------------- 28,268 22,556 18,818 (TABLE CONTINUED ON FOLLOWING PAGE) 9 Natural Gas (MMcf) Located in the United States------------------------ 199,392 196,400 202,735 Located in the Kingdom of Thailand-- 33,474 10,668 -- Total Company--------------------------------------- 232,866 207,068 202,735 Present value of estimated future net revenues, before income taxes (in thousands) Located in the United States---------------------- $386,674 $390,893 $349,754 Located in the Kingdom of Thailand---------------- 17,166 14,208 -- Total Company------------------------------------- $403,840 $405,101 $349,754 Proved Developed Reserves (all located in the United States): Oil, condensate, and natural gas liquids (thousands of Bbls)----------------------------------------------- 20,976 18,798 17,550 Natural Gas (MMcf)------------------------------------- 183,139 175,523 188,090 Present value of estimated future net revenues, before income taxes (in thousands)--------------------- $375,287 $378,300 $337,524
Natural gas liquids comprise approximately 14% of the Company's total proved liquids reserves and approximately 18% of the Company's proved developed liquids reserves. All hydrocarbon liquid reserves are expressed in standard 42 gallon Bbls. All gas volumes and gas sales are expressed in MMcf at the pressure and temperature bases of the area where the gas reserves are located. 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 nonassociated, 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, (a) pressure maintenance, (b) cycling, and (c) 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: 10 (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. Because of the direct relationship between quantities of proved undeveloped reserves and development plans, only reserves assigned to undeveloped locations that will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which will definitely be developed have been included in the proved undeveloped category. The Company has interests in certain tracts which may have substantial additional hydrocarbon quantities which cannot be classified as proved and are not included herein. The Company has active exploratory and development drilling programs which in all likelihood will result in the reclassification of significant additional quantities to the proved category. In computing future revenues from gas reserves attributable to the Company's interests, prices in effect at December 31, 1993 were used, including current market prices, contract prices and fixed and determinable price escalations where applicable. In accordance with Commission guidelines, the future 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 gas sold under contract, the contract gas price including fixed and determinable escalations, exclusive of inflation adjustments, was used until the contract expires and then was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves. In computing future revenues from liquids attributable to the Company's interest, prices in effect at December 31, 1993 were used and these prices were held constant to depletion of the properties. 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. The accumulated gas production imbalances have been taken into account. 11 Production data used to arrive at the estimates set forth above includes estimated production for the last few months of 1993. The future production rates from reservoirs now on production may be more or less than estimated because of, among other reasons, mechanical breakdowns and changes in market demand or allowables set by regulatory bodies. Properties 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, and as a general rule, reserve estimates based upon volumetric analysis 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 governmental regulatory authorities and agencies, including the Federal Energy Regulatory Commission ('FERC') and the Federal Trade Commission. In addition, estimates are from time to time furnished to governmental agencies in connection with specific matters pending before such agencies. The basis for reporting reserves to these agencies, in some cases, is not comparable to that furnished above because of the nature of the various reports required. The major differences 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. No estimates by the Company of its total proved net oil and gas reserves, however, were filed with or included in reports to any federal authority or agency other than the Commission during 1993. GOVERNMENT REGULATION The Company's operations are affected from time to time in varying degrees by political developments and federal and state laws and regulations. Rates of production of oil and gas have for many years been subject to federal and state 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 12 will be taken into account in computing the Company's alternative minimum tax. See 'Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources.' ENVIRONMENTAL MATTERS Offshore oil and gas operations are subject to extensive federal and state 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.' Regulations of the Department of the Interior currently impose absolute liability upon the lessee under a federal lease for the costs of clean-up of pollution resulting from a lessee's operations, and such lessee may also be subject to possible legal 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 Oil Pollution Act of 1990 (the 'OPA') and regulations thereunder impose a variety of regulations on 'responsible parties' (which include owners and operators of offshore facilities) related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. In addition it imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. On August 25, 1993, the Mineral Management Service (the 'MMS') published an advance notice of its intention to adopt a rule under OPA that would require owners and operators of offshore oil and gas facilities to establish $150,000,000 in financial responsibility. Under the proposed rule, financial responsibility could be established through insurance, guaranty, indemnity, surety bond, letter of credit, qualification as a self-insurer or a combination thereof. There is substantial uncertainty as to whether insurance companies or underwriters will be willing to provide coverage under OPA because the statute provides for direct lawsuits against insurers who provide financial responsibility coverage, and most insurers have strongly protested this requirement. The financial tests or other criteria that will be used to judge self-insurance are also uncertain. The Company cannot predict the final form of the financial responsibility rule that will be adopted by the MMS, but such rule has the potential to result in the imposition of substantial additional annual costs on the Company or otherwise materially adversely affect the Company. The impact of the rule should not be any more adverse to the Company than it will be to other similar owners or operators in the Gulf of Mexico. 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. See 'Legal Proceedings' for a discussion of other environmental matters. 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 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. In addition, the recent trend toward stricter standards in environmental legislation and regulation may continue. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas production wastes as 'hazardous wastes' which would make the reclassified exploration and production wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on the operating costs of the 13 Company, as well as the oil and gas industry in general. State initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these various initiatives could have a similar impact on the Company. During 1993, the Company incurred capital expenditures of approximately $750,000 for environmental control facilities, including two salt water disposal facilities, one each in its Red Tank and Sand Dunes fields in New Mexico. The Company currently has budgeted $987,000 for environmental control facilities, including three salt water disposal facilities during 1994. 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, prevention, and other matters. The effect of these statutes and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit allowable production from the Company's properties and thereby to limit its revenues. OTHER REGULATIONS AND LEGISLATIVE PROPOSALS Prior to January 1, 1993 various aspects of the Company's natural gas operations were subject to regulations by the FERC under the Natural Gas Act of 1938 (the 'NGA') and the Natural Gas Policy Act of 1978 (the 'NGPA') with respect to 'first sales' of natural gas, including price controls and certificate and abandonment authority regulations. However, as a result of the enactment of the Natural Gas Decontrol Act of 1989, the remaining 'first sales' restrictions imposed by the NGA and the NGPA terminated on January 1, 1993. Commencing in late 1985, the FERC has issued a series of orders that have had a major impact on natural gas pipeline operations, services and rates and thus have significantly altered the marketing and price of natural gas. Order 636, issued in April 1992, requires each pipeline company, among other things, to 'unbundle' its traditional wholesale services and create and make available on an open and nondiscriminatory basis numerous constituent services (such as gathering services, storage services, firm and interruptible transportation services, and stand-by sales services) and to adopt a new rate making methodology to determine appropriate rates for those services. To the extent the pipeline company or its sales affiliate makes gas sales as a merchant in the future, it will do so in direct competition with all other sellers pursuant to private contracts; however, pipeline companies and their affiliates are not required to remain 'merchants' of gas, and some of the interstate pipelines companies have or will become 'transporters only.' In subsequent orders, the FERC largely affirmed Order 636 and denied a stay of the implementation of the new rules pending judicial review. In addition, the FERC has generally accepted rate filings implementing Order 636 on essentially every interstate pipeline as of the end of 1993. Order 636, as well as the FERC orders approving the individual pipeline rate filings implementing Order 636, are the subject of numerous appeals to the United States Courts of Appeals. The Company cannot predict whether the latest orders will be affirmed on appeal or what the effects will be on its business. EMPLOYEES As of December 31, 1993, the Company had 102 employees. 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. 14 PRINCIPAL PROPERTIES As of January 1, 1994, approximately 81% of the Company's domestic proved oil and gas equivalent reserves and approximately 68% of the Company's total proved oil and gas equivalent reserves were located on properties in the Gulf of Mexico. Five significant producing areas, of which four are located in the Gulf of Mexico and the fifth is located in New Mexico, accounted for approximately 59% of the estimated proved natural gas reserves and approximately 74% of the estimated oil, condensate and natural gas liquids reserves of the Company as of January 1, 1994. These producing areas accounted for approximately 60% of natural gas production and 90% of oil, condensate and natural gas liquids production for 1993. Reserves and production data for the five principal producing areas, as estimated by Ryder Scott, are shown in the following table. No other major producing area accounted for more than 5% of the estimated discounted future net revenues attributable to the Company's estimated proved reserves as of January 1, 1994. However, the Company's Thailand concession, which is currently not a producing property, accounts for approximately 14% of the Company's total estimated net proved reserves of natural gas, approximately 19% of the Company's total estimated net proved reserves of oil, condensate and natural gas liquids and approximately 16% of the Company's total net proved oil and gas equivalent reserves.
SIGNIFICANT PRODUCING AREAS NET PROVED RESERVES 1993 AVERAGE NET AS OF JANUARY 1, 1994 DAILY PRODUCTION NATURAL GAS LIQUIDS(A) NATURAL GAS LIQUIDS(A) (MMCF) % (MBBLS) % (MCF) % (BBLS) % OFFSHORE Eugene Island---------------------- 92,742 39.8% 10,448 37.0% 24,000 27.1% 4,600 39.8% South Marsh Island----------------- 6,811 2.9 2,579 9.1 2,101 2.4 1,378 11.9 Main Pass-------------------------- 9,186 3.9 2,722 9.6 3,721 4.2 598 5.2 East Cameron----------------------- 12,423 5.3 75 0.3 13,852 15.6 76 0.7 ONSHORE New Mexico Lea/Eddy Counties---------------- 16,219 7.0 4,994 17.7 9,660 10.9 3,714 32.1 DISCOUNTED FUTURE NET REVENUES(B) % OFFSHORE Eugene Island---------------------- 53.3% South Marsh Island----------------- 5.1 Main Pass-------------------------- 4.5 East Cameron----------------------- 4.2 ONSHORE New Mexico Lea/Eddy Counties---------------- 9.9 (a) 'Liquids' includes oil, condensate and natural gas liquids. (b) Before income taxes, discounted at 10%.
Set forth below are descriptions of certain of the Company's significant producing areas. Contained in certain of these descriptions and elsewhere in this Annual Report are production rate test results with regard to certain wells and fields in which the Company has an interest. Such production rate tests, while accurate, are never indicative of actual sustained production rates. EUGENE ISLAND The Company's most significant reserves are in the Eugene Island area located 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 13 blocks in the Eugene Island area. These comprise eight fields containing 90 gross oil and gas wells producing from multiple reservoirs and horizons. The Eugene Island Block 330 field is the Company's most significant asset, with 28 productive Pleistocene horizons between 4,000 and 8,000 feet, containing multiple reservoirs. The 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 18 wells producing primarily natural gas and 35 wells producing primarily oil on the block. In 1993, a successful five well drilling program was completed in the field which included one horizontal and four vertical wells. A multi-well program off of the field's 'D' platform commenced in early January 1994. Since initial production in 1973, the Eugene Island 15 Block 330 field has produced approximately 619 billion cubic feet ('Bcf') of natural gas and 122 million barrels ('MMBbls') of oil and condensate (167 Bcf and 35 MMBbls, attributable to the Company's net revenue interest). Reserves have been added to this field consistently since production commenced. These increases have been derived from new exploratory horizons, infill drilling, field expansions and higher than anticipated recovery efficiencies. Another significant field to the Company is Eugene Island Block 295. In production since 1973, this block has recorded gross production of over 387 Bcf of natural gas and over 2.9 MMBbls of oil and condensate during its twenty-year life. In August 1993, the Company effected an exchange of working interests in Eugene Island Block 295 with another working interest owner in such block. Pursuant to this exchange, the Company increased its working interest in Eugene Island Block 295 to 100% on 3,125 acres above 3,000 feet, to 20% on 1,875 acres above 3,000 feet and to 20% on all of the block below 3,000 feet. During the fourth quarter of 1993, the Company successfully drilled and completed five horizontal wells to exploit the natural gas potential located in certain shallow reservoirs on this block in an area where it has a 100% working interest. These five wells tested at a gross calculated cumulative daily flow rate of 100 MMcf of natural gas per day, although platform compression capacity and lease burdens dictate that ultimate net production volumes will be substantially less than this amount. The Company completed construction of a production platform over these wells and commenced initial production from the first of these wells in late February 1994. The Eugene Island 212 field consists of Eugene Island Blocks 211 and 212 and Ship Shoal Block 175. The field contains eight productive horizons which have four oil wells and one natural gas well producing from a platform set in 1985. The Company and its partners drilled a successful infill development well in this field during the second half of 1993. SOUTH MARSH ISLAND The Company currently owns five blocks in the South Marsh Island area, located offshore Louisiana. Three of the leases were acquired in 1974, a fourth in 1980 and the most recent in 1992. Three blocks contain a total of five drilling and production platforms. These platforms currently have 44 oil and gas wells producing from Pleistocene age sandstone reservoirs located at depths from 5,000 to 10,000 feet. The South Marsh Island Block 128 field, in which the Company owns a 16% working interest, comprises South Marsh Island Blocks 125, 127 and 128. This field primarily produces oil, with 36 oil wells and six natural gas wells producing from 20 separate reservoirs. The first four wells in a supplemental five well drilling program in this field were completed in 1993. The current drilling program is based on the ongoing analysis of a 3-D seismic survey in conjunction with a detailed reservoir study of the field. The Company also owns a 25% working interest in the South Marsh Island Block 160 field which is producing from two oil wells at a depth of approximately 9,700 feet. A single platform was set on this block in 1983. A two-well drilling program in this field is currently being considered as a result of recent analysis of a 3-D seismic survey on the block. MAIN PASS The Company's nine blocks in the Main Pass area are located near the mouth of the Mississippi River in the Gulf of Mexico and include leases purchased from 1974 to 1992. The primary drilling objectives in these fields are Pliocene and Miocene sandstone reservoirs with productive formation depths from 5,000 to 12,000 feet. The Company's interests in the Main Pass area include 57 producing oil and gas wells producing from six platforms. A field including Main Pass Blocks 72, 73 and 72/74 was unitized in 1982 with the Company's working interest at 14%. This field contains 33 oil wells and 11 natural gas wells operated by one of 16 the Company's joint venture partners. The field is located in 125 feet of water with 38 mapped horizons adjacent to and surrounding a salt dome. These horizons contain over 150 separate reservoirs between 5,000 and 12,000 feet. A successful three-well workover program in this field was completed in 1992. Many of the producing reservoirs in this field have consistently outperformed their initial recovery estimates. Based on the high historical recovery efficiency, it is anticipated that some of the multiple behind pipe reservoirs remaining will also outperform their existing reserve estimates. Main Pass Block 123 was acquired in the federal lease sale of 1990. Pogo Gulf Coast, for which the Company is the general partner, has a 75% working interest and is the operator on the block. Along with its non-operating joint venture partner, Pogo Gulf Coast drilled two discovery wells on the block in 1993 and is currently planning additional drilling as well as the installation of a production platform in late 1994. EAST CAMERON The original lease purchased by the Company and its partners 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 4 offshore blocks in this area which contain three fields and 16 producing gas wells. During 1992, the Company and its partners conducted a 3-D seismic survey of the East Cameron Block 334/335 field area where the Company has a 42% working interest. The Company currently anticipates commencing a multi-well drilling program in this field during the first half of 1994. NEW MEXICO The Company considers southeastern New Mexico to be an area of significant growth in both production and reserves as a result of recent exploration and development activities. The Company believes that during the past four 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 50,000 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 range from of 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. Through December 31, 1993, the Company and its partners had drilled and completed as productive 151 consecutive wells in Lea and Eddy Counties, including, among others, 52 wells in the Sand Dunes field where the Company's working interest ranges from 4% to 89%; 27 wells in the East Loving field where the Company's working interest ranges from 33% to 98%; 43 wells in the Livingston Ridge field where the Company's working interest ranges from 41% to 83%; and 8 wells in the Red Tank field where the Company's working interest ranges from 89% to 100%. The oil fields in this area are generally developed on 40 acre spacings. The Company anticipates drilling many additional locations in these and other fields in southeastern New Mexico during 1994 and in future years. 17 DOMESTIC OFFSHORE PROPERTIES -- The following is a listing of Pogo's domestic offshore properties as of December 31, 1993.
POGO EXPLORATORY DEVELOPMENT WORKING WELLS PLATFORMS WELLS INTEREST DRILLED OR SET OR DRILLED OR DATE BLOCK % DRILLING ANNOUNCED DRILLING ACQUIRED OFFSHORE TEXAS -- FEDERAL Mustang Island A-3 20.0 8-89 Matagorda Island A-4 27.0 3 1 2 8-83 670 30.7 1 1 2 8-83 Brazos A-104 10.8 1 1 8-89 Galveston 225 18.0 8-89 325 20.0 8-91 High Island/South Addition A-515 25.0 2 1 11-79 High Island/East Addition/South Extension A-323 1.8 4 1 17 6-73 A-325 9.9 7 2 9 6-73 A-355 13.2 1 1 5 5-74 A-356 20.0 1 1 4 5-74 TOTAL TEXAS 20 9 39 OFFSHORE LOUISIANA -- FEDERAL West Cameron 63 20.0 3-91 97 20.0 3-90 196 (A) 3 1 2 5-83 202 39.3 3 1 2 11-82 252 80.0 1 Share 253 Platform 2 11-82 253 80.0 1 1 6 6-77 310 20.0 3-91 352 15.0 1 1 8 10-74 385 20.0 3-90 532 4.0 5 Share 533 Platform 3 12-72 533 4.0 2(B) 2 7 12-72 609 16.0 1 1 7 10-74 East Cameron 201 20.0 1 1 3-90 270 30.0 3 2 30 12-70 334 42.0 5(B) 1 10 12-70 335 42.0 3 2 23 6-73 (TABLE CONTINUED ON FOLLOWING PAGE) DATE OR LEASE ANTICIPATED EFFECTIVE DATE OF DATE PRODUCTION OFFSHORE TEXAS -- FEDERAL Mustang Island 11-1-89 Matagorda Island 10-1-83 9-89 10-1-83 10-89 Brazos 10-1-89 6-90 Galveston 10-1-89 11-1-91 High Island/South Addition 1-1-80 11-84 High Island/East Addition/South Exten 8-1-73 6-78 8-1-73 8-81 7-1-74 8-80 7-1-74 7-80 TOTAL TEXAS OFFSHORE LOUISIANA -- FEDERAL West Cameron 5-1-91 5-1-90 7-1-83 12-90 1-1-83 8-85 1-1-83 8-84 8-1-77 7-84 7-1-91 12-1-74 8-79 6-190 2-1-73 9-76 2-1-73 9-76 12-1-74 7-78 East Cameron 5-1-90 1994 1-1-71 2-73 2-1-71 8-77 8-1-73 9-77 (A) Block farmed out -- Over-riding Royalty Interest only (B) Includes offset contribution well
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POGO EXPLORATORY DEVELOPMENT WORKING WELLS PLATFORMS WELLS INTEREST DRILLED OR SET OR DRILLED OR DATE BLOCK % DRILLING ANNOUNCED DRILLING ACQUIRED Vermilion 175 70.0 1 1 5-91 188 70.0 Share 175 Platform 5-91 227 16.4 1 3-89 South Marsh Island 125 16.0 3 1 8 10-74 127 16.0 Share 128 Platform 3 10-74 128 16.0 6 3 62 3-74 160 25.0 2 1 4 9-80 188 25.0 5-92 Eugene Island 101 20.0 3-91 102 20.0 3-91 211 33.3 Share 212 Platform 3 5-83 212 33.3 1 1 3 5-83 256 69.2 5 1 7 12-70 261 66.7 2 1 15 10-74 295* 20.0 /100.0 7(B) 2 29 12-70 312 4.0 5 Share 333 Platform 7 3-74 318 20.0 1 3-91 330 35.0 (D) 10(B) 4 89 12-70 333 4.0 3 2 22 12-72 337 37.5 3 1 8 2-76 Ship Shoal 175 33.3 Share EI 212 Platform 2 5-83 240 30.0 1 1 3-89 255 30.0 3-89 256 30.0 3-90 South Timbalier 109 26.7 3-89 198 25.0 2 1 4 5-85 +214 25.0 (C) 1 Share 198 Platform 1 5-85 287 20.0 1 3-89 West Delta 59 20.0 3-90 South Pass +33 6.0 (C) Share 49 Platform 2 10-74 49 4.8 5(B) 1 19 9-72 50 50.0 1 Share 49 Platform 7-93 +57 12.0 Share 57/58 Platform 3 11-76 +78 9.0 5 1 12 9-72 Mississippi Canyon 63 6.0 2 1 5 5-75 (TABLE CONTINUED ON FOLLOWING PAGE) DATE OR LEASE ANTICIPATED EFFECTIVE DATE OF DATE PRODUCTION Vermilion 9-1-85 12-91 6-1-89 5-1-89 South Marsh Island 12-1-74 7-77 12-1-74 7-77 5-1-74 7-77 11-1-80 2-84 9-1-92 Eugene Island 5-1-91 5-1-91 7-1-83 1-87 7-1-83 1-87 2-1-71 10-79 12-1-74 10-79 2-1-71 2-73 5-1-74 7-77 6-1-91 1-1-71 4-73 2-1-73 7-77 3-1-76 6-85 Ship Shoal 7-1-83 7-88 6-1-89 1-95 7-1-89 5-1-90 South Timbalier 6-1-89 9-1-85 8-90 9-1-85 8-90 5-1-89 West Delta 6-1-90 South Pass 12-1-74 2-83 11-1-72 10-80 8-1-88 12-93 1-1-77 7-82 10-1-72 4-81 Mississippi Canyon 7-1-75 6-84 (B) Includes offset contribution well (C) Block farmed in (D) Pogo owns 30% in a small portion of the property * Pogo owns 20% in rights below 3,000 feet and 100% in rights at 3,000 feet and above in certain portions of the block. See -- 'Principal Properties; Eugene Island' (+) Represents portion of block
19
POGO EXPLORATORY DEVELOPMENT WORKING WELLS PLATFORMS WELLS INTEREST DRILLED OR SET OR DRILLED OR DATE BLOCK % DRILLING ANNOUNCED DRILLING ACQUIRED Main Pass +30 25.0 (E) 2 1 8(F) 10-81 37 25.0 4 1 5 7-79 61 24.0 1 3-90 +72 14.0 1 Share 73 Platform 2 5-75 +72/74 14.0 4 2 43 11-76 73 14.0 4 1 16 10-74 123 30.0 2 1 3-90 131 33.0 5-92 TOTAL LOUISIANA 115 42 482 STATE LEASES Offshore Louisiana South Pass +57/58 12.0 3 1 13 5-74 Main Pass 31 50.0 1 1 1 3-85 Breton Sound 2 100.0 2(F) 1 1 4-80 23 22.5 1 1 1 9-78 24 22.5 1 1 1 9-78 North Lighthouse Point S/L340 50.0 1 3 5-84 TOTAL STATE LEASES 9 5 20 TOTAL DOMESTIC OFFSHORE 144 56 541 DATE OR LEASE ANTICIPATED EFFECTIVE DATE OF DATE PRODUCTION Main Pass 12-1-81 11-87 10-1-79 7-82 7-1-90 7-1-75 8-79 1-1-77 8-79 12-1-74 8-79 5-1-90 1-95 9-1-92 TOTAL LOUISIANA STATE LEASES Offshore Louisiana South Pass 5-13-74 7-82 Main Pass 3-18-85 2-90 Breton Sound 9-15-80 8-87 9-18-78 7-84 9-18-78 7-84 North Lighthouse Point 5-1-84 10-84 TOTAL STATE LEASES TOTAL DOMESTIC OFFSHORE (E) Portion of block farmed out (F) Includes one farmout well (+) Represents portion of block
20 ITEM 3. LEGAL PROCEEDINGS. In 1989, a large number of exploration and production companies, including the Company, were circularized with Special Notice Letters in accordance with CERCLA from the EPA regarding a particular waste disposal site in Louisiana known as the 'Gulf Coast Vacuum Site' utilized by a trucking company. The EPA subsequently developed a list based on its investigation showing the Company bearing an approximate 1.4% responsibility for this site based on the trucking company's shipping records. The Company utilized the trucking company to dispose of salt water produced from a well in which the Company had an interest. The Company, however, believes that none of this salt water was delivered to the Gulf Coast Vacuum Site. In any event, the Company believes that the trucking company shipped only oilfield waste for the Company which is exempt pursuant to CERCLA and, further, that such shipments, if any, were sent to a properly permitted waste disposal site. The Company has learned that the EPA has recently entered a consent decree, the details of which have not been made public, with parties that are believed to be responsible for a majority of the disposal occurring at the site. 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. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS. Not Applicable. ITEM S-K 401(B). EXECUTIVE OFFICERS OF REGISTRANT. Executive officers of the Company are appointed annually to serve for the ensuing year or until their successors have been elected or appointed. The executive officers of the Company, their age as of February 1, 1994, 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 48 1991 and Chief Executive Officer Kenneth R. Good--------------------------- Senior Vice President -- 56 1991 Land and Budgets D. Stephen Slack-------------------------- Senior Vice President, Chief 44 1988 Financial Officer and Treasurer Stuart P. Burbach------------------------- Vice President and 41 1991 Offshore Division Manager Jerry A. Cooper--------------------------- Vice President and 45 1990 Western Division Manager Harvey L. Gold---------------------------- Vice President -- Engineering 58 1988 Thomas E. Hart---------------------------- Vice President and Controller 51 1988 R. Phillip Laney-------------------------- Vice President and 53 1991 International Division Manager John O. McCoy, Jr.------------------------ Vice President and 42 1989 Chief Administrative Officer J. D. McGregor---------------------------- Vice President -- Sales 49 1988 Sammie M. Shaw---------------------------- Vice President -- Operations 62 1992 Ronald B. Manning------------------------- Corporate Secretary and 40 1990 Associate General Counsel
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 was President and 21 Chief Operating Officer of the Company since 1990, Senior Vice President and General Counsel of the Company since 1986, Vice President and General Counsel of the Company since 1982, and General Counsel of the Company since 1979; Mr. Good was Vice President - Land of the Company since 1988 and Chief Landman of the Company since 1977; Mr. Slack was Regional Manager of Chemical Bank of New York's Southwest Energy and Minerals Division since 1982; Mr. Burbach was Vice President of Norfolk Holding Inc. since 1986 and Exploration Manager for Tricentrol Ltd. Canada and Tricentrol U.S. since 1981; Mr. Cooper was a Division Landman for the Company since 1983 and a Landman for the Company since 1979; Mr. Gold was Manager of Reservoir Engineering for the Company since 1977; Mr. Hart was Controller for the Company since 1977; Mr. Laney was International Exploration Manager for the Company since 1983 and Exploration Coordinator for the Gulf Coast Division of the Company since 1977; Mr. McCoy was Director of Personnel and Administration for the Company since 1978; Mr. McGregor was Manager of Hydrocarbon Sales and Contracts for the Company since 1981; Mr. Shaw was Operations Manager for the Company since 1981; Mr. Manning was an Associate General Counsel for the Company since 1989 and prior thereto was an attorney with the Federal Bureau of Investigation, and Chevron U.S.A., and Assistant to the General Counsel of Primary Fuels, Inc. 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 Company's Common Stock trades under the symbol PPP. The Company's Common Stock is also listed on the Pacific Stock Exchange. The Board of Directors of the Company has not declared cash dividends on the Company's Common Stock since the fourth quarter of 1986, and has no current plans to pay dividends. Pursuant to various agreements under which the Company has borrowed funds, the 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 acquire for value any shares of its capital stock if (after giving effect to the proposed payment, distribution, or acquisition) the aggregate amount of all such payments, distributions or acquisitions on and after a specified date would exceed an amount determined based on the consolidated income or cash flow of the Company and its consolidated subsidiaries from and after such date. As of December 31, 1993, $33,803,000 was available for dividends under the most restrictive of such limitations. LOW HIGH 1992 1st Quarter------------------------------------- 5 1/8 6 1/2 2nd Quarter------------------------------------- 5 1/8 6 3/8 3rd Quarter------------------------------------- 5 1/2 10 3/8 4th Quarter------------------------------------- 9 3/4 13 7/8 1993 1st Quarter------------------------------------- 9 3/4 17 1/4 2nd Quarter------------------------------------- 16 1/8 21 3rd Quarter------------------------------------- 13 5/8 19 1/8 4th Quarter------------------------------------- 14 3/8 19 3/4 As of February 10, 1994, there were 4,216 holders of record of the Company's Common Stock. 22 ITEM 6. SELECTED FINANCIAL DATA.
