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Triton Energy Ltd – ‘10-K’ for 12/31/00

On:  Thursday, 3/15/01, at 4:25pm ET   ·   For:  12/31/00   ·   Accession #:  1009404-1-500010   ·   File #:  1-11675

Previous ‘10-K’:  ‘10-K/A’ on 8/1/00 for 12/31/99   ·   Latest ‘10-K’:  This Filing

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  As Of                Filer                Filing    For·On·As Docs:Size

 3/15/01  Triton Energy Ltd                 10-K       12/31/00    9:360K

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                        113±   519K 
 2: EX-10.69    Material Contract                                      2±     8K 
 3: EX-10.70    Material Contract                                     14±    64K 
 4: EX-12.1     Statement re: Computation of Ratios                    2±    11K 
 5: EX-12.2     Statement re: Computation of Ratios                    2±    12K 
 6: EX-21.1     Subsidiaries of the Registrant                         1      7K 
 7: EX-23.1     Consent of Experts or Counsel                          1      8K 
 8: EX-23.2     Consent of Experts or Counsel                          1      9K 
 9: EX-23.3     Consent of Experts or Counsel                          1      8K 


10-K   —   Annual Report
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Items 1. and 2. Business and Properties
5Malaysia-Thailand
8Oil and Gas Operations
"Markets
9Executive Officers
"Item 3. Legal Proceedings
"Item 4. Submission of Matters to a Vote of Security Holders
10Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
"8% Convertible Preference Shares
"Item 6. Selected Financial Data
11Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
12Results of Operations
"Oil and Gas Sales
14Disclosure Regarding Forward-Looking Information
"Certain Factors That Could Affect Future Operations
17Item 7.A. Quantitative and Qualitative Disclosures about Market Risk
"Item 8. Financial Statements and Supplementary Data
"Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
18Item 10. Directors and Executive Officers of the Registrant
"Item 11. Executive Compensation
"Item 12. Security Ownership of Certain Beneficial Owners and Management
"Item 13. Certain Relationships and Related Transactions
"Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
"Report of Independent Accountants
23NOLs
28Total
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED: December 31, 2000 OR () TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 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 of other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) CALEDONIAN HOUSE JENNETT 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 (SECTION 229.405 OF THIS CHAPTER) 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 OUTSTANDING ORDINARY SHARES HELD BY NON-AFFILIATES OF THE REGISTRANT AT MARCH 7, 2001 (FOR SUCH PURPOSES ONLY, ALL DIRECTORS AND EXECUTIVE OFFICERS ARE PRESUMED TO BE AFFILIATES) WAS APPROXIMATELY $877.7 MILLION, BASED ON THE CLOSING SALES PRICE OF $24.69 ON THE NEW YORK STOCK EXCHANGE. AS OF MARCH 7, 2001, 37,451,051 ORDINARY SHARES OF THE REGISTRANT WERE OUTSTANDING. DOCUMENTS INCORPORATED BY REFERENCE PORTIONS OF THE PROXY STATEMENT PERTAINING TO THE 2001 ANNUAL MEETING OF SHAREHOLDERS OF TRITON ENERGY LIMITED ARE INCORPORATED BY REFERENCE INTO PART III HEREOF. TRITON ENERGY LIMITED TABLE OF CONTENTS [Enlarge/Download Table] Form 10-K Item Page -------------- ---- PART I ITEMS 1. and 2. Business and Properties . . . . . . . . . . . . . . . . . . . . . 2 ITEM 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . 23 ITEM 4. Submission of Matters to a Vote of Security Holders . . . . . . . 25 PART II ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . 26 ITEM 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . 31 ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. . . . . . . . . . . . . . . . . . . . . . 32 ITEM 7.A. Quantitative and Qualitative Disclosures about Market Risk. . . . 53 ITEM 8. Financial Statements and Supplementary Data . . . . . . . . . . . 54 ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . . . . . . . . . . . . . . . . . . . . . 54 PART III ITEM 10. Directors and Executive Officers of the Registrant. . . . . . . . 55 ITEM 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . . 55 ITEM 12. Security Ownership of Certain Beneficial Owners and Management. . 55 ITEM 13. Certain Relationships and Related Transactions. . . . . . . . . . 55 PART IV ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . 56 PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES GENERAL Triton Energy Limited is an international oil and gas exploration and production company. Our principal properties, operations, and oil and gas reserves are located in Colombia, Equatorial Guinea and Malaysia-Thailand. We explore for oil and gas in these areas, as well as in southern Europe, Africa and the Middle East. Unless this report indicates otherwise or the context otherwise requires, the terms "we," "our," "us," "Triton" and the "Company" as used in this report refer to Triton Energy Limited and its subsidiaries and other affiliates through which Triton conducts its business. We conduct substantially all of our exploration and production operations outside the United States. All of our oil and gas sales currently are from production in Colombia and, commencing with the first quarter of 2001, offshore Equatorial Guinea. For a discussion of certain political, economic and other uncertainties associated with operations in foreign countries, particularly in the oil and gas business, see the "Certain Factors That Could Affect Future Operations" section in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." Triton Energy Limited was incorporated in the Cayman Islands in 1995 to become the parent holding company of Triton Energy Corporation, a corporation formed in Texas in 1962 and reincorporated in Delaware in 1995. Our principal executive offices are located at Caledonian House, Jennett Street, George Town, Grand Cayman, Cayman Islands, and our telephone number there is (345) 949-0050. You can also obtain information regarding Triton by contacting our Investor Relations department at Triton Energy, 6688 North Central Expressway, Suite 1400, Dallas, Texas 75206, telephone number (214) 691-5200, or at our web site, www.tritonenergy.com. The information on our web site is not incorporated by reference into this report and should not be considered to be a part of this document. Our web site address is included in this report as an inactive textual reference only. OIL AND GAS PROPERTIES Through various subsidiaries and affiliates, we have participating interests in exploration licenses in Latin America, Southeast Asia, Africa, Europe and the Middle East. The following is intended to describe our interests in these licenses and recent operations over these licenses. We have defined certain technical terms used in this report in the glossary that is included at the end of this section. The following description of our properties and activities contains a number of forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. This information is subject to the "Safe Harbor" provisions of those statutes. Forward-looking statements include statements concerning our plans, objectives, expectations, goals, budgets, strategies and future operations and performance and the assumptions underlying these forward-looking statements. We use the words "anticipates," "estimates," "expects," "believes," "intends," "plans," "budgets," "may," "will," "should" and similar expressions to identify forward-looking statements. Please see the "Disclosure Regarding Forward-Looking Information" and "Certain Factors That Could Affect Future Operations" sections in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a description of a number of risks and uncertainties that could cause actual results and developments to differ materially from those expressed in or implied by our forward-looking statements. COLOMBIA We hold a 12% interest in the Santiago de Las Atalayas ("SDLA") contract area, covering approximately 66,000 acres, the Tauramena contract area, covering approximately 36,300 acres, and the Rio Chitamena contract area, covering approximately 6,700 acres, which include the Cusiana and Cupiagua fields. These areas are located approximately 160 kilometers (100 miles) northeast of Bogota in the Andean foothills of the Llanos Basin area in eastern Colombia. Our partners in these areas are Empresa Colombiana De Petroleos ("Ecopetrol"), the Colombian national oil company, with a 50% interest, and subsidiaries of BP Amoco p.l.c. ("BP") and TotalFinaElf SA ("TOTAL"), each with a 19% interest. BP is the operator. Our net revenue interest is approximately 9.6% after governmental royalties. We have an agreement with one of our original co-investors that entitles that party to 3.75% of our net revenue if it pays its proportionate share of related costs. The SDLA, Tauramena and Rio Chitamena contracts give BP, TOTAL and us, as the private contractors, the right to produce oil and gas from the areas subject to the contracts during their terms. The SDLA contract expires in 2010, the Tauramena contract in 2016, and the Rio Chitamena contract in 2015 or 2019, depending on contract interpretation. In July 1994, Triton, BP, TOTAL and Ecopetrol agreed to a procedure for developing the Cusiana field over the three