SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) ( X ) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED) FOR THE FISCAL YEAR ENDED: December 31, 1996 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) FOR THE TRANSITION PERIOD FROM ___________ TO ______________ Commission File Number: 1-11675 TRITON ENERGY LIMITED (Exact name of registrant as specified in its charter) CAYMAN ISLANDS NONE (State or other jurisdiction of (I.R.S.Employer incorporation or organization) Identification No.) CALEDONIAN HOUSE MARY STREET, P.O. BOX 1043 GEORGE TOWN GRAND CAYMAN, CAYMAN ISLANDS NONE (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 345-949-0050 Securities registered pursuant to Section 12(b) of the Act: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED Ordinary Shares, $.01 par value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None. INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES X NO 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 VOTING STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT AT MARCH 7, 1997 (FOR SUCH PURPOSES ONLY, ALL DIRECTORS AND EXECUTIVE OFFICERS ARE PRESUMED TO BE AFFILIATES) WAS APPROXIMATELY $1.5 BILLION, BASED ON THE CLOSING SALES PRICE OF $ 41 7/8 ON THE NEW YORK STOCK EXCHANGE. AS OF MARCH 7, 1997, 36,381,884 ORDINARY SHARES OF THE REGISTRANT WERE OUTSTANDING. DOCUMENTS INCORPORATED BY REFERENCE PORTIONS OF THE PROXY STATEMENT PERTAINING TO THE 1997 ANNUAL MEETING OF SHAREHOLDERS OF TRITON ENERGY LIMITED ARE INCORPORATED BY REFERENCE INTO PART III HEREOF. TRITON ENERGY LIMITED TABLE OF CONTENTS Form 10-K Item Page - ------------------------------------------------------------------------------- ---- PART I ITEMS 1. and 2. Business and Properties 1 ITEM 3. Legal Proceedings 19 ITEM 4. Submission of Matters to a Vote of Security Holders 20 PART II ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters 21 ITEM 6. Selected Financial Data 23 ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 24 ITEM 8. Financial Statements and Supplementary Data 32 ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 32 PART III ITEM 10. Directors and Executive Officers of the Registrant 33 ITEM 11. Executive Compensation 33 ITEM 12. Security Ownership of Certain Beneficial Owners and Management 33 ITEM 13. Certain Relationships and Related Transactions 33 PART IV ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 34 PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES GENERAL Triton Energy Limited is an international oil and gas exploration company primarily engaged in exploration and production through subsidiaries and affiliates. The Company's principal properties, operations and oil and gas reserves are located in Colombia and Malaysia-Thailand. The Company also has oil and gas interests in other Latin American, Asian and European countries. Triton Energy Limited was incorporated in the Cayman Islands in 1995 to become the parent holding company of Triton Energy Corporation ("TEC"), a corporation formed in Texas in 1962 and reincorporated in Delaware in 1995. The Company's principal executive offices are located at Caledonian House, Mary Street, George Town, Grand Cayman, Cayman Islands, and its telephone number is (345) 949-0050. The terms "Company" and "Triton" when used herein mean Triton Energy Limited and its subsidiaries and other affiliates through which Triton conducts its business, unless the context otherwise implies. OIL AND GAS OPERATIONS General The Company's oil and gas exploration and development activities are, or have been, conducted through the Company's wholly owned subsidiaries, except as noted in this paragraph. In Malaysia-Thailand, the Company's activities are conducted by the Company's wholly owned subsidiaries, Triton Oil Company of Thailand and Triton Oil Company of Thailand (JDA) Limited (collectively, "Triton Thailand"), and Triton Thailand's 50% owned affiliate, Carigali - Triton Operating Company Sdn. Bhd. ("CTOC"). In Europe, its activities were conducted by its wholly owned (but until March 1994, 59.5% owned) subsidiary, Triton Europe Limited ("Triton Europe"). In Indonesia, its activities are or were conducted by its wholly owned subsidiaries, Triton Indonesia, Inc., Triton Indonesia Resources, Inc. and TriBlora Indonesia B.V. (collectively, "Triton Indonesia") and its 33.7% owned (but until August 1994, 63.7% owned) affiliate, New Zealand Petroleum Company Limited ("New Zealand Petroleum"). In the United States, its activities were conducted by its wholly owned subsidiary, Triton Oil & Gas Corp. ("Triton Oil"), and Crusader Limited ("Crusader"), a 49.9% owned affiliate until the Company's sale of its interest in 1996. In New Zealand, its activities are or were conducted by New Zealand Petroleum and Crusader. In Canada its activities were conducted by Crusader, until June 1995, and by Triton Canada Resources Ltd. ("Triton Canada") until August 1993, and in Australia its activities were conducted by Crusader. Production and Sales The following table sets forth the net quantities of oil and gas produced by the Company for the years ended December 31, 1996 and 1995, the seven months ended December 31, 1994, and the year ended May 31, 1994, including production attributable to the Company's 49.9% ownership interest in Crusader through the date of its sale (which included the minority interests in Crusader's consolidated subsidiaries). The production and sales information relating to properties or subsidiary or affiliate ownership interests acquired or disposed of is reflected in the table only since or up to the effective dates of their respective acquisitions or sales, as the case may be. OIL PRODUCTION (1) GAS PRODUCTION ------------------------------------------------------------------ --------------- SEVEN MOS. YEAR YEAR ENDED ENDED ENDED YEAR ENDED DECEMBER 31, DEC. 31, MAY 31, DECEMBER 31, ------------------------- ------------ 1996 1995 1994 1994 1996 1995 ------------ ----- ---------- ------- ------------ ----- (IN MBBLS) (IN MMCF) Colombia(2) 5,738 5,089 435 467 298 158 Argentina --- --- --- 18 --- --- France(3) --- 498 514 1,053 --- --- Indonesia(4) 95 255 186 441 --- --- United States(5) 20 121 66 156 475 1,207 Canada(5) --- --- --- 102 --- --- Crusader(6): Australia 134 287 180 404 1,744 3,884 Canada --- 53 99 213 --- 63 United States --- --- 8 32 --- --- ------------ ----- ---------- ------- ------------ ----- Total 5,987 6,303 1,488 2,886 2,517 5,312 ------------ ----- ---------- ------- ------------ ----- GAS PRODUCTION --------------- SEVEN MOS. YEAR ENDED ENDED DEC. 31, MAY 31, 1994 1994 ---------- ------- Colombia(2) --- --- Argentina --- --- France(3) --- --- Indonesia(4) --- --- United States(5) 618 1,150 Canada(5) --- 3,521 Crusader(6): Australia 2,707 4,202 Canada 96 150 United States 6 55 ---------- ------- Total 3,427 9,078 ---------- ------- ____________________ (1) Includes natural gas liquids and condensate. (2) Includes Ecopetrol reimbursement and excludes .7 million and .4 million barrels of oil produced and delivered for the years ended December 31, 1996 and 1995, respectively, in connection with the Company's forward sale of oil in May 1995. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations" and note 3 of Notes to Consolidated Financial Statements. (3) In August 1995, Triton Europe sold its interest in its subsidiary, Triton France S.A. (4) In May 1996, the Company sold substantially all of the assets of Triton Indonesia, Inc. (5) In March 1996, Triton Oil sold substantially all of its domestic royalty and mineral interests. During the fiscal year ended May 31, 1994, Triton Oil sold substantially all its working interests in oil and gas reserves in the United States and its common equity interest in Triton Canada. See note 2 of Notes to Consolidated Financial Statements. (6) In 1996, the Company sold all of its interest in Crusader. In June 1995, Crusader sold all of its interest in Ausquacan Energy Limited and in September 1994, Crusader sold all of its oil and gas interests in the United States. The following tables summarize for the years ended December 31, 1996 and 1995, the seven months ended December 31, 1994, and the year ended May 31, 1994: (i) the average sales price per barrel of oil and Mcf of natural gas; (ii) the average sales price per equivalent barrel of production; (iii) the depletion cost per equivalent barrel of production; and (iv) the production cost per equivalent barrel of production: AVERAGE SALES PRICE AVERAGE SALES PRICE PER BARREL OF OIL (1) PER MCF OF GAS ------------------------------ -------------------------- SEVEN MOS. YEAR SEVEN MOS. YEAR YEAR ENDED ENDED ENDED YEAR ENDED ENDED ENDED DECEMBER 31, DEC. 31, MAY 31, DECEMBER 31, DEC. 31, MAY 31, ------------------------------ --------------------------- 1996 1995 1994 1994 1996 1995 1994 1994 ---------------------- ------ ----------- -------- -------------------- ----- ----------- -------- Colombia $ 19.62 $16.29 $ 14.37 $ 12.66 $ 2.56 $1.96 $ --- $ --- Argentina --- --- --- 9.22 --- --- --- --- France --- 18.11 17.64 16.38 --- --- --- --- Indonesia 19.54 17.77 17.06 16.29 --- --- --- --- United States 16.00 13.62 15.65 14.19 1.15 1.49 1.55 2.23 Canada --- --- --- 16.43 --- --- --- 1.11 Crusader: Australia 19.95 20.38 18.39 15.33 1.69 1.69 1.43 1.50 Canada --- 15.42 14.62 12.43 --- 0.99 1.01 1.11 United States --- --- 17.75 15.23 --- --- 1.25 1.53 PER EQUIVALENT BARREL (2) ------------------------------------------------------------------------------------------------------------------ AVERAGE SALES PRICE DEPLETION(3) ------------------------------------------------------- ------------ SEVEN MOS. YEAR SEVEN MOS. YEAR ENDED ENDED ENDED YEAR ENDED ENDED DECEMBER 31, DEC. 31, MAY 31, DECEMBER 31, DEC. 31, -------------------- ---------------- 1996 1995 1994 1994 1996 1995 1994 -------------------- ------ ---------------- -------- ----------- ----- ---------- Colombia $ 19.58 $16.26 $ 14.37 $ 12.66 $ 2.83 $2.67 $ 2.57 Argentina --- --- --- 9.22 --- --- --- France --- 18.11 17.64 16.38 --- 3.14 4.15 Indonesia 19.54 17.77 17.06 16.29 0.52 0.95 1.60 United States 8.75 10.68 11.77 13.75 5.59 6.05 7.04 Canada --- --- --- 8.13 --- --- --- Crusader: Australia 13.23 13.29 9.53 11.31 3.47 3.35 3.99 Canada --- 13.87 13.43 11.83 --- 2.35 2.31 United States --- --- 16.56 13.88 --- --- 5.22 DEPLETION(3) PRODUCTION COST ------------ ----------------------------------- YEAR SEVEN MOS. YEAR ENDED YEAR ENDED ENDED ENDED MAY 31, DECEMBER 31, DEC. 31, MAY 31, ------------------------ 1994 1996 1995 1994 1994 ----------- ---------------- ------ ----------- -------- Colombia $ 1.96 $ 5.66 $ 5.52 $ 9.87 $ 9.06 Argentina --- --- --- --- 13.83 France 8.97 --- 10.96 11.25 9.83 Indonesia 3.09 15.89 17.34 11.04 14.54 United States 6.58 3.25 1.03 0.85 7.00 Canada 3.60 --- --- --- 4.24 Crusader: Australia 3.33 4.10 4.77 4.01 3.97 Canada 2.97 --- 7.52 7.96 7.44 United States 13.82 --- --- 6.00 7.77 ____________________ (1) Includes natural gas liquids and condensate. (2) Natural gas has been converted into equivalent barrels based on six Mcf of natural gas per barrel. (3) Includes depreciation calculated on the unit of production method for support equipment and facilities. Competition The Company encounters strong competition from major oil companies (including government-owned companies), independent operators and other companies for favorable oil and gas concessions, licenses, production sharing contracts and leases, drilling rights and markets. Additionally, the governments of certain countries in which the Company operates may from time to time give preferential treatment to their nationals. The oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The principal means of competition in the sale of oil and gas are product availability, price and quality. While it is not possible for the Company to state precisely its competitive position in the oil and gas industry, the Company believes that it represents a minor competitive factor. Markets Crude oil, natural gas, condensate and other oil and gas products generally are sold to other oil and gas companies, government agencies and other industries. The Company does not believe that the loss of any single customer or contract pursuant to which oil and gas is sold would have a long-term material, adverse effect on the revenues from the Company's oil and gas operations. In Colombia, crude oil is exported through the Caribbean port of Covenas where it is sold at prices based on United States prices, adjusted for quality and transportation. The oil produced from the Cusiana Field is transported to the export terminal through pipelines owned by the Colombian national oil company or joint stock companies partially owned by the Company. This pipeline system is in the process of being upgraded to accommodate additional production from the Cusiana and Cupiagua fields. See "Oil and Gas Properties - Colombia" and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations." For a discussion of certain factors regarding the Company's markets and potential markets that could affect future operations, see note 20 of Notes to Consolidated Financial Statements. OIL AND GAS PROPERTIES Colombia Through the Company's wholly owned subsidiaries, Triton Colombia, Inc. and Triton Resources Colombia, Inc. (collectively, "Triton Colombia"), the Company has varying participation interests in seven licenses in Colombia. Cusiana and Cupiagua Fields Contract Terms. In the foothills of the Llanos Basin area in eastern Colombia, Triton Colombia holds a 12% interest in the SDLA, Tauramena and Rio Chitamena contract areas, covering approximately 66,000, 36,300 and 6,700 acres, respectively, where an active appraisal and development program is being carried out in the Cusiana and Cupiagua fields. Triton's partners in these areas are Empresa Colombiana De Petroleos ("Ecopetrol"), the Colombian national oil company, with a 50% interest, BP Exploration Company (Colombia) Limited ("BP"), the operator, with a 19% interest, and TOTAL Exploratie en Produktie Maatschippij B.V. ("TOTAL"), also with a 19% interest. In 1993, Ecopetrol declared the Cusiana and Cupiagua fields to be commercial and exercised its right to acquire a 50% interest. Triton's net revenue interest is approximately 9.6% after governmental royalties. Triton's net revenue is reduced by up to 0.36% pursuant to an agreement with an original co-investor, subject to Triton being reimbursed for a proportionate share of expenditures relating thereto. The Company and its private partners have secured the right to produce oil and gas from the SDLA and Tauramena contract areas through the years 2010 and 2016, respectively, and from the Rio Chitamena contract area through 2015 or 2019, depending on contract interpretation. In July 1994, Triton Colombia, BP, TOTAL and Ecopetrol entered into an Integral Plan for the Unified Exploitation of the Cusiana Oil Structure in the SDLA, Tauramena and Rio Chitamena Association Contract Areas. Under the plan, the parties have agreed to develop the Cusiana oil structure in a technically efficient and cooperative manner during three consecutive periods of time. During the initial period (ending with the expiration of the SDLA association contract in 2010), petroleum produced from the unified area will be owned by the parties according to their respective undivided interests in each contract area. Within the first quarter of 2005, an independent determination of the original barrels of oil equivalent ("BOE") of petroleum in place under the unified area and under each association contract will be made, as a result of which a "tract factor" will be calculated for each association contract. Each tract factor will be the amount of original BOEs of petroleum in place under the particular association contract as a percentage of the total original BOEs under the unified area. Each party's unified area interest during the second period (commencing from the expiration of the SDLA association contract in 2010) and during the final period (commencing from the termination of the second association contract to termination) will be the aggregate of that party's interest in each remaining association contract multiplied by the tract factor for each such contract. Recent Drilling Results. In the Cusiana Field, Triton Colombia and its working interest partners have completed and have in service 24 producing wells and six gas injection wells. The injection wells recycle to the reservoir most of the gas that is associated with the oil production to increase the oil recoverable over the life of the field. There are currently five drilling rigs operating in the Cusiana Field, and it is expected that 18 oil production and gas injection wells will be completed during 1997. Development drilling is proceeding on a schedule which is intended to have sufficient well capacity at all times to meet production capacities of field facilities and export pipelines from the area. In the Cupiagua Field during 1996, Triton Colombia and its working interest partners completed an additional six wells, bringing the yearend total completions to 10 wells, which are awaiting startup of production facilities in 1997. There are currently six drilling rigs operating in the Cupiagua Field, and it is expected that 15 additional wells will be completed during 1997. Development wells drilled during 1996 more fully defined the areal extent of the field and defined hydrocarbon/water contacts in the fields. The Cupiagua-5 well was completed in late 1995 and was tested in 1996. The well penetrated the Mirador, Barco and Guadalupe reservoirs, and the lower extension of the well discovered a lower thrust of the Mirador Formation which underlies the main body of the Cupiagua Field. The lower thrust of the Mirador was confirmed in the Cupiagua-7 and Cupiagua-10 development wells. The well data and the 3D seismic results are being analyzed to determine the optimum development plan for this underlying Mirador reservoir. In 1997, Triton Colombia and its working interest partners plan to drill additional wells dedicated to exploring the lower thrust. Tests of the Cupiagua-5 well, which were conducted in early 1996, indicated the well has a productive capacity of about 75 MMcf of gas and 22,000 barrels of condensate per day through 7" tubing. The well was tied in to the Cusiana central processing facility in August 1996 and put on production at rates over 16,000 barrels of condensate per day. Additional Cupiagua wells will be placed on production in 1997 and tied in to the Cusiana central processing facility for early production prior to the completion of the Cupiagua central processing facility in 1997. Production Facilities and Pipelines. The four initial production units of the Cusiana Field central processing facility are designed to handle approximately 180,000 barrels of daily production throughput. Construction is under way to increase production capacity from the Cusiana and Cupiagua fields to at least 500,000 barrels per day by yearend 1997. Additional pipeline capacity is required to meet the transportation needs associated with development of these fields. To that end, in April 1995, Triton Pipeline Colombia, Inc., a wholly owned subsidiary of the Company, along with Ecopetrol, BP Colombia Pipelines Ltd., Total Pipeline Colombie, S.A., IPL Enterprises (Colombia) Inc. and TCPL International Investments Inc., completed the formation of a company, Oleoducto Central S.A. ("OCENSA"), to own and finance pipeline and port facilities to be constructed and operated for the transport of crude oil from the Cusiana and Cupiagua fields to the Caribbean port of Covenas. Triton's equity participation in OCENSA is 9.6%. This pipeline project consists of a 793-kilometer (495-mile) pipeline system from the Cusiana and Cupiagua fields to the port of Covenas. It loops and generally follows the route of the two existing pipelines: the Central Llanos pipeline from El Porvenir to Vasconia and the Oleoducto de Colombia pipeline from Vasconia to Covenas. A portion of the Central Llanos pipeline and pump station upgrades at El Porvenir and Miraflores were acquired by OCENSA during 1995. Expansion of the pipeline system is under way and scheduled for completion in 1997. The current plan is to increase pipeline capacity to transport at least 500,000 barrels of oil per day from the Fields by yearend 1997. Other Areas in Colombia Triton owns rights to four additional licenses in Colombia. In the Middle Magdalena Valley basin and adjacent foothills, Triton owns a 50% interest (before certain royalties and government participation) in the El Pinal contract area, which covers approximately 71,000 acres (after contractually required relinquishment in 1996) approximately 330 kilometers (205 miles) north of Bogota. In the southern part of El Pinal, Triton discovered and confirmed the Liebre Field with two wells (the Liebre-1 and - -2). In 1995, Ecopetrol approved Triton's application to declare the Liebre Field commercial, and production from the field began in January 1997 at an initial rate of 1,200 barrels of oil per day from the two wells. The Yumeca-1 exploratory well, located in the northern part of El Pinal, was drilled to a total depth of 13,675 feet and tested in 1995. It was intended that the well test a new play concept in the foothills of the Middle Magdalena Valley. The well encountered hydrocarbon shows at various intervals but was plugged and abandoned after four zones were tested. The Yumeca-2 exploratory well, completed in 1997, was drilled to a total depth of 13,500 feet and plugged and abandoned after electronic logs failed to confirm the presence of commercial quantities of oil or gas. In June 1995, the Company was awarded the Guayabo A and B and Las Amelias association contracts covering a contiguous area of approximately 1.8 million acres. The area is located approximately 150 kilometers (93 miles) north of Bogota and 140 kilometers (87 miles) northwest of the Cusiana and Cupiagua fields, and is contiguous with the El Pinal contract area to the north. The terms of these association contracts are less favorable than the terms of the Cusiana and Cupiagua association contracts. Triton is acquiring seismic data in a program totaling 142 kilometers (85 miles) over the Guayabo A block, 36 kilometers (22 miles) over the Guayabo B block, and 250 kilometers (150 miles) over the Las Amelias block. In March 1996, the Company executed an agreement with Deminex Colombia Petroleum GmbH ("Deminex") providing Deminex the right to earn a 50% interest in the El Pinal, Guayabo A and B and Las Amelias contract areas. The Ministry of Mines and Energy of Colombia formally approved this assignment in August 1996. Triton Colombia sold its 22.5% and 20% interests (before certain royalties), respectively, in the 32,834-acre Tolima-B and 32,240-acre San Luis contract areas in December 1996. Malaysia-Thailand Contract Terms In April 1994, Triton Thailand became a party to a production sharing contract covering an area located offshore, designated as Block A-18 of the Malaysia-Thailand Joint Development Area. The contract area, which encompasses approximately 731,000 acres, had been the subject of overlapping claims between Malaysia and Thailand. The other parties to the production sharing contract are the Malaysia-Thailand Joint Authority (the "MTJA"), which has been established by treaty to administer the Joint Development Area, and Petronas Carigali (JDA) Sdn. Bhd. ("Carigali"), a subsidiary of the Malaysian national oil company. The treaty provides for the development of the Joint Development Area that includes Block A-18. Triton Thailand previously held a license from Thailand that covered part of the Joint Development Area. The term of the contract is 35 years, subject to possible relinquishment of certain areas and subject to the treaty between Malaysia and Thailand creating the MTJA remaining in effect. Triton and Carigali have the right to explore for oil and gas for the first five years of the contract. The contract provides that if there is a discovery of natural gas (not associated with crude oil) and the MTJA agrees, the contractors will be able to hold that gas field without production for an additional five-year period, provided the contractors submit to the MTJA an acceptable development plan for the field. The contractors then have a five-year period from the MTJA's acceptance of the development plan to develop the field, and have the right to produce gas from the field for 20 years plus a number of years equal to the number of years, if any, prior to the end of the holding period that gas production commenced (or until the termination of the contract, if earlier). The contract grants to the operators the right to produce oil from an oil field for 25 years plus a number of years equal to the number of years, if any, prior to the fifth anniversary of the contract that oil production commenced (or until the termination of the contract, if earlier). Any areas not developed and producing within the periods provided will be relinquished. As oil and gas are produced, the MTJA is entitled to a 10% royalty. Up to 50% of each unit of production is considered "cost oil" or "cost gas" and will be allocated to the contractors to the extent of their recoverable costs, with the balance considered "profit oil" or "profit gas" to be divided 50% to the MTJA and 50% to the contractors (i.e., 25% to Carigali and 25% to Triton). Triton's share of production is subject to an additional royalty equal to 0.75% of Block A-18 production. Tax rates imposed by the MTJA on behalf of the governments of Malaysia and Thailand are 0% for the first eight years of production, 10% for the next seven years of production and 20% for any remaining production. Simultaneously with the execution of the production sharing contract, the parties executed a joint operating agreement governing Block A-18 operations. The operating agreement designated as operator CTOC, a company owned equally by Triton Thailand and Carigali. Negotiations for a Gas-Sales Agreement In May 1996, the MTJA, Triton and Carigali signed a Memorandum of Understanding on the sale and purchase of natural gas with Petronas and PTT, the national oil companies of Malaysia and Thailand, respectively. The Memorandum of Understanding provides a basis for negotiation of a gas-sales agreement for natural gas to be produced from Block A-18. The parties currently are negotiating a heads of agreement intended to include agreement in principle on the key gas-sales agreement terms. The Company expects that negotiation and execution of a definitive gas-sales agreement reflecting the heads of agreement will follow execution of the heads of agreement. Recent Drilling Results The initial phase of Block A-18 operations included a 2D seismic survey covering approximately 5,700 kilometers (3,542 miles), a 3D seismic survey conducted in 1995 covering approximately 620 square kilometers (239 square miles) over the Cakerawala Field, data analysis and the drilling of three exploratory wells. In August 1995, the first of the three wells, the Cakerawala-1A, was tested at a combined flow rate of 58 MMcf of gas and 945 barrels of condensate and oil per day. The well was drilled in approximately 200 feet of water to a total depth of 7,878 feet. A second well, Suriya-1, was tested at a combined flow rate of 58 MMcf of gas and 351 barrels of condensate per day. The Suriya-1 well was drilled in approximately 180 feet of water to a total depth of 7,273 feet and is located on a separate structure. The Suriya-1 well is located approximately 11 kilometers (7 miles) east-southeast of the Cakerawala-1A well. A third well, Cakerawala East-1, was drilled in approximately 180 feet of water to a total depth of 11,808 feet. Cakerawala East-1 tested at 22 MMcf of gas and 138 barrels of condensate per day from the two shallow sequences that constitute the principal producing zones for phase one field development. The well confirmed anticipated fault separations from the structure on which the Cakerawala-1A well and the Pilong well (drilled by Exxon in 1971) were drilled, and found comparable sand thickness, flow rates and gas-water contacts and lesser CO2 content than the same sequences in the Cakerawala-1A and Pilong wells. Intermediate sequences were wet and were not tested. The well also confirmed the presence of deeper, overpressure sandstone sequences, but the deeper zones tested wet or inconclusively due to mechanical difficulties. The deeper zones remain an exploratory prospect for future drilling. During 1996, petroleum operations in Block A-18 included the drilling of six wells and the acquisition of a second 3D seismic survey that covered 534 square kilometers (206 square miles). In March 1996, two appraisal wells, Cakerawala-2 and Cakerawala-3, were drilled to delineate the Cakerawala Field. The Cakerawala-2 well was tested at a combined rate of 31 MMcf of gas and 645 barrels of condensate per day. The well was drilled in approximately 190 feet of water to a total depth of 9,650 feet, approximately seven kilometers (four miles) north of the Cakerawala-1A well. The Cakerawala-3 