FOR THE YEAR ENDED DECEMBER 31, 1993 1992 1991 1990 1989 FINANCIAL DATA (Expressed in thousands, except per share data) Revenues: Crude oil and condensate--------- $ 64,042 $ 64,224 $ 54,420 $ 54,018 $ 41,396 Natural gas---------------------- 66,173 67,366 63,225 74,111 76,287 Natural gas liquids-------------- 7,288 5,833 3,442 3,496 3,516 Other, net----------------------- (950) 1,705 3,338 794 (79) Oil and gas revenues------------- 136,553 139,128 124,425 132,419 121,120 Interest on tax refunds---------- 2,322 -- -- 22,499 -- Gains (losses) on sales---------- 679 1,702 44 (98) (173) Total------------------------ $ 139,554 $ 140,830 $ 124,469 $ 154,820 $ 120,947 Income before extraordinary item----- $ 25,061 $ 18,495 $ 10,322 $ 44,036 $ 2,638 Extraordinary gains on purchase of debt------------------------------- -- -- 1,336 -- -- Net income--------------------------- $ 25,061 $ 18,495 $ 11,658 $ 44,036 $ 2,638 Per share data: Primary and fully diluted earnings: Before extraordinary item---- $ 0.76 $ 0.66 $ 0.37 $ 1.69 $ 0.11 Extraordinary item----------- -- -- 0.05 -- -- Net income------------------- $ 0.76 $ 0.66 $ 0.42 $ 1.69 $ 0.11 Price range of common stock: High------------------------- $ 21.00 $ 13.88 $ 8.25 $ 10.13 $ 10.25 Low-------------------------- $ 9.75 $ 5.13 $ 4.63 $ 5.75 $ 4.00 Weighted average number of common and common equivalent shares outstanding------------------------ 32,860 27,929 27,611 26,029 24,157 Long-term debt at year end----------- $ 134,539 $ 129,260 $ 184,260 $ 217,000 $ 264,000 Production payment obligation at year end-------------------------------- $ -- $ 24,854 $ 45,475 $ 46,893 $ 51,352 Shareholders' equity (deficit) at year end--------------------------- $ 33,803 $ 5,648 $ (56,636) $ (68,429) $ (132,557) Total assets at year end------------- $ 239,774 $ 206,347 $ 213,772 $ 244,226 $ 227,508 PRODUCTION (SALES) DATA Net daily average and weighted average price: Natural gas (Mcf per day)-------- 91,700 105,200 104,200 107,300 111,300 Price (per Mcf)-------------- $ 1.98 $ 1.75 $ 1.66 $ 1.89 $ 1.88 Crude oil-condensate (Bbl. per day)--------------------------- 9,851 8,699 7,108 6,209 6,013 Price (per Bbl.)------------- $ 17.81 $ 20.17 $ 20.98 $ 23.84 $ 18.86 Natural gas liquids (Bbl. per day) Leasehold ownership---------- 1,538 1,037 609 593 804 Plant ownership-------------- 140 144 54 104 144 Price (per Bbl.)--------- $ 11.90 $ 13.50 $ 14.21 $ 13.75 $ 10.16 CAPITAL EXPENDITURES(A) (Expressed in thousands) Oil and gas: Domestic Offshore: Exploration---------------------- $ 4,600 $ 1,700 $ 1,600 $ 2,900 $ 4,700 Development---------------------- 33,700 5,500 23,600 24,900 15,900 Purchase of reserves------------- -- 8,900 5,100 -- -- Domestic Onshore: Exploration---------------------- 5,200 4,900 4,700 2,300 1,900 Development---------------------- 24,300 15,600 13,900 8,100 2,100 International Exploration---------- 4,600 1,400 -- -- -- Total oil and gas---------------- $ 72,400 $ 38,000 $ 48,900 $ 38,200 $ 24,600 Other-------------------------------- 200 600 2,400 -- 300 TOTAL---------------------------- $ 72,600 $ 38,600 $ 51,300 $ 38,200 $ 24,900 (a) Prior years have been restated to include interest capitalized and to reflect non oil and gas (Other) capital expenditures as a separate category.
23 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. RESULTS OF OPERATIONS The Company reported net income for 1993 of $25,061,000 or $0.76 per share compared to net income for 1992 of $18,495,000 or $0.66 per share and net income for 1991 of $11,658,000 or $0.42 per share. Included in net income for 1991 are extraordinary gains of $1,336,000 or $0.05 per share in connection with purchases at less than face value of the Company's 8% Convertible Subordinated Debentures due 2005 (the 'Convertible Subordinated Debentures'). Earnings per common share are based on the weighted average number of shares of common and common equivalent shares outstanding for 1993 of 32,860,000 compared to 27,929,000 for 1992 and 27,611,000 for 1991. The increases in the weighted average number of common and common equivalent shares outstanding for 1993 primarily related to the issuance of 4,500,000 shares of common stock in December 1992 as set forth in the Consolidated Statements of Shareholders' Equity included in 'Item 8. Financial Statements and Supplementary Data.' The Company's total revenues for 1993 were $139,554,000, or approximately equal to total revenues of $140,830,000 for 1992, and an increase of approximately 12% from total revenues of $124,469,000 for 1991. The Company's oil and gas revenues for 1993 were $136,553,000, a slight decrease of approximately 2% from oil and gas revenues of $139,128,000 for 1992, and an increase of approximately 10% from oil and gas revenues of $124,425,000 for 1991. The following table reflects an analysis of variances in the Company's oil and gas revenues between 1993 and the previous two years: 1993 COMPARED TO 1992 1991 (IN THOUSANDS) Increase (decrease) in oil and gas revenues resulting from variances in: Natural gas Price------------------------ $ 8,738 $ 11,984 Production------------------- (9,931) (9,036) (1,193) 2,948 Crude oil and condensate Price------------------------ (7,514) (8,209) Production------------------- 7,332 17,831 (182) 9,622 Natural gas liquids Price------------------------ (689) (560) Production------------------- 2,144 4,406 1,455 3,846 Other, net----------------------- (2,655) (4,288) Increase (decrease) in oil and gas revenues--------------------------- $ (2,575) $ 12,128 Average natural gas prices received by the Company for the two years prior to 1991 were relatively stable. Though seasonal variations were experienced, the average annual prices received per Mcf were $1.88 for 1989 and $1.89 for 1990. The industry's perceived ability to deliver more natural gas on a daily basis than demanded by customers resulted in a decrease in the average annual price for 1991 to $1.66 per Mcf. Prices of natural gas reached a low in February 1992, when the Company's prices averaged only $1.13 per Mcf, during a time of typically high winter prices, due, in part, to decreased demand resulting from a milder than anticipated winter. The natural gas prices received by the Company then began recovering again, averaging $1.75 per Mcf for 1992 and $1.98 per Mcf for 24 1993. Prices recovered after February 1992 due to late winter cold snaps which drew down natural gas storage supplies and created demand in the spring and summer to replenish storage facilities. In late August 1992, production in the Gulf of Mexico was shut-in for approximately four days as a result of Hurricane Andrew. This shut-in and decreased production from hurricane damage put upward pressure on natural gas prices for the balance of the year. Natural gas prices continued to strengthen in 1993, partially as a result of severe late winter weather that drew down natural gas storage supplies which, coupled with relatively high crude oil prices that inhibited fuel switching from natural gas to residual heating oil at that time, created a substantial demand in the spring and the summer to replenish depleted storage facilities and to supply natural gas for the industrial and electric generation markets. See 'Business -- Miscellaneous; Competition and Market Conditions.' Natural gas production in 1993 averaged 91.7 MMcf per day, a decrease of approximately 13% from average production of 105.2 MMcf per day in 1992, and a decrease of approximately 12% from average production of 104.2 MMcf per day in 1991. The Company's decrease in natural gas production during 1993 compared to prior periods was primarily related to decreased natural gas deliverability from certain of the Company's Gulf of Mexico wells; production downtime due to drilling, workover and maintenance operations designed to increase the Company's deliverability; weather related problems and the exchange of properties discussed in 'Business -- Domestic Offshore Acquisitions; Lease Acquisitions' which temporarily reduced the Company's delivery capacity. The Company anticipates that, as a result of its workover and drilling program, when natural gas production commences from its new platform currently under construction on Eugene Island Block 295 (which construction is scheduled, weather permitting, to be completed during March 1994) the Company's natural gas production will increase substantially from its average 1993 production rates. Crude oil and condensate prices averaged $17.81 per barrel in 1993 compared to $20.17 per barrel in 1992 and $20.98 per barrel in 1991. Crude oil and condensate prices were relatively stable during 1991, 1992 and the first six months of 1993. However, commencing in July 1993, the average price per barrel that the Company received for its production began to decline until, by December 1993, the average price per barrel for crude oil and condensate that the Company received for its production averaged only $13.39 per barrel. The decrease in the average price that the Company receives for its crude oil and condensate production has resulted primarily from a worldwide excess of crude oil supplies resulting from increased production from both Organization of Petroleum Exporting Countries ('OPEC') and certain non-OPEC countries coupled with flat or only marginally increased demand from consumer countries. See 'Business -- Miscellaneous; Competition and Market Conditions.' Crude oil and condensate production for 1993 averaged 9,851 Bbls per day, an increase of approximately 13% from 8,699 Bbls per day for 1992, and an increase of approximately 39% from 7,108 Bbls per day for 1991. The increase in crude oil and condensate production was a result of ongoing development programs both offshore (primarily in the Eugene Island area) and onshore in several fields located in Lea and Eddy counties of southeastern New Mexico. Liquid products are often extracted from natural gas streams and sold separately as natural gas liquids ('NGL'). The Company's NGL production averaged 1,678 Bbls per day for 1993, an increase of approximately 42% from an average of 1,181 Bbls per day for 1992 and an increase of approximately 153% from an average of 663 Bbls per day for 1991. The Company's NGL production during 1993, compared to prior periods, increased primarily as a result of extracting liquids from several new high Btu content wells, increased ownership interest in plants, and capital improvements which increased plant efficiency. The Company's total liquids production during 1993, including crude oil, condensate and NGL, averaged 11,529 Bbls per day, an increase of approximately 17% from an average total liquids production of 9,880 Bbls per day for 1992, and an increase of approximately 48% from an average total liquids production of 7,771 Bbls per day for 1991. 25 'Other, net' revenues for 1993, 1992, and 1991 included, among others, the following significant items: 1993 1992 1991 (IN THOUSANDS) Offset of FERC Order 93A adjustments against FERC Order 94A obligations------------------------ $ -- $ 1,642 $ -- Natural gas sales contract settlement------------------------- -- -- 2,750 Gains on retirement of debt---------- -- -- 646 Settlement of federal and state royalty disputes------------------- (803) (65) -- Other, net--------------------------- (147) 128 (58) $ (950) $ 1,705 $ 3,338 For 1993 and 1992, the Company made adjustments to its revenues to reflect the settlement of certain litigation with the State of Louisiana regarding past royalty disputes pertaining to the Company's offshore state leases. For 1992 additional adjustments were also made to reflect an agreement with the MMS to allow the Company to offset FERC Order 93A payments previously made by the Company on behalf of the MMS against FERC Order 94A obligations due from the Company and the resulting overaccrual of related interest expenses. For 1991, the Company recorded adjustments to reflect the settlement of a dispute regarding a natural gas sales contract and the purchase, at a discount, of certain of the Company's Convertible Subordinated Debentures on the open market. Lease operating expenses for 1993 were $26,633,000, an increase of approximately 3% from lease operating expenses of $25,842,000 for 1992, but a decrease of approximately 6% from lease operating expenses of $28,192,000 for 1991. The increase in lease operating expenses for 1993, compared to 1992, was primarily related to increased operating costs on existing properties, as well as increased operating costs related to additional properties brought on production in the second half of 1992. The increased operating costs were partially offset by lower maintenance costs. The decrease in lease operating expenses for 1993, compared to 1991, was primarily related to a decrease in special maintenance projects and to a decrease in lifting costs. General and administrative expenses for 1993 were $14,550,000, an increase of approximately 11% from general and administrative expenses of $13,129,000 for 1992, but were essentially equal to general and administrative expenses of $14,555,000 for 1991. The increase in general and administrative expenses for 1993, compared to 1992, was primarily related to increased business insurance premiums resulting from the Company's increased drilling activity and insurance premium rate increases resulting from the insurance industry's recent loss experience in general, rather than losses specifically relating to the Company's operations, as well as normal salary adjustments and a 4% increase in the Company's work force resulting from increased activity. Exploration expenses consist primarily of delay rentals and geological and geophysical ('G&G') costs which are expensed as incurred. Exploration expenses for 1993 were $2,455,000, a decrease of approximately 21% from exploration expenses of $3,102,000 for 1992, and a slight increase of approximately 2% from exploration expenses of $2,408,000 for 1991. The decline in exploration expenses for 1993, compared to 1992, was primarily related to the costs of conducting a G&G survey, primarily in 1992, on the Company's oil and gas concession in the Kingdom of Thailand. Dry hole and impairment expenses relate to costs of unsuccessful wells drilled along with impairments to the associated unproved property costs and impairments to previously proved property costs as a result of decreases in expected reserves. The Company's dry hole and impairment expenses for 1993 were $4,690,000, a decrease of approximately 50% from dry hole and impairment expenses of $9,314,000 for 1992, but a slight increase of approximately 3% from dry hole and impairment expenses of $4,554,000 for 1991. 26 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. 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 determined on a field-by-field basis using the units of production method. The Company's DD&A expense for 1993 was $40,693,000, a decrease of approximately 4% from DD&A expenses of $42,302,000 for 1992, but an increase of approximately 8% from DD&A expenses of $37,521,000 for 1991. The decreases in the Company's DD&A expenses for 1993, compared to 1992, were primarily due to a decrease in natural gas production. The increases in the Company's DD&A expenses for 1993, compared to 1991, were primarily related to increased volumes produced (largely related to the increased crude oil and condensate production discussed above) and, to a lesser extent, an increase in the composite DD&A rate. See 'Financial Statements and Supplementary Data -- Note 1 of Notes to Consolidated Financial Statements.' Interest charges for 1993 were $10,956,000, a decrease of approximately 42% from interest charges of $19,036,000 for 1992 and a decrease of approximately 56% from interest charges of $24,946,000 for 1991. The decrease in interest expense for 1993, compared to 1992 and 1991, related primarily to the retirement or refinancing of high cost debt at more favorable interest rates and the reduction in total debt to $134,539,000 on December 31, 1993, from $158,114,000 (including the production payment obligation) on December 31, 1992, a decrease of approximately 15%. In addition, interest expense has also been reduced, to a limited extent, by decreases in applicable floating interest rates. As of December 31, 1993, the Company had entered into swap agreements on $15,000,000 of its bank debt, $5,000,000 of which terminated in January 1994 and $10,000,000 of which terminates in July 1994. The swap agreements on the bank debt effectively change the interest the Company pays on its bank debt from variable rates to fixed rates which average 5.78% on the $15,000,000. LIQUIDITY AND CAPITAL RESOURCES The Consolidated Statement of Cash Flows for the year ended December 31, 1993 reflects net cash provided by operating activities of $83,144,000, proceeds from sales of tubular stock and non-strategic properties of $2,713,000 and cash received from stock options exercised of $2,026,000. The Company invested $62,353,000 of such cash flow in capital projects during 1993. The Company continued to reduce its total debt and production payment obligation from $158,114,000 at December 31, 1992 to $134,539,000 at December 31, 1993, a decrease of $23,575,000 or approximately 15% of the Company's combined debt and Eugene Island 330 production payment obligation since the end of 1992, and a decline of approximately 42% in its combined debt and Eugene Island 330 production payment obligation since the end of 1991. During 1993, the Company retired its Eugene Island 330 production payment obligation. The Company's cash and cash investments were $6,713,000 at December 31, 1993. The Company's capital and exploration budget for 1994 has been established by the Company's Board of Directors at $75,000,000, or approximately equal to the Company's capital and exploration expenditures of approximately $74,600,000 for 1993, an increase of 82% over capital and exploration expenditures of approximately $41,300,000 for 1992 and an increase of 41% over capital and exploration expenditures of approximately $53,100,000 for 1991. In addition to anticipated capital and exploration expenses as of December 31, 1993, other material 1994 cash requirements that the Company anticipates include an annual sinking fund requirement of $4,000,000 on the Company's 10.25% Convertible Subordinated Notes due 1999 (the 'Convertible Subordinated Notes') and ongoing operating, general and administrative, income tax, 27 and interest expenses. Cash requirements for future payments of federal income taxes are expected to be greater than those experienced in the immediate past. The increased tax payments are anticipated from increased taxable income, increased tax rates and the utilization in 1993 and prior years of available tax credits and tax loss carryforwards. The Company currently anticipates that cash provided by operating activities and funds available under its Credit Agreement will be sufficient to fund the Company's ongoing expenses and the Company's 1994 capital and exploration budget. As of December 31, 1993, the Company amended its bank credit agreement (the 'Credit Agreement'). The Credit Agreement currently provides for a $100,000,000 revolving/term credit facility which will be fully revolving until June 29, 1996, after which the balance will be due in eight quarterly term loan installments, commencing July 31, 1996. The amount that may be borrowed under the Credit Agreement may not exceed a borrowing base, determined semiannually by the lenders in accordance with the Credit Agreement, based on the discounted present value of certain of the Company's oil and gas reserves. The borrowing base currently exceeds $100,000,000. The Credit Agreement is governed by various financial and other covenants, including requirements to maintain positive working capital and a specified fixed charge ratio, and limitations on debt, dividends, mergers and consolidations, and asset dispositions. See 'Market for the Registrant's Common Stock and Related Security Holder Matters.' Upon the occurrence or declaration of certain events, the banks would be entitled to a security interest in the borrowing base properties, which include substantially all of the Company's domestic properties. Borrowings under the Credit Agreement bear interest at Base (Prime) rate plus 1/4%, a certificate of deposit rate plus 1 7/8%, or LIBOR plus 1 3/4%, at the Company's option. A commitment fee of 1/2 of 1% per annum of the unborrowed amount under the Credit Agreement is also due. As of December 31, 1993, indebtedness in the principal amount of $67,000,000 was outstanding under the Credit Agreement. The outstanding principal amount of the Convertible Subordinated Notes was $24,000,000 as of December 31, 1993. The Convertible Subordinated Notes are convertible into Common Stock at $23.95 per share, subject to adjustment in certain circumstances, including stock splits, and require annual sinking fund payments of $4,000,000 each April, with a final maturity of April 1, 1999. In addition, the Company is entitled to make optional sinking fund payments at par in amounts up to $4,000,000 per year, with maximum optional sinking fund payments at par of $12,000,000. The outstanding principal amount of the Convertible Subordinated Debentures was $43,539,000 as of December 31, 1993. The Convertible Subordinated Debentures are convertible into Common Stock at $39.50 per share, subject to adjustment in certain circumstances, including stock splits, and are also subject to mandatory annual sinking fund requirements of $3,000,000, due each December, with a final maturity of December 31, 2005. The Company currently has $4,460,000 face amount of Convertible Subordinated Debentures which it may tender in satisfaction of future sinking fund requirements. See 'Financial Statements and Supplementary Data -- Note 3 to Notes to Consolidated Financial Statements.' OTHER MATTERS 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 dollar is running much below the general annual inflation rates of several years ago. While the Company, like other companies, continues to be affected by fluctuations in the purchasing power of the dollar, such effect is not currently considered significant. 28 ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1993 POGO PRODUCING COMPANY AND SUBSIDIARIES HOUSTON, TEXAS 29 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, 1993 and 1992, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of Pogo's management. Our responsibility is to express an opinion on these financial statements and schedules 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, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in Item 14(a)-2 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN & CO. Houston, Texas February 8, 1994 30 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME YEAR ENDED DECEMBER 31, 1993 1992 1991 (EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Oil and gas---------------------- $ 136,553 $ 139,128 $ 124,425 Interest on tax refund----------- 2,322 -- -- Gains on sales------------------- 679 1,702 44 Total------------------------ 139,554 140,830 124,469 Operating Costs and Expenses: Lease operating------------------ 26,633 25,842 28,192 General and administrative------- 14,550 13,129 14,555 Exploration---------------------- 2,455 3,102 2,408 Dry hole and impairment---------- 4,690 9,314 4,554 Depreciation, depletion and amortization------------------- 40,693 42,302 37,521 Total------------------------ 89,021 93,689 87,230 Operating Income--------------------- 50,533 47,141 37,239 Interest: Charges-------------------------- (10,956) (19,036) (24,946) Income--------------------------- 14 191 1,686 Capitalized---------------------- 451 391 637 Income Before Taxes and Extraordinary Item--------------------------------- 40,042 28,687 14,616 Income Tax Expense------------------- (14,981) (10,192) (4,294) Income Before Extraordinary Item----- 25,061 18,495 10,322 Extraordinary Gains on Purchase of Debt, net of tax------------------- -- -- 1,336 Net Income--------------------------- $ 25,061 $ 18,495 $ 11,658 Primary and Fully Diluted Earnings per Common Share: Before extraordinary item-------- $0.76 $0.66 $0.37 Extraordinary item--------------- -- -- 0.05 Net income----------------------- $0.76 $0.66 $0.42 The accompanying notes to consolidated financial statements are an integral part hereof. 31 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1993 1992 (EXPRESSED IN THOUSANDS) ASSETS Current Assets: Cash and cash investments-------- $ 6,713 $ 5,037 Accounts receivable-------------- 18,480 22,652 Other receivables---------------- 10,123 4,173 Federal income taxes and interest receivable--------------------- 3,320 -- Inventories---------------------- 1,105 1,383 Other---------------------------- 727 367 Total current assets--------- 40,468 33,612 Property and Equipment: Oil and gas, on the basis of successful efforts accounting Proved properties being amortized------------------ 817,218 869,192 Unproved properties and properties under development, not being amortized------------------ 6,465 5,962 Other, at cost------------------- 6,961 6,851 830,644 882,005 Less -- accumulated depreciation, depletion, and amortization, including $4,452 and $4,032, respectively, applicable to other property----------------- 638,658 717,428 191,986 164,577 Other-------------------------------- 7,320 8,158 $ 239,774 $ 206,347 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable----------------- $ 8,307 $ 9,899 Other payables------------------- 22,955 5,541 Current portion of long-term debt--------------------------- 4,000 4,000 Current portion of production payment------------------------ -- 10,517 Accrued interest payable--------- 1,202 1,122 Accrued payroll and related benefits----------------------- 1,005 942 Other---------------------------- 122 142 Total current liabilities---- 37,591 32,163 Long-Term Debt----------------------- 130,539 129,260 Production Payment------------------- -- 14,337 Deferred Federal Income Tax---------- 29,724 17,435 Deferred Credits--------------------- 8,117 7,504 Total liabilities------------ 205,971 200,699 Shareholders' Equity: Preferred stock, $1 par; 2,000,000 shares authorized---- -- -- Common stock, $1 par; 43,333,333 shares authorized, 32,449,197 and 32,103,864 shares issued, respectively------------------- 32,449 32,104 Additional capital--------------- 125,919 122,846 Retained earnings (deficit)------ (124,241) (149,302) Treasury stock, at cost---------- (324) -- Total shareholders' equity--------------------- 33,803 5,648 $ 239,774 $ 206,347 The accompanying notes to consolidated financial statements are an integral part hereof. 