contract areas in a unified manner. Until the expiration of the SDLA contract in 2010, oil and gas produced from the three contract areas will be owned by the parties according to their percentage interests in each contract area. In the first quarter of 2005, the parties will have an independent party determine the original BOEs of petroleum in place under the unified area and under each contract area. Then a "tract factor" will be calculated for each contract area. Each tract factor will be the amount of original BOEs of petroleum in place under the particular contract area as a percentage of the total original BOEs under the three contract areas. After the expiration of the SDLA contract in 2010, each party's interest in the remaining contract areas, until their expiration, will be the aggregate of that party's interest in each remaining contract area multiplied by the tract factor for each such contract area. Recent Operating Activity In the Cusiana field, through the end of 2000, the working interest partners had completed a total of 49 producing wells, 13 gas injection wells and three water injection wells. The gas injection wells recycle to the Mirador formation most of the gas that is associated with the oil production to increase the oil recoverable during the life of the field. The water injection wells inject the field's produced water into the Barco and Guadalupe formations for disposal and pressure maintenance. There are currently two drilling rigs operating in the Cusiana field, and we expect that three wells will be completed during 2001. In the Cupiagua field, through the end of 2000, the working interest partners had completed a total of 30 producing wells and nine gas injection wells. There are currently two drilling rigs operating in the Cupiagua field, and we expect that three wells will be completed during 2001. Recetor Contract Area In 1999, we acquired a 20% interest in the Recetor contract area, covering approximately 70,215 acres, subject to certain government royalties. The area is located adjacent to and north of the SDLA contract area and includes an extension of the Cupiagua field. Our partners in these areas are BP, with a 63.3% interest, and Inaquimicas, with a 16.7% interest. BP is the operator. In June 2000, Ecopetrol granted commerciality over a limited area and exercised its right to acquire up to a 50% interest in the commercial area, reducing our interest to 10% and the interests of our partners proportionately. Our interest is subject to a further royalty of 20%, which reduces our net revenue interest to 8%. The contract provides BP, Inaquimicas and us, as the private contractors, the right to produce oil and gas from the Recetor contract area through the year 2017. In January 2000, the working interest partners completed the Liria YD-2 well on an extension of the Cupiagua field in the Recetor contract area. The well reached a total depth of 16,991 feet and is producing into the Cupiagua central processing facility. Currently, one drilling rig is operating in the Recetor contract area. We expect that at least two additional wells will be drilled in the Cupiagua field in the Recetor contract area in 2001. Production Gross production from the Cusiana and Cupiagua fields has reached over 600 million barrels of oil since production commenced, and averaged approximately 339,000 BOPD during 2000. Although the fields are maturing and are in decline, the rate of decline in 2000 was greater than the operator, we and our engineers had expected. This greater rate of decline was primarily due to factors such as mechanical difficulties in some producing wells, scale buildup in some producing wells, which inhibits oil production and requires chemical treatment, a decrease in workovers, delayed drilling of new wells and the disappointing performance of some of the new wells that were drilled. The operator has devised a plan to enhance reservoir management by implementing a more aggressive well-maintenance and workover program. This includes underbalanced drilling in existing and new wells, modifications to surface facilities, and a chemical treatment to alleviate the scale problem and improve well production. Based on this plan, we are estimating that average gross production from the fields will be approximately 270,000 BOPD to 280,000 BOPD (26,000 to 27,000 net to us) in 2001. We cannot assure you that these attempts to offset the decline in production will be successful or that the Colombian fields will not continue to experience significantly less production than the operator, we and our engineers project.
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Production Facilities and Pipelines We have completed the production facilities in the Cusiana and Cupiagua fields. The components of the Cusiana central processing facility consist of a long-term test facility, four early production units, and two 80,000 BOPD production trains. The production capacity of the Cusiana central processing facility is approximately 320,000 BOPD. Currently, the production of the Cusiana field is limited by the gas handling capacity of the Cusiana central processing facility of about 1,400 million cubic feet of gas per day. The components of the Cupiagua central processing facility consist of two 100,000 BOPD production trains. The gas handling capacity of the Cupiagua central processing facility is approximately 1,300 million cubic feet of gas per day. We transport the crude oil and condensate produced from the Cusiana and Cupiagua fields to the Caribbean port of Covenas through the 832-kilometer (520-mile) pipeline system operated by Oleoducto Central S. A. ("OCENSA"). OCENSA also transports crude oil from other parties in Colombia. OCENSA is a Colombian company formed in 1994 by Ecopetrol, BP, TOTAL, Triton, IPL Enterprises (Colombia) Inc. and TCPL International Investments Inc. We own a 9.6% equity interest in OCENSA. El Pinal Contract Area During 2000, we completed the sale of our 100% interest in the El Pinal contract area. EQUATORIAL GUINEA We have interests in production sharing contracts covering three blocks with the Republic of Equatorial Guinea. Our interest in Blocks F and G became effective in April 1997, and in January 2001, we agreed to acquire an interest in Block L. Blocks F and G We are the operator of Blocks F and G, with an 85% contract interest, and our partner in these blocks is Energy Africa with a 15% contract interest. The government has a carried 5% participating interest in any commercial field discovered on the blocks, which is applied to us and our partner proportionately. The contracts currently cover a contiguous area of approximately one million acres located offshore and southwest of the city of Bata in water depths of up to 5,200 feet. Recent Operating Activity - the Ceiba Field ------------------------------------------------- In October 1999, we announced the discovery of the Ceiba oil field, located on Block G in approximately 2,200 to 2,600 feet of water, approximately 22 miles off the continental coast. During 2000, we successfully implemented an accelerated appraisal and development program for the Ceiba field, drilling the Ceiba-3, -4 and -5 subsea production wells. We commenced production in November 2000, achieved production from three wells by the end of 2000, and in February 2001, we commenced production from a fourth well. The wells are connected through flowlines to a floating production, storage and offloading vessel ("FPSO"). Based on our development plan and production history to date, we expect gross production from the Ceiba field to average approximately 37,000 BOPD to 43,000 BOPD (26,000 to 30,000 net to us) during 2001. We cannot assure you that actual production rates will meet our expectations. Actual production rates will depend on well and reservoir performance, our ability to improve pressure support through water injection, and other factors. Development Plans. The current plan for development calls for a total of 10 production wells and four water injection wells, including the production wells that already have been drilled. Our plan is to have the water injection wells and at least seven production wells drilled and completed in 2001, and the remaining production wells drilled and completed in 2002. Currently, the FPSO vessel provides storage for up to two million barrels of oil and initial processing capacity of up to 60,000 barrels of fluids per day. In connection with the next phase of development, we are planning to increase processing capacity to approximately 160,000 barrels of fluids per day and to install onboard water-injection facilities to inject up to 135,000 barrels per day of water. We expect that the additional wells and production and water-injection facilities will enable us to increase production in 2002. We are uncertain as to what the production rate will be in this latter phase of development. The actual production rate will depend on a number of factors, including the timing of the completion of the additional production and water-injection facilities, well performance, the timing of the connection of the production and water injection wells to the FPSO, reservoir performance, our ability to improve pressure support through water injection and other factors. In order to install the necessary equipment to increase the processing capacity of the facilities, we expect that we will be required to temporarily