well was tested at a combined rate of 47 MMcf of gas, 225 barrels of condensate and 3,002 barrels of oil per day. The well was drilled in approximately 180 feet of water to a total depth of 9,814 feet, approximately three kilometers (two miles) southwest of Cakerawala-1A. The two appraisal wells confirmed the gas pools proven in the earlier wells drilled in the field and also discovered oil in relatively shallow zones, which require further delineation. Following delineation of the Cakerawala Field, two exploratory wells were drilled to test other prospects in Block A-18. The Bulan-1 well tested at a combined rate of 36 MMcf of gas and 123 barrels of condensate per day. The well was drilled in approximately 180 feet of water to a total depth of 7,140 feet, approximately seven kilometers (four miles) west-northwest of Cakerawala-1A. The well proved a third commercial field in the block on a separate structure immediately west of the Cakerawala Field. The Bumi-1 well tested at a combined rate of 73 MMcf of gas and 305 barrels of condensate per day. The well was drilled in approximately 180 feet of water to a total depth of 9,279 feet, approximately four kilometers (three miles) east of the Suriya-1 well. The well proved a fourth commercial field on the block on a separate structure immediately east of the Suriya Field. Two other wells were drilled in 1996 to appraise the Suriya and Bulan fields. The Suriya-2 well confirmed the discovery made by Suriya-1. The well tested at a combined rate of 56 MMcf of gas and 268 barrels of condensate per day. The well was drilled in approximately 180 feet of water to a total depth of 8,315 feet, approximately five kilometers (three miles) south of Suriya-1. The Bulan-2 well confirmed the discovery made by Bulan-1. The well tested at a combined rate of 30 MMcf of gas and 185 barrels of condensate per day. The well was drilled in approximately 176 feet of water to a total depth of 9,160 feet approximately five kilometers (three miles) south of the Bulan-1 well. A field development plan for the Cakerawala Field was submitted to the MTJA for approval in October 1996. Development of the field is expected to commence following execution of the heads of agreement and to take approximately 30 to 36 months to complete. Argentina Through the Company's subsidiaries, Triton Argentina, Inc. and Triton Resources Argentina, Inc., the Company holds a 100% working interest in the approximately 47,000-acre Sierra Azul Sur license in the oil and gas producing Neuquen Basin in western Argentina. In September 1996, Triton assigned its interests in the Loma Cortaderal and Cerro Dona Juana blocks to Cordex Petroleums Argentina Ltd. In consideration of the assigned interest, Cordex agreed to undertake certain work obligations and to grant Triton an overriding royalty interest of 8% on any future hydrocarbon production from the areas covered by these blocks. The assignment of these two areas is subject to government approval. Triton relinquished its interest in the Malargue Sur license in March 1996. In January 1997, the Company announced that, after a review of certain technical information, it had determined that its interest in the Sierra Azul Sur license, although commercially prospective, did not meet its exploration objectives. Accordingly, the Company recorded a charge against its results of operations for the year ended December 31, 1996. See Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations." Ecuador Through the Company's subsidiary, Triton Ecuador, Inc. LLC, the Company holds an interest in Block 19, which covers approximately 494,000 acres located in the Ecuadorian foothills of the eastern side of the Andes Mountains in the Oriente Basin. Triton's partners in the block are Vintage Petroleum Ecuador, Inc., with a 30% interest, and Ranger Oil Limited, with a 15% interest, subject to certain government approvals. The partners' work program commitments for Block 19 consist of the acquisition of 400 kilometers (250 miles) of new seismic data and the drilling of two exploratory wells during a four-year exploration period. A total of 442 kilometers (275 miles) of new seismic data was acquired during 1996. The first exploratory well is expected to be drilled in 1997. Guatemala Through the Company's subsidiary, Triton Guatemala S.A., the Company has acquired an interest in two contiguous blocks. The blocks cover a total of approximately 608,000 acres located on the border with Mexico in an extension of the Chiapas Fold Belt province. During 1996, Triton processed and interpreted seismic and gravity data acquired in 1995 and conducted other preparatory operations for the planned drilling of the Piedras Blancas #1 well to test the extension of the Chiapas Fold Belt. Drilling is expected to begin in 1997. China The Company's subsidiary, Triton China, Inc. LLC, has signed production sharing contracts with the China National Offshore Oil Company ("CNOOC"), which give the Company the right to explore and develop two contiguous offshore contract areas, Blocks 16/03 and 16/22. The blocks are located approximately 175 kilometers (110 miles) offshore from Hong Kong in water depths ranging from 300 to 650 feet. Block 16/22 (791,000 acres) and Block 16/03 (2.2 million acres) are located in the Huizhou Sub-basin of the Pearl River Mouth Basin. Block 16/22 has a primary three-year exploration term with a commitment of reprocessing 500 kilometers (310 miles) of existing seismic and the drilling of an exploratory well for a total expenditure of not less than $7.5 million. Block 16/03 has a primary one-and-one-half-year exploration term with a commitment of reprocessing 1,000 kilometers (621 miles) of existing seismic and the drilling of an exploratory well for a total expenditure of not less than $3 million. Seismic reprocessing on both blocks of an aggregate of approximately 8,800 kilometers (5,500 miles), was completed in 1995 and 1996. In April 1996, Triton executed an agreement with Mobil Exploration & Production China Inc. ("Mobil") providing Mobil the right to earn a 50% interest in both blocks. Subsequently, the HZ 23-2-1 exploratory well was drilled on Block 16/22 to a total depth of 14,830 feet in water depths of 390 feet. The well was plugged and abandoned after encountering hydrocarbon shows, although in noncommercial quantities. The remaining obligatory well for Block 16/03 is expected to be drilled in 1997. Effective January 1997, Triton signed two one-year offshore Joint Study Agreements with CNOOC. JSA 24/05 covers approximately 1.5 million acres in water depths ranging from 50 to 200 feet in the Liedong area of the South China Sea. This study area has a commitment of 3,500 kilometers (2,175 miles) of existing seismic to be reprocessed. JSA 24/10 covers approximately 3.7 million acres in water depths ranging from 30 to 295 feet in the South Yellow Sea. This study area has a commitment of 4,000 kilometers (2,500 miles) of existing seismic to be reprocessed. Italy The Company has a 40% interest in each of the contiguous DR71 and DR72 licenses operated by Enterprise Oil, plc, in the Adriatic Sea, and a 50% interest in three onshore licenses, operated by Triton, in the southern Apennines Mountains. Triton has applied for two new licenses onshore in the southern Apennines and one new license offshore in the Adriatic. The DR71 and DR72 licenses lie 45 kilometers (28 miles) offshore from the city of Brindisi and cover approximately 493,000 acres. One well, Medusa-1, was drilled on DR72 in 1996 to a total depth of 4,725 feet. The well proved the presence of oil and gas in a new play but in noncommercial quantities and was not tested. Additional drilling is expected in late 1997 or early 1998. The contiguous Southern Apennines licenses - Fosso del Lupo, Valsinni and Masseria di Sole - cover approximately 101,000 acres in the Matera province. The licenses were awarded in August 1996. Triton intends to purchase and acquire seismic data over the licenses in 1997. Oman The Company's subsidiary, Triton Oman, Inc., was awarded a 100% interest in a production sharing contract covering Block 22, Masirah Bay, by the Sultanate of Oman in June 1996. The offshore block covers approximately two million acres in water depths ranging from 50 to 200 feet. The minimum contractual obligation during the initial three-year exploration period requires the reprocessing and reinterpretation of existing seismic data, 1,000 kilometers (625 miles) of seismic acquisition and one exploratory well contingent on the results of the seismic program. Indonesia In February 1997, the Company's subsidiary, TriBlora Indonesia B.V., signed, subject to government approval, an agreement with Eurafrep B.V. to acquire a 30% interest in the Blora production sharing contract covering a block of approximately 1.4 million acres located within Central Java. Triton's partners are Eurafrep B.V., the operator, with a 40% interest, and YPF International Ltd. with a 30% interest. The work program calls for an unspecified amount of seismic reprocessing, as well as the acquisition of 150 kilometers (95 miles) of 2D seismic and the drilling of a well within the three-year initial exploration period for a total expenditure of not less than $4.5 million. Reprocessing of seismic began in January 1997 with acquisition of new seismic to be undertaken in the third quarter of 1997. Exploratory drilling is planned to begin in 1998. In 1996, the Company sold its interest in the Enim project in Indonesia. RESERVES The following table sets forth a summary of the estimated oil and gas reserves of the Company at December 31, 1996, and is based on separate estimates of the Company's net proved reserves, prepared by the independent petroleum engineers, DeGolyer and MacNaughton, with respect to all proved reserves in the Cusiana and Cupiagua fields in Colombia, and by the Company's own petroleum engineers with respect to all proved reserves in Malaysia-Thailand and the Liebre Field in Colombia. This table sets forth the estimated net quantities of proved developed and undeveloped oil and gas reserves and total proved oil and gas reserves owned by the Company and its consolidated subsidiaries. At December 31, 1996, the Company had no proved developed or proved undeveloped reserves in Argentina, Ecuador, Guatemala, China, Italy, Oman or Indonesia. For additional information regarding the Company's reserves, including the standardized measure of future net cash flows, see note 25 of Notes to Consolidated Financial Statements. Oil reserves data include natural gas liquids and condensate. Net Proved Reserves at December 31, 1996: PROVED PROVED TOTAL DEVELOPED UNDEVELOPED PROVED ---------- ------------ -------- OIL GAS OIL GAS OIL GAS (MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF) ---------- ------- ------------ -------- -------- -------- Colombia(1) 67,193 11,146 68,117 3,505 135,310 14,651 Malaysia-Thailand(2) --- --- 24,700 871,100 24,700 871,100 ---------- ------- ------------ -------- -------- -------- Total 67,193 11,146 92,817 874,605 160,010 885,751 ---------- ------- ------------ -------- -------- -------- ____________________ (1) Includes liquids to be recovered from Ecopetrol as reimbursement for precommerciality expenditures. (2) As of December 31, 1996, the Company did not have a contract for the sale of gas to be produced from its interest in the Malaysia-Thailand Joint Development Area. In estimating its reserves attributable to such interest, the Company assumed that production from the interest would be sold at prices for natural gas derived from what the Company believed to be the most comparable market price at December 31, 1996. There can be no assurance that the price to be provided in any gas contract will be equal to the price used in the Company's calculations. Reserve estimates are approximate and may be expected to change as additional information becomes available. Furthermore, estimates of oil and gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, there can be no assurance that the reserves set forth herein will ultimately be produced nor can there be assurance that the proved undeveloped reserves will be developed within the periods anticipated. No estimates of total proved net oil or gas reserves have been filed by the Company with, or included in any report to, any United States authority or agency pertaining to the Company's individual reserves since the beginning of the Company's last fiscal year. ACREAGE The following table shows the total gross and net developed and undeveloped oil and gas acreage held by Triton at December 31, 1996. "Gross" refers to the total number of acres in an area in which the Company holds an interest without adjustment to reflect the actual percentage interest held therein by the Company. "Net" refers to the gross acreage as adjusted for working interests owned by parties other than the Company. "Developed" acreage is acreage spaced or assignable to productive wells. "Undeveloped" acreage is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves. DEVELOPED UNDEVELOPED ACREAGE ACREAGE(1) ------------------------- ------------------- GROSS NET GROSS NET --------- -------------- ------------ ----- (In thousands) Colombia 30 4 1,940 939 Malaysia-Thailand --- --- 731 366 Argentina --- --- 47 47 Ecuador --- --- 494 272 Guatemala --- --- 608 608 China(2) --- --- 2,990 1,495 Italy --- --- 594 248 Oman --- --- 2,044 2,044 --------- -------------- ------------ ----- Total 30 4 9,448 6,019 --------- -------------- ------------ ----- ____________________ (1) Triton's interests in certain of this acreage may expire if not developed at various times in the future pursuant to the terms and provisions of the leases, licenses, concessions, contracts, permits or other agreements under which it was acquired. (2) Does not include acreage attributable to the two Joint Study Agreements signed with CNOOC in January 1997. PRODUCTIVE WELLS AND DRILLING ACTIVITY In this section, "gross" wells refers to the total number of wells drilled in an area in which the Company holds any interest without adjustment to reflect the actual ownership interest held. "Net" refers to the gross number of wells drilled adjusted for working interests owned by parties other than the Company. At December 31, 1996, Triton held gross and net working interests in 33 and 4.22 productive wells, respectively, in Colombia. The following tables set forth the results of the oil and gas well drilling activity on a gross basis for wells in which the Company held an interest for the years ended December 31, 1996 and 1995, the seven months ended December 31, 1994, and for the year ended May 31, 1994. GROSS EXPLORATORY WELLS PRODUCTIVE (1) DRY -------------- ------------ SEVEN MOS. YEAR YEAR ENDED ENDED ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, MAY 31, DECEMBER 31, --------------------------- 1996 1995 1994 1994 1996 ------------ ------------ ---------- ------- ------------ Colombia 3 2 1 3 --- Malaysia-Thailand 7 2 --- --- --- Argentina --- --- --- --- 2 Italy --- --- --- --- 1 China --- --- --- --- 1 New Zealand --- --- --- 1 --- Crusader(1): Argentina --- 1 1 --- --- Australia 14 23 9 5 4 Canada --- --- --- --- --- United States --- --- --- 2 --- Philippines --- --- --- --- --- ------------ ------------ ---------- ------- ------------ Total 24 28 11 11 8 ------------ ------------ ---------- ------- ------------ GROSS EXPLORATORY WELLS DRY TOTAL ------------------------------- ----------------------------------- SEVEN MOS. YEAR SEVEN MOS. YEAR YEAR ENDED ENDED ENDED YEAR ENDED ENDED ENDED DECEMBER 31, DEC. 31, MAY 31, DECEMBER 31, DEC. 31, MAY 31, ---------------- 1995 1994 1994 1996 1995 1994 1994 ---- ---------- ------- ---- ---- ---------- ------- Colombia 2 --- --- 3 4 1 3 Malaysia-Thailand --- --- --- 7 2 --- --- Argentina 2 --- --- 2 2 --- --- Italy --- --- 1 1 --- --- 1 China --- --- --- 1 --- --- --- New Zealand --- --- --- --- --- --- 1 Crusader(1): Argentina 2 --- --- --- 3 1 --- Australia 11 3 2 18 34 12 7 Canada --- --- 1 --- --- --- 1 United States --- 2 1 --- --- 2 3 Philippines --- 1 --- --- --- 1 --- ---- ---------- ------- ---- ---- ---------- ------- Total 17 6 5 32 45 17 16 ---- ---------- ------- ---- ---- ---------- ------- GROSS DEVELOPMENT WELLS PRODUCTIVE (1) DRY ------------------------------------------------------ -------------------------------------------- SEVEN MOS. YEAR SEVEN MOS. YEAR YEAR ENDED ENDED ENDED YEAR ENDED ENDED ENDED DECEMBER 31, DEC. 31, MAY 31, DECEMBER 31, DEC. 31, MAY 31, ------------ ------------ 1996 1995 1994 1994 1996 1995 1994 1994 ------------ ---- ---------- ------- ------------ ---- ---------- ------- Colombia 15 8 3 --- --- --- --- --- Malaysia-Thailand --- --- --- --- --- --- --- --- Indonesia --- --- --- 3 --- --- --- 1 Crusader(1): Australia 2 5 8 13 --- 1 1 1 Canada --- --- --- 9 --- --- --- --- United States --- --- 1 --- --- --- --- 1 ------------ ---- ---------- ------- ------------ ---- ---------- ------- Total 17 13 12 25 --- 1 1 3 ------------ ---- ---------- ------- ------------ ---- ---------- ------- GROSS DEVELOPMENT WELLS TOTAL ---------------------------------------------- SEVEN MOS. YEAR YEAR ENDED ENDED ENDED DECEMBER 31, DEC. 31, MAY 31, ------------ 1996 1995 1994 1994 ------------ ---- ---------- ------- Colombia 15 8 3 --- Malaysia-Thailand --- --- --- --- Indonesia --- --- --- 4 Crusader(1): Australia 2 6 9 14 Canada --- --- --- 9 United States --- --- 1 1 ------------ ---- ---------- ------- Total 17 14 13 28 ------------ ---- ---------- ------- ____________________ (1) In 1996, the Company sold all of its interest in Crusader and in the Enim project in Indonesia. In 1995, Crusader sold its interests in Argentina and Canada. The following tables set forth the results of drilling activity on a net basis for wells in which the Company held an interest for the years ended December 31, 1996 and 1995, the seven months ended December 31, 1994 and for the year ended May 31, 1994 (those wells acquired or disposed of since May 31, 1993 are reflected in the following tables only since or up to the effective dates of their respective acquisitions or sales, as the case may be): NET EXPLORATORY WELLS PRODUCTIVE (1) DRY ----------------------------------------------- --------------------------------------------- SEVEN MOS. YEAR SEVEN MOS. YEAR YEAR ENDED ENDED ENDED YEAR ENDED ENDED ENDED DECEMBER 31, DEC. 31, MAY 31, DECEMBER 31, DEC. 31, MAY 31, -------------------------- ------------ 1996 1995 1994 1994 1996 1995 1994 1994 -------------- ---- ---------- ------- ------------ ---- ---------- ------- Colombia(2) 0.12 0.12 0.12 1.24 0.50 2.00 --- --- Malaysia-Thailand 3.50 1.00 --- --- --- --- --- --- Argentina --- --- --- --- 2.00 2.00 --- --- Italy --- --- --- --- 0.40 --- --- 0.10 China --- --- --- --- 0.50 --- --- --- New Zealand --- --- --- 0.20 --- --- --- --- Crusader(3): Argentina --- 0.06 0.12 --- --- 0.12 --- --- Australia 0.34 0.35 0.15 0.10 0.10 0.29 0.63 0.02 Canada --- --- --- --- --- --- --- 0.50 United States --- --- --- 0.20 --- --- 0.40 0.10 Philippines --- --- --- --- --- --- 0.20 --- ---- ---- ---------- ------- ---- ---- ---------- ------- Total 3.96 1.53 0.39 1.74 3.50 4.41 1.23 0.72 ---- ---- ---------- ------- ---- ---- ---------- ------- NET EXPLORATORY WELLS TOTAL -------------------------------------- SEVEN MOS. YEAR YEAR ENDED ENDED ENDED DECEMBER 31, DEC. 31, MAY 31, ------------------ 1996 1995 1994 1994 ------------ ---- ---------- ------- Colombia(2) 0.62 2.12 0.12 1.24 Malaysia-Thailand 3.50 1.00 --- --- Argentina 2.00 2.00 --- --- Italy 0.40 --- --- 0.10 China 0.50 --- --- --- New Zealand --- --- --- 0.20 Crusader(3): Argentina --- 0.18 0.12 --- Australia 0.44 0.64 0.78 0.12 Canada --- --- --- 0.50 United States --- --- 0.40 0.30 Philippines --- --- 0.20 --- ---- ---- ---------- ------- Total 7.46 5.94 1.62 2.46 ---- ---- ---------- ------- NET DEVELOPMENT WELLS PRODUCTIVE (1) DRY ----------------------------------------- --------------------------------------- SEVEN MOS. YEAR SEVEN MOS. YEAR YEAR ENDED ENDED ENDED YEAR ENDED ENDED ENDED DECEMBER 31, DEC. 31, MAY 31, DECEMBER 31, DEC. 31, MAY 31, -------------------- ------------------ 1996 1995 1994 1994 1996 1995 1994 1994 -------------- ---- ---------- ------- ------------ ---- ---------- ------- Colombia (2) 1.80 0.96 0.36 --- --- --- --- --- Malaysia-Thailand --- --- --- --- --- --- --- --- Indonesia --- --- --- 3.00 --- --- --- 1.00 Crusader(3): Australia 0.05 1.10 0.17 0.40 --- 0.02 0.01 0.02 Canada --- --- --- 2.00 --- --- --- --- United States --- --- 0.20 --- --- --- --- 0.20 ---- ---- ---------- ------- ---- ---- ---------- ------- Total 1.85 1.06 0.73 5.40 --- 0.02 0.01 1.22 ---- ---- ---------- ------- ---- ---- ---------- ------- NET DEVELOPMENT WELLS TOTAL ------------ SEVEN MOS. YEAR YEAR ENDED ENDED ENDED DECEMBER 31, DEC. 31, MAY 31, ------------------ 1996 1995 1994 1994 ------------ ---- ---------- ------- Colombia (2) 1.80 0.96 0.36 --- Malaysia-Thailand --- --- --- --- Indonesia --- --- --- 4.00 Crusader(3): Australia 0.05 0.12 0.18 0.42 Canada --- --- --- 2.00 United States --- --- 0.20 0.20 ---- ---- ---------- ------- Total 1.85 1.08 0.74 6.62 ---- ---- ---------- ------- ____________________ (1) A productive well is producing or capable of producing oil and/or gas in commercial quantities. Multiple completions have been counted as one well. Any well in which one of the multiple completions is an oil completion is classified as an oil well. (2) Adjusted to reflect the national oil company participation at commerciality for the Cusiana and Cupiagua fields. (3) Adjusted to reflect the Company's 49.9% interest in Crusader, which was sold in 1996. OTHER PROPERTIES The Company owns or has interests in oil and gas production facilities relating to its oil and gas production operations throughout the world. In addition, the Company leases or owns office space and other properties for its various operations in various parts of the world. For additional information on the Company's leases, including its office leases, see note 21 of Notes to Consolidated Financial Statements. FORWARD-LOOKING INFORMATION Certain statements in this Annual Report on Form 10-K, including statements of the Company's and management's expectations, intentions, plans and beliefs, including those contained in or implied by Items 1 and 2, "Business and Properties", and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," are forward-looking statements, as defined in Section 21D of the Securities Exchange Act of 1934, that are dependent on certain events, risks and uncertainties that may be outside of the Company's control. These forward-looking statements include statements of management's plans and objectives for future operation and statements of future economic performance; information regarding drilling schedules, expected or planned production or transportation capacity, the future construction or upgrades or upgrades of pipelines (including costs), when the Cusiana and Cupiagua fields might become self-financing, future production of the Cusiana and Cupiagua fields, the negotiation of a gas sales contract and commencement of production in Malaysia-Thailand, the Company's capital budget and future capital requirements, the Company's meeting its future capital needs, the amount by which production from the Cusiana and Cupiagua fields may increase or when such increased production may commence, the Company's realization of its deferred tax asset, the level of future expenditures for environmental costs and the outcome of regulatory and litigation matters, and proven oil and gas reserves and discounted future net cash flows therefrom; and the assumptions described in this report underlying such forward-looking statements. Actual results and developments could differ materially from those expressed in or implied by such statements due to a number of factors, including those described in the context of such forward-looking statements and in notes 20 and 21 of Notes to Consolidated Financial Statements. EMPLOYEES At March 7, 1997, the Company employed approximately 270 full-time employees. EXECUTIVE OFFICERS OF THE COMPANY The following table sets forth certain information regarding the executive officers of the Company at March 7, 1997: SERVED WITH ----------- THE COMPANY ----------- NAME AGE POSITION WITH THE COMPANY SINCE - ---------------------- --- ---------------------------------------------------- ----------- Thomas G. Finck 50 Chairman of the Board and Chief Executive Officer 1992 Nick De'Ath 48 Senior Vice President, Exploration 1993 Robert B. Holland, III 44 Senior Vice President, General Counsel and Secretary 1993 Peter Rugg 49 Senior Vice President and Chief Financial Officer 1993 A.E. Turner, III 48 Senior Vice President, Operations 1994 In August 1992, Mr. Finck was elected Director, President and Chief Operating Officer of the Company. Effective January 1993, Mr. Finck was elected Chief Executive Officer and effective May 1995 he assumed the additional position of Chairman of the Board. From July 1991 to August 1992, Mr. Finck served as President and Chief Executive Officer of American Energy Group, an independent oil and natural gas exploration and production company. From May 1984 until June 1991, Mr. Finck served as President and Chief Executive Officer of Ensign Oil & Gas, Inc., a private domestic oil and gas exploration company. Mr. De'Ath was elected Senior Vice President, Exploration in 1993. From 1992 to 1993, Mr. De'Ath served as President and owner of Pinnacle Ltd., a management consulting firm providing services to multinational companies in Colombia, and from 1971 to 1991 served in various positions with subsidiaries of British Petroleum Company, p.l.c., including general manager of exploration for BP International Limited in Mexico from 1991 to 1992 and general manager of BP's Colombian operation from 1986 to 1991. Mr. Holland was elected Senior Vice President, General Counsel and Secretary of the Company in January 1993. For more than five years prior to joining the Company, Mr. Holland was a partner of the law firm of Jackson & Walker, L.L.P., Dallas, Texas. Mr. Rugg was elected Senior Vice President and Chief Financial Officer in April 1993. From September 1992 to April 1993, Mr. Rugg served as Vice President of J.P. Morgan & Co., Incorporated ("J.P. Morgan"), a financial services firm, and for more than the five years prior to September 1992, Mr. Rugg served as Vice President of Morgan Guaranty Trust Company of New York, an international bank owned by J.P. Morgan. Mr. Turner was elected Senior Vice President, Operations in March 1994. From 1988 to February 1994, Mr. Turner served in various positions with British Gas Exploration & Production, Inc., including Vice President and General Manager of operations in Africa and the Western Hemisphere from October 1993. All executive officers of the Company are elected annually by the Board of Directors of the Company to serve in such capacities until removed or their successors are duly elected and qualified. There are no family relationships among the executive officers of the Company. ITEM 3. LEGAL PROCEEDINGS LITIGATION The Company and subsidiaries or former subsidiaries of the Company, including Triton Oil, are among numerous defendants in three related lawsuits brought in the Superior Court of the State of California, County of Los Angeles, by (i) National Union Fire Insurance Company ("National Union") and The Restaurant Enterprises Group, (ii) Travelers Indemnity Company ("Travelers") and (iii) the City of Redondo Beach. All three lawsuits arise out of a 1988 tidal wave at King Harbor in Redondo Beach, California. The lawsuits allege, among other things, that the defendants' negligence contributed to the collapse of a hotel and the flooding of a restaurant in the tidal wave. In the case of Triton Oil, the alleged negligence was Triton Oil's drilling of nearby oil wells and alleged resulting ground subsidence which purportedly lowered the height of the King Harbor breakwater. The Travelers lawsuit asserts damages in excess of $14.6 million, although in a separate lawsuit against the Army Corps of Engineers, the court found damages to be approximately $6.7 million. Of that $6.7 million, Travelers recovered $4 million from the City of Redondo Beach. The National Union lawsuit asserts damages in excess of $4.75 million, although in a separate lawsuit against the Army Corps of Engineers, the court found damages to be approximately $3.7 million. Of that $3.7 million, Travelers recovered $1 million from the City of Redondo Beach. The City of Redondo Beach lawsuit asserts damages in excess of $13.2 million, including indemnity for amounts it paid to settle the foregoing lawsuits and other claims arising out of the flooding. The three lawsuits have been consolidated for trial, which has been set for October 1997. The Company believes that it and its subsidiaries have meritorious defenses and intend to defend the suits vigorously. During the quarter ending September 30, 1995, the United States Environmental Protection Agency and Justice Department advised the Company that one of its domestic oil and gas subsidiaries, as a potentially responsible party for the clean-up of the Monterey Park, California Superfund site operated by Operating Industries, Inc., could agree to contribute approximately $2.8 million to settle its alleged liability for certain remedial tasks at the site. The offer did not address responsibility for any groundwater remediation. The subsidiary was advised that if it did not accept the settlement offer, it, together with other potentially responsible parties, may be ordered to perform or pay for various remedial tasks. After considering the cost of possible remedial tasks, its legal position relative to potentially responsible parties and insurers, possible legal defenses and other factors, the subsidiary declined to accept the offer. In June 1994, the Company and numerous other defendants were served by the State of Nevada, Division of Environmental Protection (the "NDEP") in a state court proceeding in Clark County, Nevada. The action seeks to hold the defendants responsible for remediation of certain underground water contamination at the McCarran International Airport and seeks civil penalties of up to $25,000 per day. The Company has been advised by the NDEP that the action was filed to toll the running of the statute of limitations on certain potential causes of action. The Company denies responsibility for the contamination at issue and does not believe that the action will have a material adverse affect on its consolidated financial position. The Company is also subject to litigation that is incidental to its business. REGULATORY MATTER In February 1997, the Company and the Securities and Exchange Commission ("SEC") concluded a settlement of the SEC's investigation of possible violations of the Foreign Corrupt Practices Act in connection with Triton Indonesia, Inc.'s former operations in Indonesia. The investigation was settled on a "consent decree" basis in which the Company neither admitted nor denied charges made by the SEC that the Company violated the Securities Exchange Act of 1934 when Triton Indonesia, Inc. made certain payments in 1989 and 1990 to a consultant advising Triton Indonesia, Inc. on its relations with the Indonesian state oil company and tax authority, misbooked the payments and failed to maintain adequate internal controls. Under the terms of the settlement, the Company's subsidiary, TEC, was permanently enjoined from future violations of the books and records and internal controls provisions of the Securities Exchange Act of 1934 and paid a civil monetary penalty of $300,000. In 1996, the Company was advised that the Department of Justice had concluded a parallel inquiry without taking any action. CERTAIN FACTORS None of the legal matters described above is expected to have a material adverse effect on the Company's consolidated financial position. However, this statement of the Company's expectation is a forward-looking statement that is dependent on certain events and uncertainties that may be outside of the Company's control. Actual results and developments could differ materially from the Company's expectation, for example, due to such uncertainties as jury verdicts, the application of laws to various factual situations, the actions that may or may not be taken by other parties and the availability of insurance. In addition, in certain situations, such as environmental claims, one defendant may be responsible for the liabilities of other parties. Moreover, circumstances could arise under which the Company may elect to settle claims at amounts that exceed the Company's expected liability for such claims in an attempt to avoid costly litigation. Judgments or settlements could, therefore, exceed any reserves. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted by the Company during the fourth quarter of the year ended December 31, 1996 to security holders, through the solicitation of proxies or otherwise. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Triton's ordinary shares are listed on the New York Stock Exchange and are traded under the symbol OIL. Set forth below are the high and low closing sales prices of Triton's ordinary shares as reported on the New York Stock Exchange Composite Tape for the periods indicated: CALENDAR PERIODS HIGH LOW - ---------------- ------ ------ 1994: First Quarter 32 26 3/4 Second Quarter 35 7/8 25 1/8 Third Quarter 36 30 Fourth Quarter 37 1/4 31 1995: First Quarter 38 1/4 31 Second Quarter 48 1/2 37 1/8 Third Quarter 55 44 1/4 Fourth Quarter 57 3/8 44 1996: First Quarter 59 3/4 46 3/4 Second Quarter 57 1/8 45 3/4 Third Quarter 49 3/8 40 1/2 Fourth Quarter 50 5/8 42 1/2 1997: First Quarter* 52 1/2 41 ______________________ *Through March 7, 1997. Triton has not declared any cash dividends on its ordinary shares since fiscal 1990. The Company's current intent is to retain earnings for use in the Company's business and the financing of its capital requirements. The payment of any future cash dividends is necessarily dependent upon the earnings and financial needs of the Company, along with applicable legal and contractual restrictions. The payment of dividends on the Company's capital stock is restricted pursuant to the Company's revolving credit facility and the indentures under which its publicly traded notes were issued. Under applicable corporate law, the Company may pay dividends or make other distributions to its shareholders in such amounts as appear to the directors to be justified by the profits of the Company or out of the Company's share premium account if the Company has the ability to pay its debts as they come due. As of March 7, 1996, the Company had outstanding 247,469 shares of its 5% Convertible Preference Shares ("5% Preference Shares"). Each 5% Preference Share may be converted into one ordinary share of Triton and bears a cash dividend, which has priority over dividends on Triton's ordinary shares, equal to 5% per annum on the redemption price of $34.41 per share, payable semi-annually on March 30 and September 30 of each year. The 5% Preference Shares have priority over Triton ordinary shares upon liquidation, and may be redeemed at Triton's option at any time on or after March 30, 1998 (or such earlier date as there are fewer than 133,005 5% Preference Shares outstanding) for cash equal to the redemption price. Any shares of 5% Preference Shares that remain outstanding on March 30, 2004, must be redeemed at the redemption price either for cash or, at the Company's option, for Triton ordinary shares. See notes 4 and 14 of Notes to Consolidated Financial Statements. The Company has adopted a Shareholder Rights Plan pursuant to which preference share rights attach to all ordinary shares at the rate of one right for each ordinary share. Each right entitles the registered holder to purchase from the Company one one-thousandth of a Series A Junior Participating Preference Share, par value $.01 per share ("Junior Preference Shares"), of the Company at a price of $120 per one one-thousandth of a share of such Junior Preference Shares, subject to adjustment. Generally, the rights only become distributable 10 days following public announcement that a person has acquired beneficial ownership of 15% or more of Triton's ordinary shares or 10 business days following commencement of a tender offer or exchange offer for 15% or more of the outstanding ordinary shares; provided that, pursuant to the terms of the plan, Oppenheimer Group, Inc. ("Oppenheimer") may increase its level of beneficial ownership to 19.9% without triggering a distribution of the rights. If, among other events, any person becomes the beneficial owner of 15% or more of Triton's ordinary shares (except as provided with respect to Oppenheimer), each right not owned by such person generally becomes the right to purchase such number of ordinary shares of the Company equal to the number obtained by dividing the right's exercise price (currently $120) by 50% of the market price of the ordinary shares on the date of the first occurrence. In addition, if the Company is subsequently merged or certain other extraordinary business transactions are consummated, each right generally becomes a right to purchase such number of shares of common stock of the acquiring person equal to the number obtained by dividing the right's exercise price by 50% of the market price of the common stock on the date of the first occurrence. Under certain circumstances, the Company's directors may determine that a tender offer or merger is fair to all shareholders and prevent the rights from being exercised. At any time after a person or group acquires 15% or more of the ordinary shares outstanding (other than with respect to Oppenheimer) and prior to the acquisition by such person or group of 50% or more of the outstanding ordinary shares or the occurrence of an event described in the prior paragraph, the Board of Directors of the Company may exchange the rights (other than rights owned by such person or group which will become void), in whole or in part, at an exchange ratio of one ordinary share, or one one-thousandth of a Junior Preference Share, per right (subject to adjustment). The rights will expire on May 22, 2005, unless such expiration date is extended or unless the rights are earlier redeemed or exchanged by the Company. At any time prior to a person acquiring beneficial ownership of 15% or more of Triton's ordinary shares, the Company may redeem the rights in whole, but not in part, at a price of $.01 per right. For so long as the rights are redeemable, the Company may, except with respect to the redemption price, amend the rights in any manner. At March 7, 1997, there were 4,459 record holders of the Company's ordinary shares. ITEM 6. SELECTED FINANCIAL DATA AS OF OR FOR SEVEN AS OF OR FOR YEAR ENDED MONTHS ENDED DECEMBER 31, DECEMBER 31, ------------------------------------ ------------ 1996 1995 1994 1994 ------------ -------- ------------ -------------- (unaudited) OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA): Sales and other operating revenues (1) $ 133,977 $107,472 $ 32,952 $ 20,736 Earnings (loss) from continuing operations (1) (2) 23,805 6,541 (49,610) (26,630) Earnings (loss) before extraordinary items and cumulative effect of accounting change 23,805 2,720 (52,701) (27,708) Net earnings (loss) (2) 22,609 2,720 (52,701) (27,708) Average ordinary and equivalent shares outstanding 36,919 35,147 34,916 34,944 Earnings (loss) per ordinary share: Continuing operations (1) (2) $ 0.62 $ 0.16 $ (1.43) $ (0.78) Before extraordinary item and cumulative effect of accounting change 0.62 0.05 (1.52) (0.81) Net earnings (loss) 0.59 0.05 (1.52) (0.81) BALANCE SHEET DATA (IN THOUSANDS): Net property and equipment $ 676,833 $524,381 $ 399,658 $ 399,658 Total assets 914,524 824,167 619,201 619,201 Long-term debt(3) 217,078 401,190 315,258 315,258 Redeemable preference shares of subsidiaries --- --- --- --- Shareholders' equity 300,644 246,025 237,195 237,195 CERTAIN OIL AND GAS DATA (4): Production Oil (Mbbls) (5) 5,987 6,303 2,534 1,488 Gas (MMcf) 2,517 5,312 5,516 3,427 Average sales price Oil (per bbl) $ 19.61 $ 16.60 $ 15.26 $ 16.41 Gas (per Mcf) $ 1.69 $ 1.64 $ 1.51 $ 1.44 AS OF OR FOR YEAR ENDED MAY 31, ---------------------------------- 1994 1993 1992 ------------ --------- --------- OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA): Sales and other operating revenues (1) $ 43,208 $ 84,414 $ 90,724 Earnings (loss) from continuing operations (1) (2) (4,597) (76,509) (81,333) Earnings (loss) before extraordinary items and cumulative effect of accounting change (9,341) (93,552) (94,037) Net earnings (loss) (2) (9,341) (89,535) (94,037) Average ordinary and equivalent shares outstanding 34,775 34,241 29,898 Earnings (loss) per ordinary share: Continuing operations (1) (2) $ (0.13) $ (2.23) $ (2.77) Before extraordinary item and cumulative effect of accounting change (0.27) (2.73) (3.19) Net earnings (loss) (0.27) (2.61) (3.19) BALANCE SHEET DATA (IN THOUSANDS): Net property and equipment $ 308,498 $330,151 $385,979 Total assets 616,101 561,931 571,169 Long-term debt(3) 294,441 159,147 27,587 Redeemable preference shares of subsidiaries --- 11,399 12,972 Shareholders' equity 263,422 255,432 336,013 CERTAIN OIL AND GAS DATA (4): Production Oil (Mbbls) (5) 2,886 3,691 3,777 Gas (MMcf) 9,078 21,958 24,366 Average sales price Oil (per bbl) $ 15.15 $ 18.67 $ 19.26 Gas (per Mcf) $ 1.44 $ 1.27 $ 1.21 ____________________ (1) Operating data for the year ended December 31, 1994 (unaudited), the seven months ended December 31, 1994 and the years ended May 31, 1994, 1993 and 1992 are restated to reflect the aviation sales and services segment and the wholesale fuel products segment as discontinued operations in 1995 and 1993, respectively. (2) Gives effect to the writedown of assets and loss provisions of $46.2 million, $1.1 million, $14.7 million, $1.0 million, $45.8 million, $99.9 million and $48.8 million for the years ended December 31, 1996, 1995 and 1994 (unaudited), the seven months ended December 31, 1994 and the years ended May 31, 1994, 1993 and 1992, respectively. (3) Long-term debt does not include current maturities totaling $199.6 million, $1.3 million, $.3 million, $.3 million, $3.4 million and $8.5 million at December 31, 1996, 1995 and 1994 and May 31, 1994, 1993 and 1992, respectively. (4) Information presented includes the 49.9% equity investment in Crusader Limited, which was sold in 1996. (5) Includes natural gas liquids and condensate. Production excludes .7 million and .4 million barrels of oil produced and delivered under a forward oil sale entered into in May 1995 for the years ended December 31, 1996 and 1995, respectively. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Liquidity and Capital Requirements Cash, cash equivalents and marketable securities totaled $14.9 million and $95.5 million at December 31, 1996 and 1995, respectively, while the unused portion of available credit facilities was $111.8 million and $58.6 million at December 31, 1996 and 1995, respectively. Working capital (deficit) was ($182.2 million) at December 31, 1996, compared with $85.6 million at December 31, 1995. The decline in working capital primarily resulted from the classification of the Company's 12 1/2% Senior Subordinated Discount Notes ("1997 Notes") due November 1997 ($189.9 million) as a current liability and use of cash and marketable securities to fund the 1996 capital spending program. The Company's capital expenditures and other capital investments were $252.7 million, $178.2 million, $89.9 million and $86.8 million during the years ended December 31, 1996 and 1995, the seven months ended December 31, 1994, and the year ended May 31, 1994, respectively, primarily for exploration and development of the Cusiana and Cupiagua fields (the "Fields") in Colombia, and for exploration in Block A-18 of the Malaysia-Thailand Joint Development Area in the Gulf of Thailand and in other areas. The 1996 capital spending program and repayment of debt were funded with cash, cash flow from operations ($80.7 million), and proceeds from sales of marketable securities ($38.5 million) and other assets ($108.1 million). At December 31, 1996, the Company had outstanding borrowings of $40.6 million under a term credit facility supported by a guarantee issued by the Export-Import Bank of the United States. In 1996, the Company signed a $125 million unsecured bank revolving credit facility. The facility matures in August 1998. The Company had outstanding borrowings of $11 million under the facility as of December 31, 1996. Also during 1996, the Company purchased in the open market $30 million face value of its 1997 Notes and realized an extraordinary after-tax expense of $1.2 million. At December 31, 1996, $210 million face value of the 1997 Notes remained outstanding. The 1995 capital spending program was funded with cash flow from operations (including a forward sale of Cusiana crude oil), cash, proceeds from marketable securities, sales of assets ($20.9 million) and net borrowings ($36.3 million). In May 1995, the Company sold 10.4 million barrels of oil in a forward oil sale. Under the terms of the sale, the Company received approximately $87 million of the approximately $124 million net proceeds and is entitled to receive substantially all of the remaining proceeds (now held in various interest-bearing reserve accounts) when the Company's Cusiana and Cupiagua fields project in Colombia becomes self-financing, which is expected in 1997, and when certain other conditions are met. During 1995, the Company repaid $25 million of short-term debt and borrowed $48.6 million under a $65 million long-term revolving credit facility. This facility was paid off in 1996 and was terminated. Capital expenditures incurred during the seven months ended December 31, 1994, were funded by cash, net proceeds from marketable securities ($30.8 million) and borrowings ($17.2 million). The principal sources for funds for the year ended May 31, 1994, used to support operations, capital expenditures and debt repayment were $100 million in proceeds from the sale of assets and approximately $124 million from the issuance of $170 million principal amount of 9 3/4% Senior Subordinated Discount Notes ("9 3/4% Notes") due December 2000. Development of the Fields, including drilling and construction of additional production facilities, will require further capital outlays. Further exploration and development activities on Block A-18, as well as exploratory drilling in other countries, also will require substantial capital outlays. The Company's capital budget for the year ending December 31, 1997, is approximately $310 million, excluding capitalized interest, of which approximately $150 million relates to the Fields and capital contributions to Oleoducto Central S.A. ("OCENSA"), $95 million relates to Block A-18, and $65 million relates to the Company's exploration and drilling program in other parts of the world. The Company assisted OCENSA in raising one tranche of debt totaling $65 million in 1996 and may assist OCENSA in raising up to $25 million of additional debt in 1997. Capital requirements for exploration and development relating to Block A-18 are expected to increase significantly into 1998. The Company has filed a shelf registration statement with the Securities and Exchange Commission that provides for the issuance of up to $600 million of securities, of which up to $200 million may be equity securities. The Company expects to meet capital needs, including raising funds to repay the 1997 Notes, in the future with a combination of some or all of the following: the Company's revolving credit facility, cash flow from its Colombian operations (including additional proceeds from the 1995 forward oil sale), cash and marketable securities, asset sales, and the issuance of debt and equity securities. The Company's indentures permit the Company to incur total indebtedness (excluding certain permitted indebtedness) of up to 25% of the sum of its indebtedness and market capitalization of its capital stock. As of yearend 1996, the revolving credit facility permitted the Company to incur total indebtedness of up to approximately $630 million. Availability under the credit facility may be more in the future under certain circumstances. Results of Operations The Company changed its fiscal yearend from May 31 to December 31 beginning in 1995. The Consolidated Statements of Operations report the Company's results of operations for the years ended December 31, 1996 and 1995, the seven months ended December 31, 1994, and the year ended May 31, 1994; however, Management's Discussion and Analysis compares the calendar years ended December 31, 1996, 1995 and 1994. The results of operations for the year ended December 31, 1994, for which the Company would have reported a net loss after preferred dividends of $53.2 million, have not been audited. Year Ended December 31, 1996, Compared with Year Ended December 31, 1995 Revenues Sales and other operating revenues were $134 million and $107.5 million in 1996 and 1995, respectively. Revenue in Colombia increased by $37.2 million in 1996 due to higher production ($15.7 million) and higher oil prices ($21.5 million) resulting from more favorable market conditions and batching of Cusiana crude that began in mid-1995. Revenue barrels in Colombia, including barrels delivered under the forward oil sale, increased from 5.5 million barrels in 1995 to 6.5 million barrels in 1996, even though the Company received .7 million fewer barrels in 1996 as reimbursement of pre-commerciality costs related to the Cusiana Field. Oil and gas sales from properties sold in late 1995 and early 1996 aggregated $17 million in 1995, compared with $2.7 million in 1996. Based on the operator's current projections, the Company expects gross production capacity from the Fields to reach 320,000 barrels per day during summer 1997 and at least 500,000 barrels per day by the end of 1997. Beginning in April 1997, the Company's delivery requirement under the forward oil sale will increase from 58,425 barrels per month to 254,136 barrels per month, which will have an adverse effect on the Company's earnings and cash flows on a per barrel basis. The Company expects that the adverse effect on the Company's results of operations and cash flows will be mitigated by increased production from the Fields. There can be no assurance, however, as to the timing of any such increase in production or that any such increase would occur in the same accounting period as the increase in the Company's forward oil sale delivery requirement. Other operating revenues in 1996 included a gain of $4.1 million resulting from the sale of the Company's royalty interests in U.S. properties for $23.8 million based on an effective date of January 1, 1996. Costs and Expenses Operating expenses increased $1.4 million in 1996, and depreciation, depletion and amortization increased $2.4 million. The Company's operating costs per equivalent barrel were $5.77 and $6.28 in 1996 and 1995, respectively. Higher production in Colombia increased operating expenses by $9.9 million and depreciation and depletion by $3.6 million. Operating expenses from properties sold in late 1995 and early 1996 were $1.8 million and $10.2 million in 1996 and 1995, respectively. During 1997, the Company expects that aggregate pipeline tariff costs from OCENSA will increase. When the pipeline expansion project is completed and shipments through the pipeline upgrade commence, and each year thereafter, OCENSA will assess to the Cusiana and Cupiagua fields shippers (the "Initial Shippers") a tariff estimated to recoup the total cost of the project over a period of 15 years, its operating expenses, which include all Colombian taxes, interest expense, and the dividend to be paid by OCENSA to its shareholders. Shippers of crude oil which are not Initial Shippers ("Third Party Shippers") will be assessed a tariff on a per barrel basis and OCENSA will use revenues from such tariffs to reduce the Initial Shippers' tariff. The Company cannot predict with any certainty the impact of the increased tariff on a per barrel basis due to the uncertainty as to the volumes of the Third Party Shippers' production to be transported by OCENSA and when the increases in production from the Cusiana and Cupiagua fields may occur. General and administrative expenses before capitalization increased $3.8 million in 1996 to $50.5 million, primarily due to greater exploration activities. Capitalized general and administrative costs were $24.6 million and $21.1 million in 1996 and 1995, respectively. In 1996, the Company's oil and gas properties and other assets in Argentina were written down $43 million following a review of technical information that indicated the acreage portfolio did not meet the Company's exploration objectives. Other Income and Expenses Interest expense before capitalization increased $2.7 million in 1996 to $43 million. Capitalized interest increased from $16.2 million in 1995 to $27.1 million in 1996 due to construction of support equipment and facilities in the Fields and greater exploration activities throughout the world. Other income, net in 1996 included a $10.4 million gain on the sale of the Company's shareholdings in Crusader, a $7.6 million benefit for settlement of a lawsuit in which the Company was plaintiff and an $11 million unrealized gain representing the change in fair market value of the West Texas Intermediate ("WTI") benchmark call options purchased in 1995. These gains were offset by $3.2 million in loss provisions for various legal matters. Other income, net in 1995 included $7.2 million received from legal settlements, a $3.5 million gain on the sale of Triton France and $2.9 million received from the early redemption of the Crusader convertible notes. These gains were offset by a $4.2 million unrealized expense representing the change in fair market value of the WTI benchmark call options. Income Taxes Statement of Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes," requires that the Company make projections about the timing and scope of certain future business transactions in order to estimate recoverability of deferred tax assets primarily resulting from the expected utilization of net operating loss carryforwards ("NOLs"). Changes in the timing or nature of actual or anticipated business transactions, projections, organizational changes, and income tax laws can give rise to significant adjustments to the Company's deferred tax expense or benefit that may be reported from time to time. For these and other reasons, compliance with SFAS 109 may result in significant differences between tax expense for income statement purposes and taxes actually paid. The income tax provision for 1996 represented current and deferred taxes in Colombia, deferred taxes on exploration projects throughout the world, and a deferred tax benefit in the United States related to anticipated future utilization of NOLs. Subject to the factors described above, the Company currently expects that its foreign deferred tax provision will substantially exceed its current tax provision (i.e., actual taxes paid) resulting in an effective tax for income statement purposes that will exceed statutory tax rates, at least until the Cusiana and Cupiagua fields project reaches peak production. The primary reason for the expected difference is the nondeductibility for Colombian tax purposes of certain capital expenses and the treatment of reimbursements for pre-commerciality costs as a return of capital under Colombian tax laws. Conversely, Colombian tax law permits the Company to adjust the tax basis of certain assets based on the Colombian inflation rate and to include any resulting increases in tax depreciation of the underlying asset based on rates of production and other factors. The Company's deferred tax liability has not been reduced to reflect the impact of this inflation adjustment. At December 31, 1996, the Company had NOLs of approximately $230.7 million, and certain subsidiaries had separate return limitation years ("SRLY") operating loss carryforwards of approximately $50.9 million. The NOLs expire from 1998 to 2012, and the SRLY operating loss carryforwards expire from 1997 to 2002. See note 12 of Notes to Consolidated Financial Statements. The Company recorded a deferred tax asset of $71.4 million, net of a valuation allowance of $30.7 million at December 31, 1996. The valuation allowance is primarily attributable to SRLY operating losses that are currently not realizable due to the lack of potential future income in the applicable subsidiaries, and the expectation that other tax credits will expire without being utilized. The minimum amount of future taxable income necessary to realize the deferred tax asset is approximately $204 million. Although there can be no assurance the Company will achieve such levels of income, management believes the deferred tax asset will be realized through increasing income from its operations. The income tax provision for 1996 decreased primarily due to the recognition of a deferred tax benefit in the United States totaling $23.5 million related to anticipated future utilization of NOLs, compared with a similar benefit of $12.8 million in 1995. The 1996 benefit reflects the improvement in the Company's anticipated operating results. Foreign current tax expense of $5.4 million in 1996 increased $1.4 million from 1995, mainly due to increased profitability from the Company's Colombian operations. Foreign deferred tax expense of $15.4 million in 1996 decreased $2.9 million from 1995, primarily due to the writedown of the Company's Argentina assets, which lowered taxes by $3.7 million in 1996 compared with 1995. Year Ended December 31, 1995, Compared with Year Ended December 31, 1994 Revenues Sales and other operating revenues were $107.5 million and $33 million in 1995 and 1994, respectively. Revenues in Colombia increased by $81.6 million in 1995 primarily due to greater production capacity from the installation in late 1994 and early 1995 of four production units in the Cusiana central processing