32 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS YEAR ENDED DECEMBER 31, 1993 1992 1991 (EXPRESSED IN THOUSANDS) Cash flows from operating activities: Cash received from customers------- $ 141,012 $ 135,877 $ 125,029 Operating, exploration, and general and administrative expenses paid------------------------------ (45,051) (41,360) (46,746) Interest paid---------------------- (10,912) (21,262) (26,701) Payment of royalties and related interest on FERC Order 94-A refunds--------------------------- -- (4,872) -- Federal income taxes paid---------- (2,800) (1,500) (2,900) Federal income taxes and interest received-------------------------- -- -- 30,836 Settlement of natural gas sales contract-------------------------- -- -- 3,300 Proceeds of life insurance policy---------------------------- -- -- 2,568 Other------------------------------ 895 828 2,974 Net cash provided by operating activities------- 83,144 67,711 88,360 Cash flows from investing activities: Capital expenditures--------------- (62,353) (30,304) (51,284) Purchase of proved reserves-------- -- (8,924) (5,077) Proceeds from the sale of property and tubular stock----------------- 2,713 4,017 2,150 Net cash used in investing activities----------------- (59,640) (35,211) (54,211) Cash flows from financing activities: Net borrowings (payments) under revolving credit agreements------- 8,000 (1,000) 17,000 Principal payments of other long-term debt obligations-------- (7,000) (54,000) (42,000) Principal payments of production payment obligation---------------- (24,854) (20,621) (14,611) Proceeds from exercise of stock options--------------------------- 2,026 703 123 Proceeds from issuance of common stock----------------------------- -- 43,313 -- Debt issue expenses paid----------- -- (1,100) -- Increase in production payment----- -- -- 13,193 Purchase of 8% debentures, due 2005------------------------------ -- -- (7,621) Net cash used in financing activities----------------- (21,828) (32,705) (33,916) Net increase (decrease) in cash and cash investments-------------------- 1,676 (205) 233 Cash and cash investments at the beginning of the year--------------- 5,037 5,242 5,009 Cash and cash investments at the end of the year------------------------- $ 6,713 $ 5,037 $ 5,242 Reconciliation of net income to net cash provided by operating activities: Net income------------------------- $ 25,061 $ 18,495 $ 11,658 Adjustments to reconcile net income to net cash provided by operating activities -- Gains on purchase of 8% debentures, due 2005: Ordinary----------------------- -- -- (646) Extraordinary, net of taxes---- -- -- (1,336) Gains on sales------------------- (679) (1,702) (44) Depreciation, depletion and amortization-------------------- 40,693 42,302 37,521 Dry hole and impairment---------- 4,690 9,314 4,554 Interest capitalized------------- (451) (391) (637) Change in assets and liabilities: Decrease in United Kingdom tax escrow deposit---------------- -- -- 2,083 (Increase) decrease in accounts receivable-------------------- 4,172 (1,191) 4,799 (Increase) decrease in federal income taxes and interest receivable-------------------- (3,320) -- 29,002 Increase in other current assets------------------------ (360) (27) (32) (Increase) decrease in other assets------------------------ 838 (3,515) 1,641 Increase (decrease) in accounts payable----------------------- (1,592) 733 (1,322) Increase (decrease) in accrued interest payable-------------- 80 (2,480) (1,342) Increase (decrease) in accrued payroll and related benefits---------------------- 63 (244) 375 Increase (decrease) in other current liabilities----------- (20) (9) 62 Increase in deferred federal income taxes------------------ 13,356 8,669 1,268 Increase (decrease) in deferred credits----------------------- 613 (2,243) 756 Net cash provided by operating activities-------------------------- $ 83,144 $ 67,711 $ 88,360 The accompanying notes to consolidated financial statements are an integral part hereof. 33
POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY SHARE- RETAINED HOLDERS' SHARES COMMON ADDITIONAL EARNINGS TREASURY EQUITY OUTSTANDING STOCK CAPITAL (DEFICIT) STOCK (DEFICIT) (DOLLARS EXPRESSED IN THOUSANDS) Balance at December 31, 1990--------- 27,428,652 $ 27,428 $ 83,598 $ (179,455) $ -- $ (68,429) Net income--------------------------- -- -- -- 11,658 -- 11,658 Exercise of stock options------------ 28,170 29 106 -- -- 135 Balance at December 31, 1991--------- 27,456,822 27,457 83,704 (167,797) -- (56,636) Net income--------------------------- -- -- -- 18,495 -- 18,495 Issuance of common stock------------- 4,500,000 4,500 38,368 -- -- 42,868 Exercise of stock options------------ 147,042 147 774 -- -- 921 Balance at December 31, 1992--------- 32,103,864 32,104 122,846 (149,302) -- 5,648 Net income--------------------------- -- -- -- 25,061 -- 25,061 Exercise of stock options------------ 345,308 345 3,072 -- -- 3,417 Acquisition of treasury stock at cost (15,575) -- -- -- (324) (324) Conversion of debenture-------------- 25 -- 1 -- -- 1 Balance at December 31, 1993--------- 32,433,622 $ 32,449 $ 125,919 $ (124,241) $ (324) $ 33,803
The accompanying notes to consolidated financial statements are an integral part hereof. 34 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION -- The consolidated financial statements include the accounts of Pogo Producing Company and its wholly-owned subsidiaries (the 'Company'), after elimination of all significant intercompany transactions. INVENTORIES -- Inventories consist primarily of tubular goods used in the Company's operations and are stated at the lower of average cost or market value. INTEREST CAPITALIZED -- Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated. EARNINGS PER SHARE -- Earnings per common and common equivalent share are based on weighted average shares of Common Stock outstanding assuming exercise of dilutive stock options. The 8% convertible subordinated debentures, due 2005 are common stock equivalents and were anti-dilutive in all periods presented. The 10.25% convertible subordinated notes, due 1999 are not common stock equivalents and were anti-dilutive in all periods presented. The weighted average number of common and common stock equivalent shares outstanding for primary earnings per share was 32,860,000, 27,929,000, and 27,611,000 in 1993, 1992, and 1991, respectively. The additional shares which would be assumed to be outstanding in the fully diluted calculation are not sufficient to change the earnings per share amounts reported in the primary calculation. 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, 1993, the Company had taken approximately 10,195 MMcf of natural gas less than it was entitled to based on its interest in those properties, and approximately 7,295 MMcf more than its entitlement on other properties placing the Company at year end in a net under-delivered position of approximately 2,900 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. 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 determined on a field-by-field basis using the units of production method. 35 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Other properties are depreciated on 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 Statement of Cash Flows. Certain such noncash transactions are disclosed in the Consolidated Statements of Shareholders' Equity relating to the acquisition of treasury stock in exchange for stock options exercised and the conversion of a debenture into Common Stock. In addition, the Company exchanged its working interest in thirteen Gulf of Mexico oil and gas properties for an increased working interest in five other Gulf of Mexico oil and gas properties in a noncash 'like kind' exchange. The oil and gas property and accumulated depreciation, depletion and amortization accounts as reflected in the Consolidated Balance Sheets have been adjusted to reflect the appropriate amounts to record the working interests acquired and disposed of. The oil and gas reserves acquired and disposed of are reflected as purchases and sales in the roll forward 'Estimates of Proved Reserves' included in the 'Unaudited Supplementary Financial Data' included elsewhere herein. COMMITMENTS AND CONTINGENCIES -- The Company's rent expense was $868,000, $808,000, and $1,069,000 in 1993, 1992, and 1991, respectively. The Company has lease commitments for office space of $809,000 per year in each year for 1994 through 1997 and $777,000 in 1998. (2) INCOME TAXES The components of federal income tax expense (benefit) for each of the three years in the period ended December 31, 1993, are as follows (expressed in thousands): 1993 1992 1991 United States Current-------------------------- $ 2,800 $ 1,500 $ 2,900 Deferred (a)--------------------- 12,360 8,672 1,125 Foreign Current-------------------------- (179) 20 269 Total------------------------ $ 14,981 $ 10,192 $ 4,294 (a) Excludes $688,000 of deferred taxes on a $2,024,000 extraordinary item in 1991. Total federal income tax expense (benefit) for each of the three years in the period ended December 31, 1993, 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): 1993 1992 1991 Federal statutory income tax rate---- 35.0% 34.0% 34.0% Increases (reductions) resulting from: Statutory depletion in excess of tax basis---------------------- (0.4) (0.1) (0.9) Foreign taxes-------------------- 2.9 1.4 1.8 Life insurance loan proceeds----- -- -- (5.9) Other---------------------------- -- 0.2 0.4 37.5% 35.5% 29.4% 36 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The deferred federal income tax provision is the result of the difference between deferred tax liabilities determined at each balance sheet date. The deferred tax liabilities are determined by applying current tax laws to temporary differences in the recognition of revenue and expense for tax and financial purposes. Temporary differences arise primarily from the amortization of productive intangible drilling costs which are capitalized and amortized for financial statement purposes but are deducted for income tax purposes and differences in depreciation rates for tangible assets for financial and tax reporting purposes. As of December 31, 1993, the Company has general business credits of approximately $1,400,000, which can be used to reduce future income taxes. In addition, the Company has alternative minimum tax credits of approximately $4,235,000 which can be used to reduce future regular income taxes payable. (3) LONG-TERM DEBT Long-term debt and the amount due within one year at December 31, 1993 and 1992, consists of the following (dollars expressed in thousands): DECEMBER 31, 1993 1992 Senior debt -- Bank revolving credit agreements debt: Prime rate loans------------- $ 27,000 $ 9,000 LIBO Rate loans-------------- 40,000 50,000 Certificate of deposit rate loans---------------------- -- -- Total senior debt-------------------- 67,000 59,000 Subordinated debt -- 10.25% Convertible subordinated notes, due 1999, $4,000 annual sinking fund requirement-------------------- 24,000 28,000 8% Convertible subordinated debentures, due 2005, $1,540 sinking fund requirement in 1995 and a $3,000 annual sinking fund requirement thereafter--------- 43,539 46,260 Total subordinated debt-------------- 67,539 74,260 Total debt--------------------------- 134,539 133,260 Amount due within one year -- Current portion of long-term debt, consisting of sinking fund requirement on 10.25% notes---- (4,000) (4,000) Long-term debt----------------------- $ 130,539 $ 129,260 The bank revolving credit agreement entered into in December 1993, extends to the Company a $100,000,000 revolving/term credit facility which will be fully revolving until June 29, 1996 and will convert to a term loan with eight quarterly installments commencing July 31, 1996. The amount that may be borrowed under the facility may not exceed a borrowing base, determined semiannually by the lenders based on the discounted present value of the Company's oil and gas reserves and the provisions of the agreement. The borrowing base currently exceeds $100,000,000. The agreement provides that total debt and total debt for borrowed money, as defined, may not exceed $230,000,000 and $200,000,000, respectively. The facility is governed by various financial covenants including the maintenance of positive working capital (excluding current maturities of debt), a fixed charge ratio, as defined, of 1.7 or greater, a $10,000,000 limit on other senior debt, and a $10,000,000 limit on prepayment (without refinancing) of subordinated debt in any one year and $20,000,000 in total through July 31, 1996. Upon the occurrence of an event of default or certain other specified events, the banks would be entitled to a security interest in the borrowing base properties, which constitute substantially all of the Company's domestic oil and gas properties. Borrowings under the facility bear 37 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) interest at Base (Prime) rate plus 1/4%, a certificate of deposit rate plus 1 7/8%, or LIBOR plus 1 3/4%, at the Company's option. A commitment fee of 1/2 of 1% per annum of the unborrowed amount under the facility is also due. The Company incurred commitment fees of $149,000 in 1993, $80,000 in 1992, and $132,000 in 1991 under this and prior revolving credit agreements. The 10.25% convertible notes are convertible into Common Stock at $23.95 per share subject to adjustment under certain circumstances, including stock splits. The convertible debentures are redeemable at the option of the Company at 103.7% through April 1, 1994, at 102.95% through April 1, 1995, and decreasing percentages thereafter, under certain market conditions, and are subject to mandatory annual sinking fund requirements of $4,000,000 which commenced April 1, 1990. The sinking fund requirements will be sufficient to retire 90% of the issue prior to maturity. The 8% convertible debentures are convertible into Common Stock at $39.50 per share subject to adjustment under certain circumstances, including stock splits. These convertible debentures are redeemable at the option of the Company at 102.8% through December 30, 1994, and decreasing percentages thereafter, and are subject to mandatory annual sinking fund requirements of $3,000,000 which commenced December 31, 1990. Such requirements will be sufficient to retire 75% of the issue prior to maturity. To date, the Company has purchased $13,740,000 principal amount of the bonds at less than face value resulting in ordinary gains of $646,000 and $902,000 in 1991 and 1990, respectively, on the bonds purchased in satisfaction of sinking fund requirements in those years, and a $1,336,000 extraordinary gain (net of taxes) in 1991 on the bonds purchased in excess of current sinking fund requirements. The Company currently has $4,460,000 face amount of the bonds purchased in excess of current sinking fund requirements which may be tendered in satisfaction of future sinking fund requirements. The Company elected to make the December 31, 1993 sinking fund payment in cash. Current maturities and sinking fund requirements during the next five years in connection with the above long-term debt are $4,000,000 in 1994, $5,540,000 in 1995, $27,100,000 in 1996, $40,500,000 in 1997 and $20,400,000 in 1998. Included in the current maturities reflected above are $20,100,000 in 1996, $33,500,000 in 1997, and $13,400,000 in 1998 relative to bank debt. The Company has established a history of refinancing its bank debt before scheduled maturities and expects to do so again before the amortization of bank debt commences in 1996. In 1993, the Company entered into interest rate swap agreements on $15,000,000 of its bank debt, $5,000,000 of which terminated in January, 1994 and $10,000,000 of which terminates in July, 1994. The swap agreements effectively change the interest rates from variable to fixed rates which average 5.78% on the $15,000,000. (4) SALES TO MAJOR CUSTOMERS The Company is an oil and gas exploration and production company that until recently sold its production to relatively few customers. As a result of recent changes in the natural gas industry, the Company, like many other producers, now sells its natural gas to numerous customers on a month-to-month basis. The Company no longer has a significant amount of its natural gas reserves committed to long-term (multiple year) contracts at higher than prevailing market prices. Sales to the following customers exceeded 10 percent of oil and gas revenues during the years indicated (expressed in thousands): 1993 1992 1991 Scurlock Oil Company----------------- $ 38,510 $ 39,729 $ 38,554 United Gas Pipeline Company---------- $ -- $ -- $ 21,074 Enron Corp--------------------------- $ 16,437 $ -- $ -- 38 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (5) EMPLOYEE BENEFITS A total of 2,353,069 shares of Common Stock are reserved for issuance to key employees and non-employee directors under the Company's stock option plans. The stock option plans authorize the granting of options 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 granted and, if not exercised, expire 10 years from the date of grant. At January 1, 1993, 1,544,484 shares were issuable under stock options outstanding. Options for 291,500 shares were granted during 1993 at prices ranging from $15.13 to $19.00 per share. During 1993, 345,308 options were exercised at prices ranging from $4.38 to $16.25 per share and no options were cancelled. At December 31, 1993, options to purchase 1,490,676 shares were outstanding (1,098,815 were exercisable) at prices ranging from $4.38 to $19.00. 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, and the Company makes matching contributions of up to 6% thereof. 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. Funds 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 $125,000 to the savings plan in 1993, $288,000 in 1992, and $265,000 in 1991. 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, 1993, 1992, and 1991. 1993 1992 1991 Actuarial present value (discounted at 7 1/2, 8 1/4, and 8 1/2%, respectively) of benefit obligations: Accumulated benefit obligations -- Vested----------------------- $ 4,019 $ 3,120 $ 2,997 Nonvested-------------------- 717 701 657 Total accumulated benefit obligations------------------ 4,736 3,821 3,654 Projected salary increases (escalated at 6%) and other changes------------------------ 1,500 2,653 2,441 Projected benefit obligations for service rendered to date------- 6,236 6,474 6,095 Plan assets at fair value, primarily listed securities with an expected long-term rate of return of 8 1/4%----------------------------- 13,481 13,830 13,505 Plan assets in excess of projected benefit obligations---------------- 7,245 7,356 7,410 Unrecognized: Net overfunding being recognized over 15 years------------------ (750) (853) (957) Net gain arising from the difference between actual experience and that assumed---- (3,209) (3,956) (4,438) Prior service cost--------------- (473) (41) (45) Accrued retirement plan asset-------- $ 2,813 $ 2,506 $ 1,970 (TABLE CONTINUED ON FOLLOWING PAGE) 39 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 1993 1992 1991 Retirement plan cost (benefit) for 1993, 1992, and 1991 included the following components: Service cost, benefits accruing each year with proration for future salary increases-------- $ 611 $ 514 $ 501 Interest cost on projected benefit obligations------------ 524 451 508 Actual return on plan assets----- (1,164) (1,141) (3,882) Net amortization and deferral---- (278) (360) 2,853 Accrued retirement plan cost (benefit)---------------------- $ (307) $ (536) $ (20) Effective January 1, 1992, the Company adopted the provisions of the Statement of Financial Accounting Standards No. 106, 'Employers' Accounting for Postretirement Benefits Other Than Pensions.' The Company currently provides full medical benefits to its retired employees and dependents. For current employees, the Company assumes all or a portion of postretirement medical and term life insurance costs based on the employee's age and length of service with the Company. The postretirement medical plan has no assets and is currently funded by the Company on a pay-as-you-go basis. The following is an analysis (in thousands of dollars) of the annual expense and activity in the deferred cost and benefits obligation accounts for 1992 and 1993. The computation assumes that future increases in medical costs will trend down from 13% to 7% per year over the next 12 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 postretirement benefits cost for 1993 by $164,000 and the accumulated postretirement benefits obligation as of December 31, 1993 by $1,171,000. ANNUAL DEFERRED BENEFITS EXPENSE COSTS OBLIGATION Transition obligation at January 1, 1992------------------------------- $ 4,263 $ (4,263) Amortization of transition cost over 14 years representing the average remaining service period of eligible employees----------------- $ 305 (305) 305 Service cost, including interest----- 303 Interest cost on transition obligation------------------------- 362 1992 expense------------------------- $ 970 (970) Current benefits paid---------------- 170 Balance at December 31, 1992--------- 3,958 (4,758) Amortization of transition costs over 14 years--------------------------- $ 305 (305) 305 Service cost, including interest----- 368 Interest cost on transition obligation------------------------- 407 1993 expense------------------------- $ 1,080 (1,080) Current benefits paid---------------- 246 Unrecognized loss-------------------- (1,400) Balance at December 31, 1993--------- $ 3,653 Plan assets at fair value------------ -- Funded status at December 31, 1993 (discounted at 7 1/2%)---- $ (6,687) 40 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The accumulated postretirement benefit obligation (in thousands of dollars) at December 31, 1993 is attributable to the following groups: Retirees and beneficiaries----------------------------------- $ 2,739 Dependents of retirees--------------------------------------- 1,188 Fully eligible active employees------------------------------ 577 Active employees, not fully eligible------------------------- 2,183 $ 6,687 (6) 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 The carrying value approximates fair value because of the short maturity of these investments. DEBT INSTRUMENT BASIS OF FAIR VALUE ESTIMATE Bank revolving credit agreement debt------------------------------- Fair value is carrying value based on recent 1993 renegotiation with banks 10.25% Convertible subordinated notes, due 1999-------------------- Fair value is 103.7% of carrying value based on the redemption premium at December 31, 1993 8% Convertible subordinated debentures, due 2005--------------- Fair value is 99.5% of carrying value based on the quoted market price for this publicly traded debt at December 31, 1993 The estimated fair value of the Company's financial instruments (in thousands of dollars) are as follows: CARRYING FAIR VALUE VALUE Cash and cash investments------------ $ 6,713 $ 6,713 Debt--------------------------------- (134,539) (135,209) 41 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) 1993 -------------------------------------- Oil and gas revenues----------------- $ 136,553 $ 136,525 $ 28 Lease operating expense-------------- (26,633) (26,633) -- Exploration expense------------------ (2,455) (1,060) (1,395) Dry hole and impairment expense------ (4,690) (2,737) (1,953) Depreciation, depletion and amortization expense--------------- (40,224) (40,193) (31) Pretax operating results------------- 62,551 65,902 (3,351) Income tax (expense) benefit--------- (22,712) (22,891) 179 Operating results-------------------- $ 39,839 $ 43,011 $ (3,172) 1992 -------------------------------------- Oil and gas revenues----------------- $ 139,128 $ 139,128 $ -- Lease operating expense-------------- (25,842) (25,842) -- Exploration expense------------------ (3,102) (1,876) (1,226) Dry hole and impairment expense------ (9,314) (9,314) -- Depreciation, depletion and amortization expense--------------- (41,849) (41,834) (15) Pretax operating results------------- 59,021 60,262 (1,241) Income tax expense------------------- (20,510) (20,490) (20) Operating results-------------------- $ 38,511 $ 39,772 $ (1,261) 1991 -------------------------------------- Oil and gas revenues----------------- $ 124,425 $ 124,425 $ -- Lease operating expense-------------- (28,192) (28,192) -- Exploration expense------------------ (2,408) (2,261) (147) Dry hole and impairment expense------ (4,554) (4,554) -- Depreciation, depletion and amortization expense--------------- (36,970) (36,965) (5) Pretax operating results------------- 52,301 52,453 (152) Income tax expense------------------- (17,725) (17,698) (27) Operating results-------------------- $ 34,576 $ 34,755 $ (179) The following table sets forth Pogo's capitalized costs (expressed in thousands) incurred for oil and gas producing activities during the years indicated. 