halt production from the Ceiba field. Currently, we expect that this production halt will begin in December 2001 and will last approximately four weeks. Development and Appraisal Wells. Following the drilling of the Ceiba-1 discovery well and the Ceiba-2 appraisal well in late 1999, we drilled the Ceiba-3, -4, -5, -6 and -7 wells to develop and appraise the Ceiba field. The Ceiba-3 development well confirmed the primary reservoir found in the Ceiba-1 and Ceiba-2 wells and encountered a deeper, similar-quality oil reservoir. The Ceiba-3 well was drilled to a total depth of 9,695 feet in 2,165 feet of water, and penetrated 256 feet of net oil-bearing pay based on the analysis of drilling, coring, wireline logging and samples. The well is approximately one mile northeast and 282 feet downdip of the Ceiba-1 discovery well and confirmed the extension of the Ceiba field to the north. The Ceiba-4 development well confirmed the oil pool found in the Ceiba-1, -2 and -3 wells. The Ceiba-4 well was drilled to a total depth of 8,957 feet in 2,431 feet of water, and penetrated 269 feet of net oil-bearing pay in three zone based on the analysis of drilling, coring, wireline logging and samples. The well is approximately one mile southwest and 207 feet downdip of the Ceiba-2 appraisal well. The Ceiba-5 appraisal well confirmed the primary oil pool found in the Ceiba-1, -2, -3 and -4 wells, and encountered a deeper pool with an additional high-quality reservoir not seen in any of the previous Ceiba wells. The Ceiba-5 well was drilled to a total depth of 9,187 feet in 2,622 feet of water, and penetrated 243 feet of net oil-bearing pay in three zones based on the analysis of drilling, wireline logging, downhole pressure measurements and rock/fluid samples. The new oil pool has an oil-water contact 328 feet below the oil-water contact of the primary Ceiba pool. The well is approximately 1.75 miles northwest of the Ceiba-3 development well. The Ceiba-6 appraisal well was a step-out well located outside and southeast of the Ceiba field approximately 2.5 miles south of the Ceiba-4 well, and was drilled to a total depth of 10,388 feet. The well was plugged and abandoned, having not encountered oil and gas. The Ceiba-7 development well was completed in February 2001. The well was side-tracked, and drilled to a total depth of 8,960 feet in 2,352 feet of water. The well penetrated 102 feet of net oil-bearing pay in two zones based on the analysis of drilling, wireline logging, downhole pressure measurements and rock/fluid samples. The well is approximately one-half mile north-northwest of the Ceiba-2 development well. Seismic Acquisition. We have acquired a 1,025,000-acre (4,200-square-kilometer) 3D seismic survey to assist in delineating the extent of the Ceiba field, identify drilling locations for the appraisal/production wells, and better define other exploration prospects on the blocks. We have completed the primary analysis of the data in the Ceiba field, and further detailed analysis is in process. Exploration Activity --------------------- In addition to the development and appraisal wells drilled in the Ceiba field, we have drilled three exploration wells in Block G and one exploration well in Block F. While our analysis of the data we have obtained from drilling and the seismic activity continues, we have identified three main areas for exploration activity in the blocks - the platform edge closest to the coast of the country, the slope, or "toe-thrust" zone, that extends west from the platform edge in Block G and the southern part of Block F, and the basin, which is in deep water. Our current plans for this year are to drill at least one and possibly two exploration wells in the toe-thrust zones and possibly one exploration well in the basin. Our plans for these wells are subject to change as circumstances warrant. The timing of the exploration wells is uncertain, as we will need to balance the drilling of exploration wells with our needs for drilling development wells in the Ceiba field. Also, any exploration well in the basin area may require a rig suitable for deepwater drilling. In February 2001, we reported that the F-1 exploration well would be plugged and abandoned. The well, the first exploration well we have drilled in Block F, was drilled in about 700 feet of water and reached a total depth of 10,180 feet. In January 2001, we reported that the G-4 exploration well would be temporarily abandoned after discovering oil on Block G. During a drill stem test, 31 degree API oil was flowed to surface, but a sustained flow rate was not achieved. We will need to perform additional technical work, and, if warranted, further appraisal drilling, to determine if the field can produce oil at commercial flow rates. The well was drilled in approximately 800 feet of water and reached a total depth of 6,610 feet. In the fourth quarter of 2000, we reported that the G-2 and G-3 exploration wells would be plugged and abandoned. The G-2 well was drilled in about 2,970 feet of water, and reached a total depth of 15,214 feet. Log analysis indicated the well encountered three oil-bearing zones, but the reservoir permeability was inadequate for oil production. The G-3 well was drilled in about 1,900 feet of water and reached a total depth of 9,065 feet. The well encountered Ceiba-quality reservoir sands that were water bearing. Contract Terms --------------- The production sharing contracts covering Blocks F and G grant to us and our partner the right to explore for and produce and sell oil and gas from the blocks. The blocks cover a total of approximately one million acres located offshore and southwest of the city of Bata. This acreage position takes into account our relinquishment of approximately 18% of the original areas in 2000. Under the terms of the contracts, we were required to relinquish 30% of the original acreage in 2000, and to relinquish an additional 20% of the remaining contract area by April 2003 if we wanted to extend the exploration period. In 2000, we agreed with the government to relinquish 18% of the acreage in 2000, with the remainder of the relinquishment requirement to be fulfilled by the end of the exploration period. In any event, under the contracts, we are not required to surrender an area that includes a commercial field or a discovery that has not then been declared commercial. When we are required to relinquish acreage, we can designate the area or areas to be surrendered, provided that, where possible, each area must be of sufficient size and convenient shape to permit petroleum operations. The initial exploration period in the contracts expires in April 2003. We can extend the exploration period of each contract for up to three additional years if we agree to certain operational commitments for those periods, subject to the relinquishment requirements described in the preceding paragraph. The contracts provide that if there is a commercial discovery of an oil or gas field on a block, the contract will remain in existence as to that field for a period of 30 years, in the case of oil, or 40 years, in the case of gas, from the date the Ministry of Mines and Energy approves the discovery as commercial. Any further discoveries of hydrocarbons in formations that underlie or overlie that field, or other deposits found within the extension of that field, will be included with that field and will be subject to the original 30- or 40- year term, as applicable. The Ministry approved the Ceiba field as commercial in December 1999.
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Under the current terms of the production sharing contracts, the Republic of Equatorial Guinea is entitled to a royalty as to each field. In the case of an oil field, the royalty is based on average daily production and is determined as follows: Rates of Daily Production of an Oil Field Royalty Per Tranche ----------------------------------------- ------------------- (calculated on an incremental basis of crude oil) From 0 to 30,000 Barrels 11% Above 30,000 to 60,000 Barrels 12% Above 60,000 to 80,000 Barrels 14% Above 80,000 to 100,000 Barrels 15% More than 100,000 Barrels 16% In the case of a gas field, the royalty is 10% of the natural gas produced from the field. After making the royalty payments, we and Energy Africa will be allocated up to 70% of the remaining production to recover specified capital and operating costs. The government of Equatorial Guinea's 5% carried participating interest does not entitle the government to receive any of the proceeds for cost recovery. After the allocation of production toward the payment of the royalty and cost recovery, the production sharing contracts entitle the Republic of Equatorial Guinea to receive a share of production based on cumulative production, determined as follows: Government Share of Contractors' Share of Cumulative Production Remaining Production Remaining Production ------------------------ --------------------- ---------------------- (in millions of barrels) From 0 to 200 20% 80% Above 200 to 350 30% 70% Above 350 to 450 40% 60% Above 450 to 550 50% 50% More than 550 60% 40% The government of Equatorial Guinea's 5% carried participating interest entitles it to receive 5% of the production allocated to the contractors in the preceding table. As a result, we would receive 80.75% of the contractors' share of remaining production and Energy Africa would receive 14.25%.