facility and higher oil prices in Colombia ($16.29 per barrel in 1995, compared with $13.16 per barrel in 1994) resulting from more favorable market conditions and batching of Cusiana crude beginning in mid-1995. The 1995 results also included revenues of $14.5 million relating to the reimbursement of pre-commerciality costs for the Cusiana Field. Oil sales in France were $5.8 million higher in 1994 than in 1995, primarily because of the sale of Triton France in August 1995. Costs and Expenses Operating expenses increased $14.1 million to $35.3 million in 1995, while depreciation, depletion and amortization increased $9.5 million to $23.2 million in 1995. Higher production in Colombia increased operating expenses by $19.1 million and depreciation, depletion and amortization by $13.4 million. The Company's operating costs per equivalent barrel were $6.28 and $10.75 in 1995 and 1994, respectively. The sale of Triton France reduced operating expenses and depletion in 1995 by $3.6 million and $3.7 million, respectively. The 1994 results included an accrual of $1.1 million for environmental clean-up costs in the United States. General and administrative expenses decreased from $29.1 million in 1994 to $25.7 million in 1995, primarily due to increased capitalization of general and administrative expenses from $14.9 million in 1994 to $21.1 million in 1995 resulting from increased exploration and development activities. Writedown of assets in 1994 totaling $14.7 million was primarily related to oil properties in France under application of the Securities and Exchange Commission full cost ceiling limitation. Other Income and Expenses Interest income was $8 million and $8.1 million in 1995 and 1994, respectively. Interest expense increased by $12 million in 1995 due to higher debt outstanding and lower capitalized interest. Capitalized interest was $16.2 million and $20.6 million in 1995 and 1994, respectively. Equity in loss of affiliates, net was $2.2 million in 1995, compared with $2.9 million in 1994. Equity in loss of Crusader for 1995 included a net gain of $3.8 million on the sale of Saracen Minerals Limited, a $2.7 million loss related to the early redemption of Crusader's Convertible Notes and writedowns of $2.9 million on unproved oil and gas properties and a coal mining property. Other income, net was $11.6 million in 1995, compared with $2.8 million in 1994. Other income during 1995 included $7.2 million received from legal settlements, a $3.5 million gain on the sale of Triton France and $2.9 million received from the early redemption of Crusader's Convertible Notes. These gains were offset by a $4.2 million noncash charge representing the change in fair market value of WTI benchmark call options purchased in 1995. Income Taxes Income tax expense of $10 million in 1995 increased $8.5 million from 1994, mainly due to increased profitability from the Company's Colombian operations and the absence of tax refunds of $2 million received in 1994. The income tax provisions for 1995 and 1994 included deferred tax benefits in the United States of $12.8 million and $10.1 million, respectively, related to anticipated future utilization of NOLs. Discontinued Operations The results of operations for the aviation sales and services segment and wholesale fuel products segment have been reported as discontinued operations. In June 1995, the Company sold the assets of its subsidiary, Jet East, Inc., for $2.9 million in cash and a note, and realized a loss of $1.4 million on the sale. The Company accrued $.6 million for costs associated with final disposal of the segment, which occurred in August 1995. The 1994 losses of the wholesale fuel products segment, which was discontinued in 1993, were offset against a loss provision of $16.1 million, net of tax, at May 31, 1993. An additional accrual of $.7 million, net of tax, was recorded at May 31, 1994, for estimated operating losses associated with the final disposition of this segment. Minority Interest in Losses of Subsidiaries The Company ceased to record minority interest related to Triton Europe following the purchase of shares held by the minority interest owners on March 31, 1994. Petroleum Price Risk Management Oil and natural gas sold by the Company are normally priced with reference to a defined benchmark, such as light sweet crude oil traded on the New York Mercantile Exchange. Actual prices received vary from the benchmark depending on quality and location differentials. It is the Company's policy to use financial market transactions with credit-worthy counterparties from time to time primarily to reduce risk associated with the pricing of a portion of the oil and natural gas that it sells. The policy is structured to underpin the Company's planned revenues and results of operations. The Company may also enter into financial market transactions to benefit from its assessment of the future prices of its production relative to other benchmark prices. There can be no assurance that the use of financial market transactions will not result in losses. With respect to the sale of oil to be produced by the Company, the Company has used a combination of swaps, options and collars to establish a minimum weighted average WTI benchmark price of $19.58 per barrel for an aggregate of 1.5 million barrels of production during the period from January through June 1997. As a result, to the extent WTI prices exceed the minimum WTI benchmark price during each month within the period, the Company will be able to sell its production at the higher market price, and to the extent that WTI prices are below the minimum WTI benchmark price, the Company will be able to realize prices related to the minimum WTI benchmark price on its hedged production. In anticipation of entering into a forward oil sale, the Company purchased WTI benchmark call options to retain the ability to benefit from future WTI price increases above a weighted average price of $20.42 per barrel. The volumes and expiration dates on the call options coincide with the volumes and delivery dates of the forward oil sale, which has delivery terms of 58,425 barrels per month through March 1997 and 254,136 barrels per month from April 1997 through March 2000. During the years ended December 31, 1996 and 1995, the Company recorded an unrealized gain of $11 million and an unrealized loss of $4.2 million, respectively, in other income, net related to the change in the fair market value of the call options. Future fluctuations in the fair market value of the call options will continue to affect other income as noncash adjustments. During the year ended December 31, 1996, markets provided the Company the opportunity to realize WTI benchmark oil prices on average $4.68 per barrel above the WTI benchmark oil price the Company set as part of its 1996 annual plan. As a result of financial and commodity market transactions settled during the year ended December 31, 1996, the Company's risk management program resulted in an average net realization of approximately $1.21 per barrel lower than if the Company had not entered into such transactions. International Operations The Company derives substantially all of its consolidated revenues from international operations. A risk inherent in international operations is the possibility of realizing economic currency-exchange losses when transactions are completed in currencies other than U.S. dollars. The Company's risk of realizing currency-exchange losses currently is largely mitigated because the Company receives U.S. dollars for sales of its petroleum products in Colombia. Exploration Operations Costs related to acquisition, holding and initial exploration of licenses in countries with no proved reserves are initially capitalized, including internal costs directly identified with acquisition, exploration and development activities. The Company's exploration licenses are periodically assessed for impairment on a country-by-country basis. If the Company's investment in exploration licenses within a country where no proved reserves are assigned is deemed to be impaired, the licenses are written down to estimated recoverable value. If the Company abandons all exploration efforts in a country where no proved reserves are assigned, all exploration costs associated with the country are expensed. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expense are difficult to predict with any certainty. Environmental Matters The Company is subject to extensive environmental laws and regulations. These laws regulate the discharge of oil, gas or other materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of such materials at various sites. Also, the Company remains liable for certain environmental matters that may arise from formerly owned fuel businesses that were involved in the storage, handling and sale of hazardous materials, including fuel storage in underground tanks. The Company believes that the level of future expenditures for environmental matters, including clean-up obligations, is impractical to determine with a precise and reliable degree of accuracy. Management believes that such costs, when finally determined, will not have a material, adverse effect on the Company's operations or consolidated financial condition. Certain Factors that Could Affect Future Operations Certain statements in this report, including statements of the Company's and management's expectations, intentions, plans and beliefs, are forward-looking statements, as defined in Section 21D of the Securities Exchange Act of 1934, that are dependent on certain events, risks and uncertainties that may be outside of the Company's control. These forward-looking statements include statements of management's plans and objectives for the Company's future operations and statements of future economic performance; information regarding drilling schedules, expected or planned production or transportation capacity, the future construction or upgrades of pipelines (including costs), when the Cusiana and Cupiagua fields might become self-financing, future production of the Cusiana and Cupiagua fields, the negotiation of a gas-sales contract and commencement of production in Malaysia-Thailand, the Company's capital budget and future capital requirements, the Company's meeting its future capital needs, the amount by which production from the Cusiana and Cupiagua fields may increase or when such increased production may commence, the Company's realization of its deferred tax asset, the level of future expenditures for environmental costs, the outcome of regulatory and litigation matters, and proven oil and gas reserves and discounted future net cash flows therefrom; and the assumptions described in this report underlying such forward-looking statements. Actual results and developments could differ materially from those expressed in or implied by such statements due to a number of factors, including those described in the context of such forward-looking statements and in notes 20 and 21 of Notes to Consolidated Financial Statements. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The financial statements required by this item begin at page F-1 hereof. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information relating to the Company's Directors and nominees for election as Directors of the Company is incorporated herein by reference from the Proxy Statement for the 1997 Annual Meeting of Shareholders of the Company (the "Proxy Statement"), specifically the discussion under the heading "Election of Directors." It is currently anticipated that the Proxy Statement will be publicly available and mailed in April 1997. Certain information as to executive officers is included herein under Items 1 and 2, "Business and Properties - Executive Officers." The discussion under "Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy Statement is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The discussion under "Management Compensation" in the Proxy Statement is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The discussion under "Voting and Principal Shareholders" in the Proxy Statement is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The discussion under "Management Compensation" in the Proxy Statement is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this Annual Report on Form 10-K: 1. Financial Statements: The financial statements filed as part of this report are listed in the "Index to Financial Statements and Schedules" on page F-1 hereof. 2. Financial Statement Schedules: The financial statement schedules filed as part of this report are listed in the "Index to Financial Statements and Schedules" on page F-1 hereof. 3. Exhibits required to be filed by Item 601 of Regulation S-K. (Where the amount of securities authorized to be issued under any of Triton Energy Limited's and any of its subsidiaries' long-term debt agreements does not exceed 10% of the Company's assets, pursuant to paragraph (b)(4) of Item 601 of Regulation S-K, in lieu of filing such as exhibits, the Company hereby agrees to furnish to the Commission upon request a copy of any agreement with respect to such long-term debt.) 3.1 Memorandum of Association.(1) 3.2 Articles of Association.(1) 4.1 Specimen Share Certificate of Ordinary Shares, $.01 par value, of the Company.(2) 4.2 Rights Agreement dated as of March 25, 1996, between Triton and Chemical Bank, as Rights Agent, including, as Exhibit A thereto, Resolutions establishing the Junior Preference Shares.(1) 4.3 Resolutions Authorizing the Company's 5% Convertible Preference Shares.(3) 4.4 Amendment No. 1 to Rights Agreement dated as of August 2, 1996, between Triton and Chemical Bank, as Rights Agent.(4) 10.1 Amended and Restated Retirement Income Plan.(5)(21) 10.2 Amended and Restated Supplemental Executive Retirement Income Plan.(6)(21) 10.3 1981 Employee Non-Qualified Stock Option Plan.(7)(21) 10.4 Amendment No. 1 to the 1981 Employee Non-Qualified Stock Option Plan.(8)(21) 10.5 Amendment No. 2 to the 1981 Employee Non-Qualified Stock Option Plan.(7)(21) 10.6 Amendment No. 3 to the 1981 Employee Non-Qualified Stock Option Plan.(5)(21) 10.7 1985 Stock Option Plan.(9)(21) 10.8 Amendment No. 1 to the 1985 Stock Option Plan.(7)(21) 10.9 Amendment No. 2 to the 1985 Stock Option Plan.(5)(21) 10.10 Amended and Restated 1986 Convertible Debenture Plan.(5)(21) 10.11 1988 Stock Appreciation Rights Plan.(10)(21) 10.12 1989 Stock Option Plan.(11)(21) 10.13 Amendment No. 1 to 1989 Stock Option Plan.(7)(21) 10.14 Amendment No. 2 to 1989 Stock Option Plan.(5)(21) 10.15 Second Amended and Restated 1992 Stock Option Plan.(13)(21) 10.16 Form of Amended and Restated Employment Agreement with Triton Energy Limited and its executive officers.(21)(22) 10.17 Form of Amended and Restated Employment Agreement with Triton Energy Limited and certain officers.(21)(22) 10.18 Amended and Restated 1985 Restricted Stock Plan.(5)(21) 10.19 First Amendment to Amended and Restated 1985 Restricted Stock Plan.(12)(21) 10.20 Second Amendment to Amended and Restated 1985 Restricted Stock Plan.(13)(21) 10.21 Executive Life Insurance Plan.(14)(21) 10.22 Long Term Disability Income Plan.(14)(21) 10.23 Amended and Restated Retirement Plan for Directors.(9)(21) 10.24 Amended and Restated Indenture dated as of March 25, 1996 between Triton and Chemical Bank, with respect to the issuance of Senior Subordinated Discount Notes due 1997.(13) 10.25 Amended and Restated Senior Subordinated Indenture by and between the Company and United States Trust Company of New York, dated as of March 25, 1996.(13) 10.26 Contract for Exploration and Exploitation for Santiago de Atalayas I with an effective date of July 1, 1982, between Triton Colombia, Inc., and Empresa Colombiana De Petroleos.(9) 10.27 Contract for Exploration and Exploitation for Tauramena with an effective date of July 4, 1988, between Triton Colombia, Inc., and Empresa Colombiana De Petroleos.(10) 10.28 Summary of Assignment legalized by Public Instrument No. 1255 dated September 15, 1987 (Assignment is in Spanish language).(10) 10.29 Summary of Assignment legalized by Public Instrument No. 1602 dated June 11, 1990 (Assignment is in Spanish language).(10) 10.30 Summary of Assignment legalized by Public Instrument No. 2586 dated September 9, 1992 (Assignment is in Spanish language).(10) 10.31 401(K) Savings Plan.(5)(21) 10.32 Contract between Malaysia-Thailand and Joint Authority and Petronas Carigali SDN.BHD. and Triton Oil Company of Thailand relating to Exploration and Production of Petroleum for Malaysia-Thailand Joint Development Area Block A-18.(15) 10.33 Triton Crude Purchase Agreement between Triton Colombia, Inc. and Oil Co., LTD. dated May 25, 1995.(16) 10.34 Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States.(12) 10.35 Amendment No. 1 to Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States.(12) 10.36 Amendment No. 2 to Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States.(13) 10.37 Agreement and Plan of Merger among Triton Energy Corporation, Triton Energy Limited and TEL Merger Corp.(12) 10.38 Credit Agreement among Triton Energy Limited and Triton Energy Corporation, as Borrowers, and NationsBank of Texas, N.A., Barclays Bank PLC, Meespierson N.V., The Chase Manhattan Bank and Societe Generale, Southwest Agency dated August 30, 1996. (17) 10.39 Credit Agreement between Triton Energy Corporation and Banque Paribas Houston Agency dated as of May 28, 1995, together with related form of revolving credit note.(18) 10.40 First Amendment to Credit Agreement between Triton Energy Corporation and Banque Paribas Houston Agency darted May 16, 1995.(19) 10.41 Security Agreement between Triton Energy Corporation and Banque Paribas Houston Agency.(18) 10.42 Second Amendment to Credit Agreement and First Amendment to Security Agreement between Triton Energy Corporation and Banque Paribas Houston Agency dated August 11, 1995.(6) 10.43 Third Amendment to Credit Agreement between Triton Energy Corporation and Banque Paribas Houston Agency dated September 29, 1995.(6) 10.44 Consent, Waiver and Guaranty among Triton Energy Limited, Triton Energy Corporation and Paribas Houston Agency dated as of March 25, 1996. (13) 10.45 Form of Indemnity Agreement entered into with each director and officer of the Company. (17) 10.46 Restated Employment Agreement between John Tatum and the Company. (21)(22) 10.47 Description of Performance Goals for Executive Bonus Compensation. (21)(22) 10.48 Demand Promissory Note - Grid executed by Triton Energy Limited and Triton Energy Corporation in favor of Banque Paribas dated as of February 6, 1997.(22) 11.1 Computation of Earnings per Share. (22) 12.1 Computation of Ratio of Earnings to Fixed Charges. (22) 12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends. (22) 21.1 Subsidiaries of the Company.(22) 23.1 Consent of Price Waterhouse LLP.(22) 23.2 Consent of DeGolyer and MacNaughton.(22) 24.1 The power of attorney of officers and directors of the Company (set forth on the signature page hereof).(22) 27.1 Financial Data Schedule.(22) 99.1 Rio Chitamena Association Contract.(20) 99.2 Rio Chitamena Purchase and Sale Agreement.(20) 99.3 Integral Plan - Cusiana Oil Structure.(20) 99.4 Letter Agreements with co-investor in Colombia.(20) 99.5 Colombia Pipeline Memorandum of Understanding.(20) 99.6 Amended and Restated Oleoducto Central S.A. Agreement dated as of March 31, 1995.(19) - ---------------------------- (1) Previously filed as an exhibit to the Company's Registration Statement on Form S-3 (No. 333-08005) and incorporated herein by reference. (2) Previously filed as an exhibit to the Company's Registration Statement on Form 8-A dated March 25, 1996 and incorporated herein by reference. (3) Previously filed as an exhibit to the Company's and Triton Energy Corporation's Registration Statement on Form S-4 (No. 333-923) and incorporated herein by reference. (4) Previously filed as an exhibit to the Company's Registration Statement on Form 8-A/A (Amendment No. 1) dated August 14, 1996 and incorporated herein by reference. (5) Previously filed as an exhibit to Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended November 30, 1993 and incorporated by reference herein. (6) Previously filed as an exhibit to Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1995 and incorporated herein by reference. (7) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31, 1992 and incorporated herein by reference. (8) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31, 1989 and incorporated by reference herein. (9) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31, 1990 and incorporated herein by reference. (10)Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31, 1993 and incorporated by reference herein. (11)Previously filed as an exhibit to Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended November 30, 1988 and incorporated herein by reference. (12)Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 1995 and incorporated herein by reference. (13)Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1996 and incorporated herein by reference. (14)Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31, 1991 and incorporated herein by reference. (15)Previously filed as an exhibit to Triton Energy Corporation's current report on Form 8-K dated April 21, 1994 and incorporated by reference herein. (16)Previously filed as an exhibit to Triton Energy Corporation's Current Report on Form 8-K dated May 26, 1995 and incorporated herein by reference. (17)Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996 and incorporated herein by reference. (18)Previously filed as an exhibit to Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1995 and incorporated herein by reference. (19)Previously filed as an exhibit to Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1995 and incorporated herein by reference. (20)Previously filed as an exhibit to Triton Energy Corporation's current report on Form 8-K/A dated July 15, 1994 and incorporated by reference herein. (21)Management contract or compensatory plan or arrangement. (22)Filed herewith. (b) Reports on Form 8-K. None SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Annual Report on Form 10-K to be signed by the undersigned thereunto duly authorized on the 18 day of March, 1997. TRITON ENERGY LIMITED By: /s/Thomas G. Finck Thomas G. Finck Chairman of the Board and Chief Executive Officer POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and directors of Triton Energy Limited (the "Company") hereby constitutes and appoints Thomas G. Finck, Robert B. Holland, III, and Peter Rugg, or any of them (with full power to each of them to act alone), his true and lawful attorney-in-fact and agent, with full power of substitution, for him and on his behalf and in his name, place and stead, in any and all capacities, to sign, execute, and file any and all documents relating to the Company's Annual Report on Form 10-K for the year ended December 31, 1996, including any and all amendments and supplements thereto, with any regulatory authority, granting unto said attorneys, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises in order to effectuate the same as fully to all intents and purposes as he himself might or could do if personally present, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done. Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 18 day of March, 1997. Signatures Title /s/Thomas G. Finck Chairman of the Board and Chief Financial Thomas G. Finck Officer /s/Peter Rugg Senior Vice President and Peter Rugg Chief Financial Officer (Principal Accounting and Financial Officer) /s/John P. Lewis Director March 18, 1997 John P. Lewis /s/Michael E. McMahon Director March 18, 1997 Michael E. McMahon /s/Ernest E. Cook Director March 18, 1997 Ernest E. Cook /s/Sheldon R. Erikson Director March 18, 1997 Sheldon R. Erikson /s/Ray H. Eubank Director March 18, 1997 Ray H. Eubank /s/Jesse E. Hendricks Director March 18, 1997 Jesse E. Hendricks /s/Fitzgerald S. Hudson Director March 18, 1997 Fitzgerald S. Hudson /s/John R. Huff Director March 18, 1997 John R. Huff /s/Wellslake D. Morse, Jr. Director March 18, 1997 Wellslake D. Morse, Jr. /s/Edwin D. Williamson Director March 18, 1997 Edwin D. Williamson TRITON ENERGY LIMITED AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS AND SCHEDULES PAGE ---- TRITON ENERGY LIMITED AND SUBSIDIARIES: Report of Independent Accountants F-2 Consolidated Statements of Operations - Years ended December 31, 1996 and 1995, seven months ended December 31, 1994 and year ended May 31, 1994 F-3 Consolidated Balance Sheets - December 31, 1996 and 1995 F-4 Consolidated Statements of Cash Flows - Years ended December 31, 1996 and 1995, seven months ended December 31, 1994 and year ended May 31, 1994 F-5 Consolidated Statements of Shareholders' Equity - Years ended December 31, 1996 and 1995, seven months ended December 31, 1994 and year ended May 31, 1994 F-6 Notes to Consolidated Financial Statements F-7 SCHEDULE: II - Valuation and Qualifying Accounts - Years ended December 31, 1996 and 1995, seven months ended December 31, 1994 and year ended May 31, 1994 F-53 All other schedules are omitted as the required information is inapplicable or presented in the consolidated financial statements or related notes REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Triton Energy Limited In our opinion, the consolidated financial statements as of and for the years ended December 31, 1996 and 1995, for the seven months ended December 31, 1994, and for the year ended May 31, 1994 listed in the accompanying index present fairly, in all material respects, the financial position of Triton Energy Limited and its subsidiaries at December 31, 1996 and 1995, and the results of their operations and their cash flows for the years ended December 31, 1996 and 1995, the seven months ended December 31, 1994 and the year ended May 31, 1994, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. Price Waterhouse LLP Dallas, Texas February 4, 1997 TRITON ENERGY LIMITED AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) SEVEN MONTHS ENDED YEAR ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, MAY 31, ------------------------- 1996 1995 1994 1994 -------------- --------- -------------- -------- SALES AND OTHER OPERATING REVENUES: Oil and gas sales $ 129,795 $106,844 $ 20,477 40,894 Other operating revenues 4,182 628 259 2,314 -------------- --------- -------------- -------- 133,977 107,472 20,736 43,208 -------------- --------- -------------- -------- COSTS AND EXPENSES: Operating 36,654 35,276 12,362 27,887 General and administrative 25,945 25,672 15,997 30,429 Depreciation, depletion and amortization 25,640 23,208 7,339 19,821 Writedown of assets 42,960 --- 984 45,754 -------------- --------- -------------- -------- 131,199 84,156 36,682 123,891 -------------- --------- -------------- -------- OPERATING INCOME (LOSS) 2,778 23,316 (15,946) (80,683) Gain on sale of Triton Canada stock --- --- --- 47,865 Interest income 6,703 7,954 4,144 6,542 Interest expense (15,897) (24,055) (7,754) (7,504) Other income (expense), net 27,361 9,385 (3,278) 10,676 -------------- --------- -------------- -------- 18,167 (6,716) (6,888) 57,579 -------------- --------- -------------- -------- EARNINGS (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES, MINORITY INTEREST AND EXTRAORDINARY ITEM 20,945 16,600 (22,834) (23,104) Income tax expense (benefit) (2,860) 10,059 3,796 (6,536) -------------- --------- -------------- -------- 23,805 6,541 (26,630) (16,568) Minority interest in loss of subsidiaries --- --- --- 11,971 -------------- --------- -------------- -------- EARNINGS (LOSS) FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEM 23,805 6,541 (26,630) (4,597) DISCONTINUED OPERATIONS: Loss from operations --- (1,858) (1,078) (4,094) Loss on disposal --- (1,963) --- (650) -------------- --------- -------------- -------- EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM 23,805 2,720 (27,708) (9,341) Extraordinary item - extinguishment of debt (1,196) --- --- --- -------------- --------- -------------- -------- NET EARNINGS (LOSS) 22,609 2,720 (27,708) (9,341) DIVIDENDS ON PREFERENCE SHARES 985 802 449 --- -------------- --------- -------------- -------- EARNINGS (LOSS) APPLICABLE TO ORDINARY SHARES $ 21,624 $ 1,918 $ (28,157) (9,341) -------------- --------- -------------- -------- Average ordinary and equivalent shares outstanding 36,919 35,147 34,944 34,775 -------------- --------- -------------- -------- EARNINGS (LOSS) PER ORDINARY SHARE: Continuing operations $ 0.62 $ 0.16 $ (0.78) (0.13) Discontinued operations --- (0.11) (0.03) (0.14) Extraordinary item (0.03) --- --- --- -------------- --------- -------------- -------- NET EARNINGS (LOSS) $ 0.59 $ 0.05 $ (0.81) (0.27) -------------- --------- -------------- -------- See accompanying notes to consolidated financial statements. TRITON ENERGY LIMITED AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA) ASSETS DECEMBER 31, ---------------------- 1996 1995 ---------- ---------- CURRENT ASSETS: Cash and equivalents $ 11,048 $ 49,050 Short-term marketable securities 3,866 42,419 Trade