1993 1992 1991 Capitalized costs incurred: Property acquisition (United States)------------------------ $ 1,520 $ 11,578 $ 7,697 Exploration -- United States---------------- 8,267 3,865 3,546 Kingdom of Thailand---------- 4,583 1,412 -- Development -- United States---------------- 57,648 20,717 37,025 Kingdom of Thailand---------- -- -- -- Interest capitalized (United States)------------------------ 451 391 637 $ 72,469 $ 37,963 $ 48,905 Provision for depreciation, depletion, and amortization: United States---------------- $ 40,193 $ 41,834 $ 36,965 Kingdom of Thailand---------- 31 15 5 $ 40,224 $ 41,849 $ 36,970 42 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. Their summary report dated January 28, 1994 is set forth as an exhibit to this Annual Report and includes definitions and assumptions that served as the basis for the discussion under the caption 'Item 1, Business -- Exploration and Production Data; Reserves'. Such definitions and assumptions should be referred to in connection with the following information. ESTIMATES OF PROVED RESERVES OIL, CONDENSATE AND NATURAL GAS LIQUIDS NATURAL GAS (BBLS.) (MMCF) Proved reserves (located in the United States) as of December 31, 1990------------------ 19,090,376 217,500 Revisions of previous estimates---------------------- 782,707 3,531 Extensions, discoveries, and other additions---------------- 1,612,983 16,157 Purchase of properties----------- 263,495 4,913 Sales of properties-------------- (5) (4) Estimated 1991 production-------- (2,931,465) (39,362) Proved reserves (located in the United States) as of December 31, 1991------------------ 18,818,091 202,735 Revisions of previous estimates---------------------- 1,721,385 20,284 Extensions, discoveries, and other additions (including 2,576,907 barrels and 10,668 MMcf located in the Kingdom of Thailand)---------------------- 5,486,273 19,126 Purchase of properties----------- 335,750 10,237 Sales of properties-------------- (194,606) (4,733) Estimated 1992 production-------- (3,611,105) (40,581) Proved reserves (located in the United States except for 2,576,907 barrels and 10,668 MMcf located in the Kingdom of Thailand) as of December 31, 1992------------------ 22,555,788 207,068 Revisions of previous estimates---------------------- 342,022 1,148 Extensions, discoveries, and other additions (including 2,847,906 barrels and 22,806 MMcf located in the Kingdom of Thailand)----------- 9,764,408 55,626 Purchase of properties----------- 182,610 13,192 Sales of properties-------------- (356,514) (11,849) Estimated 1993 production-------- (4,219,873) (32,319) Proved reserves (located in the United States except for 5,424,813 barrels and 33,474 MMcf located in the Kingdom of Thailand) as of December 31, 1993------------------ 28,268,441 232,866 Proved developed reserves (located in the United States) as of: December 31, 1990---------------- 17,841,751 202,471 December 31, 1991---------------- 17,549,830 188,090 December 31, 1992---------------- 18,798,149 175,523 December 31, 1993---------------- 20,976,194 183,139 43 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES 1993 TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND (EXPRESSED IN THOUSANDS) Future gross revenues---------------- $ 869,783 $ 744,201 $ 125,582 Future production costs: Lease operating expense---------- (186,464) (158,934) (27,530) Future development and abandonment costs------------------------------ (133,258) (79,735) (53,523) Future net cash flows before income taxes------------------------------ 550,061 505,532 44,529 Discount at 10% per annum------------ (146,221) (118,858) (27,363) Discounted future net cash flow Before income taxes---------------- 403,840 386,674 17,166 Future income taxes, net of discount at 10% per annum------------------- (103,580) (98,788) (4,792) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves-------- $ 300,260 $ 287,886 $ 12,374 1992 Future gross revenues---------------- $ 856,238 $ 791,865 $ 64,373 Future production costs: Lease operating expense---------- (179,721) (173,355) (6,366) Future development and abandonment costs------------------------------ (105,843) (80,887) (24,956) Future net cash flows before income taxes------------------------------ 570,674 537,623 33,051 Discount at 10% per annum------------ (165,573) (146,730) (18,843) Discounted future net cash flow before income taxes---------------- 405,101 390,893 14,208 Future income taxes, net of discount at 10% per annum------------------- (97,444) (91,848) (5,596) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves-------- $ 307,657 $ 299,045 $ 8,612 1991 Future gross revenues---------------- $ 725,360 $ 725,360 $ -- Future production costs: Lease operating expense---------- (163,262) (163,262) -- Future development and abandonment costs------------------------------ (67,671) (67,671) -- Future net cash flows before income taxes------------------------------ 494,427 494,427 -- Discount at 10% per annum------------ (144,673) (144,673) -- Discounted future net cash flow before income taxes---------------- 349,754 349,754 -- Future income taxes, net of discount at 10% per annum------------------- (76,423) (76,423) -- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves-------- $ 273,331 $ 273,331 $ -- 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. 44 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- (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. The standardized measure of discounted future net cash flows does not purport to present the fair market value of Pogo'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 unless otherwise noted. YEAR ENDED DECEMBER 31, 1993 TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND (EXPRESSED IN THOUSANDS) Beginning balance-------------------- $ 307,657 $ 299,045 $ 8,612 Revisions to prior years' proved reserves: Net changes in prices and production costs--------------- (41,775) (34,842) (6,933) Net changes due to revisions in quantity estimates------------- 4,066 4,066 -- Net changes in estimates of future development costs------- 662 (871) 1,533 Accretion of discount------------ 40,510 39,089 1,421 Changes in production rate------- 5,134 6,728 (1,594) Other---------------------------- 2,278 3,935 (1,657) Total revisions-------------- 10,875 18,105 (7,230) New field discoveries and extensions, net of future production and development costs:----------------- 39,247 29,059 10,188 Purchases of properties-------------- 22,516 22,516 -- Sales of properties------------------ (19,633) (19,633) -- Sales of oil and gas produced, net of production costs------------------- (110,870) (110,870) -- Previously estimated development costs incurred--------------------- 56,604 56,604 -- Net change in income taxes----------- (6,136) (6,940) 804 Net change in standardized measure of discounted future net cash flows------------- (7,397) (11,159) 3,762 Ending balance----------------------- $ 300,260 $ 287,886 $ 12,374 45 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- (CONTINUED) YEAR ENDED DECEMBER 31, 1992 1991 (EXPRESSED IN THOUSANDS) Beginning balance-------------------- $ 273,331 $ 400,937 Revisions to prior years' proved reserves: Net changes in prices and production costs--------------- 38,348 (174,464) Net changes due to revisions in quantity estimates------------- 42,829 9,940 Net changes in estimates of future development costs------- (21,015) (28,740) Accretion of discount------------ 34,975 52,517 Changes in production rate------- (5,733) (6,518) Other---------------------------- 6,607 (7,404) Total revisions-------------- 96,011 (154,669) New field discoveries and extensions, net of future production and development costs: United States---------------- 29,552 28,286 Kingdom of Thailand---------- 14,208 -- Purchases of properties-------------- 13,870 6,827 Sales of properties------------------ (7,430) (7) Sales of oil and gas produced, net of production costs------------------- (111,581) (92,895) Previously estimated development costs incurred--------------------- 20,717 37,039 Net change in income taxes: United States---------------- (15,425) 47,813 Kingdom of Thailand---------- (5,596) -- Net change in standardized measure of discounted future net cash flows------------- 34,326 (127,606) Ending balance----------------------- $ 307,657 $ 273,331 46 QUARTERLY RESULTS Summaries of Pogo's results of operations by quarter for the years 1993 and 1992 are as follows: QUARTER ENDED MAR. 31 JUNE 30 SEPT. 30 DEC. 31 (EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1993 Revenues----------------------------- $34,681 $ 34,533 $ 37,210 $ 33,130 Gross profit(a)---------------------- $17,331 $ 15,391 $ 17,903 $ 14,458 Net income--------------------------- $ 7,160 $ 5,596 $ 7,161 $ 5,144 Earnings per share (primary and fully diluted)-------- $ 0.22 $ 0.17 $ 0.22 $ 0.16 1992 Revenues----------------------------- $28,347 $ 34,072 $ 34,907 $ 43,504 Gross profit(a)---------------------- $ 7,147 $ 12,646 $ 16,165 $ 24,312 Net income (loss)-------------------- $(1,216) $ 3,276 $ 5,535 $ 10,900 Earnings (loss) per share (primary and fully diluted)-------- $ (0.04) $ 0.12 $ 0.20 $ 0.38 (a) Represents revenues less lease operating, exploration, dry hole and impairment, and depreciation, depletion and amortization expenses. ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. Not applicable. 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 26, 1994, to be filed within 120 days of December 31, 1993 pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the Company's '1994 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 1994 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 1994 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 1994 Proxy Statement is incorporated herein by reference. 47 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (A) FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, FINANCIAL STATEMENT SCHEDULES AND EXHIBITS PAGE 1. Financial Statements and Supplementary Data: Report of Independent Public Accountants----------------- 30 Consolidated statements of income------------------------ 31 Consolidated balance sheets------------------------------ 32 Consolidated statements of cash flows-------------------- 33 Consolidated statements of shareholders' equity---------- 34 Notes to consolidated financial statements--------------- 35 2. Financial Statement Schedules: V --Property and Equipment for the Years Ended December 31, 1993, 1992 and 1991------------------- S-1 VI --Reserves for Depreciation, Depletion and Amortization of Property and Equipment For the Years Ended December 31, 1993, 1992 and 1991------- S-1 X --Supplementary Income Statement Information For the Years Ended December 31, 1993, 1992 and 1991--- S-2 Schedules other than those listed above are 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 3(a), Annual Report on Form 10-K for the year ended December 31, 1987, File No. 0-5468). *3(a)(1) -- 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 July 24, 1990. (Exhibit 3(a), Quarterly Report on Form 10-Q for the quarter ended June 30, 1990, File No. 0-5468). *4(a)(i) -- Credit Agreement dated as of September 23, 1992, among Pogo Producing Company, the lenders party thereto, Bank of Montreal as Agent, and Banque Paribas as Co-Agent. (Exhibit 10(a), Quarterly Report on Form 10-Q for the quarter ended September 30, 1992, File No. 1-7792). 4(a)(ii) -- First Amendment dated as of September 30, 1992 to Credit Agreement dated as of September 23, 1992, among Pogo Producing Company, the lenders party thereto, Bank of Montreal as Agent, and Banque Paribas as Co-Agent. 4(a)(iii) -- Second Amendment dated as of December 31, 1993 to Credit Agreement dated as of September 23, 1992, among Pogo Producing Company, the lenders party thereto, Bank of Montreal as Agent, and Banque Paribas as Co-Agent. 48 *4(b) -- Indenture dated as of October 15, 1980 to Chemical Bank, as Trustee. (Exhibit 4, File No. 2-69428). The Company agrees to furnish to the Commission upon request a copy of any agreement defining the rights of holders of long-term debt of the 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 the Company and its subsidiaries on a consolidated basis. EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (comprising Exhibits 10(a) through 10(f)(14)(ii), inclusive) *10(a) -- 1977 Stock Option Plan of Pogo Producing Company, as amended as of September 28, 1981 and July 24, 1984. (Exhibit 10(a), Annual Report on Form 10-K for the year ended December 31, 1984, File No. 0-5468). *10(a)(1) -- Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (with stock appreciation rights and without employment restrictions). (Exhibit 10(a)(1), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468). *10(a)(2) -- Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (with stock option appreciation rights and without employment restrictions). (Exhibit 10(a)(2), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468). *10(a)(3) -- Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (without stock appreciation rights and with employment restrictions). (Exhibit 10(a)(3), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468). *10(a)(4) -- Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (without stock option appreciation rights and with employment restrictions). (Exhibit 10(a)(4), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468). *10(a)(5) -- Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (with stock appreciation rights and with employment restrictions). (Exhibit 10(a)(5), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468). *10(a)(6) -- Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (with stock option appreciation rights and with employment restrictions). (Exhibit 10(a)(6), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468). *10(a)(7) -- Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (without stock appreciation rights and without employment restrictions). (Exhibit 10(a)(7), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468). *10(a)(8) -- Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (without stock option appreciation rights and without employment restrictions). (Exhibit 10(a)(8), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468). *10(b) -- 1981 Stock Option Plan of Pogo Producing Company, as amended as of July 24, 1984. (Exhibit 10(b), Annual Report on Form 10-K for the year ended December 31, 1984, File No. 0-5468). *10(b)(1) -- Form of Stock Option Agreement under 1981 Nonqualified Stock Option Plan (with stock appreciation rights). (Exhibit 10(b)(1), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468). *10(b)(2) -- Form of Stock Option Agreement under 1981 Nonqualified Stock Option Plan (without stock appreciation rights). (Exhibit 10(b)(2), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468). 49 *10(c) -- 1981 Incentive and Nonqualified Stock Option Plan of Pogo Producing Com- pany, as amended as of July 24, 1984. (Exhibit 10(c), Annual Report on Form 10-K for the year ended December 31, 1984, File No. 0-5468). *10(c)(1) -- Form of Stock Option Agreement under 1981 Incentive Stock Option Plan. (Exhibit 10(c)(1), Annual Report of Form 10-K for the year ended December 31, 1981, File No. 0-5468). *10(d) -- 1989 Incentive and Nonqualified Stock Option Plan of Pogo Producing Com- pany, as amended and restated effective January 22, 1991. (Exhibit 10(d), Annual Report on Form 10-K for the year ended December 31, 1991, file No. 0-5468). *10(d)(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(d)(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(e) -- Form of Letter Agreement respecting treatment of options upon change in control. (Exhibit 19(f), Quarterly Report on Form 10-Q for the quarter ended June 30, 1982. File No. 0-5468). *10(f)(1) -- Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated February 1, 1992. (Exhibit 19(a)(1), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792). *10(f)(2)(i) -- Extension Agreement to Continue Employment Agreement between Stuart P. Burbach and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(2), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792). 10(f)(2)(ii) -- Extension Agreement to Continue Employment Agreement between Stuart P. Burbach and Pogo Producing Company, dated as of February 1, 1994. *10(f)(3) -- Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated February 1, 1992. (Exhibit 19(a)(2), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792). *10(f)(4)(i) -- Extension Agreement to Continue Employment Agreement between Jerry A. Cooper and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(4), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792). 10(f)(4)(ii) -- Extension Agreement to Continue Employment Agreement between Jerry A. Cooper and Pogo Producing Company, dated as of February 1, 1994. *10(f)(5) -- Employment Agreement by and between Pogo Producing Company and Kenneth R. Good, dated February 1, 1992. (Exhibit 19(a)(3), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792). *10(f)(6)(i) -- Extension Agreement to Continue Employment Agreement between Kenneth R. Good and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(6), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792). 10(f)(6)(ii) -- Extension Agreement to Continue Employment Agreement between Kenneth R. Good and Pogo Producing Company, dated as of February 1, 1994. *10(f)(7) -- Employment Agreement by and between Pogo Producing Company and R. Phillip Laney, dated February 1, 1992. (Exhibit 19(a)(4), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792). *10(f)(8)(i) -- Extension Agreement to Continue Employment Agreement between R. Phillip Laney and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(8), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792). 50 10(f)(8)(ii) -- Extension Agreement to Continue Employment Agreement between R. Phillip Laney and Pogo Producing Company, dated as of February 1, 1994. *10(f)(9) -- Employment Agreement by and between Pogo Producing Company and John O. McCoy, Jr., dated February 1, 1992. (Exhibit 19(a)(5), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792). *10(f)(10)(i) -- Extension Agreement to Continue Employment Agreement between John O. McCoy, Jr. and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(10), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792). 10(f)(10)(ii) -- Extension Agreement to Continue Employment Agreement between John O. McCoy, Jr. and Pogo Producing Company, dated as of February 1, 1994. *10(f)(11) -- Employment Agreement by and between Pogo Producing Company and D. Stephen Slack, dated February 1, 1992. (Exhibit 19(a)(6), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792). *10(f)(12)(i) -- Extension Agreement to Continue Employment Agreement between D. Stephen Slack and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(12), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792). 10(f)(12)(ii) -- Extension Agreement to Continue Employment Agreement between D. Stephen Slack and Pogo Producing Company, dated as of February 1, 1994. *10(f)(13) -- Employment Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated February 1, 1992. (Exhibit 19(a)(7), Quarterly Report on Form 10-Q for the quarter ended June 30, 1992, File No. 1-7792). *10(f)(14)(i) -- Extension Agreement to Continue Employment Agreement between Paul G. Van Wagenen and Pogo Producing Company, dated as of February 1, 1993. (Exhibit 10(f)(14), Annual report on Form 10-K for the year ended December 31, 1992, File No. 1-7792). 10(f)(14)(ii) -- Extension Agreement to Continue Employment Agreement between Paul G. Van Wagenen and Pogo Producing Company, dated as of February 1, 1994. *10(g) -- Undertaking by Pogo Producing Company dated as of August 8, 1977. (Exhibit 10(e), Annual Report on Form 10-K for the year ended December 31, 1980, File No. 0-5468). *10(h) -- 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). 21 -- List of Subsidiaries of Pogo Producing Company. 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, 1993. 28 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers dated January 28, 1994 relating to oil and gas reserves of Pogo Producing Company. * Asterisk indicates exhibits incorporated by reference as shown. (B) REPORTS ON FORM 8-K None 51 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: February 28, 1994 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 FEBRUARY 28, 1994. SIGNATURES 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/ D. STEPHEN SLACK Principal Financial D. STEPHEN SLACK Officer and Director SENIOR VICE PRESIDENT, CHIEF FINANCIAL OFFICER AND TREASURER /s/ THOMAS E. HART Principal Accounting THOMAS E. HART Officer VICE PRESIDENT AND CONTROLLER TOBIN ARMSTRONG* Director TOBIN ARMSTRONG JACK S. BLANTON* Director JACK S. BLANTON W. M. BRUMLEY, JR.* Director W. M. BRUMLEY, JR. JOHN B. CARTER, JR.* Director JOHN B. CARTER, JR. WILLIAM L. FISHER* Director WILLIAM L. FISHER WILLIAM E. GIPSON* Director WILLIAM E. GIPSON GERRITT W. GONG* Director GERRITT W. GONG J. STUART HUNT* Director J. STUART HUNT FREDERICK A. KLINGENSTEIN* Director FREDERICK A. KLINGENSTEIN NICHOLAS R. PETRY* Director NICHOLAS R. PETRY JACK A. VICKERS* Director JACK A. VICKERS *By: /s/ THOMAS E. HART THOMAS E. HART ATTORNEY-IN-FACT 52 SCHEDULE V & VI POGO PRODUCING COMPANY AND SUBSIDIARIES SCHEDULE V -- PROPERTY AND EQUIPMENT FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991 (EXPRESSED IN THOUSANDS)
BALANCE BALANCE BEGINNING ADDITIONS RETIREMENT OTHER END OF DESCRIPTION OF PERIOD AT COST OR SALES CHANGES PERIOD 1993: Oil and gas---------------------- $ 875,154 $ 72,469 $ (120,893) $ (3,047) $ 823,683 Other---------------------------- 6,851 163 (48) (5) 6,961 Total---------------------------- $ 882,005 $ 72,632 $ (120,941) $ (3,052) $ 830,644 1992: Oil and gas---------------------- $ 907,336 $ 37,963 $ (61,182) $ (8,963) $ 875,154 Other---------------------------- 6,680 589 -- (418) 6,851 Total---------------------------- $ 914,016 $ 38,552 $ (61,182) $ (9,381) $ 882,005 1991: Oil and gas---------------------- $ 867,183 $ 48,905 $ (4,264) $ (4,488) $ 907,336 Other---------------------------- 9,270 2,416 (5,017) 11 6,680 Total---------------------------- $ 876,453 $ 51,321 $ (9,281) $ (4,477) $ 914,016
SCHEDULE VI -- RESERVES FOR DEPRECIATION, DEPLETION, AND AMORTIZATION OF PROPERTY AND EQUIPMENT FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991 (EXPRESSED IN THOUSANDS)
CHARGED TO RETIREMENT BALANCE PROFIT AND RENEWALS BALANCE BEGINNING LOSS OR AND OTHER END OF DESCRIPTION OF PERIOD INCOME REPLACEMENTS CHANGES PERIOD 1993: Oil and gas---------------------- $ 713,396 $ 40,224 $ (120,160) $ 746 $ 634,206 Other---------------------------- 4,032 469 (49) 4,452 Total---------------------------- $ 717,428 $ 40,693 $ (120,209) $ 746 $ 638,658 1992: Oil and gas---------------------- $ 730,835 $ 41,849 $ (60,887) $ 1,599 $ 713,396 Other---------------------------- 3,578 453 -- 1 4,032 Total---------------------------- $ 734,413 $ 42,302 $ (60,887) $ 1,600 $ 717,428 1991: Oil and gas---------------------- $ 696,459 $ 36,970 $ (2,622) $ 28 $ 730,835 Other---------------------------- 7,148 551 (4,089) (32 ) 3,578 Total---------------------------- $ 703,607 $ 37,521 $ (6,711) $ (4 ) $ 734,413