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In addition, as any new field is discovered, the contractors must make a non-recoverable production payment to the government in the amount of $750,000 when the Ministry of Mines and Energy approves the discovery as commercial. The contractors must pay the government certain production bonuses if and when production from a field, including the Ceiba field, averages certain levels for a 60-day period for the first time, determined as follows: Average Production Total Per Day Production Bonus ------ ----------------- (in barrels) 30,000 $3 million 60,000 $3 million 100,000 $4 million These production bonuses would be added to the capital costs the contractors are entitled to recover. Block L In January 2001, we agreed to acquire a 25% interest in a production sharing contract covering Block L in the Republic of Equatorial Guinea. The contract covers approximately one million acres located offshore Equatorial Guinea, contiguous to Block F to the north and extending west and south contiguous Blocks F and G. Block L is in water depths from approximately 1,300 feet to 6,800 feet. Our partners in this area are subsidiaries of Chevron Corporation, with a 65% interest, and Sasol Limited, a South African company, with a 10% interest. Chevron is the operator. If there is a discovery in the block, the government will receive a 7.5% carried interest at such time as it approves the first development and production plan for the discovery, and the private partners' interests will be reduced proportionately. Under the contract, we have the right to explore for oil and gas in the block for a period that ends in October 2005. If we fulfill our contract obligations during this initial five-year period, we can extend the exploration phase of the contract for up to two additional one-year periods. However, if we desire to extend the contract, we would be required to relinquish 40% of the acreage at the expiration of the initial exploration period and 25% of the acreage remaining at the end of each extension year. By October 2003, we will be required to have acquired and processed at least 2,000 kilometers of 2D seismic data and at least 800 square kilometers of 3D seismic data, and to have drilled at least one exploration well. In addition, by October 2005, and subject to our agreement to do so, we will be required to have drilled a second exploration well. If we wish to exercise our option to extend the exploration period by one year, we will be obligated to drill at least one well, which could be an exploration well or an appraisal well. This would apply to the second one-year extension as well. Currently, we are conducting a 3D seismic survey covering 1,500 square kilometers, and we plan to drill an exploration well by the end of 2002.
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MALAYSIA-THAILAND In Block A-18 of the Malaysia-Thailand Joint Development Area in the Gulf of Thailand, we and our partners have discovered eight natural gas fields - known as the Bulan, Bumi, Bumi East, Cakerawala, Samudra, Senja, Suriya, and Wira fields. We own our interest through a one-half interest in a company that holds a 50% contract interest in a production sharing contract covering Block A-18. A subsidiary of BP, which acquired the Atlantic Richfield Company in 2000, owns the other half of the shares of the company. The operator is Carigali-Triton Operating Company Sdn. Bhd., a company owned by BP and us, through our jointly owned company, and Petronas Carigali (JDA) Sdn. Bhd., a subsidiary of the Malaysian national oil company. Block A-18 encompasses approximately 731,000 acres. The area had been the subject of overlapping claims between Malaysia and Thailand. The two countries established the Malaysia-Thailand Joint Authority to administer the development of the Joint Development Area. In April 1994, we entered into a production sharing contract with the Malaysia-Thailand Joint Authority and Petronas Carigali. We previously held a license from Thailand that covered part of the Joint Development Area. Contract Terms The term of the production sharing contract is 35 years, subject to possible relinquishment of certain areas and subject to the treaty between Malaysia and Thailand creating the Malaysia-Thailand Joint Authority remaining in effect. The contract gives us the right to explore for oil and gas for the first eight years of the contract, which will expire in April 2002. If we discover a natural gas field (not associated with crude oil), we must submit to the Malaysia-Thailand Joint Authority a development plan for the field. If the Malaysia-Thailand Joint Authority accepts the development plan, we can then hold that gas field without production for an additional five-year period, but not beyond the tenth anniversary of the contract. We then have a five-year period from the Malaysia-Thailand Joint Authority's acceptance of the development plan to develop the field, and have the right to produce the field for approximately 20 years (or until the termination of the contract, if earlier). We are required to drill two exploration wells before April 2002. If we discover an oil field, we would have the right to produce oil from the field for 25 years (or until the termination of the contract, if earlier). We would have to relinquish any areas not developed and producing within the periods provided. As oil and gas are produced, the Malaysia-Thailand Joint Authority is entitled to a 10% royalty. A portion 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 Malaysia-Thailand Joint Authority and 50% to the contractors (i.e., 25% to Petronas Carigali and 25% to the company we own jointly with BP). The portion that will be considered "cost gas" for production in the first phase of development is a maximum of 60%. The portion that will be considered "cost gas" following the first phase of development is a maximum of 50%. There is an additional royalty attributable to Triton's and BP's joint interest equal to 0.75% of Block A-18 production. Tax rates imposed by the Malaysia-Thailand Joint Authority 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. Our agreements with BP require BP to pay the future exploration and development costs attributable to our collective interest in Block A-18, up to $377 million or until first production from a gas field. Once gas production starts, or once BP has paid $377 million, whichever occurs first, we and BP would each pay 50% of our share of exploration and development costs. Under our agreements with BP, once production commences and "cost oil" or "cost gas" is allocated to the contractors for their recoverable costs under the production sharing contract, we will recover our investment in recoverable costs in the project first, and then BP will recover its investment in recoverable costs. We have estimated our recoverable costs to be approximately $100 million. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and note 2 of Notes to Consolidated Financial Statements. Gas Sales Agreement In October 1999, we and the other parties to the production sharing contract for Block A-18 executed a gas sales agreement providing for the sale of the first phase of gas to Malaysia. The sales agreement provides for gas deliveries over a term concurrent with the production sharing contract and contemplates initial deliveries of 195 MMcf per day for up to the first six months of the agreement, and 390 MMcf per day for a period of twenty years. We believe that this first phase of the agreement will cover approximately 2.5 Tcf to 3 Tcf of gas in total. The sales agreement includes a take-or-pay provision that specifies that the buyers must take a minimum of 90% of the annual daily contract quantity and the sellers must be able to deliver a maximum of 110% of the daily contract quantity. Delivery is made at the offshore production platform. The agreement provides that the initial delivery date will be a date to be agreed upon by the sellers and the buyers between April 1, 2002 and June 30, 2002. If the parties do not agree on a date for initial delivery, the agreement provides that the date will be deemed to be June 30, 2002. By the first delivery date, we and the other sellers will be required to have completed the facilities necessary to meet our delivery obligations. The Malaysia-Thailand Joint Authority had previously approved the field development plan for the Cakerawala field in December 1997. Carigali-Triton Operating Company, the operator, has begun field development work and has awarded several contracts for long lead-time equipment, including carbon dioxide removal, structural steel, refrigeration, power generation and gas compression. In March 2000, Carigali-Triton Operating Company awarded the contract for engineering, procurement and construction of three wellhead platforms, a production platform with living quarters platform, a riser platform and a floating storage and off-loading vessel for oil and condensate. The initial development plan calls for 35 development wells. As of February 2001, we believe that the work under the sellers' engineering, procurement and construction contract was approximately 50% complete. The buyers currently do not have in place facilities necessary to transport and process the gas. While it is not a requirement of the sales agreement, the buyers anticipate constructing pipeline and processing facilities onshore Thailand to accept deliveries of the gas. The sales agreement does recognize that the buyers' downstream facilities will require that certain environmental approvals be obtained before the buyers' facilities can be constructed. The agreement provides that, if a delay in obtaining the necessary environmental approvals results in a delay of the completion of the buyers' downstream facilities, and the buyers have satisfied other specified conditions precedent, then this will be treated as a force majeure event and will excuse the buyers from their take-or-pay obligations for the length of the delay. We cannot give you any assurance as to when the environmental approvals will be obtained, and a lengthy approval process or significant opposition to the project could delay construction and the commencement of gas sales, as could a number of events unrelated to the environmental approval that are beyond our control. Based on the delays to date in obtaining the environmental approval, for internal planning purposes we are assuming that production will begin no earlier than the fourth quarter of 2002. The price for gas will be adjusted annually for changes in the U.S. Consumer Price Index, the Producer Price Index for Oil Field and Gas Field Machinery and Tools, and medium fuel oil (180 centistokes) in Singapore. The price is calculated annually based on changes in the factors from the prior year and will apply to sales over the succeeding twelve months. All calculations and payments are in U.S. dollars. The base price is $2.30 per MMbtu. Based on the formula, the price would have been $2.59 per MMbtu for the contract year from October 1, 2000 to September 30, 2001. To give the buyers incentive to accelerate the timing of the delivery of the gas, the sales agreement gives the buyers a discount of 5% after 500 Bcf has been delivered and a discount of 10% after an aggregate of 1.3 Tcf has been delivered. When we sold one half of our interest in Block A-18 to BP in 1998, BP agreed to pay the future exploration and development costs attributable to our collective interest in Block A-18, up to $377 million or until first production from a gas field. BP also agreed to pay us specified incentive payments if the requisite criteria were met. The first $65 million in incentive payments is conditioned upon having the production facilities for the sale of gas from Block A-18 completed by June 30, 2002. If the facilities are completed after June 30, 2002 but before June 30, 2003, the incentive payment would be reduced to $40 million. A lengthy environmental approval process, or delays in construction of the facilities, could result in our receiving a reduced incentive payment or possibly the complete loss of the first incentive payment. For purposes of estimating our discounted net cash inflows from our proved reserves in Block A-18, we have assumed that we would be entitled to a $40 million incentive payment. Notwithstanding a possible future delay in the buyers' environmental approvals process, in order to meet the June 30, 2002 deadline, the sellers are committed to, or will be required to commit to, significant expenditures, including the engineering, procurement and construction contract. Although BP is committed to pay all development costs associated with Block A-18 up to $377 million, we have agreed to share some of the costs of development with BP in the event that the environmental approval process delays production by agreeing to pay BP $1.25 million per month for each month, if applicable, that first gas sales are delayed beyond 30 months following the award of the engineering, procurement and construction contract for the project in March 2000. Our obligation is capped at 24 months of these payments, or $30 million.