receivables, net 11,526 6,504 Other receivables 49,000 16,683 Inventories, prepaid expenses and other 8,920 4,128 ---------- ---------- TOTAL CURRENT ASSETS 84,360 118,784 Long-term marketable securities --- 3,985 Property and equipment, at cost, net 676,833 524,381 Deferred income taxes 71,416 47,283 Investments and other assets 81,915 129,734 ---------- ---------- $ 914,524 $ 824,167 ---------- ---------- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of long-term debt $ 199,552 $ 1,313 Accounts payable and accrued liabilities 38,545 23,794 Deferred income 28,466 8,079 ---------- ---------- TOTAL CURRENT LIABILITIES 266,563 33,186 Long-term debt, excluding current maturities 217,078 401,190 Deferred income taxes 45,431 29,897 Deferred income and other 84,808 113,869 Convertible debentures due to employees --- --- SHAREHOLDERS' EQUITY: Preference shares, par value $.01 for 1996 and without par value for 1995; authorized 5,000,000 shares; issued 247,469 and 410,017 shares at December 31, 1996 and 1995, respectively; stated value $34.41 8,515 14,109 Ordinary shares, par value $.01 and $1.00 for 1996 and 1995, respectively; authorized 200,000,000 shares; issued 36,342,181 and 35,927,279 shares at December 31, 1996 and 1995, respectively 363 35,927 Additional paid-in capital 582,581 516,326 Accumulated deficit (288,685) (311,294) Other (2,128) (8,705) ---------- ---------- 300,646 246,363 Less cost of ordinary shares in treasury 2 338 ---------- ---------- TOTAL SHAREHOLDERS' EQUITY 300,644 246,025 ---------- ---------- Commitments and contingencies (note 21) $ 914,524 $ 824,167 ---------- ---------- The Company uses the full cost method to account for its oil- and gas-producing activities. See accompanying notes to consolidated financial statements. TRITON ENERGY LIMITED AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) SEVEN MONTHS ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, ------------------------- 1996 1995 1994 ----------- ---------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES: Net earnings (loss) $ 22,609 $ 2,720 $ (27,708) Adjustments to reconcile net earnings (loss) to net cash provided (used) by operating activities: Depreciation, depletion and amortization 25,640 23,467 7,587 Amortization of debt discount 15,897 23,928 7,939 Proceeds from forward oil sale --- 86,610 --- Amortization of unearned revenue (8,105) (4,725) --- (Gain) loss on sale of assets, net (15,831) (2,938) 201 Gain on sale of Triton Canada stock --- --- --- Writedowns, loss provisions and discontinued operations 45,753 7,192 984 Deferred income taxes (8,759) 5,444 4,569 Minority interest in undistributed loss of subsidiaries --- --- --- Other, net (5,815) (536) 5,198 Changes in working capital: Marketable debt securities - trading 4,149 8,074 10,429 Receivables (5,048) (1,677) (3,064) Inventories, prepaid expenses and other (787) (790) (4,408) Accounts payable and accrued liabilities 10,732 2,367 2,657 Income taxes 270 (42) (6,398) ----------- ---------- ---------- Net cash provided (used) by operating activities 80,705 149,094 (2,014) ----------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures and investments (252,684) (178,161) (89,895) Purchases of investments and marketable securities --- (45,281) (5,879) Proceeds from sale of investments and marketable securities 38,507 42,050 36,664 Proceeds from sale of shareholdings in Crusader 69,583 --- --- Sales of property and equipment and other assets 38,505 20,866 539 Proceeds from sale of Triton Canada stock --- --- --- Proceeds from sale of discontinued operations --- 2,100 1,737 Other 571 (1,368) (3,509) ----------- ---------- ---------- Net cash used by investing activities (105,518) (159,794) (60,343) ----------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term debt 53,911 85,627 1,701 Proceeds from short-term borrowings with maturities greater than three months --- --- 7,671 Short-term borrowings, net --- (10,000) 8,040 Payments on long-term debt (70,884) (39,366) (212) Payments on debt associated with discontinued operations --- (2,004) (1,883) Issuance of ordinary shares 5,874 8,398 639 Other (1,879) (3,752) (707) ----------- ---------- ---------- Net cash provided (used) by financing activities (12,978) 38,903 15,249 ----------- ---------- ---------- Effects of exchange rate changes on cash and equivalents (211) (1,494) 444 ----------- ---------- ---------- Net increase (decrease) in cash and equivalents (38,002) 26,709 (46,664) CASH AND EQUIVALENTS AT BEGINNING OF PERIOD 49,050 22,341 69,005 ----------- ---------- ---------- CASH AND EQUIVALENTS AT END OF PERIOD $ 11,048 $ 49,050 $ 22,341 ------------- ---------- ---------- YEAR ENDED MAY 31, 1994 ------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net earnings (loss) $ (9,341) Adjustments to reconcile net earnings (loss) to net cash provided (used) by operating activities: Depreciation, depletion and amortization 20,490 Amortization of debt discount 7,852 Proceeds from forward oil sale --- Amortization of unearned revenue --- (Gain) loss on sale of assets, net (8,328) Gain on sale of Triton Canada stock (47,865) Writedowns, loss provisions and discontinued operations 46,404 Deferred income taxes (10,224) Minority interest in undistributed loss of subsidiaries (11,971) Other, net 2,090 Changes in working capital: Marketable debt securities - trading --- Receivables (1,797) Inventories, prepaid expenses and other (6,310) Accounts payable and accrued liabilities (12,126) Income taxes 6,162 ------------ Net cash provided (used) by operating activities (24,964) ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures and investments (86,819) Purchases of investments and marketable securities (190,025) Proceeds from sale of investments and marketable securities 119,905 Proceeds from sale of shareholdings in Crusader --- Sales of property and equipment and other assets 22,816 Proceeds from sale of Triton Canada stock 59,029 Proceeds from sale of discontinued operations 18,450 Other (4,370) ------------ Net cash used by investing activities (61,014) ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term debt 123,408 Proceeds from short-term borrowings with maturities greater than three months --- Short-term borrowings, net (1,640) Payments on long-term debt (3,150) Payments on debt associated with discontinued operations (18,959) Issuance of ordinary shares 3,164 Other (1,054) ------------ Net cash provided (used) by financing activities 101,769 ------------ Effects of exchange rate changes on cash and equivalents 275 ------------ Net increase (decrease) in cash and equivalents 16,066 CASH AND EQUIVALENTS AT BEGINNING OF PERIOD 52,939 ------------ CASH AND EQUIVALENTS AT END OF PERIOD $ 69,005 ------------ See accompanying notes to consolidated financial statements. TRITON ENERGY LIMITED AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (IN THOUSANDS) SEVEN MONTHS ENDED YEAR ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, MAY 31, ------------------------- 1996 1995 1994 1994 ----------- ---------- -------------- ------------ PREFERENCE SHARES: Balance at beginning of period $ 14,109 $ 17,976 $ 17,978 $ --- Purchase of minority interest in Triton Europe --- --- --- 17,978 Conversion of 5% preference shares (5,594) (3,867) (2) --- ----------- ---------- -------------- ------------ Balance at end of period 8,515 14,109 17,976 17,978 ----------- ---------- -------------- ------------ ORDINARY SHARES: Balance at beginning of period 35,927 35,577 35,519 35,231 Exercise of employee stock options and debentures 81 238 58 288 Conversion of 5% preference shares 153 112 --- --- Reduction in par value (35,783) --- --- --- Other, net (15) --- --- --- ----------- ---------- -------------- ------------ Balance at end of period 363 35,927 35,577 35,519 ----------- ---------- -------------- ------------ ADDITIONAL PAID-IN CAPITAL: Balance at beginning of period 516,326 505,256 505,122 502,217 Cash dividends, 5% preference shares (985) (802) (449) --- Exercise of employee stock options and debentures 7,974 8,160 464 2,876 Conversion of 5% preference shares 5,441 3,755 --- --- Reduction in par value 35,783 --- --- --- Sale of shareholdings in Crusader 20,413 --- --- --- Other, net (2,371) (43) 119 29 ----------- ---------- -------------- ------------ Balance at end of period 582,581 516,326 505,256 505,122 ----------- ---------- -------------- ------------ ACCUMULATED DEFICIT: Balance at beginning of period (311,294) (314,014) (286,306) (276,965) Net earnings (loss) 22,609 2,720 (27,708) (9,341) ----------- ---------- -------------- ------------ Balance at end of period (288,685) (311,294) (314,014) (286,306) ----------- ---------- -------------- ------------ FOREIGN CURRENCY TRANSLATION ADJUSTMENT: Balance at beginning of period (8,616) (5,639) (7,163) (4,087) Sale of foreign operations --- (3,268) --- (3,341) Sale of shareholdings in Crusader 4,890 --- --- --- Translation rate changes 1,600 291 1,524 265 ----------- ---------- -------------- ------------ Balance at end of period (2,126) (8,616) (5,639) (7,163) ----------- ---------- -------------- ------------ OTHER, NET: Balance at beginning of period (89) (1,384) (1,046) (246) Valuation reserve on marketable securities 87 1,295 (429) (955) Adjustment for minimum pension liability --- --- 91 155 ----------- ---------- -------------- ------------ Balance at end of period (2) (89) (1,384) (1,046) ----------- ---------- -------------- ------------ TREASURY SHARES: Balance at beginning of period (338) (577) (682) (718) Purchase of treasury shares (5) (4) (3) (5) Transfer of shares to employee benefit plans 137 243 108 41 Retirement of treasury shares 204 --- --- --- ----------- ---------- -------------- ------------ Balance at end of period (2) (338) (577) (682) ----------- ---------- -------------- ------------ TOTAL SHAREHOLDERS' EQUITY $ 300,644 $ 246,025 $ 237,195 $ 263,422 ----------- ---------- -------------- ------------ See accompanying notes to consolidated financial statements. TRITON ENERGY LIMITED AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (AMOUNTS IN TABLES IN THOUSANDS, EXCEPT FOR SHARE DATA) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GENERAL Triton Energy Limited ("Triton") is an international oil and gas exploration company primarily engaged in exploration and production through subsidiaries and affiliates. The term "Company" when used herein means Triton and its subsidiaries and other affiliates through which the Company conducts its business. The Company's principal properties, operations and oil and gas reserves are located in Colombia and Malaysia-Thailand. All sales are currently derived from oil and gas production in Colombia. The Company also has oil and gas interests in other Latin American, Asian and European countries. Triton, a Cayman Islands company, was incorporated in August 1995 to become the parent holding company of Triton Energy Corporation, a Delaware corporation ("TEC"). On March 25, 1996, the stockholders of TEC approved the merger of a wholly owned subsidiary of Triton with and into TEC (the "Reorganization"). Pursuant to the Reorganization, Triton became the parent holding company of TEC and each share of common stock, par value $1.00, and 5% preferred stock of TEC outstanding on March 25, 1996, was converted into one ordinary share, par value $.01, and one 5% preference share, respectively, of Triton. The Reorganization has been accounted for as a combination of entities under common control. CHANGE IN FISCAL YEAREND Effective January 1, 1995, the Company changed its fiscal yearend from May 31 to December 31. These financial statements include the Company's transition period for the seven months ended December 31, 1994. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Triton and its majority-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. Investments in 20%-to-50%-owned affiliates in which the Company exercises significant influence over operating and financial policies are accounted for using the equity method. Investments in less than 20%-owned affiliates are accounted for using the cost method. CASH EQUIVALENTS AND MARKETABLE SECURITIES Cash equivalents are highly liquid investments purchased with an original maturity of three months or less. Investments in marketable debt securities are reported at fair value except for those investments that management has the positive intent and the ability to hold to maturity. Investments available-for-sale are classified based on the stated maturity of the securities and changes in fair value are reported as a separate component of shareholders' equity. Trading investments are classified as current regardless of the stated maturity of the underlying securities and changes in fair value are reported in other income, net. Investments that will be held-to-maturity are classified based on the stated maturity of the securities. PROPERTY AND EQUIPMENT The Company follows the full cost method of accounting for exploration and development of oil and gas reserves, whereby all acquisition, exploration and development costs are capitalized. Individual countries are designated as separate cost centers. All capitalized costs plus the undiscounted future development costs of proved reserves are depleted using the unit of production method based on total proved reserves applicable to each country. A gain or loss is recognized on sales of oil and gas properties only when the sale involves significant reserves. Costs related to acquisition, holding and initial exploration of licenses in countries with no proved reserves are initially capitalized, including internal costs directly identified with acquisition, exploration and development activities. Costs related to production, general overhead or similar activities are expensed. The Company's exploration licenses are periodically assessed for impairment on a country-by-country basis. If the Company's investment in exploration licenses within a country where no proved reserves are assigned is deemed to be impaired, the licenses are written down to estimated recoverable value. If the Company abandons all exploration efforts in a country where no proved reserves are assigned, all acquisition and exploration costs associated with the country are expensed. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expense are difficult to predict with any certainty. The net capitalized costs of oil and gas properties for each cost center, less related deferred income taxes, cannot exceed the sum of (i) the estimated future net revenues from the properties, discounted at 10%; (ii) unevaluated costs not being amortized; and (iii) the lower of cost or estimated fair value of unproved properties being amortized; less (iv) income tax effects related to differences between the financial statement basis and tax basis of oil and gas properties. The estimated costs, net of salvage value, of dismantling facilities or projects with limited lives or facilities that are required to be dismantled by contract, regulation or law and the estimated costs of restoration and reclamation associated with oil and gas operations are included in estimated future development costs as part of the amortizable base. Support equipment and facilities are depreciated using the unit of production method based on total reserves of the field related to the support equipment and facilities. Other property and equipment, which includes furniture and fixtures, vehicles, aircraft and leasehold improvements, are depreciated principally on a straight-line basis over estimated useful lives ranging from 3 to 30 years. Repairs and maintenance are expensed as incurred, and renewals and improvements are capitalized. ENVIRONMENTAL MATTERS Environmental costs are expensed or capitalized depending on their future economic benefit. Costs that relate to an existing condition caused by past operations and have no future economic benefit are expensed. Liabilities for future expenditures of a noncapital nature are recorded when future environmental expenditures and/or remediation is deemed probable, and the costs can be reasonably estimated. INCOME TAXES Deferred tax liabilities or assets are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of the Company's assets and liabilities using the enacted tax rates in effect at yearend. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. REVENUE RECOGNITION Oil and gas revenues are recognized at the point of first measurement after production which is generally upon delivery into field storage tank/processing facilities or pipelines. Cost reimbursements arising from carried interests granted by the Company are revenues to the extent the reimbursements are contingent upon and derived from production. Obligations arising from net profit interest conveyances are recorded as operating expenses when the obligation is incurred. FOREIGN CURRENCY TRANSLATION The U.S. dollar is the designated functional currency for all of the Company's foreign operations, except for foreign operations of certain affiliates where the local currencies are used as the functional currency. The cumulative translation effects from translating balance sheet accounts from the functional currency into U.S. dollars at current exchange rates are included as a separate component of shareholders' equity. RISK MANAGEMENT Oil and natural gas sold by the Company are normally priced with reference to a defined benchmark, such as light sweet crude oil traded on the New York Merchantile Exchange (West Texas Intermediate or "WTI"). Actual prices received vary from the benchmark depending on quality and location differentials. It is the Company's policy to use financial market transactions with credit-worthy counterparties from time to time primarily to reduce risk associated with the pricing of a portion of the oil and natural gas that it sells. The Company may also enter into financial market transactions to benefit from its assessment of the future prices of its production relative to other benchmark prices. Gains or losses on financial market transactions that qualify for hedge accounting are recognized in oil and gas sales at the time of settlement of the underlying hedged transactions. Premiums paid for financial market contracts are capitalized and amortized as operating expenses over the contract period. Changes in the fair market value of financial market transactions that do not qualify for hedge accounting are reflected as noncash adjustments to other income, net in the period the change occurs. Realized gains or losses on financial market transactions that do not qualify for hedge accounting are recorded in oil and gas sales. The Company occasionally enters into foreign exchange contracts to reduce risk of unfavorable exchange-rate movements. The gains or losses arising from currency exchange contracts offset foreign exchange gains or losses on the underlying assets or liabilities or are deferred and offset against the carrying value of the firm commitment. DISCONTINUED OPERATIONS AND RECLASSIFICATIONS The Company discontinued its aviation sales and services segment in June 1995. The Consolidated Statements of Operations for the seven months ended December 31, 1994, and the year ended May 31, 1994, have been restated to reflect the aviation sales and services segment as discontinued operations. Certain other previously reported financial information has been reclassified to conform to the current period's presentation. EARNINGS (LOSS) PER ORDINARY SHARE Primary earnings (loss) per ordinary share amounts were computed by dividing net earnings (loss) after deduction of dividends on preference shares by the weighted average number of ordinary and dilutive equivalent shares outstanding. Ordinary share equivalents were not material or were antidilutive for the year ended December 31, 1995, the seven months ended December 31, 1994, and the year ended May 31, 1994. Prior to the Company's sale of its investment in Crusader Limited ("Crusader") in July 1996, the Company's proportionate shares owned by Crusader were not considered outstanding for purposes of determining weighted average number of shares outstanding. Fully diluted earnings (loss) per ordinary share is not presented due to the antidilutive effect of including all potentially dilutive securities. STOCK-BASED COMPENSATION Statement of Financial Accounting Standards No. 123 ("SFAS 123"), "Accounting for Stock-Based Compensation," encourages, but does not require, the adoption of a fair value-based method of accounting for employee stock-based compensation transactions. The Company has elected to continue to apply the provisions of Accounting Principles Board Opinion No. 25 ("Opinion 25"), "Accounting for Stock Issued to Employees," and related interpretations, in accounting for its stock-based compensation plans. Under Opinion 25, compensation cost is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant above the amount an employee must pay to acquire the stock. THE USE OF ESTIMATES IN PREPARING FINANCIAL STATEMENTS The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. 2. DIVESTITURES AND DISCONTINUED OPERATIONS In June and July 1996, the Company sold its 49.9% shareholdings in Crusader for total cash proceeds of $69.6 million to an unrelated third party in conjunction with a May 1996 take-over bid by the same party for the outstanding shares of Crusader. The Company recorded a total gain of $10.4 million in other income, net and an increase to additional paid-in capital of $20.4 million, representing the Company's proportion of Triton ordinary shares owned by Crusader that were previously treated as owned by Triton. In March 1996, the Company sold its royalty interests in U.S. properties for $23.8 million based on an effective date of January 1, 1996. The Company recorded the resulting gain of $4.1 million in other operating revenues. In August 1995, the Company sold Triton France S.A. to an unrelated third party. The Company received net proceeds, including repayment of intercompany debt, of approximately $16 million and recorded a net gain of $3.5 million and a reduction in shareholder equity of approximately $3.3 million for the foreign currency translation adjustment. In June 1995, the Company sold the assets of its subsidiary, Jet East, Inc., for $2.9 million in cash and a note, and realized a loss of $1.4 million on the sale. The Company accrued $.6 million for costs associated with final disposal of the segment, which occurred in August 1995. Summarized information for the aviation sales and services segment portion of discontinued operations follows: YEAR ENDED SEVEN YEAR ENDED DECEMBER 31, MONTHS ENDED MAY 31, 1995 DEC. 31, 1994 1994 -------------- --------------- ------------ Revenues $ 4,694 $ 6,117 $ 12,885 -------------- --------------- ------------ Loss before income taxes $ (2,022) $ (1,078) $ (4,094) Income tax expense (benefit) --- --- --- -------------- --------------- ------------ Net loss $ (2,022) $ (1,078) $ (4,094) -------------- --------------- ------------ In the first quarter of fiscal 1994, the Company completed the sale of its 76% interest in the common stock of Triton Canada Resources Ltd. The Company received net proceeds of $59 million and recorded a gain of $47.9 million. In August and October 1993, the Company sold its working interest in U.S. properties for net proceeds of $19.5 million, resulting in a gain of $7 million. The properties that were sold accounted for approximately 55.7% of discounted future net revenues associated with U.S. proved properties at May 31, 1993. In fiscal 1993, the Company initiated a plan to discontinue its remaining operations in the wholesale fuel products segment. An accrual of $16.1 million was recorded at May 31, 1993, as an estimate of the results of operations for discontinued operations during fiscal 1994 and the anticipated loss on disposal of the segment. An additional accrual of $.7 million was recorded at May 31, 1994, for estimated operating losses caused by closing the sales of several operating divisions later than originally anticipated. All operations have been sold. Summarized information for the wholesale fuel products segment portion of discontinued operations follows: SEVEN YEAR ENDED MONTHS ENDED MAY 31, DEC. 31, 1994 1994 --------------- ------------ Revenues $ 8,820 $ 81,383 --------------- ------------ Loss before income taxes $ (2,070) $ (14,422) Income tax expense 5 7 --------------- ------------ Net loss $ (2,075) $ (14,429) --------------- ------------ 3. FORWARD SALE OF COLOMBIAN OIL PRODUCTION In May 1995, the Company sold 10.4 million barrels of oil in a forward oil sale. Under the terms of the sale, the Company received approximately $87 million of the approximately $124 million net proceeds and is entitled to receive substantially all of the remaining proceeds (now held in various interest-bearing reserve accounts) when the Company's Cusiana and Cupiagua fields project in Colombia becomes self-financing, which is expected in 1997, and when certain other conditions are met. At December 31, 1996, proceeds held in interest-bearing reserve accounts of $30 million and $5.6 million have been recorded as current and long-term receivables, respectively. The Company has recorded the net proceeds as deferred income and will recognize such revenue when the barrels of oil are delivered during a five-year period that began in June 1995. The Company is required to deliver to the buyer 58,425 barrels per month through March 1997 and 254,136 barrels per month from April 1997 to March 2000. 4. PURCHASE OF THE TRITON EUROPE MINORITY INTEREST On March 31, 1994, the Company acquired all of the outstanding shares not owned by the Company, representing the minority shareholders' 40.5% interest in Triton Europe plc ("Triton Europe"), in exchange for 522,460 shares of the Company's 5% Convertible Preferred Stock ("5% preferred stock"), with a value of $18 million, and $2.6 million in cash, including transaction costs. The transaction was recorded as a purchase, and accordingly, 100% of Triton Europe's operating results have been included in the Company's results of operations since March 31, 1994. The excess of the purchase price over the carrying value of the minority interest in Triton Europe of $3.5 million was allocated to the full cost pools within Triton Europe. 5. INVESTMENTS IN MARKETABLE SECURITIES The carrying values of marketable securities are as follows: DECEMBER 31, ---------------- 1996 1995 ------- ------- Short-term marketable securities: Held-to-maturity $ --- $18,861 Available-for-sale 1,998 17,519 Trading 1,868 6,039 ------- ------- Total short-term marketable securities $ 3,866 $42,419 ------- ------- Long-term available-for-sale $ --- $ 3,985 ------- ------- Proceeds from the sale of available-for-sale securities were $19.5 million and $7.7 million in the years ended December 31, 1996 and 1995, respectively. 6. OTHER RECEIVABLES Other receivables consisted of the following: DECEMBER 31, ----------------- 1996 1995 -------- ------- Receivable from the forward oil sale $ 30,000 $ --- Central Llanos pipeline receivable 6,380 9,930 Receivable from partners 5,371 3,171 Other 7,249 3,582 -------- ------- $ 49,000 $16,683 -------- ------- Triton Colombia, Inc. ("Triton Colombia"), along with its joint venture partners in the Cusiana and Cupiagua fields in Colombia, advanced 50% of the cost to upgrade the capacity of the Central Llanos pipeline that was formerly owned by Empresa Colombiana de Petroleos ("Ecopetrol"). In November 1995, Oleoducto Central S.A. ("OCENSA") acquired the Central Llanos pipeline from Ecopetrol. The Company will recover the remaining outstanding receivable based on the production from the Cusiana and Cupiagua fields transported through the pipeline. The outstanding balance of the receivable bears interest at the London Interbank Offered Rate ("LIBOR") plus 1%. 7. PROPERTY AND EQUIPMENT Property and equipment, at cost, are summarized as follows: DECEMBER 31, ------------------- 1996 1995 --------- -------- Oil and gas properties, full cost method: Evaluated $ 398,446 $506,405 Unevaluated 149,648 173,061 Support equipment and facilities 194,116 87,289 Other 31,044 22,422 --------- -------- 773,254 789,177 Less accumulated depreciation and depletion 96,421 264,796 --------- -------- $ 676,833 $524,381 --------- -------- The Company capitalizes interest on qualifying assets, principally unevaluated oil and gas properties, major development projects in progress and support equipment and facilities under construction. Capitalized interest amounted to $27.1 million and $16.2 million in the years ended December 31, 1996 and 1995, respectively, $11.8 million in the seven months ended December 31, 1994, and $16.9 million in the year ended May 31, 1994. The Company capitalized general and administrative expenses related to exploration and development activities of $24.6 million and $21.1 million in the years ended December 31, 1996 and 1995, respectively, $9.5 million in the seven months ended December 31, 1994, and $11.2 million in the year ended May 31, 1994. Evaluated oil and gas properties and accumulated depreciation and depletion decreased by $246.9 million and $228.3 million, respectively, in 1996 due to the sales of the Company's royalty interests in U.S. properties and the assets of Triton Indonesia, Inc. and $265.5 million and $247 million, respectively, in 1995 due to the sale of Triton France S.A. 8. INVESTMENTS AND OTHER ASSETS Investments and other assets consisted of the following: DECEMBER 31, ------------------ 1996 1995 -------- -------- Investment in OCENSA $ 34,311 $ 15,789 Investment in ODC 11,108 11,108 Investment in Crusader --- 31,530 WTI benchmark call options 11,048 4,580 Unamortized debt issue costs 6,878 9,349 Receivable from the forward oil sale 5,613 35,613 Other 12,957 21,765 -------- -------- $ 81,915 $129,734 -------- -------- The Company's wholly owned subsidiary Triton Pipeline Colombia, Inc. ("Triton Pipeline") owns the Company's 9.6% interest in OCENSA. Triton Colombia, owns approximately 6.6% in Oleoducto de Colombia S.A. ("ODC"). The Company amortizes debt issue costs over the life of the borrowing using the interest method. Amortization related to the Company's debt issue costs was $3.6 million and $2.3 million in the years ended December 31, 1996 and 1995, respectively, $1.3 million in the seven months ended December 31, 1994, and $1.5 million in the year ended May 31, 1994. 