S-1 SCHEDULE X POGO PRODUCING COMPANY AND SUBSIDIARIES SCHEDULE X -- SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991 (EXPRESSED IN THOUSANDS) 1993 1992 1991 Maintenance and repairs-------------- $ 3,658 $ 4,435 $ 6,498 Taxes, other than payroll and income taxes: Severance, ad valorem, franchise and other------------------------ $ 3,133 $ 2,423 $ 2,222 S-2 EX-4.A.II 2 FIRST AMENDMENT TO CREDIT AGREEMENT EXHIBIT 4(a)(ii) POGO PRODUCING COMPANY ______________________ First Amendment Dated as of September 30, 1992 to Credit Agreement Dated as of September 23, 1992 ______________________ THIS FIRST AMENDMENT TO CREDIT AGREEMENT, dated as of September 30, 1992 (the "Amendment"), between Pogo Producing Company, a Delaware corporation (the "Borrower"), the various financial institutions which are or may become parties to the Credit Agreement, as amended hereby (collectively, the "Lenders"), Bank of Montreal, acting through its Chicago, Illinois branch, (the "Bank"), as agent (the "Agent") for the Lenders and Banque Paribas, acting through its Houston Agency, as co-agent (the "Co-Agent"), for the Lenders, W I T N E S S E T H WHEREAS the Borrower, the Lenders, the Agent and the Co-Agent are parties to a certain Credit Agreement dated as of September 23, 1992 (the "Credit Agreement"); and WHEREAS the Borrower desires to amend certain provisions of the Credit Agreement; NOW, THEREFORE, the parties hereto hereby agree as follows: 1. DEFINITIONS. 1.1 AMENDMENT. The definition of "EBITDA" as set forth in the Credit Agreement is amended in its entirety as set forth below and such definition is hereby incorporated by reference into the Credit Agreement, as amended by this Amendment: `"EBITDA" means, for any period for which a determination thereof is to be made, on a consolidated basis and without duplication, the sum of the amounts for such period of (i) net income (or loss) after taxes, (ii) interest expense, (iii) depreciation expense and depletion expense, (iv) amortization expense, (v) federal, state and foreign taxes, (vi) other non-cash charges and expenses and (vii) any losses arising outside of the ordinary course of business which have been included in the determination of consolidated net income; less any gains arising outside of the ordinary course of business which have been included in the determination of consolidated net income, all as determined on a consolidated basis for the Borrower and its Subsidiaries.' 1.2 USE OF DEFINED TERMS. Unless otherwise defined herein or the context otherwise requires, or except as the definition may be amended by this Amendment, terms used in this Amendment, including its preamble and recitals, shall have the meanings provided in the Credit Agreement, as hereby amended. 2. AMENDMENTS TO CREDIT AGREEMENT. 2.1 AMENDMENT OF SECTION 7.8 OF CREDIT AGREEMENT. Clause (e) of Section 7.8 of the Credit Agreement is replaced in its entirety by the following: "(e) the Borrower shall not have on or before July 31, 1994 (x) repaid in full (subject to Section 8.6(b) and to the proviso set forth below) the 12.5% State Farm Senior Subordinated Notes or (y) refinanced the 12.5% State Farm Senior Subordinated Notes (subject to the proviso set forth below) in whole on terms which shall provide for (i) covenants regarding the matters set forth in SECTION 8.4 that are no more restrictive than the covenants contained in SECTION 8.4 of this Agreement, (ii) subordination terms that are no less favorable to holders of the Notes than the original subordination terms contained in the 12.5% State Farm Senior Subordinated Notes, (iii) no principal payments in excess of $5,000,000 (less the principal amount of any 12.5% State Farm Senior Subordinated Notes that remain outstanding as contemplated by the proviso below) in the aggregate for any and all such principal payments before December 31, 1996 and (iv) except for principal payments contemplated by the preceding clause, no other scheduled principal payments due before December 31, 1997; PROVIDED THAT, notwithstanding the above, an aggregate principal amount of no more than $5,000,000 of the 12.5% State Farm Senior Subordinated Notes due on December 31, 1996 may remain outstanding, and such notes will nonetheless be deemed to have been repaid or refinanced in whole." 3. REPRESENTATIONS AND WARRANTIES. In order to induce the Lenders and the Agent to enter into this Amendment, the Borrower hereby reaffirms, as of the date hereof, its representations and warranties contained in Article VI of the Credit Agreement (except to the extent any such representation and warranty relates solely to an earlier date) and additionally represents and warrants as follows: 2 3.1 ORGANIZATION. The Borrower and each of its corporate Subsidiaries is a corporation validly organized and existing and in good standing under the laws of the state, or country, of its incorporation, and is duly qualified to do business and is in good standing as a foreign corporation in each jurisdiction where the nature of its business requires such qualification, except where failure to qualify would not have a material adverse effect on the business or financial condition of the Borrower and its Subsidiaries taken as a whole or the Borrower's ability to perform the Loan Documents, as such may be amended hereby, or this Amendment. Each of the Borrower's Subsidiaries which is organized as a partnership is validly organized and existing and in good standing under the laws of the state of its formation, and is duly qualified to do business and is in good standing as a foreign partnership where the nature of its business requires such qualification, except where failure to qualify would not have a material adverse effect on the business or financial condition of the Borrower, or the Borrower and its Subsidiaries taken as a whole or the Borrower's ability to perform under the Loan Documents, as such may be amended hereby, or this Amendment. The Borrower and each of its Subsidiaries has full power and authority and holds all requisite governmental licenses, permits and other approvals to enter into and perform its Obligations under the Credit Agreement, as amended hereby, each other Loan Document and this Amendment and to own and hold under lease its property and to conduct its business substantially as currently conducted by it. 3.2 DUE AUTHORIZATION, NON-CONTRAVENTION. The execution, delivery and performance by the Borrower of this Amendment and the consummation of the transactions contemplated hereby and by the Credit Agreement as so amended, are within the Borrower's corporate powers, have been duly authorized by all necessary corporate action, and do not (a) contravene the Borrower's Organic Documents; (b) contravene any contractual restriction, law or governmental regulation or court decree or order binding on or affecting the Borrower or any Subsidiary; or (c) result in, or require the creation or imposition of, any Lien on any properties of the Borrower or its Subsidiaries except as Liens will be imposed, created, or required upon execution and delivery of the Security Documents pursuant to SECTION 7.8 of the Credit Agreement. 3.3 GOVERNMENTAL APPROVAL. No authorization or approval or other action by, and no notice to or filing with, any governmental authority or regulatory body is required for the due execution, delivery or performance by the Borrower of this Amendment. 3 3.4 VALIDITY, ETC. This Amendment and the Credit Agreement as amended hereby constitute the legal, valid and binding obligations of the Borrower, enforceable in accordance with their respective terms except as such enforceability is subject to the effect of (i) any applicable bankruptcy, insolvency, reorganization or similar law relating to or affecting creditors' rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law), including concepts of materiality, reasonableness, good faith and fair dealing. 4. EFFECT OF AMENDMENT. This Amendment shall be deemed to be an amendment to the Credit Agreement, and the Credit Agreement, as amended hereby, is hereby ratified, approved and confirmed in each and every respect. All references to the Credit Agreement in any other document, instrument, agreement or writing shall hereafter be deemed to refer to the Credit Agreement as amended hereby. 5. GOVERNING LAW, SEVERABILITY, ETC. THIS AMENDMENT SHALL BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF THE STATE OF ILLINOIS. Whenever possible each provision of this Amendment shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Amendment shall be prohibited by or invalid under applicable law, such provision shall be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Amendment. THIS WRITTEN AMENDMENT AND THE CREDIT AGREEMENT AS AMENDED BY THIS AMENDMENT REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. 6. MISCELLANEOUS. 6.1 SUCCESSORS AND ASSIGNS. This Amendment shall be binding upon and shall inure to the benefit of the parties hereto and their respective successors and assigns. 6.2 COUNTERPARTS. This Amendment may be executed in one or more counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument. 6.3 EFFECTIVENESS. This Amendment shall become effective when counterparts hereof executed on behalf of the Borrower and each Lender (or notice thereof satisfactory to the Agent) shall 4 have been received by the Agent and notice thereof shall have been given by the Agent to the Borrower and each Lender. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly authorized as of the day and year first written above. POGO PRODUCING COMPANY By: D. STEPHEN SLACK Name: D. Stephen Slack Title: Sr. V.P. Finance BANK OF MONTREAL, acting through its U.S. branches and agencies, including initially its Chicago Illinois branch, as Agent By: MARK GREEN Name: Mark Green Title: Director BANQUE PARIBAS acting through its Houston Agency, as Co-Agent By: BARTON D. SCHOUEST Name: Barton D. Schouest Title: Group Vice President By: MEI WAN TONG Name: Mei Wan Tong Title: Vice President BANK OF MONTREAL By: MARK GREEN Name: Mark Green Title: Director 5 BANQUE PARIBAS By: BARTON D. SCHOUEST Name: Barton D. Schouest Title: Group Vice President By: MEI WAN TONG Name: Mei Wan Tong Title: Vice President THE FIRST NATIONAL BANK OF BOSTON By: ILLEGIBLE SIGNATURE Name: Title: NBD BANK, N.A. By: JAMES L. CALDWELL, IV Name: James L. Caldwell, IV Title: First Vice President 6 EX-4.A.III 3 SECOND AMENDMENT TO CREDIT AGREEMENT EXHIBIT 4(a)(iii) POGO PRODUCING COMPANY _______________________ Second Amendment Dated as of December 31, 1993 to Credit Agreement Dated as of September 23, 1992 THIS SECOND AMENDMENT TO CREDIT AGREEMENT, dated as of December 31, 1993 (the "Amendment"), between Pogo Producing Company, a Delaware Corporation (the "Borrower"), the various financial institutions which are or may become parties to the Credit Agreement, as amended hereby (collectively, the "Lenders"), Bank of Montreal, acting through its Chicago, Illinois branch, (the "Bank"), as agent (the "Agent") for the Lenders and Banque Paribas, acting through its Houston Agency, as co- agent (the "Co-Agent"), for the Lenders, W I T N E S S E T H WHEREAS the Borrower, the Lenders, the Agent and the Co-Agent are parties to a certain Credit Agreement dated as of September 23, 1992, as amended by the First Amendment to Credit Agreement dated as of September 30, 1992, (the "Credit Agreement"); and WHEREAS the Borrower desires to amend certain provisions of the Credit Agreement; NOW, THEREFORE, the parties hereto hereby agree as follows: 1. DEFINITIONS. 1.1 AMENDMENT. The following definitions as set forth in the Credit Agreement are amended in their entirety as set forth below and such definitions, as so amended, are hereby incorporated by reference into the Credit Agreement, as amended by this Amendment: "APPLICABLE MARGIN" means, at any time that the Borrower's Implied Senior Debt Rating is equal to any rating set forth below, the percentages per annum set forth opposite such Implied Senior Debt Rating for CD Rate Loans and LIBO Rate Loans; 2 provided, that if the Borrower's Implied Senior Debt Rating shall change at any time, the Applicable Margin set forth below shall become effective on the immediately next Quarterly Payment Date: MINIMUM IMPLIED SENIOR DEBT RATING FROM STANDARD & POORS (or an equivalent rating from Moodys or another approved rating agency) CD RATE LOANS LIBO RATE LOANS BB- or lower . . . . . . . . . 1 7/8% 1 3/4% BB (including BB+) . . . . . . 1 3/4% 1 5/8% BBB- or higher . . . . . . 1 5/8% 1 1/2% "BORROWING BASE" means, at any time, that amount, determined in accordance with SECTION 2.6 and calculated using information in the then most recent Reserve Report or Alternate Reserve Report, which equals the lesser of (i) the sum total of (a) the Discounted Present Value of the Future Net Income for each category of Proved Reserves multiplied by (b) the relevant Applicable Percentage for each category of Proved Reserves, and (ii) the product of 10/7 times sixty-five percent (65%) of the Discounted Present Value of Future Net Income attributable to the Proved Developed Producing Reserves. During the period from December 31, 1993, to the date of the next determination of the Borrowing Base pursuant to the provisions of SECTION 7.2, the amount of the Borrowing Base shall be One Hundred Million Dollars ($100,000,000) PROVIDED THAT, if pursuant to a Reserve Report dated January 1st of any year the ratio of (x) Borrowing Base to (y) Commitment Amount plus the amount of Senior Debt (other than the Loans) that is outstanding on such date which is permitted pursuant to SECTION 8.2(a)(ii) is at least 1.5 to 1.0, then the Borrowing Base shall not be redetermined pursuant to the Alternate Reserve Report dated as of the following July 1st. "BORROWING BASE PROPERTIES" means those oil and gas properties of the Borrower or, to the extent provided below, of a Majority- owned Subsidiary of the Borrower (including the Borrower's or such Majority-owned Subsidiary's pro rata share of Qualified Partnership Properties pro rated on the basis of the lesser of (i) Borrower's or such Majority-owned Subsidiary's share of income from the partnership and (ii) the Borrower's or such Majority-owned Subsidiary's share of partnership properties or proceeds thereof upon a liquidation of the partnership) included in the most recent Reserve Report or Alternate Reserve Report; PROVIDED, HOWEVER, that Borrowing Base Properties shall not include: (i) properties located outside the United States 3 (ii) properties owned by the Borrower's Subsidiaries (other than Qualified Partnership Properties to the extent of the Borrower's or its Subsidiary's pro rata share thereof) except as permitted by the provisions of the sentence immediately following, (iii) properties which secure Non-Recourse Indebtedness and (iv) properties subject to Liens other than those permitted under CLAUSES (d), (e), (f), (g) and (i) of SECTION 8.3; PROVIDED THAT, unless the Discounted Present Value of such properties, (i.e., i-iv), in the aggregate, is no more than $5,000,000, no properties of the Borrower or any Majority-owned Subsidiary of Borrower (including the Borrower's or such Majority-owned Subsidiary's pro rata share of Qualified Partnership Properties) included in the most recently delivered Reserve Report or Alternate Reserve Report, as the case may be, may be deleted from a subsequent Reserve Report or Alternate Reserve Report, including the imposition of a Lien thereon or the securing of Non-Recourse Indebtedness thereby, without the consent of the Required Lenders, which consent shall not be unreasonably withheld and shall not require the payment of a fee or other compensation by the Borrower. Notwithstanding the immediately preceding sentence, the Borrower or a Subsidiary of the Borrower may transfer Borrowing Base Properties to one or more Majority-owned Subsidiaries of the Borrower PROVIDED THAT (i) such transfer is permitted pursuant to SECTION 8.8(b) and (ii) the Subsidiary to which such properties are transferred by the Borrower or any Majority-owned Subsidiary of the Borrower shall have executed and delivered to the Agent a Subsidiary Guaranty. Nothing herein shall prevent a Subsidiary from transferring Borrowing Base Properties to the Borrower at any time. Eugene Island Block 330 shall be included as a Borrowing Base Property in the Reserve Report dated as of January 1, 1994. "CHANGE IN CONTROL" means the acquisition by any Person, or two or more Persons acting in concert, of beneficial ownership (within the meaning of Rule 13d-3 of the Securities and Exchange Commission under the Securities Exchange Act of 1934) of fifty percent (50%) or more of the outstanding shares of voting stock of the Borrower. "IMPLIED SENIOR DEBT RATING" means that "implied senior debt rating", if any, from time to time assigned to the Borrower by any of Standard & Poors, Moody's or another nationally recognized debt rating agency, PROVIDED THAT such other agency is acceptable to the Agent and Co-Agent. "LIEN" means any security interest, mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance or lien (statutory or other) of any kind or nature whatsoever with respect to any property, real or personal. "LOAN DOCUMENT" means this Agreement, the Notes, the Security Documents and any Subsidiary Guaranty. 4 "NON-RECOURSE INDEBTEDNESS" shall mean any Indebtedness of the Borrower and its Subsidiaries with respect to which the holder thereof agrees that (i) the Borrower and its Subsidiaries are not personally liable and (ii) such holder may require payment only to the extent specifically identified properties of the Borrower and its Subsidiaries are available to provide therefor, such matters to be set forth in an agreement or other instrument in form and substance reasonably satisfactory to the Required Lenders. "REVOLVING LOAN COMMITMENT AMOUNT" means, on any date, $100,000,000, as such amount may be changed from time to time pursuant to SECTION 2.2. "SECURITY DOCUMENTS" means, collectively, the Mortgage, Deed of Trust, Assignment, Security Agreement and Financing Statement from the Borrower or a Subsidiary as the case may be, substantially in the form attached hereto as EXHIBIT H and the Act of Collateral Mortgage (Louisiana) and Collateral Mortgage Note, each substantially in the form shown in EXHIBIT I attached hereto and the Security Agreement and Financing Statement (Louisiana), substantially in the form attached hereto in EXHIBIT J, PROVIDED that, any Security Document executed by a Subsidiary of the Borrower shall name such Subsidiary of the Borrower as the Mortgagor and/or Debtor, as the case may be, and shall, in the case of the Mortgage, Deed of Trust, Assignment, Security Agreement and Financing Statement and the Security Agreement and Financing Statement (Louisiana), include the obligations of such Subsidiary pursuant to its Subsidiary Guaranty in "Secured Indebtedness" as defined therein. "STATED MATURITY DATE" means (a) with respect to Revolving Loans, June 29, 1996; and (b) with respect to the Term Loans, June 30, 1998. "SUBORDINATED INDEBTEDNESS" means (i) the eight percent (8%) Convertible Subordinated Debentures due December 31, 2005 issued by the Borrower pursuant to the Indenture dated as of October 15, 1980, between the Borrower and First Interstate Bank of Texas, Trustee, (ii) the ten and one quarter percent (10.25%) Convertible Subordinated Notes due April 1, 1999 issued by the Borrower pursuant to the Note Agreements dated as of April 1, 1984 between the Borrower and each of the Northwestern Mutual Life Insurance Company, American General Life Insurance Company, Massachusetts Mutual Life Insurance Company and Mass Mutual Corporate Investors, Inc., (iii) the ten and one quarter percent (10.25%) Convertible Subordinated Notes due April 1, 1999 issued by the Borrower pursuant to the Note Agreements dated as of May 1, 1984 between the Borrower and each of American Gas and Oil Investors and AmGO II, and (iv) new Indebtedness incurred, all or a portion of the proceeds of which are used to repay in whole or in part any issue of Subordinated Indebtedness of the Borrower, 5 PROVIDED THAT: (a) such new Indebtedness has covenants regarding the matters set forth in SECTION 8.4 not materially more restrictive to the Borrower than the covenants contained in SECTION 8.4 of this Agreement; (b) such new Indebtedness has subordination terms not materially less favorable to the holders of the Notes than the Subordinated Indebtedness to be repaid; (c) any principal payments for such new Indebtedness scheduled to be paid are no greater than those under the existing schedule of principal payments prior to such date of the Subordinated Indebtedness being repaid; and (d) the maturity dates thereof are no earlier than those of the Subordinated Indebtedness being refinanced. "TERM LOAN COMMITMENT AMOUNT" means the least of (i) the aggregate Revolving Loans outstanding to all Lenders as of the Revolving Loan Commitment Termination Date, (ii) the Commitment Amount in effect with respect to Revolving Loans as of the Resolving Loan Commitment Termination Date, or (iii) the Borrowing Base in effect on the Revolving Loan Commitment Termination Date minus all Senior Debt other than the Revolving Loans outstanding on such date. 1.2 PARTIAL AMENDMENT. The definition of "INDEBTEDNESS" as set forth in the Credit Agreement is partially amended as set forth below and such definition, as so amended, is hereby incorporated by reference into the Credit Agreement as amended by this Amendment: (a) inserting an "and" at the end of clause (f), (b) deleting the "; and" at the end of clause (g) and replacing it with a "."; and (c) deleting clause (h) in its entirety. 1.3 DELETION. The definition of "EUGENE ISLAND BLOCK 330 PRODUCTION PAYMENT" is no longer used in the Credit Agreement and is therefore deleted in its entirety. 1.4 ADDITION. The following definitions shall be added to the Credit Agreement: (a) immediately after the definition of "Loan Document", the following 6 "MAJORITY-OWNED SUBSIDIARY" means, with respect to any Person, any partnership or joint venture in which such Person is a general partner and any corporation of which more than 90% of the outstanding capital stock having ordinary voting power to elect a majority of the board of directors of such corporation (irrespective of whether at the time capital stock of any other class or classes of such corporation shall or might have voting power upon the occurrence of any contingency) is at the time directly or indirectly owned by such Person, by such Person and one or more other Subsidiaries of such Person, or by one or more other Subsidiaries of such Person. (b) immediately after the definition of "Subsidiary", the following "SUBSIDIARY GUARANTY" means any Guaranty executed and delivered by a Subsidiary of the Borrower pursuant to Section 7.10, substantially in the form of EXHIBIT K, as the same may from time to time be amended, supplemented, restated or otherwise modified. 1.5 USE OF DEFINED TERMS. Unless otherwise defined herein or the context otherwise requires, or except as the definition may be amended by this Amendment, terms used in this Amendment, including its preamble and recitals, shall have the meanings provided in the Credit Agreement, as hereby amended. 2. AMENDMENTS TO CREDIT AGREEMENT. 2.1 AMENDMENT OF SECTION 2.1.3(a) OF THE CREDIT AGREEMENT. Section 2.1.3(a) of the Credit Agreement is hereby amended and replaced in its entirety by the following: (a) in the case of Revolving Loans, the aggregate outstanding principal amount of all Revolving Loans outstanding would exceed the lesser of (i) the Revolving Loan Commitment Amount and (ii) the Borrowing Base then in effect minus all other Senior Debt outstanding; 2.2 PARTIAL AMENDMENT OF SECTION 3.1.2 OF THE CREDIT AGREEMENT. Section 3.1.2 of the Credit Agreement is hereby amended and partially replaced by the following: (a) The first paragraph of Section 3.1.2 of the Credit Agreement is hereby amended and replaced in its entirety as follows: 7 Section 3.1.2 MANDATORY PREPAYMENTS ON REVOLVING LOANS. If at any time prior to the Revolving Loan Commitment Termination Date, the aggregate principal amount of all Senior Debt outstanding shall exceed the Borrowing Base then in effect, the Borrower shall, at the Borrower's option, either (i) forthwith repay the Revolving Loans in an aggregate amount equal to such excess or (ii) prepay the Revolving Loans, in no more than five substantially equal monthly installments, in an amount such that upon the conclusion of such mandatory prepayments, the aggregate principal amount of all outstanding Senior Debt will not exceed the Borrowing Base. The first such payment pursuant to CLAUSE (ii) above shall be due within 30 days after the date on which it is first determined that the principal amount of all Senior Debt exceeds such Borrowing Base, and the remaining payments shall be due on the numerically corresponding day of each of the subsequent months. If a subsequent month does not contain a numerically corresponding day, the Borrower shall make such payment on the last Business Day of such month, or if the numerically corresponding day is not a Business Day, such payment will be due on the preceding Business Day. (b) The second and third paragraphs of Section 3.1.2 of the Credit Agreement are hereby partially amended and replaced by substituting the phrase "Senior Debt" for the Phrase "Revolving Loans" wherever it appears in such paragraphs. 2.3 PARTIAL AMENDMENT OF SECTION 3.1.3 OF THE CREDIT AGREEMENT. Section 3.1.3 of the Credit Agreement is hereby partially amended and replaced by replacing the first paragraph thereof in its entirety with the following: Section 3.1.3 MANDATORY PREPAYMENT ON TERM LOANS. If at any time after the making of the Term Loans, the ratio of (a) the lesser of (i) the Discounted Present Value of Future Net Income attributable to Proved Reserves or (ii) 10/7 times the Discounted Present Value of Future Net Income attributable to the Proved Developed Producing Reserves (in either case based on the data in the Reserve Report or Alternate Reserve Report, as the case may be, used to determine the Borrowing Base then in effect), to (b) the outstanding principal amount of the Senior Debt shall at any time be less that 1.5 to 1.0, the Borrower shall, at the Borrower's option, either (i) forthwith repay Term Loans in an aggregate amount equal to such deficiency, or (ii) prepay the Term Loans, in no more than five substantially equal monthly installments, in an amount such that, upon the conclusion of such mandatory prepayments, such ratio would 8 be at least 1.5 to 1.0. The first such payment pursuant to CLAUSE(ii) above shall be due within 30 days after the date on which it is first determined that such ratio is less than 1.5 to 1.0, and the remaining payments shall be due on the numerically corresponding day of each of the subsequent months. 2.4 AMENDMENT OF SECTION 4.11 OF CREDIT AGREEMENT. Section 4.11 of the Credit Agreement is hereby amended and replaced in its entirety by the following: SECTION 4.11. USE OF PROCEEDS. The Borrower shall apply the proceeds of each Borrowing in accordance with the THIRD RECITAL; without limiting the foregoing, and except as permitted by SECTION 8.5(d), no proceeds of any Loan will be used to acquire any equity security of a class which is registered pursuant to Section 12 of the Securities Exchange Act of 1934 if such acquisition would result in the Borrower's owning more than five percent (5%) of the issuer's outstanding voting stock and no proceeds of any Loan will be used to acquire such stock if such acquisition would result in any violation of F.R.S. Board Regulation U by the Borrower or any Lender. 