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GABON In 2000, we acquired a 38% interest in the Tolo and Otiti blocks offshore Gabon. Our partners in the two blocks are Australia-based Broken Hill Proprietary Company Limited, the operator, and Sasol Limited. The Tolo block covers approximately 836,000 acres located offshore and west of Libreville in water depths from 1,600 to 8,200 feet. The contract for the Tolo block provides an exploration term expiring in July 2003 with a commitment of one exploration well. We expect to drill this well in second half of 2001, subject to rig availability. The Otiti block covers approximately 815,000 acres located offshore and southwest of Libreville in water depths from 1,600 to 6,600 feet. The contract for the Otiti block provides an exploration term expiring in July 2003, with a commitment of 750 kilometers of 2D seismic and 250 square kilometers of 3D seismic. GREECE We have an 88% interest in the Gulf of Patraikos contract area. Hellenic Petroleum, the national oil company of Greece, has the remaining 12% interest. The Gulf of Patraikos contract area covers approximately 402,000 acres located offshore between the western coast of Greece and the offshore Ionian islands of Lefkas, Kefalonia and Zakynthos in water depths of up to 920 feet. The contract provides a primary exploration term expiring in September 2001. We have remaining a commitment to drill one exploration well. We had an interest in the Aitoloakarnania onshore contract area. During 2000, we completed our commitments for this area, including the drilling of two commitment wells, which were dry holes. In September 2000, we surrendered our interest in the area. ITALY We hold interests in three licenses in Italy comprising three offshore blocks in the Adriatic Sea. We have a 47% interest in each of the DR71 and DR72 licenses covering approximately 369,400 acres. The license areas are located in the Adriatic Sea located 45 kilometers (28 miles) offshore the city of Brindisi. Our partner is Enterprise Oil Italiana, S.p.A., the operator, with a 53% interest. During 1998, we drilled the Giove-1 well. The well was drilled to a total depth of 3,458 feet but was prematurely abandoned due to a gas blowout and mechanical failure. We drilled a replacement well, Giove-2, to a total depth of 4,285 feet and encountered oil and gas, although additional work is required to evaluate the commercial potential of the licenses. We have a 20% interest in the FR33AG offshore license. The license covers approximately 71,600 acres and is adjacent to the DR71 and DR72 licenses. Eni S.p.A. is operator, with a 50% interest, and Enterprise holds the remaining 30% interest. The license provides a primary exploration term expiring in September 2004 with a commitment of 250 kilometers (156 miles) of new 2D seismic and the drilling of one exploration well. In January 2001, we and our partner applied to relinquish our interest in the Fosso del Lupo, Valsinni and Masseria de Sole onshore licenses in the Matera province. MADAGASCAR We are a party to a production sharing contract with the Office of National Mines and Strategic Industries in Madagascar for the Ambilobe Block, covering approximately 4.3 million acres. The block is located directly offshore from Ambilobe in water depths of up to 11,500 feet. We have acquired approximately 3,000 kilometers (1,875 miles) of 2D seismic. The contract provides that it will expire in November 2001, unless we elect to extend the contract, which would require us to commit to drill one exploration well. OMAN We are a party to a production sharing contract for Block 40, covering approximately 1.3 million acres located offshore in the Straits of Hormuz. The contract provides an exploration term expiring in July 2002 with a commitment of the drilling of one exploration well. We are the operator with a 50% contract interest and Atlantis Holding Norway AS is our partner with a 50% interest. We have completed the reprocessing and interpretation of 4,083 kilometers (2,546 miles) of existing 2D seismic, and the processing and interpretation of a 620-square-kilometer 3D seismic survey acquired in January 2000. We are processing the information from a recently completed site survey in preparation for drilling an exploration well in late 2001 or early 2002. RESERVES The following table sets forth a summary of our estimated proved oil and gas reserves at December 31, 2000, and is based on separate estimates of our net proved reserves prepared by: - the independent petroleum engineers, DeGolyer and MacNaughton, with respect to the proved reserves in the Cusiana and Cupiagua fields in Colombia, - the independent petroleum engineers, Netherland, Sewell & Associates, Inc., with respect to the proved reserves in the Ceiba field in Equatorial Guinea, and - the internal petroleum engineers of the operating company, Carigali-Triton Operating Company, with respect to the proved reserves in Malaysia-Thailand on Block A-18 in the Gulf of Thailand. For additional information regarding our reserves, including the standardized measure of future net cash flows, see note 21 of Notes to Consolidated Financial Statements. Oil reserves data include natural gas liquids and condensate.
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Net proved reserves at December 31, 2000, were: [Enlarge/Download Table] PROVED PROVED TOTAL DEVELOPED UNDEVELOPED PROVED ------------------- ---------------------- ------------------ OIL GAS OIL GAS OIL GAS (MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF) ---------- ------- ------------ -------- -------- -------- Colombia (1) 81,101 10,865 25,303 --- 106,404 10,865 Equatorial Guinea 24,663 --- 50,504 --- 75,167 --- Malaysia-Thailand (2) --- --- 13,124 581,708 13,124 581,708 ---------- ------- ------------ -------- -------- -------- Total 105,764 10,865 88,931 581,708 194,695 592,573 ========== ======= ============ ======== ======== ======== ____________________ (1) Includes liquids to be recovered from Ecopetrol as reimbursement for precommerciality expenditures. (2) As of December 31, 2000, gas sales had not yet commenced. The proved gas reserves are calculated using the base price in the gas sales agreement of $2.30. The base price is subject to annual adjustments based on various indices. We cannot assure you that the actual price when gas sales commence will be the same as the price we used in our assumptions. Because of the cost-recovery feature of the production sharing contract, a higher price would result in lower volumes of reserves, but a higher measure of discounted net cash inflows. See "Items 1. and 2. Business and Properties - Malaysia-Thailand." Reserve quantities are estimates and there are a number of uncertainties. Reserve estimates are approximate and may be expected to change as additional information becomes available. In addition, there are inherent uncertainties in making reserve estimates, such as the following: - reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way; - the accuracy of reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment; - we, and if applicable our independent engineers, must make certain assumptions and projections based on engineering data; - there are uncertainties inherent in interpreting engineering data; and - we, and if applicable our independent engineers, must project future rates of production and the timing of development expenditures. Accordingly, we cannot assure you that we will ultimately produce the quantity of reserves set forth in the table, and we cannot assure you that the proved undeveloped reserves will be developed within the periods anticipated. We do not file estimates of total proved net oil or gas reserves with, or included estimates of total proved net oil or gas reserves in any report to, any United States authority or agency.