9. CRUSADER Crusader, a 49.9% owned affiliate until the Company's sale of its shareholdings in June and July 1996, is an Australian company engaged in oil and gas exploration and production and coal mining in Australia. Summarized financial information for Crusader follows: DECEMBER 31, 1995 ------------- ASSETS Current assets $ 44,190 Noncurrent assets 103,387 ------------- $ 147,577 ------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities $ 7,002 Noncurrent liabilities 56,114 Minority interest in subsidiaries 8,884 Shareholders' equity 75,577 ------------- $ 147,577 ------------- SEVEN YEAR ENDED YEAR ENDED MONTHS ENDED MAY 31, DEC. 31, 1995 DEC. 31, 1994 1994 ------------- --------------- ------------ Revenues $ 46,867 $ 22,535 $ 40,193 Costs and expenses (52,990) (25,145) (40,574) Income tax (expense) benefit (1,757) (6,934) 476 Minority interest 2,927 1,052 716 ----------- ------------ ------------ Net earnings (loss) $ (4,953) $ (8,492) $ 811 ----------- ------------ ------------ Company's equity in earnings (loss) $ (2,249) $ (4,102) $ 554 ----------- ------------ ------------ Company's share of dividends $ --- $ --- $ 620 ----------- ------------ ------------ In March 1995, Crusader completed the sale of Saracen Minerals Limited for proceeds of $14.3 million. This sale resulted in a net gain to the Company of approximately $3.8 million. In June 1995, Crusader recorded a $5.3 million loss (the Company's share - $2.7 million) due to a payment to holders of its 12% Convertible Subordinated Unsecured Notes to effect early redemption of these Notes to shares of Crusader common stock. The Company received approximately $2.9 million from its exchange of such notes and recorded the proceeds as other income. Also in 1995, Crusader contributed its Irish coal briquetting operations to Phoenix Coal Limited ("Phoenix"), a corporate joint venture, in exchange for preference shares and 49% of Phoenix's common shares outstanding. Crusader recorded its investment in Phoenix at historical book value. At December 31, 1995, Crusader owned approximately 3% of the Company's ordinary shares. Crusader's investment in the Company, using the cost method of accounting, was $12.2 million at December 31, 1995. The Company's investment in Crusader and additional paid-in capital were reduced to eliminate the Company's proportionate share of its ordinary shares owned by Crusader. The Company charged Crusader $.2 million and $.6 million for the years ended December 31, 1996 and 1995, respectively, $.3 million for the seven months ended December 31, 1994, and $.6 million for the year ended May 31, 1994, for administrative services. Also during fiscal 1994, the Company was paid $1.2 million by Crusader for acting as agent in issuing its 6% Notes and recorded $.6 million as other income. 10. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES Accounts payable and accrued liabilities are summarized as follows: DECEMBER 31, ----------------- 1996 1995 -------- ------- Accrued exploration and development $ 21,082 $ 8,112 Accounts payable, principally trade 2,697 8,004 Litigation and environmental matters 3,282 1,836 Employee compensation and benefits 2,315 2,405 Other 9,169 3,437 -------- ------- $ 38,545 $23,794 -------- ------- 11. LONG-TERM DEBT A summary of long-term debt follows: DECEMBER 31, -------------------- 1996 1995 ---------- -------- Senior Subordinated Discount Notes due 1997 $ 189,869 $192,220 Senior Subordinated Discount Notes due 2000 170,000 155,203 Term credit facility maturing 2001 40,622 --- Revolving credit facility maturing 1998 11,000 --- Revolving credit facility --- 48,628 Other notes and capitalized leases 5,139 6,452 ---------- -------- 416,630 402,503 Less current maturities 199,552 1,313 ---------- -------- $ 217,078 $401,190 ---------- -------- On November 13, 1992, the Company completed the sale of $240 million in principal amount of Senior Subordinated Discount Notes ("1997 Notes") due November 1, 1997, providing net proceeds to the Company of approximately $126 million. The original issue price was 54.76% of par, representing a yield to maturity of 12 1/2% per annum compounded on a semi-annual basis without periodic payments of interest. The Indenture, as amended, for the 1997 Notes contains financial covenants including certain limitations on indebtedness, dividends, certain investments, transactions with affiliates, and engaging in mergers and consolidations. Additional provisions include optional and mandatory redemptions, and requirements associated with changes in control. During 1996, the Company purchased in the open market $30 million face value of its 1997 Notes and realized an extraordinary expense of $1.2 million, net of a $.6 million tax benefit. At December 31, 1996, $210 million face value of the 1997 Notes remained outstanding. The Company believes that it will be able to extinguish or refinance the 1997 Notes at maturity with a combination of some or all of the following: the Company's revolving credit facility, cash flow from its Colombian operations, cash and marketable securities, asset sales, and the issuance of debt and equity securities. On December 15, 1993, the Company completed the sale of $170 million in principal amount of 9 3/4% Senior Subordinated Discount Notes ("9 3/4% Notes") due December 15, 2000, providing net proceeds to the Company of approximately $124 million. The original issue price was 75.1% of par, representing a yield to maturity of 9 3/4%. No interest was payable on the 9 3/4% Notes during the first three years of issue. Commencing December 15, 1996, interest on the 9 3/4% Notes began to accrue at the rate of 9 3/4% per annum and will be payable semi-annually on June 15 and December 15, beginning on June 15, 1997. The Indenture, as amended, for the 9 3/4% Notes contains financial covenants that include certain limitations on indebtedness, dividends, certain investments, transactions with affiliates, and engaging in mergers and consolidations. Additional provisions include optional and mandatory redemptions, and requirements associated with changes in control. The indentures for the 1997 Notes and the 9 3/4% Notes permit the Company to incur total indebtedness (excluding certain permitted indebtedness) of up to 25% of the sum of its indebtedness and market capitalization of its capital stock. In November 1995, the Company signed an unsecured term credit facility with a bank supported by a guarantee issued by the Export-Import Bank of the United States ("EXIM") for $45 million, which matures in January 2001. Principal and interest payments are due semi-annually on January 15 and July 15 beginning on July 15, 1996 and borrowings bear interest at LIBOR (5.5% at December 31, 1996) plus .25%, adjusted on a semi-annual basis. At December 31, 1996, the Company had outstanding borrowings of $40.6 million under the facility. In 1996, the Company signed a $125 million unsecured bank revolving credit facility that matures in August 1998. Borrowings bear interest at various spreads over either prime or LIBOR. At December 31, 1996, the Company had outstanding borrowings of $11 million and letters of credit for $2.3 million under the facility. The revolving credit facility contains financial covenants that include certain limitations on dividends, investments, prepayments of debt, transactions with affiliates, and mergers and acquisitions, and include certain mandatory pay-down requirements. As of December 31, 1996, the revolving credit facility permitted the Company to incur total indebtedness of up to approximately $630 million. Availability under the credit facility may be greater in the future under certain circumstances. At December 31, 1995, the Company had outstanding borrowings of $48.6 million under a $65 million revolving credit facility with a bank. The facility was secured by the Company's marketable securities portfolio and the Company's ownership in Crusader shareholdings. The facility was paid in full in 1996 and was terminated. The aggregate maturities of long-term debt for the five years in the period ending December 31, 2001, are as follows: 1997 -- $199.6 million; 1998 -- $20.7 million; 1999 -- $9.7 million; 2000 -- $179.7 million; and 2001 -- $5.2 million. The 1997 amount excludes future accretion of interest on the 1997 Notes. 12. INCOME TAXES The components of earnings (loss) from continuing operations before income taxes, minority interest, and extraordinary item were as follows: SEVEN YEAR ENDED YEAR ENDED DECEMBER 31, MONTHS ENDED MAY 31, ------------------------ 1996 1995 DEC. 31, 1994 1994 ------------- --------- --------------- ------------ Cayman Islands $ (446) $ --- $ --- $ --- United States 3,006 (21,412) (23,197) 33,869 Foreign - other 18,385 38,012 363 (56,973) ------------- --------- --------------- ------------ $ 20,945 $ 16,600 $ (22,834) $ (23,104) ------------- --------- --------------- ------------ Pursuant to the Reorganization in March 1996, Triton, a Cayman Islands company, became the parent holding company of TEC, a Delaware Corporation. As a result, the Company's corporate domicile became the Cayman Islands. The components of the provision for income taxes on continuing operations were as follows: SEVEN YEAR ENDED YEAR ENDED DECEMBER 31, MONTHS ENDED MAY 31, ---------------------- 1996 1995 DEC. 31, 1994 1994 ----------- --------- --------------- ------------ Current: Cayman Islands $ --- $ --- $ --- $ --- United States (172) 627 71 (8) Foreign - other 5,427 3,988 (844) 3,696 ----------- --------- --------------- ------------ Total current 5,255 4,615 (773) 3,688 ----------- --------- --------------- ------------ Deferred: Cayman Islands --- --- --- --- United States (23,489) (12,797) (61) (9,426) Foreign - other 15,374 18,241 4,630 (798) ----------- --------- --------------- ------------ Total deferred (8,115) 5,444 4,569 (10,224) ----------- --------- --------------- ------------ Total $ (2,860) $ 10,059 $ 3,796 $ (6,536) ----------- --------- --------------- ------------ A reconciliation of the differences between the Company's applicable statutory tax rate and the Company's effective income tax rate follows: YEAR ENDED DECEMBER 31, SEVEN YEAR ENDED --------------------- MONTHS ENDED MAY 31, 1996 1995 DEC. 31, 1994 1994 ------- ------- ------------- ---------- Tax provision at statutory tax rate 0.0 % 35.0 % 35.0 % 35.0 % Increase (decrease) resulting from: Net change in valuation allowance (111.6) % (201.6) % (103.8) % (4.4) % Recognition of outside basis adjustments (20.3) % (107.6) % 84.2 % --- % Foreign items without tax benefit 25.8 % 23.9 % (10.7) % (18.8) % Income tax rate changes --- % 16.9 % --- % 12.0 % Income subject to tax in excess of statutory rate 58.4 % --- % --- % --- % Branch loss recapture/Subpart F --- % 97.1 % --- % --- % Current year change in NOL/credit carryforwards (59.2) % 51.2 % (15.6) % --- % Temporary differences: Oil and gas basis adjustments 80.6 % 116.4 % (14.2) % --- % Reimbursement of pre-commerciality costs 10.9 % 30.5 % --- % --- % Other 1.8 % (1.2) % 8.5 % 4.5 % ------ -- ------- -- ------- -- ------- -- (13.6) % 60.6 % (16.6) % 28.3 % ------ -- ------- -- ------- -- ------- -- The components of the net deferred tax asset and liability are as follows: DECEMBER 31, 1996 DECEMBER 31, 1995 --------------------------------- ---------------------------------- OTHER OTHER U.S. COLOMBIA FOREIGN U.S. COLOMBIA FOREIGN ---------- ---------- --------- ----------- --------- ---------- Deferred tax asset: Net operating loss carryforwards $ 98,555 $ 9,540 $ 2,347 $ 88,426 $ 4,631 $ 3,619 Depreciable/depletable property 1,558 --- --- 5,523 --- --- Credit carryforwards 2,054 --- --- 3,046 --- --- Reserves 1,259 --- --- 1,664 --- --- Other 792 --- --- 2,670 --- 28 ---------- ---------- --------- ----------- --------- ---------- Gross deferred tax asset 104,218 9,540 2,347 101,329 4,631 3,647 Valuation allowances (30,657) --- --- (54,046) --- --- ---------- ---------- --------- ----------- --------- ---------- Net deferred tax asset 73,561 9,540 2,347 47,283 4,631 3,647 ---------- ---------- --------- ----------- --------- ---------- Deferred tax liability: Depreciable/depletable property --- (50,874) (6,444) --- (30,069) (8,106) WTI benchmark call options (2,145) --- --- --- --- --- ---------- ---------- --------- ----------- --------- ---------- Net deferred tax asset (liability) 71,416 (41,334) (4,097) 47,283 (25,438 (4,459) Less current deferred tax asset (liability) --- --- --- --- --- --- ---------- ---------- --------- ----------- --------- ---------- Noncurrent deferred tax asset (liability) $ 71,416 $ (41,334) $ (4,097) $ 47,283 $ (25,438) $ (4,459) ---------- ---------- --------- ----------- --------- ---------- At December 31, 1996, the Company had net operating loss ("NOL") and depletion carryforwards for U.S. tax purposes of $230.7 million and $6.8 million, respectively. In addition, at December 31, 1996, certain subsidiaries had separate return limitation year ("SRLY") operating loss and depletion carryforwards of $50.9 million and $13.5 million, respectively, which are available to offset only the future taxable income of those subsidiaries. The depletion carryforwards are available indefinitely. The NOL and SRLY operating loss carryforwards expire from 1997 through 2012 as follows: NOLS SRLYS EXPIRING EXPIRING BY YEAR BY YEAR --------- --------- May 1997 $ --- $ 10,740 May 1998 10,939 8,964 May 1999 8,809 8,437 May 2000 7,315 13,066 May 2001 20,713 9,675 May 2002 22,670 32 May 2003 - May 2012 160,226 --- --------- --------- $ 230,672 $ 50,914 --------- --------- The deferred tax valuation allowance was reduced by $23.4 million in 1996 due to changes in expectations of future U.S. taxable income resulting from improvements in anticipated operating results. The remaining valuation allowance is primarily attributable to SRLY operating losses that are currently not realizable due to the lack of potential future income in the applicable subsidiaries, and the expectation that other tax credits will expire without being utilized. Furthermore, changes in the timing or nature of actual or anticipated business transactions, projections, organizational changes, and income tax laws may give rise to significant adjustments to the Company's deferred tax expense or benefit that may be reported in the future. If certain changes in the Company's ownership should occur, there would be an annual limitation on the amount of NOL carryforwards that can be utilized. To the extent a change in ownership does occur, the limitation is not expected to materially impact the utilization of such carryforwards. 13. EMPLOYEE BENEFITS PENSION PLANS The Company has a defined benefit pension plan covering substantially all employees in the United States. The benefits are based on years of service and the employee's final average monthly compensation. Contributions are intended to provide for benefits attributed to past and future services. The Company also has a Supplemental Executive Retirement Plan ("SERP") that is unfunded and provides supplemental pension benefits to a select group of management and key employees. The funding status of the plans follows: DECEMBER 31, 1996 DECEMBER 31, 1995 ------------------- -------------------- DEFINED DEFINED BENEFIT SERP BENEFIT SERP PLAN PLAN PLAN PLAN --------- -------- ---------- -------- Actuarial present value of benefit obligations: Vested benefit obligations $ 3,748 $ 4,079 $ 3,632 $ 3,849 --------- -------- ---------- -------- Accumulated benefit obligations $ 4,037 $ 4,079 $ 3,844 $ 3,849 --------- -------- ---------- -------- Projected benefit obligations $ 4,849 $ 5,288 $ 4,513 $ 4,966 Plan assets at fair value, primarily listed stocks and United States government securities 4,790 --- 4,326 --- --------- -------- ---------- -------- Unfunded projected benefit obligations 59 5,288 187 4,966 Unrecognized net gain (loss) 2 (46) (54) (283) Prior service cost not yet recognized in net periodic pension cost (653) (144) (709) (155) Unrecognized net asset (liability) at adoption 11 (1,456) 13 (1,624) Adjustment required to recognize minimum liability --- 437 --- 945 --------- -------- ---------- -------- Accrued (prepaid) pension cost $ (581) $ 4,079 $ (563) $ 3,849 --------- -------- ---------- -------- A summary of the components of pension expense follows: SEVEN YEAR ENDED YEAR ENDED DECEMBER 31, MONTHS ENDED MAY 31, ------------------------- 1996 1995 DEC. 31, 1994 1994 --------- ------- --------------- ------------ Service cost - benefits earned during the period $ 767 $ 780 $ 454 $ 733 Interest cost on projected benefit obligation 736 653 344 553 Actual return on plan assets (387) (849) 219 111 Net amortization and deferral 244 793 (256) (173) --------- ------- --------------- ------------ $ 1,360 $1,377 $ 761 $ 1,224 --------- ------- --------------- ------------ The projected benefit obligations at December 31, 1996 and 1995, assume a discount rate of 8% and a rate of increase in compensation expense of 5%. The expected long-term rate of return on assets is 9% for the defined benefit plan. EMPLOYEE STOCK OWNERSHIP PLAN Effective January 1, 1994, the Company amended and restated the employee stock ownership plan to form a 401(k) plan (the "plan"). The Company recognizes expense relating to the plan based on actual amounts contributed since the inception of the plan. The Company used the shares allocated method prior to the January 1, 1994 amendment. 14. SHAREHOLDERS' EQUITY PREFERENCE SHARES In connection with the acquisition of the minority interest in Triton Europe, the Company designated a series of 550,000 preferred shares (522,460 shares issued) as 5% preferred stock, no par value, with a stated value of $34.41 per share. Pursuant to the Reorganization, Triton converted each share of 5% preferred stock into one 5% preference share, par value $.01. Each share of the Company's 5% preference shares is convertible into one ordinary share, subject to adjustment in certain events. The 5% preference shares are convertible any time on or after October 1, 1994, and bear a fixed cumulative cash dividend of 5% per annum payable semi-annually on March 30 and September 30, commencing September 30, 1994. The Company may, at its option, redeem the preference shares, in whole or in part, at any time on or after March 30, 1998, or at any time there are fewer than 133,005 preference shares outstanding. If not converted or redeemed earlier, each 5% preference share will be redeemed on March 30, 2004, either for cash, or at the option of the Company, for the Company's ordinary shares. At December 31, 1996 and 1995, 247,469 and 410,017 preference shares were outstanding, respectively. ORDINARY SHARES Changes in issued ordinary shares were as follows: SEVEN MONTHS ENDED YEAR ENDED YEAR ENDED DECEMBER 31, DEC. 31, MAY 31, ------------------------- 1996 1995 1994 1994 ------------- ---------- ------------ ---------- Balance at beginning of period 35,927,279 35,577,009 35,519,103 35,231,142 Exercise of employee stock options and debentures 258,333 237,875 57,858 287,961 Conversion of 5% preference shares 162,548 112,395 48 --- Other, net (5,979) --- --- --- ------------- ---------- ------------ ---------- Balance at end of period 36,342,181 35,927,279 35,577,009 35,519,103 ------------- ---------- ------------ ---------- Changes in ordinary shares held in treasury were as follows: SEVEN MONTHS ENDED YEAR ENDED YEAR ENDED DECEMBER 31, DEC. 31, MAY 31, ------------------------ 1996 1995 1994 1994 ----------- -------- ------------- ------- Balance at beginning of period 26,635 45,837 54,354 57,483 Purchase of treasury shares 91 89 98 149 Transfer of shares to employee benefit plans (10,797) (19,291) (8,615) (3,278) Retirement of treasury shares (15,889) --- --- --- ----------- -------- ------------- ------- Balance at end of period 40 26,635 45,837 54,354 ----------- -------- ------------- ------- 15. STOCK COMPENSATION PLANS STOCK OPTION PLANS Options to purchase ordinary shares of the Company may be granted to officers and employees under various stock option plans. The exercise price of each option equals the market price of the Company's ordinary shares on the date of grant. Grants generally become exercisable in 25% cumulative annual increments beginning one year from the date of issuance and expire during a period between 5 to 10 years after the date of grant, depending on terms of the grant. Pursuant to the 1992 stock option plan, each non-employee director receives an option to purchase 15,000 shares each year. These grants become exercisable in 33% cumulative annual increments beginning one year from the date of issuance and expire at the end of 10 years. At December 31, 1996 and 1995, shares available for grant were 731,090 and 624,165, respectively. A summary of the status of the Company's stock option plans is presented below: DECEMBER 31,1996 DECEMBER 31, 1995 ------------------------- ----------------------- WEIGHTED WEIGHTED AVERAGE AVERAGE EXERCISE EXERCISE SHARES PRICE SHARES PRICE ------------- --------- ------------- --------- Outstanding at beginning of year 3,177,304 $ 35.49 3,074,854 $ 33.80 Granted 971,000 47.97 373,500 49.33 Exercised (216,333) 30.40 (237,875) 35.30 Canceled (77,925) 40.74 (33,175) 35.62 ------------- ------------- Outstanding at end of year 3,854,046 38.81 3,177,304 35.49 ------------- ------------- Options exercisable at yearend 2,042,492 1,449,424 Weighted average fair value per share of options granted during the year $ 19.89 $ 20.75 DECEMBER 31, 1994 MAY 31, 1994 ---------------------- --------------------- WEIGHTED WEIGHTED AVERAGE AVERAGE EXERCISE EXERCISE SHARES PRICE SHARES PRICE ---------- --------- ---------- --------- Outstanding at beginning of year 2,666,545 $ 33.52 1,721,406 $ 34.48 Granted 544,500 34.11 1,414,800 31.95 Exercised (48,691) 9.22 (133,411) 9.98 Canceled (87,500) 41.08 (336,250) 41.16 ---------- ---------- Outstanding at end of year 3,074,854 33.80 2,666,545 33.52 ---------- ---------- Options exercisable at yearend 873,551 563,741 Weighted average fair value per share of options granted during the year The following table summarizes information about stock options outstanding at December 31, 1996: OPTIONS OUTSTANDING OPTIONS EXERCISABLE -------------------------------------- ------------------------- WEIGHTED RANGE AVERAGE WEIGHTED WEIGHTED OF NUMBER REMAINING AVERAGE NUMBER AVERAGE EXERCISE OUTSTANDING AT CONTRACTUAL EXERCISE EXERCISABLE AT EXERCISE PRICES DEC. 31, 1996 LIFE PRICE DEC. 31, 1996 PRICE - -------------- -------------- ----------- --------- --------------- --------- 8.38 - 19.88 68,156 3.7 years $ 11.00 68,156 $ 11.00 28.50 - 39.63 2,107,440 6.9 years 33.11 1,495,586 33.36 40.00 - 48.38 899,250 6.6 years 42.47 374,750 41.88 50.20 - 57.38 779,200 9.0 years 52.44 104,000 51.55 ----------- ------------ 3,854,046 2,042,492 ----------- ------------ CONVERTIBLE DEBENTURE PLAN The Company has a convertible debenture plan under which key management personnel and others may purchase debentures that are convertible into ordinary shares of the Company. The aggregate number of ordinary shares issuable upon conversion of the debentures cannot exceed 1,000,000 shares, subject to adjustment in certain events. Each debenture represents an unsecured, subordinated obligation due in 10 years and may be redeemed after three years at a redemption price of 120% of the principal amounts. The debentures outstanding at December 31, 1996, bear interest at the prime rate. The participants in the plan purchased debentures by delivery of promissory notes to the Company. The promissory notes are secured by the debentures that are held as security by the Company, are due on the earlier of 10 years from the date of issue or termination of employment and require annual interest payments equal to prime plus 1/8%. The debentures are reflected as a noncurrent liability, net of the related promissory notes, in the Consolidated Balance Sheets as follows: DECEMBER 31, --------------------- 1996 1995 ---------- --------- Convertible debentures due employees $ 15,491 $ 16,969 Promissory notes (15,491) (16,969) ---------- --------- $ --- $ --- ---------- --------- A summary of the status of the Company's convertible debenture plan is presented below: DECEMBER 31, 1996 DECEMBER 31, 1995 DECEMBER 31, 1994 ---------------------- --------------------- ------------------ WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE ----------- --------- ---------- --------- -------- --------- Outstanding at beginning of year 500,000 $ 33.94 250,000 $ 25.13 259,167 $ 24.52 Granted --- --- 250,000 42.75 --- --- Exercised (42,000) 35.20 --- --- (9,167) 8.00 ------------ ---------- -------- Outstanding at yearend 458,000 33.82 500,000 33.94 250,000 25.13 ------------ ---------- -------- Options exercisable at yearend 458,000 250,000 --- Weighted average fair value per share of options granted during the year --- $ 19.45 MAY 31, 1994 -------------------- WEIGHTED AVERAGE EXERCISE SHARES PRICE --------- --------- Outstanding at beginning of year 163,717 $ 11.64 Granted 250,000 25.13 Exercised (154,550) 11.86 --------- Outstanding at yearend 259,167 24.52 --------- Options exercisable at yearend 9,167 Weighted average fair value per share of options granted during the year The following table summarizes information about convertible debentures outstanding at December 31, 1996: OPTIONS OUTSTANDING OPTIONS EXERCISABLE --------------------------------------- -------------------------- WEIGHTED RANGE AVERAGE WEIGHTED WEIGHTED OF NUMBER REMAINING AVERAGE NUMBER AVERAGE EXERCISE OUTSTANDING AT CONTRACTUAL EXERCISE EXERCISABLE AT EXERCISE PRICES DEC. 31, 1996 LIFE PRICE DEC. 31, 1996 PRICE - --------- --------------- ----------- --------- --------------- --------- 25.13 232,000 7.3 years $ 25.13 232,000 $ 25.13 42.75 226,000 8.3 years 42.75 226,000 42.75 EMPLOYEE STOCK PURCHASE PLAN The Company has an employee stock purchase plan that provides for the award of up to 100,000 ordinary shares to key officers and employees. At December 31, 1996 and 1995, shares available for grant were 49,417 and 20,124, respectively. Under the terms of the plan, employees can choose each semi-annual period to have up to 15% of their annual gross or base compensation withheld to purchase the Company's ordinary shares. The purchase price of the stock is 85% of the lower of its beginning of period or end of period market price. Under the plan, the Company sold 22,633 shares and 21,314 shares to employees for the years ended December 31, 1996 and 1995, respectively. The Company applies Opinion 25 in accounting for its plans. Accordingly, no compensation cost has been recognized for its fixed stock option plans, convertible debenture plan, and its stock purchase plan. Had the Company elected to recognize compensation expense consistent with the fair value-based methodology in SFAS 123, the Company's net income and earnings per share would have been reduced by $4.2 million or $0.09 per share in 1996, and $2.6 million or $0.05 per share in 1995. The fair value of each option or debenture granted was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in 1996 and 1995: dividend yield of 0%; expected volatility of 26.9% and 27.8%, respectively; risk-free interest rate of approximately 6%; and expected life of five to seven years. SHAREHOLDER RIGHTS PLAN The Company has adopted a Shareholder Rights Plan pursuant to which preference share rights attach to all ordinary shares at the rate of one right for each ordinary share. Generally, the rights become exercisable only if a person acquires beneficial ownership of 15% or more of the Company's ordinary shares or announces a tender offer for 15% or more of the ordinary shares. If, among other events, any such person becomes the beneficial owner of 15% or more of the Company's ordinary shares, each right not owned by such person generally becomes the right to purchase such number of ordinary shares of the Company, equal to the number obtained by dividing the right's exercise price (currently $120) by 50% of the market price of the ordinary shares on the date of the first occurrence. In addition, if the Company is subsequently merged or certain other extraordinary business transactions are consummated, each right generally becomes a right to purchase such number of shares of common stock of the acquiring person, which is equal to the amount obtained by dividing the right's exercise price by 50% of the market price of the common stock on the date of the first occurrence. The rights will expire on May 22, 2005, unless such expiration date is extended or unless the rights are earlier redeemed or exchanged by the Company. At any time prior to a person acquiring beneficial ownership of 15% or more of the Company's ordinary shares, the Company may redeem the rights in whole, but not in part, at a price of $.01 per right. STOCK APPRECIATION RIGHTS PLAN The Company has a stock appreciation rights ("SARs") plan which authorizes the granting of SARs to non-employee directors of the Company. Upon exercise, SARs allow the holder to receive the difference between the SARs' exercise price and the fair market value of the ordinary shares covered by SARs on the exercise date and expire at the earlier of 10 years or a date based on the termination of the holder's membership on the board of directors. At December 31, 1996, SARs covering 25,000 ordinary shares, with an exercise price of $8 per share, were outstanding. 