2.5 AMENDMENT OF SECTION 5.2.1(D) OF THE CREDIT AGREEMENT. Section 5.2.1(d) of the Credit Agreement is hereby amended and replaced in its entirety with the following: (d) the Commitment Amount plus all Senior Debt outstanding other than the Loans does not exceed the Borrowing Base and the Borrower is in compliance with the Current Ratio and Fixed Charge Coverage Ratio as required by SECTIONS 8.4(c) and 8.4(d), respectively, and, immediately after giving effect to the proposed Borrowing, Senior Debt shall not exceed the Borrowing Base then in effect and the Indebtedness of the Borrower shall not exceed the amount permitted under CLAUSE(a), and Specified Debt shall not exceed the amount permitted under CLAUSE (b), of SECTION 8.4. 2.6 AMENDMENT OF SECTION 6.8 OF CREDIT AGREEMENT. Section 6.8 of the Credit Agreement is hereby amended and replaced in its entirety by the following: SECTION 6.8. SUBSIDIARIES. The Borrower has no Subsidiaries, except those Subsidiaries (a) which are identified in ITEM 6.8 (a) ("Existing Subsidiaries") of the Disclosure Schedule; or 9 (b) which are permitted to have been acquired or formed in accordance with SECTION 8.5 or 8.7. As of September 23, 1992, the Borrower is the record or beneficial owner of the issued and outstanding shares of capital stock of each such corporate Subsidiary which is identified in ITEM 6.8(a) of the Disclosure Schedule. Such shares are free and clear of any Liens, including, without limitation, claims arising out of any preemptive rights granted in connection with the issuance of any such shares. All such shares are duly issued, fully paid and nonassessable and there are no outstanding options, warrants or other rights entitling the holder thereof to purchase any shares of capital stock of any such Subsidiary. The Borrower's partnership interest in any Subsidiary organized as a partnership is free and clear of any Liens. 2.7 AMENDMENT OF SECTION 6.12 OF CREDIT AGREEMENT. Section 6.12 of the Credit Agreement is hereby partially amended and replaced as follows: (a) SECTION 6.12 (b) is hereby amended and replaced in its entirety as follows: "(b) to the best knowledge of the Borrower, there have been no past, and there are no pending or threatened (i) claims, complaints, or notices received by the Borrower or any of its Subsidiaries with respect to any alleged violation of any Environmental Law, or (ii) claims, complaints, notices or inquiries to, or requests for information received by, the Borrower or any of its Subsidiaries regarding potential liability under any Environmental Law relating to operations or the condition of any facilities or property (including underlying groundwater) owned, leased or operated by the Borrower or any of its Subsidiaries that, singly or in the aggregate, have or may reasonably be expected to have, a material adverse effect on the financial condition, operations, assets, business, properties or prospects of the Borrower and its Subsidiaries taken as a whole;" (b) SECTION 6.12(d) of the Credit Agreement is hereby amended and replaced as follows: "(d) to the best knowledge of Borrower, the Borrower and its Subsidiaries have been issued and are in material compliance with all permits, certificates, approvals, licenses and other authorizations relating to environmental matters that are necessary for their businesses;". 10 2.8 AMENDMENT OF SECTION 6.14 OF CREDIT AGREEMENT. Section 6.14 of the Credit Agreement is hereby amended and replaced in its entirety by the following: SECTION 6.14. RANK OF INDEBTEDNESS. The obligations of the Borrower to pay the principal of and interest on the Loans made hereunder and the Notes and all other amounts payable by the Borrower hereunder constitute direct and general obligations of the Borrower and rank in right of payment prior to or PARI PASSU with all unsecured indebtedness and liabilities for borrowed money, or other obligations arising out of the extension of credit, of the Borrower. As of December 31, 1993, the Borrower does not have outstanding any such liability or obligation which is subordinated to any other such indebtedness, liability or obligation but which is not subordinated to all indebtedness of the Borrower for money borrowed hereunder and under the Notes. There is no Senior Debt outstanding as of December 31, 1993 other than obligations pursuant to this Agreement, the Notes, and the other Loan Documents. 2.9 AMENDMENT OF SECTION 6.17 OF CREDIT AGREEMENT. Section 6.17 of the Credit Agreement is hereby amended and replaced in its entirety by the following: SECTION 6.17. NO CONTRACTUAL VIOLATION. Borrower has no contract or agreement to which it or any of its Subsidiaries is a party or by which it or its properties are bound (excluding any agreements or contracts governing Indebtedness that do not exceed $1,000,000 at any one time outstanding in the aggregate which have been incurred to vendors to finance acquisition of assets as to the assets financed with such Indebtedness) prohibiting or having the effect of prohibiting the creation or assumption of any Lien upon any of its assets, properties or revenues whether now owned or hereafter acquired, or restricting the ability of the Borrower to amend or otherwise modify this Agreement or any other Loan Document, except as provided in this Agreement and the other Loan Documents. 2.10 PARTIAL AMENDMENT OF SECTION 7.2 OF THE CREDIT AGREEMENT. Section 7.2 of the Credit Agreement is hereby partially amended and replaced by (a) deleting the word "and" at the end of paragraph (k) thereof, (b) deleting the period at the end of paragraph (l) thereof and replacing it with a semi-colon and adding the word "and" thereto, and (c) adding the following paragraph (m) to such Section: (m) as soon as reasonably possible and in any event within ten (10) Business Days if the principal of the Senior Debt outstanding (including the Loans) shall exceed the Borrowing Base then in effect, notice of such excess. 2.11 AMENDMENT OF SECTION 7.3 OF CREDIT AGREEMENT. Section 7.3 of the Credit Agreement is hereby amended and replaced in its entirety by the following: 11 SECTION 7.3. COMPLIANCE WITH LAWS, ETC. The Borrower will, and will cause each of its Subsidiaries to, comply in all material respects with all applicable laws, rules, regulations and orders, such compliance to include (without limitation): (a) the maintenance and preservation of its corporate or partnership existence and qualification as a foreign corporation or partnership except as contemplated by SECTION 8.7 or except where the failure to do so would not have a material adverse effect on the business and operations of the Borrowers and its Subsidiaries taken as a whole. (b) the payment, before the same become delinquent, of all taxes, assessments and governmental charges imposed upon it or upon its property except to the extent being diligently contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been set aside on its books or except where the failure to do so would not have a material adverse effect on the business or operations of the Borrower and its Subsidiaries taken as a whole. 2.12 AMENDMENT OF SECTION 7.6 OF CREDIT AGREEMENT. Section 7.6 of the Credit Agreement is hereby amended by inserting the word "material" immediately prior to the word "business" in the third line of the first sentence of such section 7.6. 2.13 AMENDMENT OF SECTION 7.7 OF CREDIT AGREEMENT. Section 7.7 (b) of the Credit Agreement is hereby amended by inserting the word "material" immediately prior to the word "violations" at the beginning of the third line of such section 7.7(b). 2.14 AMENDMENT OF SECTION 7.8 OF CREDIT AGREEMENT. Section 7.8 of the Credit Agreement is hereby partially amended and replaced as follows: (a) SECTION 7.8(c) is hereby amended by adding the word "or" to the end of the section; (b) SECTION 7.8(d) is hereby amended by deleting the "; or" at the end of the section and adding a "."; (c) SECTION 7.8(e) is hereby deleted in its entirety; (d) SECTION 7.8(f) is hereby redesignated as Section 7.8(e) and references thereto in the Credit Agreement, including the reference to "CLAUSE (f)" in the carryover paragraph at the top of page 61, are hereby amended to refer to Section 7.8(e) and Section 7.8(f) is further amended by: 12 (i) adding after the word "deliver" in the first line thereof the phrase ", and cause each Subsidiary to which Borrowing Base Properties have been transferred pursuant to SECTION 8.8(b) to execute and deliver," (ii) adding after the phrase "Collateral Agent" in the first line thereof the phrase "the Security Documents," (iii) adding after the word "Borrower" in the tenth line thereof the phrase "or such Subsidiary," (iv) adding after the word "Borrower's" in the eleventh line thereof the phrase "or such Subsidiary's"; and (v) adding after the term "(the "Collateral")" in the fifteenth line thereof the phrase "as set forth"; (e) Section 7.8(g) is hereby amended and replaced in its entirety as follows: "(f) deliver to the Agent, within 15 days from the date of occurrence described in CLAUSES (a), (b), (c) or (d) above, a plan setting forth in reasonable detail the manner in which required payments, if any, on the Loans will be made."; and 13 (f) The last full paragraph of Section 7.8 is hereby amended by deleting the first sentence thereof in its entirety and by deleting the word "also" in the remaining sentence thereof. 2.15 AMENDMENT OF SECTION 8.2 OF CREDIT AGREEMENT. Section 8.2 of the Credit Agreement is hereby amended and replaced in its entirety by the following: SECTION 8.2. INDEBTEDNESS. The Borrower hereby agrees that it shall not, and shall not permit any of its Subsidiaries to: (a) create, incur, assume or suffer to exist or otherwise become or be liable in respect of any Senior Debt, other than, without duplication, the following: (i) Senior Debt in respect of the Loans and other Obligations; and (ii) other Senior Debt not to exceed $10,000,000 in the aggregate at any time outstanding; or (b) create, incur, assume or suffer to exist or otherwise become or be liable in respect of any Non-Recourse Indebtedness secured by a Lien on Borrowing Base Properties. 2.16 AMENDMENT OF SECTION 8.3 OF CREDIT AGREEMENT. Section 8.3 of the Credit Agreement is hereby partially amended as follows: (a) Section 8.3(a) is hereby amended and replaced in its entirety by the following: "(a) Liens securing payment of the Obligations of Borrower, or obligations of a Subsidiary pursuant to any Subsidiary Guaranty, granted pursuant to any Security Document executed by the Borrower pursuant to SECTION 7.8;" (b) Section 8.3(i) is hereby amended by inserting the word "and" at the end of such section; (c) Section 8.3(j) is hereby deleted in its entirety; and 14 (d) Section 8.3(k) is hereby amended and replaced in its entirety by the following: "(j) Liens which do not encumber Borrowing Base Properties and which secure or relate to Non-Recourse Indebtedness." 2.17 AMENDMENT OF SECTION 8.8 OF CREDIT AGREEMENT. Section 8.8 of the Credit Agreement is hereby amended and replaced in its entirety by the following: SECTION 8.8. ASSET DISPOSITIONS. In either of the first two or last two Fiscal Quarters of any Fiscal Year: (a) the aggregate value of assets (including cash accounts, accounts receivable, production payments, and capital stock of or partnership interests in Subsidiaries, but excluding oil, gas, and other liquid or gaseous hydrocarbons sold in the ordinary course of business) sold, transferred, leased, contributed, or otherwise conveyed by the Borrower and its Subsidiaries other than to the Borrower or its Subsidiaries, or to which the Borrower and its Subsidiaries may grant options, warrants, or other rights, shall not exceed, in the aggregate, $5,000,000. Notwithstanding the foregoing, the Borrower and its Subsidiaries may grant, sell, or convey production payments as permitted by this Agreement in connection with Non- Recourse Indebtedness. For purposes of this SECTION 8.8(a), the value of any asset is the greater of its book value or fair market value at the time of any disposition; and (b) the Discounted Present Value of Borrowing Base Properties sold, transferred, leased, contributed or otherwise conveyed by the Borrower to any Subsidiary shall not exceed, in the aggregate, ten percent (10%) of the Borrowing Base determined pursuant to the most recent Reserve Report or Alternate Reserve Report without first obtaining the consent of the Required Lenders, which consent shall not be unreasonably withheld and shall not require the payment of a fee or other compensation by the Borrower. 2.18 AMENDMENT OF SECTION 8.9 OF CREDIT AGREEMENT. Section 8.9 of the Credit Agreement is hereby amended and replaced in its entirety by the following: 15 SECTION 8.9. MODIFICATION OF CERTAIN AGREEMENTS. The Borrower will not consent to any amendment, supplement or other modification of any of the terms or provisions contained in, or applicable to any document or instrument evidencing or governing any existing Subordinated Indebtedness, other than any amendment, supplement or other modification which (a) does not accelerate the date of or increase the amount of any repayment or redemption required pursuant to such agreements, prior to June 30, 1998, (b) does not contain covenants regarding the matters set forth in SECTION 8.4 materially more restrictive than the covenants contained in SECTION 8.4 of this Agreement, (c) does not increase the rate of interest payable or fees and other compensation, except to the extent such fees and other compensation are usual and customary for transactions of such type, and (d) does not contain or result in subordination terms materially less favorable to holders of the Notes than the original terms. After giving effect to any amendment, supplement, or modification which conforms to CLAUSES (a), (b), (c), and (d) of this SECTION 8.9, the Indebtedness of the Borrower shall not exceed the limits permitted pursuant to CLAUSE (a) of SECTION 8.4. 2.19 DELETION OF SECTION 8.11 OF CREDIT AGREEMENT. The text of Section 8.11 of the Credit Agreement is deleted in its entirety and is hereby replaced by the phrase "{Intentionally Omitted}". 2.20 AMENDMENT OF SECTION 8.12 OF CREDIT AGREEMENT. Section 8.12 of the Credit Agreement is hereby amended and replaced in its entirety by the following: SECTION 8.12. NEGATIVE PLEDGES, ETC. The Borrower will not, and will not permit any of its Subsidiaries to, enter into any agreement (excluding this Agreement, any other Loan Document, any agreement related to Indebtedness permitted under SECTION 8.2(a)(ii) and any agreement governing Indebtedness not to exceed $1,000,000 at any one time outstanding in the aggregate which is incurred to vendors to finance acquisitions of assets as to the assets financed with proceeds of such Indebtedness) prohibiting or having the effect of prohibiting the creation or assumption of any Lien upon any of its properties, revenues or assets, whether now owned or hereafter acquired, or restricting the ability of the Borrower to amend or otherwise modify this Agreement or any other Loan Document; PROVIDED, HOWEVER, that any agreement related to Indebtedness permitted under SECTION 8.2(a)(ii), which is excluded from the provisions of this SECTION 8.12, shall not prohibit the Lenders from exercising their rights pursuant to SECTION 7.8 hereof. 2.21 AMENDMENT OF SECTION 9.1.3 OF CREDIT AGREEMENT. Section 9.1.3 of the Credit Agreement is hereby amended and replaced in its entirety by the following: 16 SECTION 9.1.3 NON-PERFORMANCE OF CERTAIN COVENANTS AND OBLIGATIONS. The Borrower shall default in the due performance and observance of any of its obligations under ARTICLE VIII (excluding SECTION 8.4) and, with respect to SECTION 8.3, 8.5 or 8.6, such default shall continue unremedied for a period of five (5) Business Days after notice thereof shall have been given to the Borrower by the Agent or any Lender. 2.22 AMENDMENT OF SECTIONS 9.1.5 AND 9.1.6 OF CREDIT AGREEMENT. The amount of "$1,000,000" set forth in the first sentence of each of Sections 9.1.5 and 9.1.6, respectively, is hereby deleted and replaced by "$5,000,000" in each section. 2.23 ADDITION. ARTICLE VII is hereby amended by the addition of a new Section 7.10 as follows: SECTION 7.10 SUBSIDIARY GUARANTIES. Prior to, or contemporaneous with, the transfer by Borrower of a Borrowing Base Property to a Subsidiary of Borrower, Borrower shall cause such Subsidiary to execute and deliver to the Lenders a Subsidiary Guaranty if such Subsidiary has not previously executed a similar Guaranty for the benefit of the Lenders. 2.24 AMENDMENT OF PERCENTAGES. The Percentage shown opposite the signature of each Lender is hereby amended and replaced with the Percentage indicated opposite the name of such Lender shown below: Bank of Montreal 31% Banque Paribas 25% The First National Bank of Boston 22% NBD Bank, N.A. 22% 2.25 PARTIAL AMENDMENT OF EXHIBIT B. Exhibit B of the Credit Agreement is hereby partially amended as follows: (a) The word "and" is deleted from the last line of clause (a) of the third paragraph thereof; (b) the period after the last line of clause (b) of the third paragraph thereof is replaced with a semicolon and the word "and" added; and (c) an additional clause (c) which reads as follows is added to the third paragraph thereof: 17 (c) Senior Debt, both before and after giving effect to the borrowing requested hereby, is not in excess of the Borrowing Base. 2.26 PARTIAL AMENDMENT OF EXHIBIT H. Exhibit "H" ("Mortgage, Deed of Trust, Assignment, Security Agreement and Financing Statement") of the Credit Agreement is hereby partially amended as follows: (a) The Preface of Exhibit H of the Credit Agreement is hereby partially amended by deleting from the fourteenth line of such Preface the phrase "and other holders of Senior Debt." (b) Section 1.1(a) of Exhibit H of the Credit Agreement is hereby partially amended by (i) deleting from the first line of such Section the phrase "Senior Debt" and replacing such phrase with the word "Loans" and (ii) deleting from the thirteenth and fourteenth lines of such Section the phrase "and {describe other indebtedness and identify 'Other Notes'} ." (c) Section 1.1(b) of Exhibit H of the Credit Agreement is hereby partially amended by deleting from the second and third lines of such Section the phrase "or Other Notes." (d) Section 2.1 of Exhibit H of the Credit Agreement is hereby partially amended by deleting from the last line of such Section the phrase "and the Other Notes." (e) Section 2.3 of Exhibit H of the Credit Agreement is hereby partially amended by deleting from the tenth line of such Section the phrase "any of the Other Notes,". (f) Section 3.2 of Exhibit H of the Credit Agreement is hereby partially amended by replacing the first indented subparagraph of such Section in its entirety with the following: FIRST: To the payment and satisfaction of all costs and expenses incurred in connection with the collection of such proceeds, and to the payment of all items of the Secured Indebtedness not evidenced by any Note. (g) Section 6.5 of Exhibit H of the Credit Agreement is hereby partially amended by deleting from the fourteenth line of such Section the phrase "and the Other Notes." (h) Section 6.7 of Exhibit H of the Credit Agreement is hereby partially amended by deleting from the second, sixth and seventh lines of such Section the phrase "or the Other Notes." (i) Section 6.8 of Exhibit H of the Credit Agreement is hereby partially amended by deleting from the second and fourth lines of such Section the phrase "or the Other Notes." 18 2.27 PARTIAL AMENDMENT OF EXHIBIT J. Exhibit J ("Security Agreement and Financing Statement (Louisiana)") of the Credit Agreement is hereby partially amended and replaced as follows: (a) The Preface of Exhibit J of the Credit Agreement is hereby partially amended by deleting from the twelfth line of such Preface the phrase "and other holders of Senior Debt." (b) Section 1.1(a) of Exhibit J of the Credit Agreement is hereby partially amended by (i) deleting from the first line of such Section the phrase "Senior Debt" and replacing such phrase with the word "Loans" and (ii) deleting from the thirteenth and fourteenth lines of such Section the phrase "and {describe other indebtedness and identify 'Other Notes'}." (c) Section 1.1(b) of Exhibit J of the Credit Agreement is hereby partially amended by deleting from the second and third lines of such Section the phrase "or Other Notes." (d) Section 2.1 of Exhibit J of the Credit Agreement is hereby partially amended by deleting from the last line of such Section the phrase "and the Other Notes." (e) Section 2.3 of Exhibit J of the Credit Agreement is hereby partially amended by deleting from the tenth line of such Section the phrase "any of the Other Notes,". (f) Section 3.2 of Exhibit J of the Credit Agreement is hereby partially amended by replacing the first indented subparagraph of such Section in its entirety with the following: FIRST: To the payment and satisfaction of all costs and expenses incurred in connection with the collection of such proceeds, and to the payment of all items of the Secured Indebtedness not evidenced by any Note. (g) Section 5.3 of Exhibit J of the Credit Agreement is hereby partially amended by deleting from the eight line of such Section the phrase "the Other Notes." (h) Section 6.4 of Exhibit J of the Credit Agreement is hereby partially amended by deleting from the fifteenth and sixteenth lines of such Section the phrase "and the Other Notes." (i) Section 6.5 of Exhibit J of the Credit Agreement is hereby partially amended by deleting from the second, sixth and seventh lines of such Section the phrase "or the Other Notes." (j) Section 6.6 of Exhibit J of the Credit Agreement is hereby partially amended by deleting from the second and fourth lines of such Section the phrase "or the Other Notes." 19 2.28 ADDITION OF EXHIBIT K. EXHIBIT A to this Amendment is hereby added to the Credit Agreement as Exhibit K thereto. 3. REPRESENTATIONS AND WARRANTIES. In order to induce the Lenders and the Agent to enter into this Amendment, the Borrower hereby reaffirms, as of the date hereof, its representations and warranties contained in Article VI of the Credit Agreement (except to the extent any such representation and warranty relates solely to an earlier date) and additionally represents and warrants as follows: 3.1 ORGANIZATION. The Borrower and each of its corporate Subsidiaries is a corporation validly organized and existing and in good standing under the laws of the state, or country, of its incorporation, and is duly qualified to do business and is in good standing as a foreign corporation in each jurisdiction where the nature of its business requires such qualification, except where failure to qualify would not have a material adverse effect on the business or financial condition of the Borrower and its Subsidiaries taken as a whole or the Borrower's ability to perform the Loan Documents, as such may be amended hereby, or this Amendment. Each of the Borrower's Subsidiaries which is organized as a partnership is validly organized and existing and in good standing under the laws of the state of its formation, and is duly qualified to do business and is in good standing as a foreign partnership where the nature of its business requires such qualification, except where failure to qualify would not have a material adverse effect on the business or financial condition of the Borrower, or the Borrower and its Subsidiaries taken as a whole or the Borrower's ability to perform under the Loan Documents, as such may be amended hereby, or this Amendment. The Borrower and each of its Subsidiaries has full power and authority and holds all requisite governmental licenses, permits and other approvals to enter into and perform its Obligations under the Credit Agreement, as amended hereby, each other Loan Document and this Amendment and to own and hold under lease its property and to conduct its business substantially as currently conducted by it. 3.2 DUE AUTHORIZATION, NON-CONTRAVENTION. The execution, delivery and performance by the Borrower of this Amendment, the New Notes (as defined hereafter) and the consummation of the transactions contemplated hereby and by the Loan Documents as so amended, are within the Borrower's corporate powers, have been duly authorized by all necessary corporate action, and do not (a) contravene the Borrower's Organic Documents; 20 (b) contravene any contractual restriction, law or governmental regulation or court decree or order binding on or affecting the Borrower or any Subsidiary; or (c) result in, or require the creation or imposition of, any Lien on any properties of the Borrower or its Subsidiaries except as Liens will be imposed, created, or required upon execution and delivery of the Security Documents pursuant to SECTION 7.8 of the Credit Agreement. 3.3 GOVERNMENTAL APPROVAL. No authorization or approval or other action by, and no notice to or filing with, any governmental authority or regulatory body is required for the due execution, delivery or performance by the Borrower of this Amendment or the Notes. 3.4 VALIDITY, ETC. This Amendment and the Loan Documents as amended hereby constitute the legal, valid and binding obligations of the Borrower, enforceable in accordance with their respective terms except as such enforceability is subject to the effect of (i) any applicable bankruptcy, insolvency, reorganization or similar law relating to or affecting creditors' rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law), including concepts of materiality, reasonableness, good faith and fair dealing. 