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OIL AND GAS OPERATIONS PRODUCTION AND SALES The following table sets forth the net quantities of oil and gas we produced during 2000, 1999 and 1998. If during these three years we acquired or sold a property or a subsidiary, the information in the table includes production and sales information relating to the property or subsidiary only during the times we owned it. The table does not reflect production from our interest in the Ceiba field in Equatorial Guinea because we did not make our first sale until January 2001. Approximately 1.25 million barrels of oil (one million net to us) were produced in the fourth quarter of 2000 and stored in the FPSO. More details regarding our revenues, assets and other data by geographical area is contained in note 19 of Notes to Consolidated Financial Statements. [Download Table] OIL PRODUCTION (1) GAS PRODUCTION ------------------------ ----------------------- YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, ------------------------ ----------------------- 2000 1999 1998 2000 1999 1998 ------ ------ ------ ------ ------ ----- (MBBLS) (MMCF) Colombia (2) 11,167 12,469 9,979 470 459 503 ____________________ (1) Includes natural gas liquids and condensate. (2) Includes Ecopetrol reimbursement barrels, and excludes oil produced and delivered over the past three years to satisfy our obligations under a forward oil sale we entered into in May 1995. We delivered 0.8 million barrels in 2000, 3.1 million barrels in 1999 and 3.1 million barrels in 1998 in connection with the forward oil sale. The following tables summarize for 2000, 1999 and 1998: (i) the average sales price per barrel of oil and per 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 ------------------------- ------------------------ YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, ------------------------- ------------------------ 2000 1999 1998 2000 1999 1998 ------ ------ ------ ------ ------ ------ Colombia (4) $27.48 $ 15.95 $12.31 $ 1.34 $ 0.88 $ 0.99 [Enlarge/Download Table] PER EQUIVALENT BARREL (2) ---------------------------------------------------------------------------- AVERAGE SALES PRICE DEPLETION (3) PRODUCTION COST ------------------------- ------------------------ ----------------------- YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, ------------------------- ------------------------ ----------------------- 2000 1999 1998 2000 1999 1998 2000 1999 1998 ------- ------ ------ ------ ------ ------ ------ ----- ------ Colombia (4) $ 27.36 $15.89 $12.27 $ 4.37 $ 3.80 $ 4.07 $ 4.64 $ 4.50 $ 5.97 ____________________________ (1) Includes natural gas liquids and condensate. (2) Natural gas has been converted into equivalent barrels of oil based on six Mcf of natural gas per barrel of oil. (3) Includes depreciation calculated on the unit of production method for support equipment and facilities. Excludes the full cost ceiling limitation writedown in 1998 totaling $241 million. (4) Includes barrels delivered under the forward oil sale which are recorded at $11.56 per barrel upon delivery. COMPETITION We encounter 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 we operate 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. We believe that the principal means of competition in the sale of oil and gas are product availability, price, quality and logistics. MARKETS We generally sell our crude oil, natural gas, condensate and other oil and gas products to other oil and gas companies, government agencies and other industries. We do not believe that the loss of any single customer or sales contract would have a long-term material, adverse effect on our revenues or oil and gas operations. In Colombia, our oil production 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 and Cupiagua fields is transported to the export terminal by pipeline. In Equatorial Guinea, our oil production is sold upon transfer from the FPSO to a buyer's vessel. We expect to be able to market our crude oil to refiners throughout the world. The price of the Ceiba crude is based on a benchmark crude oil, such as Dated Brent, adjusted for quality and transportation. Initially, for operational reasons, we have limited sales to relatively smaller cargo vessels capable of loading quantities of 1,000,000 barrels or less. We believe this has somewhat limited the number of potential purchasers due to the relatively higher transportation costs per barrel. In addition, Ceiba crude is a relatively new crude oil previously unknown to refiners, with an acid quality that certain refiners will not readily be able to process, which could discourage those refiners from purchasing the crude without a price discount. We believe that, as our operational efficiency improves to permit us to market the crude to larger vessels, and therefore to a greater number of refiners, the price of Ceiba crude in relation to applicable benchmarks should improve. We cannot assure you that this price differential will improve or if it does, that it will improve by a material amount. For a discussion of certain factors regarding our markets and potential markets that could affect future operations, see the "Certain Factors That Could Affect Future Operations" section in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." ACREAGE The following table shows the total gross and net developed and undeveloped oil and gas acreage we held at December 31, 2000. "Gross" refers to the total number of acres in an area in which we hold an interest without adjustment to reflect the actual percentage interest we hold. "Net" acreage is adjusted for working interests owned by other parties. "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. [Download Table] DEVELOPED UNDEVELOPED ACREAGE ACREAGE (1) ------------------ ------------------ GROSS NET(2) GROSS NET(2) -------- -------- -------- -------- (In thousands) Colombia 29 3 150 17 Equatorial Guinea 1 1 2,127 1,177 Malaysia-Thailand --- --- 731 183 Gabon --- --- 1,651 628 Greece --- --- 402 354 Italy(3) --- --- 441 188 Madagascar --- --- 4,300 4,300 Oman --- --- 1,322 661 -------- -------- -------- -------- Total 30 4 11,124 7,508 ======== ======== ======== ======== ____________________ (1) Our interest in certain of this acreage may expire if not developed at various times in the future pursuant to the terms of the leases, licenses, concessions, contracts, permits or other agreements under which it was acquired. (2) The net acreage position does not take into account royalties, net revenue interests, carried interests or similar interests held by third parties that reduce our net revenue interest but not our working interest. (3) Excludes approximately 58,000 gross acres (29,000 net acres) attributable to onshore licenses that we relinquished in January 2001. PRODUCTIVE WELLS AND DRILLING ACTIVITY In this section, when we refer to "gross" wells, we mean every well drilled in an area in which we hold any interest. When we refer to "net" wells, we mean the gross number of wells drilled adjusted for our percentage interest in the area. The following table summarizes the approximate total gross and net working interests we held in productive wells at December 31, 2000: [Download Table] PRODUCTIVE WELLS(1) GROSS NET -------------- -------------- OIL GAS OIL GAS ------ ------ ------ ------ Colombia 105 --- 12.58 --- Equatorial Guinea(2) 5 --- 4.25 --- ------ ------ ------ ------ Total 110 --- 16.83 --- ====== ====== ====== ====== ___________________ (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) Our net interest does not take into account the 5% carried interest held by the government of Equatorial Guinea. The following tables set forth the results of the oil and gas well drilling activity on a gross basis for wells in which we held an interest during 2000, 1999 and 1998. If during these three years we acquired or sold a property or a subsidiary, the information in the tables includes production and sales information relating to the property or subsidiary only during the times we owned it. For purposes of the following tables, the Ceiba-5 and -6 wells are counted as exploration wells because they were drilled outside the area that included proved reserves at the time they were drilled. The Ceiba-3 and -4 wells are counted as development wells. [Enlarge/Download Table] GROSS EXPLORATION WELLS PRODUCTIVE (1) DRY TOTAL ------------------------ ----------------------- ----------------------- YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, ------------------------ ----------------------- ----------------------- 2000 1999 1998 2000 1999 1998 2000 1999 1998 ------ ------ ------ ------ ------ ----- ------- ------ ------ Colombia --- --- 1 --- 1 --- --- 1 1 Equatorial Guinea 1 2 --- 3 --- --- 4 2 --- Malaysia-Thailand --- --- 2 --- --- --- --- --- 2 Italy --- --- --- --- --- 2 --- --- 2 China --- --- --- --- --- 1 --- --- 1 Greece --- --- --- 2 --- --- 2 --- --- Tunisia --- --- --- --- --- 1 --- --- 1 ------ ------ ------ ------ ------ ----- ------- ------ ------ Total 1 2 3 5 1 4 6 3 7 ====== ====== ====== ====== ====== ===== ======= ====== ====== [Enlarge/Download Table] GROSS DEVELOPMENT WELLS PRODUCTIVE (1) DRY TOTAL ------------------------ ----------------------- ----------------------- YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, ------------------------ ----------------------- ----------------------- 2000 1999 1998 2000 1999 1998 2000 1999 1998 ------ ------ ------ ------ ------ ----- ------- ------ ------ Colombia 14 14 13 --- --- --- 14 14 13 Equatorial Guinea 2 --- --- --- --- --- 2 --- --- Malaysia-Thailand --- --- --- --- --- --- --- --- --- ------ ------ ------ ------ ------ ----- ------- ------ ------ Total 16 14 13 --- --- --- 16 14 13 ====== ====== ====== ====== ====== ===== ======= ====== ====== ___________________ (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.