16. FAIR VALUE OF FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CREDIT RISK CONCENTRATIONS FAIR VALUE OF FINANCIAL INSTRUMENTS At December 31, 1996 and 1995, the Company's financial instruments included cash, cash equivalents, short-term receivables, marketable securities, long-term receivables, short-term and long-term debt and financial market transactions. The fair value of cash, cash equivalents, short-term receivables and short-term debt approximated carrying values because of the short maturities of these instruments. The fair values of the Company's marketable securities, long-term receivables and financial market transactions, based on broker quotes, quoted market prices and discounted cash flows approximated the carrying values. The estimated fair value of long-term debt, based on quoted market prices and market data for similar instruments, was $433 million and $396 million at December 31, 1996 and 1995, respectively. RISK MANAGEMENT Oil and natural gas sold by the Company are normally priced with reference to a defined benchmark, such as light sweet crude oil traded on the New York Mercantile Exchange. Actual prices received vary from the benchmark depending on quality and location differentials. It is the Company's policy to use financial market transactions with credit-worthy counterparties from time to time primarily to reduce risk associated with the pricing of a portion of the oil and natural gas that it sells. The policy is structured to underpin the Company's planned revenues and results of operations. The Company may also enter into financial market transactions to benefit from its assessment of the future prices of its production relative to other benchmark prices. There can be no assurance that the use of financial market transactions will not result in losses. With respect to the sale of oil to be produced by the Company, the Company has used a combination of swaps, options and collars to establish a minimum weighted average WTI benchmark price of $19.58 per barrel for an aggregate of 1.5 million barrels of production during the period from January through June 1997. As a result, to the extent WTI prices exceed the minimum WTI benchmark price during each month within the period, the Company will be able to sell its production at the higher market price, and to the extent that WTI prices are below the minimum WTI benchmark price, the Company will be able to realize prices related to the minimum WTI benchmark price on its hedged production. In anticipation of entering into a forward oil sale, the Company purchased WTI benchmark call options to retain the ability to benefit from future WTI price increases above a weighted average price of $20.42 per barrel. The volumes and expiration dates on the call options coincide with the volumes and delivery dates of the forward oil sale, which has delivery terms of 58,425 barrels per month through March 1997 and 254,136 barrels per month from April 1997 through March 2000. During the years ended December 31, 1996 and 1995, the Company recorded an unrealized gain of $11 million and an unrealized loss of $4.2 million, respectively, in other income, net related to the change in the fair market value of the call options. Future fluctuations in the fair market value of the call options will continue to affect other income as noncash adjustments. During the year ended December 31, 1996, markets provided the Company the opportunity to realize WTI benchmark oil prices on average $4.68 per barrel above the WTI benchmark oil price the Company set as part of its 1996 annual plan. As a result of financial and commodity market transactions settled during the year ended December 31, 1996, the Company's risk management program resulted in an average net realization of approximately $1.21 per barrel lower than if the Company had not entered into such transactions. CONCENTRATION OF CREDIT RISK Financial instruments that are potentially subject to concentrations of credit risk consist of cash equivalents, marketable securities, receivables and financial market transactions. The Company places its cash equivalents, marketable securities and financial market transactions with high credit-quality financial institutions. The Company believes the risk of incurring losses related to credit risk is remote. Triton Colombia sells its crude oil production from the Cusiana and Cupiagua fields through an agreement with a third party to approximately 10 to 15 refineries located primarily in the United States. The Company does not believe that the loss of any single customer or a termination of the agreement with the third party would have a long-term material, adverse effect on its operations. 17. OTHER INCOME (EXPENSE), NET Other income (expense), net is summarized as follows: SEVEN YEAR ENDED YEAR ENDED DECEMBER 31, MONTHS ENDED MAY 31, ----------------------- 1996 1995 DEC. 31, 1994 1994 -------- -------- --------------- ----------- Change in fair market value of WTI benchmark call options $ 10,987 $(4,171) $ --- $ --- Gain on sale of shareholdings in Crusader 10,417 --- --- --- Proceeds from legal settlements 7,624 7,222 --- --- Loss provisions (3,193) (1,058) --- --- Gain on the sale of Triton France --- 3,496 --- --- Gain on early redemption of Crusader's convertible notes --- 2,899 --- --- Gain on sale of U.S. working interest properties --- --- --- 7,028 Gain on sale of Aero Services International Inc.'s common stock --- --- --- 1,500 Foreign exchange gain (loss) (561) 1,874 383 252 Equity in earnings (loss) of affiliates, net 118 (2,249) (4,102) 645 Other 1,969 1,372 441 1,251 --------- -------- ---------- ----------- $ 27,361 $ 9,385 $ (3,278) $ 10,676 --------- -------- ---------- ----------- 18. WRITEDOWN OF ASSETS Writedown of assets are summarized as follows: SEVEN YEAR ENDED YEAR ENDED DECEMBER 31, MONTHS ENDED MAY 31, ----------------------- 1996 1995 DEC. 31, 1994 1994 -------- --------- -------------- ----------- Evaluated oil and gas properties $ --- $ --- $ 984 $ 44,123 Unevaluated oil and gas properties 39,963 --- --- 251 Inventory --- --- --- 1,064 Investments and other assets 2,997 --- --- 316 -------- -------- -------------- ----------- $ 42,960 $ --- $ 984 $ 45,754 -------- -------- -------------- ----------- In 1996, the Company's oil and gas properties and other assets in Argentina were written down $43 million following a review of technical information that indicated the acreage portfolio did not meet the Company's exploration objectives. During fiscal 1994, the carrying amounts of the Company's evaluated oil properties in France were written down by $43.2 million through application of the ceiling limitation prescribed by the Securities and Exchange Commission principally as a result of a temporary drop in oil prices and a downward revision in estimated reserves. 19. STATEMENTS OF CASH FLOWS Supplemental disclosures of cash payments and noncash investing and financing activities follows: SEVEN YEAR ENDED YEAR ENDED DECEMBER 31, MONTHS ENDED MAY 31, ------------------------ 1996 1995 DEC. 31, 1994 1994 ------------ ------ -------------- ----------- Cash paid during the year for: Interest (net of amount capitalized) $ --- $ --- $ --- $ --- Income taxes 200 920 5,557 222 Noncash investing and financing activities: Preferred stock issued for purchase of Triton Europe minority interest --- --- --- 17,978 Conversion of preferred stock into common stock 5,594 3,867 --- --- Property and equipment exchanged for a long-term note receivable --- 650 --- 1,980 20. CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS Certain statements in this report, including statements of the Company's and management's expectations, intentions, plans and beliefs, including those contained in or implied by "Management's Discussion and Analysis of Financial Condition and Results of Operations" and these Notes to Consolidated Financial Statements, are forward-looking statements, as defined in Section 21D of the Securities Exchange Act of 1934, that are dependent on certain events, risks and uncertainties that may be outside the Company's control. These forward-looking statements include statements of management's plans and objectives for the Company's future operations and statements of future economic performance; information regarding drilling schedules, expected or planned production or transportation capacity, the future construction or upgrades of pipelines (including costs), when the Cusiana and Cupiagua fields might become self-financing, future production of the Cusiana and Cupiagua fields, the negotiation of a gas-sales contract and commencement of production in Malaysia-Thailand, the Company's capital budget and future capital requirements, the Company's meeting its future capital needs, the amount by which production from the Cusiana and Cupiagua fields may increase or when such increased production may commence, the Company's realization of its deferred tax asset, the level of future expenditures for environmental costs, the outcome of regulatory and litigation matters and proven oil and gas reserves and discontinued future net cash flows therefrom; and the assumptions described in this report underlying such forward-looking statements. Actual results and developments could differ materially from those expressed in or implied by such statements due to a number of factors, including those described in the context of such forward-looking statements, as well as those presented below. CERTAIN FACTORS RELATING TO THE OIL AND GAS INDUSTRY The Company's strategy is to focus its exploration activities on what the Company believes are relatively high-potential prospects. No assurance can be given that these prospects contain significant oil and gas reserves or that the Company will be successful in its exploration activities thereon. The Company follows the full cost method of accounting for exploration and development of oil and gas reserves whereby all acquisition, exploration and development costs are capitalized. Costs related to acquisition, holding and initial exploration of licenses in countries with no proved reserves are initially capitalized, including internal costs directly identified with acquisition, exploration and development activities. The Company's exploration licenses are periodically assessed for impairment on a country-by-country basis. If the Company's investment in exploration licenses within a country where no proved reserves are assigned is deemed to be impaired, the licenses are written down to estimated recoverable value. If the Company abandons all exploration efforts in a country where no proved reserves are assigned, all exploration costs associated with the country are expensed. The Company's assessments of whether its investment within a country is impaired and whether exploration activities within a country will be abandoned are made from time to time based on its review and assessment of drilling results, seismic data and other information it deems relevant. Due to the unpredictable nature of exploration drilling activities, the amount and timing of impairment expense are difficult to predict with any certainty. The markets for oil and natural gas historically have been volatile and are likely to continue to be volatile in the future. Oil and natural-gas prices have been subject to significant fluctuations during the past several decades in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign government regulations, political conditions in the Middle East and other production areas, the foreign supply of oil and natural gas, the price and availability of alternative fuels, and overall economic conditions. It is impossible to predict future oil and gas price movements with any certainty. The Company's oil and gas business is also subject to all of the operating risks normally associated with the exploration for and production of oil and gas, including, without limitation, blowouts, cratering, pollution, earthquakes, labor disruptions and fires, each of which could result in substantial losses to the Company due to injury or loss of life and damage to or destruction of oil and gas wells, formations, production facilities or other properties. In accordance with customary industry practices, the Company maintains insurance coverage limiting financial loss resulting from certain of these operating hazards. Losses and liabilities arising from uninsured or underinsured events would reduce revenues and increase costs to the Company. There can be no assurance that any insurance will be adequate to cover losses or liabilities. The Company cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase. The Company's oil and gas business is also subject to laws, rules and regulations in the countries in which it operates, which generally pertain to production control, taxation, environmental and pricing concerns, and other matters relating to the petroleum industry. Many jurisdictions have at various times imposed limitations on the production of natural gas and oil by restricting the rate of flow for oil and natural-gas wells below their actual capacity. There can be no assurance that present or future regulation will not adversely affect the operations of the Company. The Company is subject to extensive environmental laws and regulations. These laws regulate the discharge of oil, gas or other materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of such materials at various sites. The Company does not believe that its environmental risks are materially different from those of comparable companies in the oil and gas industry. Nevertheless, no assurance can be given that environmental laws and regulations will not, in the future, adversely affect the Company's consolidated results of operations, cash flows or financial position. Pollution and similar environmental risks generally are not fully insurable. CERTAIN FACTORS RELATING TO INTERNATIONAL OPERATIONS The Company derives substantially all of its consolidated revenues from international operations. Risks inherent in international operations include loss of revenue, property and equipment from such hazards as expropriation, nationalization, war, insurrection and other political risks; trade protection measures; 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 other companies. Other risks inherent in international operations are the possibility of realizing economic currency-exchange losses when transactions are completed in currencies other than U.S. dollars and the Company's ability to freely repatriate its earnings under existing exchange control laws. To date, the Company's international operations have not been materially affected by these risks. COMPETITION The Company encounters strong competition from major oil companies (including government-owned companies), independent operators and other companies for favorable oil and gas concessions, licenses, production-sharing contracts and leases, drilling rights and markets. Additionally, the governments of certain countries in which the Company operates may from time to time give preferential treatment to their nationals. The oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. MARKETS Crude oil, natural gas, condensate, and other oil and gas products generally are sold to other oil and gas companies, government agencies and other industries. The availability of ready markets for oil and gas that might be discovered by the Company and the prices obtained for such oil and gas depend on many factors beyond the Company's control, including the extent of local production and imports of oil and gas, the proximity and capacity of pipelines and other transportation facilities, fluctuating demands for oil and gas, the marketing of competitive fuels, and the effects of governmental regulation of oil and gas production and sales. Pipeline facilities do not exist in certain areas of exploration and, therefore, any actual sales of discovered oil or gas might be delayed for extended periods until such facilities are constructed. CERTAIN FACTORS RELATING TO COLOMBIA The Company is a participant in significant oil and gas discoveries located in the Llanos Basin in the foothills of the Andes Mountains, approximately 160 kilometers (100 miles) northeast of Bogota, Colombia. The Company owns interests in three contiguous areas known as the Santiago de las Atalayas ("SDLA"), Tauramena and Rio Chitamena contract areas. Well results to date indicate that significant oil and gas deposits lie across the Cusiana and Cupiagua fields. Development of reserves in the Cusiana and Cupiagua fields will take more than one year and require additional drilling and extensive production facilities, which in turn will require significant additional capital expenditures, the ultimate amount of which cannot be predicted. Pipelines connect the major producing fields in Colombia to export facilities and to refineries. These pipelines are in the process of being upgraded and expanded to accommodate production from the Cusiana and Cupiagua fields. Guerrilla activity in Colombia has from time to time disrupted the operation of oil and gas projects and increased costs. Although the Colombian government, the Company and its partners have taken steps to improve security and improve relations with the local population, there can be no assurance that attempts to reduce or prevent guerrilla activity will be successful or that such activity will not disrupt operations in the future. Colombia is among several nations whose progress in stemming the production and transit of illegal drugs is subject to annual certification by the President of the United States. In 1997, the President of the United States announced that Colombia would neither be certified nor granted a national interest waiver. The consequences of the failure to receive certification generally include the following: all bilateral aid, except anti-narcotics and humanitarian aid, has been or will be suspended; the Export-Import Bank of the United States and the Overseas Private Investment Corporation will not approve financing for new projects in Colombia; U.S. representatives at multilateral lending institutions will be required to vote against all loan requests from Colombia, although such votes will not constitute vetoes; and the President of the United States and Congress retain the right to apply future trade sanctions. Each of these consequences of the failure to receive such certification could result in adverse economic consequences in Colombia and could further heighten the political and economic risks associated with the Company's operations in Colombia. Any changes in the holders of significant government offices could have adverse consequences on the Company's relationship with the Colombian national oil company and the Colombian government's ability to control guerrilla activities and could exacerbate the factors relating to foreign operations discussed above. CERTAIN FACTORS RELATING TO MALAYSIA-THAILAND The Company is a partner in a significant gas exploration project located in the upper Malay Basin in the Gulf of Thailand approximately 450 kilometers northeast of Kuala Lumpur and 750 kilometers south of Bangkok. The Company is a contractor under a production-sharing contract covering Block A-18 of the Malaysia-Thailand Joint Development Area. Well results to date indicate that significant gas deposits lie across four fields within the block. Development of gas production is in the early planning stages but is expected to take several years and require the drilling of additional wells and the installation of production facilities, which will require significant additional capital expenditures, the ultimate amount of which cannot be predicted. Pipelines also will be required to be connected between Block A-18 and ultimate markets. The terms on which any gas produced from the Company's contract area in Malaysia-Thailand may be sold may be affected adversely by the present monopoly gas-purchase and transportation conditions in both Thailand and Malaysia, including the Thai national oil company's monopoly in transportation within Thailand and its territorial waters. LITIGATION The outcome of litigation and its impact on the Company are difficult to predict due to many uncertainties, such as jury verdicts, the application of laws to various factual situations, the actions that may or may not be taken by other parties and the availability of insurance. In addition, in certain situations, such as environmental claims, one defendant may be responsible, or potentially responsible, for the liabilities of other parties. Moreover, circumstances could arise under which the Company may elect to settle claims at amounts that exceed the Company's expected liability for such claims in order to avoid costly litigation. Judgments or settlements could, therefore, exceed any reserves. 21. COMMITMENTS AND CONTINGENCIES Development of the Cusiana and Cupiagua fields ("the Fields"), including drilling and construction of additional production facilities, will require further capital outlays. Further exploration and development activities on Block A-18, as well as exploratory drilling in other countries, also will require substantial capital outlays. The Company's capital budget for the year ending December 31, 1997, is approximately $310 million, excluding capitalized interest, of which approximately $150 million relates to the Fields and capital contributions to OCENSA, $95 million relates to Block A-18, and $65 million relates to the Company's exploration and drilling program in other parts of the world. The Company assisted OCENSA in raising one tranche of debt totaling $65 million in 1996 and may assist OCENSA in raising up to $25 million of additional debt in 1997. Capital requirements for exploration and development relating to Block A-18 are expected to increase significantly into 1998. The Company expects to meet capital needs in the future with a combination of some or all of the following: the Company's revolving credit facility, cash flow from its Colombian operations (including additional proceeds from the 1995 forward oil sale), cash and marketable securities, asset sales, and the issuance of debt and equity securities. The Company's indentures permit the Company to incur total indebtedness (excluding certain permitted indebtedness) of up to 25% of the sum of its indebtedness and market capitalization of its capital stock. As of yearend 1996, the revolving credit facility permitted the Company to incur total indebtedness of up to approximately $630 million. Availability under the credit facility may be more in the future under certain circumstances. During the normal course of business, the Company is subject to the terms of various operating agreements and capital commitments associated with the exploration and development of its oil and gas properties. It is management's belief that such commitments, including the capital requirements in Colombia and Malaysia-Thailand discussed above, will be met without any material, adverse effect on the Company's operations or consolidated financial condition. The Company leases office space, other facilities and equipment under various operating leases expiring through 2011. Total rental expense was $2 million and $1.9 million for the years ended December 31, 1996 and 1995, respectively, $1.3 million for the seven months ended December 31, 1994, and $2.6 million for the year ended May 31, 1994. At December 31, 1996, the minimum payments required over the next five years are as follows: 1997 -- $2.5 million; 1998 - -- $2.3 million; 1999 -- $1.8 million; 2000 -- $.9 million; 2001 -- $.2 million; and thereafter -- $1.2 million. GUARANTEES At December 31, 1996, the Company had guaranteed loans of approximately $4.5 million of a Colombian pipeline company in which the Company has an ownership interest and guaranteed performance of $4.1 million in future exploration expenditures in various countries. These commitments are backed primarily by unsecured letters of credit and bank guarantees. ENVIRONMENTAL MATTERS The Company is subject to extensive environmental laws and regulations. These laws regulate the discharge of oil, gas or other materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of such materials at various sites. Also, the Company remains liable for certain environmental matters that may arise from formerly owned fuel businesses that were involved in the storage, handling and sale of hazardous materials, including fuel storage in underground tanks. The Company believes that the level of future expenditures for environmental matters, including clean-up obligations, is impracticable to determine with a precise and reliable degree of accuracy. Management believes that such costs, when finally determined, will not have a material adverse effect on the Company's operations or consolidated financial condition. LITIGATION The Company and subsidiaries or former subsidiaries of the Company, including Triton Oil and Gas Corportaion ("Triton Oil"), are among numerous defendants in three related lawsuits brought in the Superior Court of the State of California, County of Los Angeles, by (i) National Union Fire Insurance Company ("National Union") and The Restaurant Enterprises Group, (ii) Travelers Indemnity Company ("Travelers") and (iii) the City of Redondo Beach. All three lawsuits arise out of a 1988 tidal wave at King Harbor in Redondo Beach, California. The lawsuits allege, among other things, that the defendants' negligence contributed to the collapse of a hotel and the flooding of a restaurant in the tidal wave. In the case of Triton Oil, the alleged negligence was Triton Oil's drilling of nearby oil wells and alleged resulting ground subsidence, which purportedly lowered the height of the King Harbor breakwater. The Travelers lawsuit asserts damages in excess of $14.6 million, although in a separate lawsuit against the Army Corps of Engineers, the court found damages to be approximately $6.7 million. Of that $6.7 million, Travelers recovered $4 million from the City of Redondo Beach. The National Union lawsuit asserts damages in excess of $4.75 million, although in a separate lawsuit against the Army Corps of Engineers, the court found damages to be approximately $3.7 million. Of that $3.7 million, Travelers recovered $1 million from the City of Redondo Beach. The City of Redondo Beach lawsuit asserts damages in excess of $13.2 million, including indemnity for amounts it paid to settle the foregoing lawsuits and other claims arising out of the flooding. The three lawsuits have been consolidated for trial, which has been set for October 1997. The Company believes that it and its subsidiaries have meritorious defenses and intend to defend the suits vigorously. The Company is also subject to other various litigation matters, none of which is expected to have a material adverse effect on the Company's operations or consolidated financial condition. 