4. CONDITIONS TO EFFECTIVENESS. The effectiveness of this Amendment is conditioned upon receipt by the Agent of all the following documents, each in form and substance satisfactory to the Agent: (a) a certificate of the Secretary or Assistant Secretary of the Borrower, certifying as to (i) resolutions of the Board of Directors of the Borrower approving the execution, delivery and performance of this Amendment and the New Notes (as herein defined); (ii) the By-laws of the Borrower; (iii) the incumbency and signatures of the officers authorized to execute this Amendment and the New Notes on behalf of the Borrower; (b) an opinion of Gerald A. Morton, Associate General Counsel of the Borrower; (c) new Notes in a form satisfactory to the Agent (the "New Notes") for delivery to the Lenders, such New Notes to be in exchange for and not in payment of the Notes now held by the Lenders and in the amount of such Lender's Commitment, as amended hereby. 21 5. EFFECT OF AMENDMENT. This Amendment shall be deemed to be an amendment to the Credit Agreement, and the Credit Agreement, as amended hereby, is hereby ratified, approved and confirmed in each and every respect. All references to the Credit Agreement in any other document, instrument, agreement or writing shall hereafter be deemed to refer to the Credit Agreement as amended hereby. All references in the Credit Agreement or any other Documents to the Notes shall be deemed to refer to the New Notes. All references in the Credit Agreement to Exhibit B shall be deemed to refer to Exhibit B as amended hereby. All references in the Credit Agreement or any other document to the Mortgage, Deed of Trust, Assignments, Security Agreement and Financing Statement shall be deemed to refer to such document as amended hereby and each reference in the Credit Agreement to Exhibit H shall be to Exhibit H as amended hereby. All references in the Credit Agreement or any other document to the Security Agreement and Financing Statement (Louisiana) shall be deemed to refer to such document as amended hereby and each reference in the Credit Agreement to Exhibit J shall refer to Exhibit J as amended hereby. 6. GOVERNING LAW, SEVERABILITY, ETC. THIS AMENDMENT SHALL BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF THE STATE OF ILLINOIS. Whenever possible each provision of this Amendment shall be interpreted in such manner as to be effective and valid under applicable laws, but if any provision of this Amendment shall be prohibited by or invalid under applicable law, such provision shall be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Amendment. THIS WRITTEN AMENDMENT AND THE CREDIT AGREEMENT AS AMENDED BY THIS AMENDMENT REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. 7. MISCELLANEOUS. 7.1 SUCCESSORS AND ASSIGNS. This Amendment shall be binding upon and shall inure to the benefit of the parties hereto and their respective successors and assigns. 7.2 COUNTERPARTS. This Amendment may be executed in one or more counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument. 22 7.3 EFFECTIVENESS. This Amendment shall become effective when counterparts hereof executed on behalf of the Borrower and each Lender (or notice thereof satisfactory to the Agent) shall have been received by the Agent, all conditions set forth in Section 4 hereof have been fulfilled and notice thereof shall have been given by the Agent to the Borrower and each Lender. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly authorized as of the day and year first written above. POGO PRODUCING COMPANY By: /s/ D. STEPHEN SLACK Name: D. Stephen Slack, Title: Senior Vice President, Finance BANK OF MONTREAL, acting through its U.S. branches and agencies, including initially its Chicago Illinois branch, as Agent By: /s/ MARK M. GREEN Name: Mark M. Green Title: Director BANQUE PARIBAS acting through its Houston Agency, as Co-Agent By: /s/ BARTON D. SCHOUEST Name: Barton D. Schouest Title: Group Vice President By: /s/ PATRICK J. MILON Name: Patrick J. Milon Title: SVP-Deputy General Manager BANK OF MONTREAL By: /s/ MARK M. GREEN Name: Mark M. Green Title: Director BANQUE PARIBAS By: /s/ BARTON D. SCHOUEST Name: Barton D. Schouest Title: Group Vice President 23 By: /s/ PATRICK J. MILON Name: Patrick J. Milon Title: SVP-Deputy General Manager NBD BANK, N.A. By: /s/ DOUGLAS R. LIFTMAN Name: Douglas R. Liftman Title: Vice President THE FIRST NATIONAL BANK OF BOSTON By: /s/ GEORGE W. PASSELA Name: George W. Passela Title: Managing Director 24 EXHIBIT A TO THE SECOND AMENDMENT EXHIBIT K GUARANTY THIS GUARANTY (this "GUARANTY"), dated as of _____ __, 19__, made by {NAME OF SUBSIDIARY}, a __________ (the "GUARANTOR"), in favor of each of the Lender Parties (as defined below). W I T N E S S E T H: WHEREAS, pursuant to a Credit Agreement, dated as of September 23, 1992, and amended as of September 30, 1992 and December ___, 1993 (as so amended and together with all further amendments and other modifications, if any, from time to time thereafter made thereto, the "CREDIT AGREEMENT"), among Pogo Producing Company, a Delaware corporation (the "BORROWER"), the various commercial lending institutions (individually a "LENDER" and collectively the "LENDERS") as are, or may from time to time become, parties thereto and Bank of Montreal, acting through its Chicago, Illinois branch, as agent (together with any successor(s) thereto in such capacity, the "AGENT") for the Lenders and Banque Paribas, acting through its Houston Agency, as co-agent (the "CO-AGENT") for the Lenders, the Lenders have extended Commitments to make Loans to the Borrower; and WHEREAS, the Guarantor has duly authorized the execution, delivery and performance of this Guaranty; and WHEREAS, it is in the best interests of the Guarantor to execute this Guaranty inasmuch as the Guarantor will derive substantial direct and indirect benefits from Loans made from time to time to the Borrower by the Lenders pursuant to the Credit Agreement; NOW THEREFORE, for good and valuable consideration the receipt of which is hereby acknowledged, and in order to induce the Lenders to make Loans (including the initial Loans) to the Borrower pursuant to the Credit Agreement, the Guarantor agrees, for the benefit of each Lender Party, as follows: ARTICLE I DEFINITIONS SECTION 1.1. CERTAIN TERMS. The following terms (whether or not underscored) when used in this Guaranty, including its preamble and recitals, shall have the following meanings (such definitions to be equally applicable to the singular and plural forms thereof): 25 "AGENT" is defined in the FIRST RECITAL. "BORROWER" is defined in the FIRST RECITAL. "CO-AGENT" is defined in the FIRST RECITAL. "CREDIT AGREEMENT" is defined in the FIRST RECITAL. "GUARANTOR" is defined in the PREAMBLE. "GUARANTY" is defined in the PREAMBLE. "LENDER" is defined in the FIRST RECITAL. "LENDER PARTY" means, as the context may require, any Lender, the Agent, the Co-Agent or the Collateral Agent and each of the respective successors, transferees and assigns of any of the foregoing. "LENDERS" is defined in the FIRST RECITAL. "OBLIGATIONS" means all obligations (monetary or otherwise) of the Borrower arising with respect to the Credit Agreement, the Notes, or any other Loan Document. "OBLIGOR" means the Borrower or any other Person (other than the Agent, Co-Agent or any Lender) obligated under any Loan Document. SECTION 1.2. CREDIT AGREEMENT DEFINITIONS. Unless otherwise defined herein or the context otherwise requires, terms used in this Guaranty, including its preamble and recitals, have the meanings provided in the Credit Agreement. ARTICLE II GUARANTY PROVISIONS SECTION 2.1. GUARANTY. The Guarantor hereby absolutely, unconditionally and irrevocably (a) guarantees the full and punctual payment when due, whether at stated maturity, by required prepayment, declaration, acceleration, demand or otherwise, of all Obligations of the Borrower now or hereafter existing under the Credit Agreement, the Notes and each other Loan Document to which the Borrower is or may become a party, whether for principal, interest, fees, expenses or otherwise (including all such amounts which would become due but for the operation of the automatic stay under Section 362(a) of the United States Bankruptcy Code, 11 U.S.C. Section 362(a), and the operation of Sections 502(b) and 506(b) of the United States Bankruptcy Code, 11 U.S.C. Section 502(b) and Section 506(b)), and 26 (b) indemnifies and holds harmless each Lender Party and each holder of a Note for any and all costs and expenses (including reasonable attorney's fees and expenses) incurred by such Lender Party or such holder, as the case may be, in enforcing any rights under this Guaranty; PROVIDED, HOWEVER, that the Guarantor shall be liable under this Guaranty for the maximum amount of such liability that can be hereby incurred without rendering this Guaranty, as it relates to the Guarantor, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer, and not for any greater amount. This Guaranty constitutes a guaranty of payment when due and not of collection, and the Guarantor specifically agrees that it shall not be necessary or required that any Lender Party or any holder of any Note exercise any right, assert any claim or demand or enforce any remedy whatsoever against the Borrower or any other Obligor (or any other Person) before or as a condition to the obligations of the Guarantor hereunder. SECTION 2.2. ACCELERATION OF GUARANTY. The Guarantor agrees that, in the event of the dissolution or insolvency of the Guarantor, or the inability or failure of the Guarantor to pay debts as they become due, or an assignment by the Guarantor for the benefit of creditors, or the commencement of any case or proceeding in respect of the Guarantor under any bankruptcy, insolvency or similar laws, and if such event shall occur at a time when any of the Obligations of the Borrower may not then be due and payable, the Guarantor will pay to the Lenders forthwith the full amount which would be payable hereunder by the Guarantor if all such Obligations were then due and payable. SECTION 2.3. GUARANTY ABSOLUTE, ETC. This Guaranty shall in all respects be a continuing, absolute, unconditional and irrevocable guaranty of payment, and shall remain in full force and effect until all Obligations of the Borrower have been paid in full, all obligations of the Guarantor hereunder shall have been paid in full and all Commitments shall have terminated. The Guarantor guarantees that the Obligations of the Borrower will be paid strictly in accordance with the terms of the Credit Agreement and each other Loan Document under which they arise, regardless of any law, regulation or order now or hereafter in effect in any jurisdiction affecting any of such terms or the rights of any Lender Party or any holder of any Note with respect thereto. The liability of the Guarantor under this Guaranty shall be absolute, unconditional and irrevocable irrespective of: (a) any lack of validity, legality or enforceability of the Credit Agreement, any Note or any other Loan Document; (b) the failure of any Lender Party or any holder of any Note 27 (i) to assert any claim or demand or to enforce any right or remedy against the Borrower, any other Obligor or any other Person (including any other guarantor) under the provisions of the Credit Agreement, any Note, any other Loan Document or otherwise, or (ii) to exercise any right or remedy against any other guarantor of, or collateral securing, any Obligations of the Borrower or any other Obligor; (c) any change in the time, manner or place of payment of, or in any other term of, all or any of the Obligations of the Borrower or any other Obligor, or any other extension, compromise or renewal of any Obligation of the Borrower or any other Obligor; (d) any reduction, limitation, impairment or termination of any Obligations of the Borrower or any other Obligor for any reason, including any claim of waiver, release, surrender, alteration or compromise, and shall not be subject to (and the Guarantor hereby waives any right to or claim of) any defense or setoff, counterclaim, recoupment or termination whatsoever by reason of the invalidity, illegality, nongenuineness, irregularity, compromise, unenforceability of, or any other event or occurrence affecting, any Obligations of the Borrower, any other Obligor or otherwise; (e) any amendment to, rescission, waiver, or other modification of, or any consent to departure from, any of the terms of the Credit Agreement, any Note or any other Loan Document; (f) any addition, exchange, release, surrender or non-perfection of any collateral, or any amendment to or waiver or release or addition of, or consent to departure from, any other guaranty, held by any Lender Party or any holder of any Note securing any of the Obligations of the Borrower or any other Obligor; or (g) any other circumstance which might otherwise constitute a defense available to, or a legal or equitable discharge of, the Borrower, any other Obligor, any surety or any guarantor. SECTION 2.4. REINSTATEMENT, ETC. The Guarantor agrees that this Guaranty shall continue to be effective or be reinstated, as the case may be, if at any time any payment (in whole or in part) of any of the Obligations is rescinded or must otherwise be restored by any Lender Party or any holder of any Note, upon the insolvency, bankruptcy or reorganization of the Borrower, any other Obligor or otherwise, all as though such payment had not been made. 28 SECTION 2.5. WAIVER, ETC. The Guarantor hereby waives promptness, diligence, notice of acceptance and any other notice with respect to any of the Obligations of the Borrower or any other Obligor and this Guaranty and any requirement that the Agent, any other Lender Party or any holder of any Note protect, secure, perfect or insure any security interest or Lien, or any property subject thereto, or exhaust any right or take any action against the Borrower, any other Obligor or any other Person (including any other guarantor) or entity or any collateral securing the Obligations of the Borrower or any other Obligor, as the case may be. SECTION 2.6. WAIVER OF SUBROGATION. The Guarantor hereby irrevocably waives any claim or other rights which it may now or hereafter acquire against the Borrower or any other Obligor that arise from the existence, payment, performance or enforcement of the Guarantor's obligations under this Guaranty or any other Loan Document, including any right of subrogation, reimbursement, exoneration, or indemnification, any right to participate in any claim or remedy of the Lender Parties against the Borrower or any other Obligor or any collateral which the Agent or other Lender Party now has or hereafter acquires, whether or not such claim, remedy or right arises in equity, or under contract, statute or common law, including the right to take or receive from the Borrower or any other Obligor, directly or indirectly, in cash or other property or by set-off or in any manner, payment or security on account of such claim or other rights. If any amount shall be paid to the Guarantor in violation of the preceding sentence and the Obligations shall not have been paid in cash in full and the Commitments have not been terminated, such amount shall be deemed to have been paid to the Guarantor for the benefit of, and held in trust for, the Lender Parties, and shall forthwith be paid to the Lender Parties to be credited and applied upon the Obligations, whether matured or unmatured. The Guarantor acknowledges that it will receive direct and indirect benefits from the financing arrangements contemplated by the Credit Agreement and that the waiver set forth in this Section is knowingly made in contemplation of such benefits. SECTION 2.7. SUCCESSORS, TRANSFEREES AND ASSIGNS; TRANSFERS OF NOTES, ETC. This Guaranty shall: (a) be binding upon the Guarantor, and its successors, transferees and assigns; and (b) inure to the benefit of and be enforceable by the Agent and each other Lender Party. Without limiting the generality of the foregoing CLAUSE (b), any Lender may assign or otherwise transfer (in whole or in part) any Note or Loan held by it to any other Person or entity, and such other Person or entity shall thereupon become vested with all rights benefits, duties and obligations in respect thereof granted to such Lender under any Loan Document (including this Guaranty) or otherwise, subject, however, to any contrary provisions in such assignment or transfer, and to the provisions of Article X and Sections 11.11, 11.12 and 11.14 of the Credit Agreement. 29 ARTICLE III REPRESENTATIONS AND WARRANTIES SECTION 3.1. REPRESENTATIONS AND WARRANTIES. The Guarantor hereby represents and warrants unto each Lender Party as set forth in this Article. SECTION 3.1.1. ORGANIZATION, ETC. {The Guarantor is a corporation duly organized, validly existing and in good standing under the laws of the State of its incorporation, and is duly qualified to do business and is in good standing as a foreign corporation in each jurisdiction where the nature of its business requires such qualification, except where failure to qualify would not have a material adverse effect on the business or financial condition of the Guarantor or on its ability to perform its Obligations pursuant to this Guaranty and each other Loan Document to which it is a party.} {The Guarantor is a partnership duly organized, validly existing and in good standing under the laws of the State of its formation, and is duly qualified to do business and is in good standing as a foreign partnership where the nature of its business requires such qualification, except where failure to qualify would not have a material adverse effect on the business or financial condition of the Guarantor or the Guarantor's ability to perform its Obligations under this Guaranty and any other Loan Documents to which it is a party.} The Guarantor has full power and authority and holds all requisite governmental licenses, permits and other approvals to enter into and perform its Obligations under this Guaranty and each other Loan Document to which it is a party and to own and hold under lease its property and to conduct its business substantially as currently conducted by it. SECTION 3.1.2. DUE AUTHORIZATION, NON-CONTRAVENTION, ETC. The execution, delivery and performance by the Guarantor of this Guaranty and each other Loan Document, including the Security Documents executed or to be executed by it, are within the Guarantor's {corporate} {partnership} powers, have been duly authorized by all necessary {corporate} {partnership} action, and do not (a) contravene the Guarantor's {Organic Documents} {partnership agreement}; (b) contravene any contractual restriction, law or governmental regulation or court decree or order binding on or affecting the Guarantor; or (c) result in, or require the creation or imposition of, any Lien on any properties of the Guarantor, except as Liens will be imposed, created, or required upon execution and delivery of the Security Documents pursuant to Section 7.8 of the Credit Agreement. 30 SECTION 3.1.3. GOVERNMENT APPROVAL, REGULATION, ETC. No authorization or approval or other action by, and no notice to or filing with, any governmental authority or regulatory body is required for the due execution, delivery or performance by the Guarantor of this Guaranty or any other Loan Document to which it is or will be a party. The Guarantor is not an "investment company" within the meaning of the Investment Company Act of 1940, as amended, or a "holding company", or a "subsidiary company" of a "holding company", or an "affiliate" of a "holding company" or of a "subsidiary company" of a "holding company", within the meaning of the Public Utility Holding Company Act of 1935, as amended. SECTION 3.1.4. VALIDITY, ETC. This Guaranty constitutes, and the Security Documents and each other Loan Document executed by the Guarantor will, on the due execution and delivery thereof, constitute, the legal, valid and binding obligations of the Guarantor, enforceable in accordance with their respective terms except as such enforceability is subject to the effect of (i) any applicable bankruptcy, insolvency, reorganization or similar law relating to or affecting creditors' rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law), including concepts of materiality, reasonableness, good faith and fair dealing. ARTICLE IV COVENANTS, ETC. SECTION 4.1. AFFIRMATIVE COVENANTS. The Guarantor covenants and agrees that, so long as any portion of the Obligations shall remain unpaid or any Lender shall have any outstanding Commitment, the Guarantor will, unless the Required Lenders shall otherwise consent in writing, perform the obligations set forth in this Section. SECTION 4.1.1. The Guarantor hereby agrees that upon the occurrence of any event or condition described in clauses (a) through (d) of Section 7.8 of the Credit Agreement, it will execute and deliver to the Collateral Agent such Security Documents as may be required or the Agent may request and cause each such Security Document to be filed, registered and recorded, as the law may require or the Agent may request, in each jurisdiction where so required or requested, and deliver to the Collateral Agent an acknowledgment copy, or other evidence satisfactory to it, of each such filing, registration and recordation, in order to mortgage, assign, grant a security interest in and pledge to the Collateral Agent, acting on behalf of the Lenders, the entire right, title and interest of the Guarantor (and, with respect to any Qualified Partnership Properties, the Guarantor's PRO RATA share of the right, title and interest of any partnership) in and to the Borrowing Base Properties and related property interests, both real and personal, and the proceeds thereof 31 (the "COLLATERAL") as set forth in such request, and to perfect and evidence the first priority of all such Security Documents (subject to liens and encumbrances permitted by the terms of such instruments). Except as noted below, Section 7.8 of the Credit Agreement, all related definitions and all ancillary provisions are hereby incorporated by reference herein as if set out in full herein, PROVIDED that (a) all references in clause (e) to "the Borrower," "the Borrower or any of its Subsidiaries" and "the Borrower or its Subsidiary" shall be deemed to be a reference to "the Guarantor", "the Guarantor or any of its Subsidiaries" or "the Guarantor or its Subsidiaries," as the case may be, and (b) any provision of such Section 7.8 requiring that the Borrower will cause its Subsidiary or Subsidiaries to take any action or will not permit its Subsidiary or Subsidiaries to take any action will be deemed to require that the Guarantor take, or refrain from taking (as the case may be), such action. SECTION 4.2. NEGATIVE COVENANTS. The Guarantor covenants and agrees that, so long as any portion of the Obligations shall remain unpaid or any Lender shall have any outstanding Commitment, the Guarantor will not, without the prior written consent of the Required Lenders, do anything prohibited in this Section. SECTION 4.2.1. The Guarantor shall not transfer any Borrowing Base Properties of the Guarantor in any manner except to the Borrower or to another Subsidiary of the Borrower which has executed a Subsidiary Guaranty in form and substance satisfactory to the Agent. ARTICLE V MISCELLANEOUS PROVISIONS SECTION 5.1. LOAN DOCUMENT. This Guaranty is a Loan Document executed pursuant to the Credit Agreement and shall (unless otherwise expressly indicated herein) be construed, administered and applied in accordance with the terms and provisions thereof. SECTION 5.2. BINDING ON SUCCESSORS, TRANSFEREES AND ASSIGNS; ASSIGNMENT. In addition to, and not in limitation of, SECTION 2.7, this Guaranty shall be binding upon the Guarantor and its successors, transferees and assigns and shall inure to the benefit of and be enforceable by each Lender Party and each holder of a Note and their respective successors, transferees and assigns (to the full extent provided pursuant to SECTION 2.7); PROVIDED, HOWEVER, the Guarantor may not assign any of its obligations hereunder without the consent of the Required Lenders. SECTION 5.3. AMENDMENTS, ETC. No amendment to or waiver of any provision of this Guaranty, nor consent to any departure by the Guarantor herefrom, shall in any event be effective unless the same shall be in writing and signed by the Agent, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given. 32 SECTION 5.4. ADDRESSES FOR NOTICES TO THE GUARANTOR. All notices and other communications hereunder to the Guarantor shall be in writing or by telex, or by facsimile delivered or transmitted to it, addressed to it at the address, telex or facsimile number set forth below its signature hereto or at such other address, telex or facsimile number as shall be designated by the Guarantor in a written notice to the Agent at the address, telex or facsimile number specified in the Credit Agreement complying as to delivery with the terms of this Section. Any notice, if mailed and properly addressed with postage prepaid, shall be deemed given when received; any notice, if transmitted by telex or facsimile, shall be deemed given when transmitted (answerback confirmed in the case of telexes). SECTION 5.5. NO WAIVER; REMEDIES. In addition to, and not in limitation of, SECTION 2.3 and SECTION 2.5, no failure on the part of any Lender Party or any holder of a Note to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law. SECTION 5.6. SECTION CAPTIONS. Section captions used in this Guaranty are for convenience of reference only, and shall not affect the construction of this Guaranty. SECTION 5.7. SETOFF. In addition to, and not in limitation of, any rights of any Lender Party or any holder of a Note under applicable law, each Lender Party and each such holder shall, upon the occurrence of any Default described in any of CLAUSES (a) through (d) of Section 9.1.9. of the Credit Agreement or any Event of Default, have the right to appropriate and apply to the payment of the obligations of the Guarantor owing to it hereunder, whether or not then due, and the Guarantor hereby grants to each Lender Party and each such holder a continuing security interest in, any and all balances, credits, deposits, accounts or moneys of the Guarantor then or thereafter maintained with such Lender Party or such holder and any and all property of every kind or description of or in the name of the Guarantor now or hereafter, for any reason or purpose whatsoever, in the possession or control of, or in transit to, such Lender Party, such holder or any agent or bailee for such Lender Party or such holder; PROVIDED, HOWEVER, that any such appropriation and application shall be subject to the provisions of Section 4.9 of the Credit Agreement. SECTION 5.8. SEVERABILITY. Wherever possible each provision of this Guaranty shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Guaranty shall be prohibited by or invalid under such law, such provision shall be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Guaranty. 