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The following tables set forth the results of drilling activity on a net basis for wells in which we held an interest during 2000, 1999 and 1998. If during these three years we acquired or sold a property or a subsidiary, the information in the tables includes production and sales information relating to the property or subsidiary only during the times we owned it. [Enlarge/Download Table] NET EXPLORATION WELLS PRODUCTIVE (1) DRY TOTAL ------------------------ ----------------------- ----------------------- YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, ------------------------ ----------------------- ----------------------- 2000 1999 1998 2000 1999 1998 2000 1999 1998 ------ ------ ------ ------ ------ ----- ------- ------ ------ Colombia (2) --- --- 0.12 --- 0.50 --- --- 0.50 0.12 Equatorial Guinea(3) .85 1.70 --- 2.55 --- --- 3.40 1.70 --- Malaysia-Thailand (4) --- --- 1.00 --- --- --- --- --- 1.00 Italy --- --- --- --- --- 0.80 --- --- 0.80 China --- --- --- --- --- 0.50 --- --- 0.50 Greece --- --- --- 2.00 --- --- 2.00 --- --- Tunisia --- --- --- --- --- 0.50 --- --- 0.50 ------ ------ ------ ------ ------ ----- ------- ------ ------ Total .85 1.70 1.12 4.55 0.50 1.80 5.40 2.20 2.92 ====== ====== ====== ====== ====== ===== ======= ====== ====== [Enlarge/Download Table] NET DEVELOPMENT WELLS PRODUCTIVE (1) DRY TOTAL ------------------------ ----------------------- ----------------------- YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, ------------------------ ----------------------- ----------------------- 2000 1999 1998 2000 1999 1998 2000 1999 1998 ------ ------ ------ ------ ------ ----- ------- ------ ------ Colombia (2) 1.66 1.68 1.56 --- --- --- 1.66 1.68 1.56 Equatorial Guinea(3) 1.70 --- --- --- --- --- 1.70 --- --- Malaysia-Thailand --- --- --- --- --- --- --- --- --- ------ ------ ------ ------ ------ ----- ------- ------ ------ Total 3.36 1.68 1.56 --- --- --- 3.36 1.68 1.56 ====== ====== ====== ====== ====== ===== ======= ====== ====== __________________ (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) The well data does not take into account the government of Equatorial Guinea's 5% carried interest. (4) The interest in the wells drilled in 1998 was not reduced to take into account the sale of our interest in Block A-18 to BP because the sale occurred after the drilling of the wells. OTHER PROPERTIES We lease office space, other facilities and equipment under various operating leases expiring through 2005. Total rental expense was $1.3 million in 2000, $1.3 million in 1999 and $2.1 million in 1998. These figures exclude the charter payments during 2000 for the FPSO, which totaled $3.2 million and were capitalized in inventory at December 31, 2000. We have chartered the FPSO through November 2002, with options to extend the charter for five additional one-year periods. At December 31, 2000, the minimum payments required under terms of the leases, including the FPSO charter, were as follows: 2001 -- $31.4 million; 2002 -- $28.9 million; 2003 -- $1.9 million; 2004 -- $1.7 million; and 2005 -- $1.0 million. For additional information on our leases, including our office leases, see note 18 of Notes to Consolidated Financial Statements. EMPLOYEES At March 6, 2001, we employed approximately 195 full-time employees. EXECUTIVE OFFICERS The following table sets forth certain information regarding our executive officers at March 6, 2001: SERVED WITH ----------- TRITON ----------- NAME AGE POSITION WITH TRITON SINCE ------------------ --- ---------------------------------- ----------- James C. Musselman 53 President and Chief Executive Officer 1998 A.E. Turner, III 52 Senior Vice President and Chief Operating Officer 1994 W. Greg Dunlevy 45 Senior Vice President, Chief Financial Officer and Treasurer 1993 Brian Maxted 43 Senior Vice President, Exploration 1994 Marvin Garrett 45 Vice President, Production 1994 Mr. Musselman was elected as a director in May 1998, and was elected Chief Executive Officer in October 1998. Mr. Musselman has served as Chairman, President and Chief Executive Officer of Avia Energy Development, LLC, a private company engaged in gas processing and drilling, since September 1994. From June 1991 to September 1994, Mr. Musselman was the President and Chief Executive Officer of Lone Star Jockey Club, LLC, a company formed to organize a horse racetrack facility in Texas. Mr. Turner was elected Senior Vice President and Chief Operating Officer in March 1999, and prior to that served as Senior Vice President, Operations, since 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. Mr. Dunlevy has served as Senior Vice President and Chief Financial Officer since September 2000. Mr. Dunlevy joined Triton in 1993 as Vice President, Investor Relations and became Treasurer in July 1998. He became Vice President, Finance in March 2000. Mr. Maxted has served as Senior Vice President, Exploration since September 2000. He served as Vice President, Exploration, since January 1998, and prior to that served as Exploration Manager of Carigali-Triton Operating Company where he led exploration activities in the Gulf of Thailand from 1994 to 1998. From 1979 to 1994, Mr. Maxted was employed by British Petroleum in various capacities, including Exploration Manager, Colombia from 1990 to 1992 and License Manager, Norway from 1992 to 1994. Mr. Garrett has served as Vice President, Production, since December 1999, and prior to that served in various capacities within our Operations Department since August 1994, including most recently as Director, Operations. Prior to joining Triton in August 1994, Mr. Garrett served in various positions with British Gas Exploration and Production, Inc., including General Manager and Managing Director of Zaafarana Joint Operating Company in Cairo, Egypt. Our executive officers are elected annually by the Board of Directors to serve until removed or their successors are duly elected and qualified. There are no family relationships among our executive officers. CERTAIN DEFINITIONS As used in this report: - "Bbl" means barrel; - "Bcf" means billion cubic feet; - "BOPD" means barrels of crude oil per day; - "BOE" means barrels of oil equivalent; - "Mcf" means thousand cubic feet; - "MMcf means million cubic feet; - "Mbbls" means thousand barrels; - "MMbtu" means million British thermal unit; and - "Tcf" means trillion cubic feet; and - "WTI" means the West Texas Intermediate price index. ITEM 3. LEGAL PROCEEDINGS In July through October 1998, eight lawsuits were filed against Triton and Thomas G. Finck and Peter Rugg, in their capacities as former officers of Triton. The lawsuits were filed in the United States District Court for the Eastern District of Texas, Texarkana Division, and have been consolidated and are styled In re: Triton Energy Limited Securities Litigation. The consolidated complaint alleges violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder, in connection with disclosures concerning our properties, operations, and value relating to a prospective sale in 1998 of Triton or of all or a part of our assets. The lawsuits seek recovery of an unspecified amount of compensatory damages, fees and costs. We have filed a motion to dismiss the claims, which is pending. We believe our disclosures were accurate and intend to vigorously defend these actions. We cannot assure you that the litigation will be resolved in our favor. An adverse result could have a material adverse effect on our financial position or results of operations. In November 1999, a lawsuit was filed against us, one of our subsidiaries and Thomas G. Finck and Peter Rugg, in their capacities as former officers of Triton, in the District Court of the State of Texas for Dallas County. The lawsuit is styled Aaron Sherman, et al. vs. Triton Energy Corporation et al. and, as amended, alleges as causes of action fraud, negligent misrepresentation and violations of the Texas securities fraud statutes in connection with our 1996 reorganization as a Cayman Islands corporation and disclosures concerning our prospective sale of all or a substantial part of our assets announced in March 1998. In their most recent filling, the plaintiffs asserted actual damages of up to $10 million and sought punitive damages of up to $50 million. We have filed various motions to dispose of the lawsuit on the grounds that the plaintiffs do not have standing and have not plead causes of action cognizable in law. The court has dismissed all claims of certain plaintiffs and some claims of the remaining plaintiffs for failure to plead viable causes of action. The Court has entered an order for proceedings in connection with further examination of plaintiffs' claims. In August 1997, we were sued in the Superior Court of the State of California for the County