22. TRITON ENERGY CORPORATION FINANCIAL INFORMATION Following the Reorganization, TEC ceased filing periodic reports with the Securities and Exchange Commission ("SEC"). TEC's 9 3/4% Notes and 1997 Notes remain outstanding and are fully guaranteed by Triton. The following table sets forth certain summarized financial information of TEC and its subsidiaries: DECEMBER 31, 1996 ------------- Current assets $ 69,783 Noncurrent assets 946,592 ------------- $ 1,016,375 ------------- Current liabilities $ 247,811 Noncurrent liabilities 379,294 Stockholders' equity 389,270 ------------- $ 1,016,375 ------------- YEAR ENDED DECEMBER 31, 1996 -------------- Sales and other operating revenues $ 132,629 Costs and expenses 69,154 -------------- Operating income 63,475 Other income, net 10,889 -------------- Earnings before income taxes and extraordinary item 74,364 Income tax expense 1,518 -------------- Earnings before extraordinary item 72,846 Extraordinary item - extinguishment of debt (1,196) -------------- Net earnings $ 71,650 -------------- Summarized financial information of TEC and its subsidiaries as of and for the year ended December 31, 1995, for the seven months ended December 31, 1994, and for the year ended May 31, 1994, is not presented herewith because such summarized financial information would be identical to the Consolidated Balance Sheet at December 31, 1995 and the Consolidated Statements of Operations for the year ended December 31, 1995, for the seven months ended December 31, 1994 and for the year ended May 31, 1994. 23. GEOGRAPHIC DATA Information about the Company's operations by geographic area follows: MALAYSIA- UNITED COLOMBIA THAILAND FRANCE INDONESIA STATES OTHER CORPORATE ---------- ----------- --------- ----------- -------- --------- ----------- YEAR ENDED DECEMBER 31, 1996: Sales and other operating revenues $ 127,071 $ --- $ --- $ 1,856 $ 5,050 $ --- $ --- Operating profit (loss) 70,874 (509) --- (340) 3,400 (47,158) (23,489) Trade and other receivables 56,647 494 --- 53 --- 3,212 120 Identifiable assets 629,978 113,364 --- 2,592 --- 55,257 113,333 YEAR ENDED DECEMBER 31, 1995: Sales and other operating revenues $ 89,851 $ --- $ 9,206 $ 4,531 $ 3,884 $ --- $ --- Operating profit (loss) 49,086 (239) 1,123 (858) (230) (2,669) (22,897) Trade and other receivables 19,823 366 --- 785 717 730 766 Identifiable assets 487,472 50,867 --- 1,744 23,261 63,159 197,664 SEVEN MONTHS ENDED DECEMBER 31, 1994: Sales and other operating revenues $ 6,249 $ --- $ 9,179 $ 3,174 $ 2,134 $ --- $ --- Operating profit (loss) (192) --- 722 (75) (919) (2,258) (13,224) Trade and other receivables 11,759 --- 3,866 1,257 1,332 667 1,360 Identifiable assets 335,474 21,372 27,038 2,553 32,232 33,477 167,055 YEAR ENDED MAY 31, 1994: Sales and other operating revenues $ 5,911 $ --- $ 17,494 $ 7,186 $ 5,629 $ 6,988 $ --- Operating loss (503) --- (49,734) (4,582) (1,269) (3,332) (21,263) Trade and other receivables 5,508 --- 3,431 1,303 1,336 1,110 1,891 Identifiable assets 237,397 15,764 28,954 3,978 37,091 36,205 256,712 TOTAL --------- YEAR ENDED DECEMBER 31, 1996: Sales and other operating revenues $133,977 Operating profit (loss) 2,778 Trade and other receivables 60,526 Identifiable assets 914,524 YEAR ENDED DECEMBER 31, 1995: Sales and other operating revenues $107,472 Operating profit (loss) 23,316 Trade and other receivables 23,187 Identifiable assets 824,167 SEVEN MONTHS ENDED DECEMBER 31, 1994: Sales and other operating revenues $ 20,736 Operating profit (loss) (15,946) Trade and other receivables 20,241 Identifiable assets 619,201 YEAR ENDED MAY 31, 1994: Sales and other operating revenues $ 43,208 Operating loss (80,683) Trade and other receivables 14,579 Identifiable assets 616,101 Corporate assets were principally cash and cash equivalents, marketable securities, the U.S. deferred tax asset and other fixed assets. Other identifiable assets primarily represented capitalized costs related to the Company's exploration activities in other areas of the world, no one country of which is material. 24. QUARTERLY FINANCIAL DATA (UNAUDITED) QUARTER ---------------------------------------------------------------- FIRST SECOND THIRD FOURTH --------------- -------------- -------------- --------------- YEAR ENDED DECEMBER 31, 1996: Sales and other operating revenues $ 35,781 $ 31,170 $ 30,780 $ 36,246 Gross profit (loss) 19,839 15,885 15,936 (22,937) Net earnings (loss) before extraordinary item 11,351 12,696 19,549 (19,791) Net earnings (loss) 11,351 12,262 18,787 (19,791) Earnings (loss) per ordinary share: Before extraordinary item 0.29 0.34 0.52 (0.53) Net earnings (loss) 0.29 0.33 0.50 (0.53) YEAR ENDED DECEMBER 31, 1995: Sales and other operating revenues $ 19,751 $ 28,504 $ 32,586 $ 26,631 Gross profit 7,013 13,670 15,351 12,954 Net earnings (loss) (1,555) 2,388 1,279 608 Net earnings (loss) per ordinary share (0.06) 0.07 0.03 0.02 Gross profit (loss) consists of sales and other operating revenues less operating expenses, depreciation, depletion and amortization, and writedowns pertaining to operating assets. In the fourth quarter of 1996, the Company recorded a writedown of $43 million related to oil and gas properties and other assets in Argentina. In the fourth quarter of 1995, the Company recorded a loss provision of $1.1 million related to property available for sale, and Crusader recorded a writedown of $3 million (the Company's share - $1.5 million) related to a coal property of its majority-owned affiliate. Also, the Company recorded a charge to deferred tax expense of $2.8 million due to a change in income tax rates in Colombia and a benefit of $8.5 million based on a reduction in the valuation allowance on its deferred U.S. tax asset. 25. OIL AND GAS DATA (UNAUDITED) The following tables provide additional information about the Company's oil and gas exploration and production activities. Equity affiliate amounts reflect only the Company's proportionate interest in Crusader, which was sold in 1996. RESULTS OF OPERATIONS The results of operations for oil- and gas-producing activities, considering direct costs only, follow: UNITED TOTAL COLOMBIA FRANCE INDONESIA STATES OTHER WORLDWIDE ---------- --------- ----------- -------------- --------- ----------- YEAR ENDED DECEMBER 31, 1996: Revenues $ 127,071 $ --- $ 1,856 $ 5,050 $ --- $ 133,977 Costs: Production costs 34,822 --- 1,510 322 --- 36,654 General operating expenses 1,909 --- 553 774 --- 3,236 Depletion 18,515 --- 49 554 --- 19,118 Writedown of assets --- --- --- --- 42,960 42,960 Income taxes 25,766 --- --- --- --- 25,766 ---------- --------- ----------- -------------- --------- ----------- Results of operations $ 46,059 $ --- $ (256) $ 3,400 $(42,960) $ 6,243 ---------- --------- ----------- -------------- --------- ----------- YEAR ENDED DECEMBER 31, 1995: Revenues $ 89,851 $ 9,206 $ 4,531 $ 3,884 $ --- $ 107,472 Costs: Production costs 24,942 5,460 4,422 452 --- 35,276 General operating expenses 740 1,061 726 1,030 --- 3,557 Depletion 14,776 1,562 241 1,950 --- 18,529 Writedown of assets --- --- --- --- --- --- Income taxes 17,395 374 --- --- --- 17,769 ---------- --------- ----------- -------------- --------- ----------- Results of operations $ 31,998 $ 749 $ (858) $ 452 $ --- $ 32,341 ---------- --------- ----------- -------------- --------- ----------- SEVEN MONTHS ENDED DECEMBER 31, 1994: Revenues $ 6,249 $ 9,179 $ 3,174 $ 1,919 $ --- $ 20,521 Costs: Production costs 4,290 5,784 2,054 144 --- 12,272 General operating expenses 997 541 897 502 --- 2,937 Depletion 1,184 2,132 298 1,189 --- 4,803 Writedown of assets --- --- --- 984 --- 984 Income taxes 82 318 --- --- --- 400 ---------- --------- ----------- -------------- --------- ----------- Results of operations $ (304) $ 404 $ (75) $ (900) $ --- $ (875) ---------- --------- ----------- -------------- --------- ----------- YEAR ENDED MAY 31, 1994: Revenues $ 5,911 $ 17,252 $ 7,186 $ 4,700 $ 6,190 $ 41,239 Costs: Production costs 4,230 10,347 6,413 2,436 3,200 26,626 General operating expenses 1,267 4,237 3,070 1,044 614 10,232 Depletion 917 9,443 1,363 2,290 2,482 16,495 Writedown of assets --- 43,201 922 --- 251 44,374 Income taxes 8 --- --- --- 195 203 ---------- --------- ----------- -------------- --------- ----------- Results of operations $ (511) $(49,976) $ (4,582) $ (1,070) $ (552) $ (56,691) ---------- --------- ----------- -------------- --------- ----------- Depletion includes depreciation on support equipment and facilities calculated on the unit of production method. The Company's equity share of Crusader's results of operations for oil- and gas-producing activities follows: UNITED AUSTRALIA CANADA STATES OTHER TOTAL ---------- ------- -------- -------- ------- December 31, 1996 $ 1,243 $ --- $ --- $ --- $1,243 ---------- ------- -------- -------- ------- December 31, 1995 $ 2,998 $ 269 $ --- $(1,401) $1,866 ---------- ------- -------- -------- ------- December 31, 1994 $ 1,339 $ 243 $ 36 $(1,662) $ (44) ---------- ------- -------- -------- ------- May 31, 1994 $ 2,904 $ 712 $(1,270) $ --- $2,346 ---------- ------- -------- -------- ------- COSTS INCURRED AND CAPITALIZED COSTS The costs incurred in oil and gas acquisition, exploration and development activities and related capitalized costs follow: MALAYSIA- UNITED TOTAL COLOMBIA THAILAND FRANCE INDONESIA STATES OTHER WORLDWIDE --------- ---------- ------- ---------- ------------- ------- ---------- DECEMBER 31, 1996: Costs incurred: Property acquisition $ --- $ --- $ --- $ --- $ --- $ 600 $ 600 Exploration 18,875 60,955 --- --- --- 33,103 112,933 Development 39,902 470 --- --- --- --- 40,372 Depletion per equivalent barrel of production 2.83 --- --- 0.52 5.59 --- 2.84 Cost of properties at period-end: Unevaluated $ 2,487 $ 97,151 $ --- $ --- $ --- $50,010 $ 149,648 --------- ---------- ------- ---------- ------------- ------- ---------- Evaluated $ 338,955 $ 10,861 $ --- $ --- $ --- $48,630 $ 398,446 --------- ---------- ------- ---------- ------------- ------- ---------- Support equipment and facilities $ 194,116 $ --- $ --- $ --- $ --- $ --- $ 194,116 --------- ---------- ------- ---------- ------------- ------- ---------- Accumulated depletion and depreciation at period-end $ 35,723 $ --- $ --- $ --- $ --- $48,630 $ 84,353 --------- ---------- ------- ---------- ------------- ------- ---------- MALAYSIA- UNITED TOTAL COLOMBIA THAILAND FRANCE INDONESIA STATES OTHER WORLDWIDE --------- ---------- -------- ---------- ------------- ------- ---------- DECEMBER 31, 1995: Costs incurred: Property acquisition $ 1,101 $ --- $ --- $ --- $ --- $ 250 $ 1,351 Exploration 45,961 25,948 --- --- --- 28,480 100,389 Development 48,419 --- --- 299 --- --- 48,718 Depletion per equivalent barrel of production 2.67 --- 3.14 0.95 6.05 --- 2.81 Cost of properties at period-end: Unevaluated $ 59,087 $ 46,282 $ --- $ --- $ 9,202 $58,490 $ 173,061 --------- ---------- -------- ---------- ------------- ------- ---------- Evaluated $ 260,058 $ --- $ --- $ 47,301 $ 190,379 $ 8,667 $ 506,405 --------- ---------- -------- ---------- ------------- ------- ---------- Support equipment and facilities $ 87,289 $ --- $ --- $ --- $ --- $ --- $ 87,289 --------- ---------- -------- ---------- ------------- ------- ---------- Accumulated depletion and depreciation at period-end $ 17,355 $ --- $ --- $ 47,153 $ 180,574 $ 8,667 $ 253,749 --------- ---------- -------- ---------- ------------- ------- ---------- DECEMBER 31, 1994: Costs incurred: Property acquisition $ 9,824 $ --- $ --- $ --- $ --- $ 1,058 $ 10,882 Exploration 21,691 5,151 79 --- --- 7,088 34,009 Development 31,892 --- 5 1 1 --- 31,899 Depletion per equivalent barrel of production 2.57 --- 4.15 1.60 7.04 --- 3.63 Cost of properties at period-end: Unevaluated $ 38,000 $ 20,334 $ 281 $ --- $ 9,202 $31,513 $ 99,330 --------- ---------- -------- ---------- ------------- ------- ---------- Evaluated $ 175,281 $ --- $265,284 $ 44,594 $ 190,396 $ 8,667 $ 684,222 --------- ---------- -------- ---------- ------------- ------- ---------- Support equipment and facilities $ 78,601 $ --- $ --- $ --- $ --- $ --- $ 78,601 --------- ---------- -------- ---------- ------------- ------- ---------- Accumulated depletion at period-end $ 2,645 $ --- $244,264 $ 44,097 $ 178,623 $ 8,667 $ 478,296 --------- ---------- -------- ---------- ------------- ------- ---------- MAY 31, 1994: Costs incurred: Property acquisition $ --- $ 750 $ --- $ --- $ --- $ 94 $ 844 Exploration 24,865 4,775 205 --- --- 12,626 42,471 Development 29,833 --- 3,575 1,050 300 2,022 36,780 Depletion per equivalent barrel of production 1.96 --- 8.97 3.09 6.58 3.60 5.47 Cost of properties at period-end: Unevaluated $ 47,833 $ 15,183 $ 212 $ --- $ 10,094 $23,847 $ 97,169 --------- ---------- -------- ---------- ------------- ------- ---------- Evaluated $ 118,215 $ --- $266,231 $ 47,677 $ 190,033 $ 7,715 $ 629,871 --------- ---------- -------- ---------- ------------- ------- ---------- Support equipment and facilities $ 45,688 $ --- $ --- $ --- $ --- $ --- $ 45,688 --------- ---------- -------- ---------- ------------- ------- ---------- Accumulated depletion at period-end $ 1,461 $ --- $243,084 $ 46,560 $ 176,450 $ 7,715 $ 475,270 --------- ---------- -------- ---------- ------------- ------- ---------- A summary of costs excluded from depletion at December 31, 1996, by year incurred follows: DECEMBER 31, MAY 31, ------------------------------ TOTAL 1996 1995 1994 1994 -------- ------------- ------- ------ -------- Property acquisition $ 1,536 $ 600 $ 250 $ --- $ 686 Exploration 130,625 80,018 38,173 7,662 4,772 Capitalized interest 17,487 10,992 3,981 1,222 1,292 -------- ------------- ------- ------ -------- Total worldwide $149,648 $ 91,610 $42,404 $8,884 $ 6,750 -------- ------------- ------- ------ -------- The Company excludes from its depletion computation property acquisition and exploration cost of unevaluated properties and major development projects in progress. The excluded costs include $97.2 million for Block A-18 in the Malaysia-Thailand Joint Development Area which will become depletable once production begins, currently estimated for early 2000. At this time, the Company is unable to predict either the timing of the inclusion of the remaining costs and the related oil and gas reserves in its depletion computation or their potential future impact on depletion rates. Drilling or other exploration activities are being conducted in each of these cost centers. The Company's equity share of costs incurred by Crusader follows: UNITED AUSTRALIA CANADA STATES OTHER TOTAL ---------- ------- ------- ------ ------- Cost of property acquisition, exploration and development: December 31, 1996 $ 2,105 $ --- $ --- $ --- $ 2,105 ---------- ------- ------- ------ ------- December 31, 1995 $ 1,187 $ 507 $ --- $ 541 $ 2,235 ---------- ------- ------- ------ ------- December 31, 1994 $ 3,557 $ 313 $ 26 $1,028 $ 4,924 ---------- ------- ------- ------ ------- May 31, 1994 $ 2,955 $ 1,099 $ 1,687 $ --- $ 5,741 ---------- ------- ------- ------ ------- Net capitalized costs: December 31, 1995 $ 25,818 $ --- $ --- $ 299 $26,117 ---------- ------- ------- ------ ------- December 31, 1994 $ 28,987 $ 3,889 $ --- $1,340 $34,216 ---------- ------- ------- ------ ------- May 31, 1994 $ 27,001 $ 4,395 $ 3,750 $ --- $35,146 ---------- ------- ------- ------ ------- OIL AND GAS RESERVE DATA The following tables present the Company's estimates of its proved oil and gas reserves. These estimates were prepared by the Company's independent petroleum engineers, DeGolyer and MacNaughton, with respect to all proved reserves in the Cusiana and Cupiagua fields in Colombia and the Company's own petroleum reservoir engineers with respect to all proved reserves in Malaysia-Thailand and the Liebre Field in Colombia. The Company emphasizes that reserve estimates are approximates and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, there can be no assurance that the reserves set forth herein will ultimately be produced nor can there be assurance that the proved undeveloped reserves will be developed within the periods anticipated. Oil reserves are stated in thousands of barrels and gas reserves are stated in millions of cubic feet. As of December 31, 1996, the Company did not have a contract for the sale of gas to be produced from its interest in the Malaysia-Thailand Joint Development Area. In estimating reserves attributable to such interest, the Company assumed that production from the interest would be sold at prices for natural gas derived from what the Company believed to be the most comparable market price at December 31, 1996. There can be no assurance that the price to be provided in any gas contract will be equal to the price used in the Company's calculations. COLOMBIA MALAYSIA-THAILAND FRANCE INDONESIA UNITED STATES ------------------ ----------------- ------- ---------- ------------------ OIL GAS OIL GAS OIL OIL OIL GAS --------- ------- ------- ------- ------- ---------- --------- -------- Proved developed and undeveloped reserves: AS OF MAY 31, 1993 86,216 16,250 --- --- 8,189 951 1,952 21,549 Revisions 3,682 --- --- --- (2,177) 165 23 (1,644) Sales --- --- --- --- (502) --- (1,171) (11,426) Extensions and discoveries 3,173 --- --- --- --- --- --- --- Production (467) --- --- --- (1,053) (441) (156) (1,150) --------- ------- ------- ------- ------- ---------- ---------- -------- AS OF MAY 31, 1994 92,604 16,250 --- --- 4,457 675 648 7,329 Revisions 10,113 (1,529) --- --- 2,301 (87) 14 486 Purchases of minerals in place 2,111 --- --- --- --- --- --- --- Production (435) --- --- --- (514) (186) (66) (618) --------- ------- ------- ------- ------- ---------- ---------- -------- AS OF DECEMBER 31, 1994 104,393 14,721 --- --- 6,244 402 596 7,197 Revisions --- --- --- --- --- 23 119 967 Sales (10,434) --- --- --- (5,746) --- --- --- Extensions and discoveries 32,556 1,127 --- --- --- --- --- --- Production (5,089) (158) --- --- (498) (255) (121) (1,207) --------- ------- ------- ------- ------- ---------- ---------- -------- AS OF DECEMBER 31, 1995 121,426 15,690 --- --- --- 170 594 6,957 Revisions 270 (403) --- --- --- --- --- --- Sales (548) (338) --- --- --- (75) (574) (6,482) Extensions and discoveries 19,900 --- 24,700 871,100 --- --- --- --- Production (5,738) (298) --- --- --- (95) (20) (475) --------- ------- ------- ------- ------- ---------- ---------- -------- AS OF DECEMBER 31, 1996 135,310 14,651 24,700 871,100 --- --- --- --- --------- ------- ------- ------- ------- ---------- ---------- -------- CANADA OTHER TOTAL WORLDWIDE ----------------- ------ ------------------ OIL GAS OIL OIL GAS ------- -------- ------ -------- -------- Proved developed and undeveloped reserves: AS OF MAY 31, 1993 2,686 78,449 --- 99,994 116,248 Revisions --- --- 18 1,711 (1,644) Sales (2,584) (74,928) --- (4,257) (86,354) Extensions and discoveries --- --- --- 3,173 --- Production (102) (3,521) (18) (2,237) (4,671) ------- -------- ------ --------- -------- AS OF MAY 31, 1994 --- --- --- 98,384 23,579 Revisions --- --- --- 12,341 (1,043) Purchases of minerals in place --- --- --- 2,111 --- Production --- --- --- (1,201) (618) ------- -------- ------ --------- -------- AS OF DECEMBER 31, 1994 --- --- --- 111,635 21,918 Revisions --- --- --- 142 967 Sales --- --- --- (16,180) --- Extensions and discoveries --- --- --- 32,556 1,127 Production --- --- --- (5,963) (1,365) ------- -------- ------ --------- -------- AS OF DECEMBER 31, 1995 --- --- --- 122,190 22,647 Revisions --- --- --- 270 (403) Sales --- --- --- (1,197) (6,820) Extensions and discoveries --- --- --- 44,600 871,100 Production --- --- --- (5,853) (773) ------- -------- ------ --------- -------- AS OF DECEMBER 31, 1996 --- --- --- 160,010 885,751 ------- -------- ------ --------- -------- COLOMBIA MALAYSIA-THAILAND FRANCE INDONESIA UNITED STATES TOTAL WORLDWIDE ---------------- ----------------- ------ --------- --------------- --------------- OIL GAS OIL GAS OIL OIL OIL GAS OIL -------- ------ ---- --- ------ --------- -------- ----- --------------- Proved developed reserves at: May 31, 1994 1,237 --- --- --- 4,457 675 648 7,329 7,017 -------- ------ ---- ----- ------ --------- -------- ----- --------------- December 31, 1994 47,789 14,721 --- --- 6,244 402 596 7,197 55,031 -------- ------ ---- ----- ------ --------- -------- ----- --------------- December 31, 1995 65,856 10,515 --- --- --- 170 594 6,957 66,620 -------- ------ ---- ----- ------ --------- -------- ----- --------------- December 31, 1996 67,193 11,146 --- --- --- --- --- --- 67,193 -------- ------ ---- ----- ------ --------- -------- ----- --------------- GAS ------ Proved developed reserves at: May 31, 1994 7,329 ------ December 31, 1994 21,918 ------ December 31, 1995 17,472 ------ December 31, 1996 11,146 ------ The Company's proportional equity interest in Crusader's estimated proved developed and undeveloped oil and gas reserves was as follows: AUSTRALIA CANADA UNITED STATES TOTAL --------- ------ ------------- ----- OIL GAS OIL GAS OIL GAS OIL GAS --------- ------ ------ ----- ------------- --- ----- ------ May 31, 1994 2,574 40,174 963 2,790 48 122 3,585 43,086 --------- ------ ------ ----- ------------- --- ----- ------ December 31, 1994 3,163 59,115 823 1,836 --- --- 3,986 60,951 --------- ------ ------ ----- ------------- --- ----- ------ December 31, 1995 3,319 60,915 --- --- --- --- 3,319 60,915 --------- ------ ------ ----- ------------- --- ----- ------ STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH INFLOWS AND CHANGES THEREIN The following table presents for the net quantities of proved oil and gas reserves a standardized measure of discounted future net cash inflows discounted at an annual rate of 10%. The future net cash inflows were calculated in accordance with Securities and Exchange Commission guidelines. Future cash inflows were computed by applying yearend prices of oil and gas relating to the Company's proved reserves to the estimated yearend quantities of those reserves. As of December 31, 1996, the Company did not have a contract for the sale of gas to be produced from its interest in the Malaysia-Thailand Joint Development Area. In estimating discounted future net cash inflows attributable to such interest, the Company assumed that production from the interest would be sold at prices for natural gas derived from what the Company believed to be the most comparable market price at December 31, 1996. Future price changes were considered only to the extent provided by contractual agreements in existence at yearend. Future production and development costs were computed by estimating those expenditures expected to occur in developing and producing the proved oil and gas reserves at the end of the year, based on yearend costs. The Company emphasizes that the future net cash inflows should not be construed as representative of the fair market value of the Company's proved reserves. The meaningfulness of the estimates is highly dependent upon the accuracy of the assumptions upon which they were used. Actual future cash inflows may vary considerably. MALAYSIA- UNITED TOTAL COLOMBIA THAILAND FRANCE INDONESIA STATES WORLDWIDE -------- ---------- ------- ---------- ------- ---------- DECEMBER 31, 1996: Future cash inflows $3,519,893 $2,530,702 $ --- $ --- $ --- $6,050,595 Future production and development costs 1,283,851 1,188,981 --- --- --- 2,472,832 ---------- ---------- ------- ---------- ------- ---------- Future net cash inflows before income taxes $2,236,042 $1,341,721 $ --- $ --- $ --- $3,577,763 ---------- ---------- ------- ---------- ------- ---------- Future net cash inflows before income taxes discounted at 10% per annum $1,283,158 $ 320,900 $ --- $ --- $ --- $1,604,058 Future income taxes discounted at 10% per annum 290,763 21,100 --- --- --- 311,863 ---------- ---------- ------- ---------- ------- ---------- Standardized measure of discounted future net cash inflows $ 992,395 $ 299,800 $ --- $ --- $ --- $1,292,195 ---------- ---------- ------- ---------- ------- ---------- MALAYSIA- UNITED TOTAL COLOMBIA THAILAND FRANCE INDONESIA STATES WORLDWIDE ----------- ---------- -------- ---------- ------- ---------- DECEMBER 31, 1995: Future cash inflows $ 2,321,424 $ --- $ --- $ 2,909 $19,076 $2,343,409 Future production and development costs 730,139 --- --- 2,250 2,037 734,426 ----------- ---------- -------- ---------- ------- ---------- Future net cash inflows before income taxes $ 1,591,285 $ --- $ --- $ 659 $17,039 $1,608,983 ----------- ---------- -------- ---------- ------- ---------- Future net cash inflows before income taxes discounted at 10% per annum $ 803,665 $ --- $ --- $ 626 $11,150 $ 815,441 Future income taxes discounted at 10% per annum 173,745 --- --- --- --- 173,745 ----------- ---------- -------- ---------- ------- ---------- Standardized measure of discounted future net cash inflows $ 629,920 $ --- $ --- $ 626 $11,150 $ 641,696 ----------- ---------- -------- ---------- ------- ---------- DECEMBER 31, 1994: Future cash inflows $ 1,764,939 $ --- $105,523 $ 6,677 $20,072 $1,897,211 Future production and development costs 440,227 --- 59,558 5,645 1,845 507,275 ----------- ---------- -------- ---------- ------- ---------- Future net cash inflows before income taxes $ 1,324,712 $ --- $ 45,965 $ 1,032 $18,227 $1,389,936 ----------- ---------- -------- ---------- ------- ---------- Future net cash inflows before income taxes discounted at 10% per annum $ 594,061 $ --- $ 25,759 $ 974 $11,824 $ 632,618 Future income taxes discounted at 10% per annum 132,948 --- --- --- --- 132,948 ----------- ---------- -------- ---------- ------- ---------- Standardized measure of discounted future net cash inflows $ 461,113 $ --- $ 25,759 $ 974 $11,824 $ 499,670 ----------- ---------- -------- ---------- ------- ---------- MAY 31, 1994: Future cash inflows $ 1,591,448 $ --- $ 76,755 $ 10,278 $23,562 $1,702,043 Future production and development costs 474,382 --- 44,603 7,575 1,945 528,505 ----------- ---------- -------- ---------- ------- ---------- Future net cash inflows before income taxes $ 1,117,066 $ --- $ 32,152 $ 2,703 $21,617 $1,173,538 ----------- ---------- -------- ---------- ------- ---------- Future net cash inflows before income taxes discounted at 10% per annum $ 506,022 $ --- $ 23,147 $ 2,570 $14,008 $ 545,747 Future income taxes discounted at 10% per annum 150,537 --- --- --- --- 150,537 ----------- ---------- -------- ---------- ------- ---------- Standardized measure of discounted future net cash inflows $ 355,485 $ --- $ 23,147 $ 2,570 $14,008 $ 395,210 ----------- ---------- -------- ---------- ------- ---------- The Company's proportional equity interest in Crusader's standardized measure of discounted future net cash inflows was as follows: UNITED AUSTRALIA CANADA STATES TOTAL ---------- ------- ------- ------- December 31, 1995 $ 30,382 $ --- $ --- $30,382 ---------- ------- ------- ------- December 31, 1994 $ 32,492 $ 3,424 $ --- $35,916 ---------- ------- ------- ------- May 31, 1994 $ 35,306 $ 3,997 $ 526 $39,829 ---------- ------- ------- ------- Changes in the standardized measure of discounted future net cash inflows follow: DECEMBER 31, MAY 31, ------------------------------------ 1996 1995 1994 1994 -------------- ---------- --------- --------- Total worldwide, excluding equity share: Beginning of period $ 641,696 $ 499,670 $395,210 $451,482 Sales, net of production costs (97,323) (67,471) (8,249) (14,613) Sales of reserves (10,473) (144,361) --- (83,462) Revisions of quantity estimates 2,617 2,348 43,816 879 Net change in prices and production costs 228,349 42,044 (14,746) (54,143) Extensions, discoveries and improved recovery 1,125,733 339,413 --- 16,521 Change in future development costs (652,902) (102,323) 3,695 (57,459) Purchases of reserves --- --- 9,573 --- Development and facilities costs incurred 92,856 28,068 45,152 57,485 Accretion of discount 80,672 62,188 31,835 60,831 Changes in production rates and other 19,088 22,917 (24,205) 11,392 Net change in income taxes (138,118) (40,797) 17,589 6,297 -------------- ---------- --------- --------- End of period $ 1,292,195 $ 641,696 $499,670 $395,210 -------------- ---------- --------- --------- SCHEDULE II TRITON ENERGY LIMITED AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS (In thousands) ADDITIONS -------------------------------------- BALANCE AT CHARGED TO BALANCE BEGINNING CHARGED TO OTHER AT CLOSE CLASSIFICATIONS OF YEAR EARNINGS ACCOUNTS DEDUCTIONS OF YEAR - ---------------------------- ----------- ------------ ----------- ------------ --------- Year ended May 31, 1994: Allowance for doubtful receivables, excluding discontinued operations $ 1,162 $ (149) $ 4 $ (144) $ 873 ----------- ------------ ----------- ------------ --------- Allowance for deferred tax asset $ 62,789 $ 1,027 $ --- $ --- $ 63,816 ----------- ------------ ----------- ------------ --------- Period ended Dec. 31, 1994: Allowance for doubtful receivables $ 873 $ 19 $ 20 $ (15) $ 897 ----------- ------------ ----------- ------------ --------- Allowance for deferred tax asset $ 63,816 $ 23,702 $ --- $ --- $ 87,518 ----------- ------------ ----------- ------------ --------- Year ended Dec. 31, 1995: Allowance for doubtful receivables $ 897 $ --- $ 41 $ (128) $ 810 ----------- ------------ ----------- ------------ --------- Allowance for deferred tax asset $ 87,518 $ (33,472) $ --- $ --- $ 54,046 ----------- ------------ ----------- ------------ --------- Year ended Dec. 31, 1996: Allowance for doubtful receivables $ 810 $ 35 $ --- $ (769) $ 76 ----------- ------------ ----------- ------------ --------- Allowance for deferred tax asset $ 54,046 $ (23,389) $ --- $ --- $ 30,657 ----------- ------------ ----------- ------------ --------- ___________________ Note -- Deductions for the allowance for doubtful receivables in the year ended December 31, 1996, related primarily to disposal of other assets.