33 SECTION 5.9. GOVERNING LAW, ENTIRE AGREEMENT, ETC. THIS GUARANTY SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE INTERNAL LAWS OF THE STATE OF ILLINOIS. THIS GUARANTY AND THE OTHER LOAN DOCUMENTS CONSTITUTE THE ENTIRE UNDERSTANDING AMONG THE PARTIES HERETO WITH RESPECT TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ANY PRIOR AGREEMENTS, WRITTEN OR ORAL, WITH RESPECT THERETO. THIS GUARANTY AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES. IN WITNESS WHEREOF, the Guarantor has caused this Guaranty to be duly executed and delivered by its officer thereunto duly authorized as of the date first above written. {NAME OF SUBSIDIARY} By: Title: Address: Attention: Telecopy: 34 EX-10.F.2.II 4 EXTENSION AGREEMENT S.P.B. EXHIBIT 10(f)(2)(ii) EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT between Stuart P. Burbach ("Executive") and Pogo Producing Company, a Delaware corporation ("Company"), dated as of February 1, 1994 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1992, and an "Extension Agreement" dated as of February 1, 1993; and WHEREAS, February 1, 1994, (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, 1996); 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, 1992 and a "Renewal Date" which is deemed herein to be February 1, 1994, is hereby extended for an additional one-year period commencing February 1, 1995 and ending January 31, 1996, unless such employment 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 February 1, 1992, and as it may have been and herein is amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1994. POGO PRODUCING COMPANY By:/s/ Paul G. Van Wagenen Chairman, President and Chief Executive Officer ATTEST: /s/ Ronald B. Manning EMPLOYEE: /s/ Stuart P. Burbach EX-10.F.4.II 5 EXTENSION AGREEMENT J.A.C. EXHIBIT 10(f)(4)(ii) EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT between Jerry A. Cooper ("Executive") and Pogo Producing Company, a Delaware corporation ("Company"), dated as of February 1, 1994 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1992, and an "Extension Agreement" dated as of February 1, 1993; and WHEREAS, February 1, 1994, (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, 1996); 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, 1992 and a "Renewal Date" which is deemed herein to be February 1, 1994, is hereby extended for an additional one-year period commencing February 1, 1995 and ending January 31, 1996, unless such employment 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 February 1, 1992, and as it may have been and herein is amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1994. POGO PRODUCING COMPANY By:/s/ Paul G. Van Wagenen Chairman, President and Chief Executive Officer ATTEST: /s/ Ronald B. Manning EMPLOYEE: /s/ Jerry A. Cooper EX-10.F.6.II 6 EXTENSION AGREEMENT K.R.G. EXHIBIT 10(f)(6)(ii) EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT between Kenneth R. Good ("Executive") and Pogo Producing Company, a Delaware corporation ("Company"), dated as of February 1, 1994 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1992, and an "Extension Agreement" dated as of February 1, 1993; and WHEREAS, February 1, 1994, (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, 1996); 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, 1992 and a "Renewal Date" which is deemed herein to be February 1, 1994, is hereby extended for an additional one-year period commencing February 1, 1995 and ending January 31, 1996, unless such employment 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 February 1, 1992, and as it may have been and herein is amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1994. POGO PRODUCING COMPANY By:/s/ Paul G. Van Wagenen Chairman, President and Chief Executive Officer ATTEST: /s/ Ronald B. Manning EMPLOYEE: /s/ Kenneth R. Good EX-10.F.8.II 7 EXTENSION AGREEMENT R.P.L. EXHIBIT 10(f)(8)(ii) EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT between Radford P. Laney ("Executive") and Pogo Producing Company, a Delaware corporation ("Company"), dated as of February 1, 1994 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1992, and an "Extension Agreement" dated as of February 1, 1993; and WHEREAS, February 1, 1994, (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, 1996); 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, 1992 and a "Renewal Date" which is deemed herein to be February 1, 1994, is hereby extended for an additional one-year period commencing February 1, 1995 and ending January 31, 1996, 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 February 1, 1992, and as it may have been and herein is amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1994. POGO PRODUCING COMPANY By:/s/ Paul G. Van Wagenen Chairman, President and Chief Executive Officer ATTEST: /s/ Ronald B. Manning EMPLOYEE: /s/ Radford P. Laney EX-10.F.10.II 8 EXTENSION AGREEMENT J.O.M. EXHIBIT 10(f)(10)(ii) EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT between John O. McCoy, Jr. ("Executive") and Pogo Producing Company, a Delaware corporation ("Company"), dated as of February 1, 1994 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1992, and an "Extension Agreement" dated as of February 1, 1993; and WHEREAS, February 1, 1994, (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, 1996); 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, 1992 and a "Renewal Date" which is deemed herein to be February 1, 1994, is hereby extended for an additional one-year period commencing February 1, 1995 and ending January 31, 1996, unless such employment 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 February 1, 1992, and as it may have been and herein is amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1994. POGO PRODUCING COMPANY By:/s/ Paul G. Van Wagenen Chairman, President and Chief Executive Officer ATTEST: /s/ Ronald B. Manning EMPLOYEE: /s/ John O. McCoy, Jr. EX-10.F.12.II 9 EXTENSION AGREEMENT D.S.S. EXHIBIT 10(f)(12)(ii) EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT between D. Stephen Slack ("Executive") and Pogo Producing Company, a Delaware corporation ("Company"), dated as of February 1, 1994 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1992, and an "Extension Agreement" dated as of February 1, 1993; and WHEREAS, February 1, 1994, (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, 1996); 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, 1992 and a "Renewal Date" which is deemed herein to be February 1, 1994, is hereby extended for an additional one-year period commencing February 1, 1995 and ending January 31, 1996, 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 February 1, 1992, and as it may have been and herein is amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1994. POGO PRODUCING COMPANY By:/s/ Paul G. Van Wagenen Chairman, President and Chief Executive Officer ATTEST: /s/ Ronald B. Manning EMPLOYEE: /s/ D. Stephen Slack EX-10.F.14.II 10 EXTENSION AGREEMENT P.G.V. EXHIBIT 10(f)(14)(ii) EXTENSION AGREEMENT TO CONTINUE EMPLOYMENT AGREEMENT between Paul G. Van Wagenen ("Executive") and Pogo Producing Company, a Delaware corporation ("Company"), dated as of February 1, 1994 WHEREAS, Executive and Company are parties to an "Employment Agreement" bearing an original "Effective Date" of February 1, 1992, and an "Extension Agreement" dated as of February 1, 1993; and WHEREAS, February 1, 1994, (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, 1996); 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, 1992 and a "Renewal Date" which is deemed herein to be February 1, 1994, is hereby extended for an additional one-year period commencing February 1, 1995 and ending January 31, 1996, unless such employment 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 February 1, 1992, and as it may have been and herein is amended, are continued in full force and effect without change as if the Employment Agreement had been initially effective as of February 1, 1994. POGO PRODUCING COMPANY By: /s/ John O. McCoy, Jr. Vice President and Chief Administrative Officer ATTEST: /s/ Ronald B. Manning EMPLOYEE: /s/ Paul G. Van Wagenen EX-21 11 LIST OF SUBSIDIARIES EXHIBIT 21 List of Subsidiaries of POGO PRODUCING COMPANY Jurisdiction of Name Incorporation 1. Thaipo Limited Kingdom of Thailand 2. Pogo Offshore Pipeline Co. Delaware 3. Pogo Gulf Coast, Ltd. Texas Limited Partnership (The Company is the general partner and a 40% limited partner) 4. Pogo Petroles Compagnie, Inc. Delaware 5. Pogo Netherlands, Inc. Delaware 6. Pogo Thailand, Inc. Delaware 7. Pogo Turkey Inc. Delaware 8. Sampack Inc. Delaware 9. Pogo British Isles, Inc. Delaware EX-23.A 12 CONSENT OF ARTHUR ANDERSEN & C0. EXHIBIT 23(a) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report dated February 8, 1994 included in this Annual Report on Form 10-K, into Pogo Producing Company's previously filed Registration Statement File Nos. 2-60725, 2-62690, 2-65374, 2-79500. ARTHUR ANDERSEN & CO. Houston, Texas February 28, 1994 EX-23.B 13 CONSENT RYDER SCOTT COMPANY EXHIBIT 23(b) CONSENT OF INDEPENDENT PETROLEUM ENGINEERS We hereby consent to the use of our name in the Annual Report on Form 10-K of Pogo Producing Company (the "Company") for the year ended December 31, 1993. 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 February 28, 1994 EX-24 14 POWERS OF ATTORNEY EXHIBIT 24 POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I Tobin Armstrong, in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ TOBIN ARMSTRONG Tobin Armstrong POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I Jack S. Blanton, in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ JACK S. BLANTON Jack S. Blanton POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I W. M. Brumley, Jr., in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ W. M. BRUMLEY, JR. W. M. Brumley, Jr. POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I John B. Carter, Jr., in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ JOHN B. CARTER, JR. John B. Carter, Jr. POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I William L. Fisher, in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ WILLIAM L. FISHER William L. Fisher POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I William E. Gipson, in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ WILLIAM E. GIPSON William E. Gipson POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I Gerrit W. Gong, in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ GERRIT W. GONG Gerrit W. Gong POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I Thomas E. Hart, in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ THOMAS E. HART Thomas E. Hart POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I J. Stuart Hunt, in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ J. STUART HUNT J. Stuart Hunt POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I Frederick A. Klingenstein, in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ FREDERICK A. KLINGENSTEIN Frederick A. Klingenstein POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I Nicholas R. Petry, in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ NICHOLAS R. PETRY Nicholas R. Petry POWER OF ATTORNEY WHEREAS, POGO PRODUCING COMPANY, a Delaware corporation (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K for the fiscal year ended December 31, 1993, as prescribed by the Commission pursuant to the Act, and the rules and regulations of the Commission promulgated thereunder, with any and all exhibits and other documents relating to said Annual Report; NOW, THEREFORE, I Jack A. Vickers, in my capacity as a director of the Company, do hereby appoint PAUL G. VAN WAGENEN, D. STEPHEN SLACK, and THOMAS E. HART, and each of them severally, my true and lawful attorney or attorneys with power to act with or without the others, and with full power of substitution and resubstitution, to execute in my name, place and stead in my capacity as a director of the Company, said Annual Report, 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 in my capacity as a director any act whatsoever that is 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 25th day of January, 1994. /s/ JACK A. VICKERS Jack A. Vickers EX-28 15 ESTIMATE OF RESERVES EXHIBIT 28 {LOGO} RYDER SCOTT COMPANY PETROLEUM ENGINEERS FAX (713) 651-0849 1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5218 TELEPHONE (713) 651-9191 January 28, 1994 Pogo Producing Company Post Office Box 61289 Houston, Texas 77208 Gentlemen: At your request we have prepared an estimate of the reserves, future production, and income attributable to certain leasehold and royalty interests of Pogo Producing Company and its wholly owned subsidiaries (the Company) as of December 31, 1993. In accordance with the requirements of FASB 69, our estimates of the Company's net proved reserves as of December 31, 1990, 1991, 1992, and 1993, as contained in this report and our previous reports, are presented in attached Table No. 1 together with a tabulation of the components of the differences in the estimates as of such dates. The Company's reserves in the United States are located in the states of Louisiana, New Mexico, Oklahoma, Texas, and in state and federal waters offshore Alabama, Louisiana, and Texas. The Company's foreign reserves are located offshore Thailand. The estimated reserve volumes and future income amounts presented in this report are related to hydrocarbon prices. December 1993 hydrocarbon prices were used in the preparation of this report as required by Securities and Exchange Commission (SEC) and Financial Accounting Standards Bulletin No. 69 (FASB 69) guidelines; however, actual future prices may vary significantly from December 1993 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ from the estimated quantities presented in this report. Our estimates of the proved net reserves attributable to the interests of the Company as of December 31, 1993 are shown below: Proved Net Reserves As of December 31, 1993 Liquid Barrels Gas MMCF Developed and Undeveloped United States 22,843,628 199,392 Foreign 5,424,813 33,474 ----------- -------- Total Worldwide 28,268,441 232,866 Developed United States 20,976,194 183,139 Foreign 0 0 ----------- -------- Total Worldwide 20,976,194 183,139 The "Liquid" reserves shown above are comprised of crude oil, condensate, and natural gas liquids. Natural gas liquids comprise 18 percent of the Company's developed liquid reserves and 14 percent of the Company's developed and undeveloped liquid reserves. All hydrocarbon liquid reserves are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in MMCF at the pressure and temperature bases of the area where the gas reserves are located. The proved reserves presented in this report comply with the SEC's Regulation S-X Part 210.4-10 Sec. (a) as clarified by subsequent Commission Staff Accounting Bulletins, and are based on the following definitions and criteria: 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 (1) that portion delineated by drilling and defined by fluid contacts, if any, and (2) 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 become 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 natural gas 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 improved recovery techniques are included in the proved classification when these qualifications are met: (1) 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 (2) 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 (1) pressure maintenance, (2) cycling, and (3) 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, 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 the 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 a new well; 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. Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed. The Company has interests in certain tracts which have substantial additional hydrocarbon quantities which cannot be classified as proved and consequently are not included herein. The Company has active exploratory and development drilling programs which may result in the reclassification of significant additional volumes to the proved category. In accordance with the requirements of FASB 69, our estimates of future cash inflows, future costs, and future net cash inflows before income tax as of December 31, 1993 from this report and as of December 31, 1992 from our previous report are presented below. As of December 31 1993 1992 Future Cash Inflows $895,060,044 $866,414,345 Future Costs Production $211,741,925 $189,897,073 Development 133,257,042 105,843,039 ------------ ------------- Total Costs $344,998,967 $295,740,112 Future Net Cash Inflows Before Income Tax $550,061,077 $570,674,233 Present Value at 10% Before Income Tax $403,840,199 $405,101,565 Our estimates as of December 31, 1993 and 1992 of future cash inflows, future costs, future net cash inflows before income tax, and present value at 10 percent before income tax are shown individually for total worldwide, total United States (onshore and offshore), and foreign areas in Table No. 2 which is attached. The future cash inflows are gross revenues before any deductions. The production costs were based on current data and include production taxes, ad valorem taxes, and certain other items such as transportation costs in addition to the operating costs directly applicable to the individual leases or wells. The development costs were based on current data and include dismantlement and abandonment costs net of salvage for properties where such costs are relatively significant. The Company furnished us with gas prices in effect at December 31, 1993 and with its forecasts of future gas prices which take into account SEC guidelines, current market prices, contract prices, and fixed and determinable price escalations where applicable. In accordance with SEC guidelines, the future gas prices used in this report make no allowances for future gas price increases which may occur as a result of inflation nor do they account for seasonal variations in gas prices which may cause future yearly average gas prices to be somewhat lower than December gas prices. For gas sold under contract, the contract gas price including fixed and determinable escalations exclusive of inflation adjustments, was used until the contract expires and then was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves. The Company furnished us with liquid prices in effect at December 31, 1993 and these prices were held constant to depletion of the properties. In accordance with SEC guidelines, changes in liquid prices subsequent to December 31, 1993 were not considered in this report. The estimates of future net revenue from the Company's foreign property are based on existing law. Operating costs for the leases and wells in this report were based on the operating expense reports of the Company and 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 were furnished to us by the Company and are based on authorizations 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, this study did not consider the salvage value of the lease equipment or the abandonment cost since both are relatively insignificant and tend to offset each other. The estimated net cost of abandonment after salvage was included for offshore properties where abandonment costs net of salvage are significant. The estimates of the offshore net abandonment costs furnished by the Company were accepted without independent verification. No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments. The Company supplied data on accumulated gas production imbalances which were taken into account in our estimates of future production and income The estimates of reserves presented herein are based upon a detailed study of the properties in which the Company owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. The Company has informed us that they have furnished us all of the accounts, records, geological and engineering data and reports, and other data required for this investigation. The ownership interests, prices, and other factual data furnished by the Company were accepted without independent verification. The estimates presented in this report are based on data available through December 1993. The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations. In general, we estimate that future gas production rates will continue to be the same as the average rate for the latest available 12 months of actual production until such time that the well or wells are incapable of producing at this rate. The well or wells were then projected to decline at their decreasing delivery capacity rate. Our general policy on estimates of future gas production rates is adjusted when necessary to reflect actual gas market conditions in specific cases. The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future cash inflows for the subject properties. Very truly yours, RYDER SCOTT COMPANY PETROLEUM ENGINEERS /s/ Fred P. Richoux Fred P. Richoux, P.E. Group Vice President TABLE NO. 1 POGO PRODUCING COMPANY Proved Net Reserve Data
United States Total Worldwide Total Onshore and Offshore 1993 1992 1991 1993 1992 1991 Net Proved Liquid(1) Reserves, Barrels Developed and Undeveloped Beginning of Year 22,555,788 18,818,091 19,090,376 19,978,881 18,818,091 19,090,376 Revisions 342,022 1,721,385 782,707 342,022 1,721,385 782,707 Extensions and Discoveries 9,764,408 5,486,273 1,612,983 6,916,502 2,909,366 1,612,983 Improved Recovery 0 0 0 0 0 0 Estimated Production -4,219,873 -3,611,105 -2,931,465 -4,219,873 -3,611,105 -2,931,465 Purchase of Reserves In-Place 182,610 335,750 263,495 182,610 335,750 263,495 Sales of Reserves In-Place -356,514 -194,606 -5 -356,514 -194,606 -5 End of Year 28,268,441 22,555,788 18,818,091 22,843,628 19,978,881 18,818,091 Developed Beginning of Year 18,798,149 17,549,830 17,841,751 18,798,149 17,549,830 17,841,751 End of Year 20,976,194 18,798,149 17,549,830 20,976,194 18,798,149 17,549,830 Net Proved Gas Reserves, Millions of Cubic Feet Developed and Undeveloped Beginning of Year 207,068 202,735 217,500 196,400 202,735 217,500 Revisions 1,148 20,284 3,531 1,148 20,284 3,531 Extensions and Discoveries 55,626 19,126 16,157 32,820 8,458 16,157 Improved Recovery 0 0 0 0 0 0 Estimated Production -32,319 -40,581 -39,362 -32,319 -40,581 -39,362 Purchase of Reserves In-Place 13,192 10,237 4,913 13,192 10,237 4,913 Sales of Reserves In-Place -11,849 -4,733 -4 -11,849 -4,733 -4 End of Year 232,866 207,068 202,735 199,392 196,400 202,735 Developed Beginning of Year 175,523 188,090 202,471 175,523 188,090 202,471 End of Year 183,139 175,523 188,090 183,139 175,523 188,090 Foreign Thailand Offshore 1993 1992 1991 Net Proved Liquid(1) Reserves, Barrels Developed and Undeveloped Beginning of Year 2,576,907 0 0 Revisions 0 0 0 Extensions and Discoveries 2,847,906 2,576,907 0 Improved Recovery 0 0 0 Estimated Production 0 0 0 Purchase of Reserves In-Place 0 0 0 Sales of Reserves In-Place 0 0 0 End of Year 5,424,813 2,576,907 0 Developed Beginning of Year 0 0 0 End of Year 0 0 0 Net Proved Gas Reserves, Millions of Cubic Feet Developed and Undeveloped Beginning of Year 10,668 0 0 Revisions 0 0 0 Extensions and Discoveries 22,806 10,668 0 Improved Recovery 0 0 0 Estimated Production 0 0 0 Purchase of Reserves In-Place 0 0 0 Sales of Reserves In-Place 0 0 0 End of Year 33,474 10,668 0 Developed Beginning of Year 0 0 0 End of Year 0 0 0 _______________________________ (1) Liquid reserves shown above are comprised of crude oil, condensate, and natural gas liquids.
TABLE NO. 2 POGO PRODUCING COMPANY Cash Inflow and Cost Data (U.S. Dollars)
United States Total Worldwide Onshore and Offshore Thailand Offshore As of December 31 As of December 31 As of December 31 1993 1992 1993 1992 1993 1992 Future Cash Inflows(1) $895,060,044 $866,414,345 $744,200,701 $791,864,973 $150,859,343 $74,549,372 Future Costs Production(2) $211,741,925 $189,897,073 $158,934,102 $173,355,154 $ 52,807,823 $16,541,919 Development(3) 133,257,042 105,843,039 79,734,742 80,887,079 53,522,300 24,955,960 Total Costs $344,998,967 $295,740,112 $238,668,844 $254,242,233 $106,330,123 $41,497,879 Future Cash Inflows Before Income Tax $550,061,077 $570,674,233 $505,531,857 $537,622,740 $ 44,529,220 $33,051,493 Present Value @ 10% Before Income Tax $403,840,199 $405,101,565 $386,673,722 $390,893,269 $ 17,166,477 $14,208,296 _______________________________ (1) Gross revenues before any deductions. (2) Includes production taxes in the U.S.A., SRB taxes in Thailand, ad valorem taxes and certain other items such as transportation charges. (3) Includes future abandonment costs net of salvage for offshore properties where such costs are relatively significant.
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