of Los Angeles, by David A. Hite, Nordell International Resources Ltd., and International Veronex Resources, Ltd. The action was removed to the United States District Court for the Central District of California. We and the plaintiffs were adversaries in a 1990 arbitration proceeding in which the interest of Nordell International Resources Ltd. in the Enim oil field in Indonesia was awarded to us (subject to a 5% net profits interest for Nordell) and Nordell was ordered to pay us nearly $1 million. The arbitration award was followed by a series of legal actions by the parties in which the validity of the award and its enforcement were at issue. As a result of these proceedings, the award was ultimately upheld and enforced. The current suit alleges that the plaintiffs were damaged in amounts aggregating $13 million primarily because of our prosecution of various claims against the plaintiffs, as well as our alleged misrepresentations, infliction of emotional distress, and improper accounting practices. The suit seeks specific performance of the arbitration award, damages for alleged fraud and misrepresentation in accounting for Enim field operating results, an accounting for Nordell's 5% net profit interest, and damages for emotional distress and various other alleged torts. The suit seeks interest, punitive damages and attorneys fees in addition to the alleged actual damages. In August 1998, the district court dismissed all claims asserted by the plaintiffs other than claims for malicious prosecution and abuse of the legal process, which the court held could not be subject to a motion to dismiss. The abuse of process claim was later withdrawn, and the damages sought were reduced to approximately $700,000 (not including punitive damages). The lawsuit was tried and the jury found in favor of the plaintiffs and assessed compensatory damages against us in the amount of approximately $700,000 and punitive damages in the amount of approximately $11 million. We believe we have acted appropriately, and we have appealed the verdict. Nordell has cross-appealed from the dismissal of its claims for an audit and an accounting related to the 5% net profits interest. Enforcement of the judgment was stayed without a bond pending the outcome of the appeal. During the quarter ended September 30, 1995, the United States Environmental Protection Agency ("EPA") and Justice Department advised us that one of our 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. Our 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, our subsidiary declined to accept the offer. In October 1997, the EPA advised us that the estimated cost of the clean-up of the site would be approximately $217 million to be allocated among the 280 known operators. Our subsidiary's share would be approximately $1 million based upon a volumetric allocation, but there can be no assurance that any allocation of liability to the subsidiary would be made on a volumetric basis. No proceeding has been brought in any court against us or our subsidiary in this matter. In addition to the matters described above, we are also subject to litigation that is incidental to our business. Certain Factors Relating to Litigation Matters We do not expect that the legal matters described above will have a material adverse effect on our consolidated financial position, results of operations and cash flows. However, this is a forward-looking statement that is dependent on certain events and uncertainties that may be outside of our control. Actual results and developments could differ materially from our 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 we may elect to settle claims at amounts that exceed our expected liability for the 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 We did not submit any matter to our security holders, through the solicitation of proxies or otherwise, during the fourth quarter of 2000.
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PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS ORDINARY SHARES Our ordinary shares are listed on the New York Stock Exchange and are traded under the symbol "OIL." The following table sets forth the high and low sales prices of our ordinary shares as reported on the New York Stock Exchange Composite Tape for the periods indicated: CALENDAR PERIODS HIGH LOW -------------------------------- ----- ----- 2001: First Quarter* 30.75 19.24 2000: Fourth Quarter 39.75 22.81 Third Quarter 50.88 34.13 Second Quarter 41.00 29.06 First Quarter 38.06 19.19 1999: Fourth Quarter 27.50 13.50 Third Quarter 14.69 10.00 Second Quarter 16.00 6.94 First Quarter 8.88 5.19 ________________________________ *Through March 6, 2001. The holders of ordinary shares are only entitled to receive such dividends as are declared by our Board of Directors. Under applicable corporate law, the Board of Directors may declare dividends or make other distributions to our shareholders in such amounts as appear to the directors to be justified by our profits or out of our share premium account if we have the ability to pay our debts as they come due. Our current intent is to retain earnings for use in our business and the financing of our capital requirements. The payment of any future cash dividends on the ordinary shares is necessarily dependent upon our earnings and financial needs, along with applicable legal and contractual restrictions. We are prohibited from paying cash dividends on the ordinary shares under both our revolving credit facility and our shareholders agreement with HM4 Triton, L.P. unless we get those parties' consents, and we are limited in the amount of dividends we could pay by the indenture governing the terms of our 8 7/8% Senior Notes due 2007. In addition, under the terms of our 8% Convertible Preference Shares, we may not pay a dividend or other distribution on the ordinary shares unless all dividends on the 8% Convertible Preference Shares have been paid in full or set aside for payment. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and note 9 of Notes to Consolidated Financial Statements. There is no tax treaty between the United States and the Cayman Islands. At March 6, 2001, there were 3,808 record holders of our ordinary shares. 8% CONVERTIBLE PREFERENCE SHARES We have one series of preference shares outstanding, the 8% Convertible Preference Shares. As of March 6, 2001, there were outstanding 5,180,761 8% Convertible Preference Shares. The following summary of certain provisions of the resolutions establishing the terms of the 8% Convertible Preference Shares is not complete. You should refer to the resolutions, a copy of which was filed as an exhibit to our Quarterly Report on Form 10-Q for the quarter ended September 30, 1998. Dividends. We are required to pay dividends on the 8% Convertible --------- Preference Shares semiannually at the rate of 8% per year of the stated value of $70 per share for each semiannual dividend period ending on June 30 and December 31 of each year. Dividends on the 8% Convertible Preference Shares are cumulative. We can choose to pay dividends in cash or in additional 8% Convertible Preference Shares. If we pay a dividend in additional shares, the number of additional shares we would issue is determined by dividing the amount of the dividend by $70, with amounts in respect of any fractional shares to be paid in cash. If we were to fail to pay an accumulated dividend on the 8% Convertible Preference Shares, the unpaid dividends would be added to the stated value of the 8% Convertible Preference Shares, and thereafter dividends would accumulate and be paid based on the adjusted stated value. We are limited in the amount of dividends we may pay in cash by the terms of the indenture under which our 8 7/8% Senior Notes due 2007 were issued as well as by our revolving credit facility. In the event that, at a time a dividend is required to be paid under the terms of the 8% Convertible Preference Shares, the dividend would exceed the applicable limits, we may be required to pay the dividend in additional 8% Convertible Preference Shares. Conversion. Holders of 8% Convertible Preference Shares generally have the ---------- right to convert their 8% Convertible Preference Shares into ordinary shares at any time before redemption at the conversion price in effect at the time of conversion. The current conversion price is $17.50 per ordinary share so that each 8% Convertible Preference Share is convertible into four ordinary shares. The conversion price is subject to adjustment under certain circumstances. Upon the conversion of 8% Convertible Preference Shares, the holder is also entitled to receive an amount in cash equal to all accumulated and unpaid dividends on the 8% Convertible Preference Shares converted through the effective date of conversion. Redemption. We cannot redeem the 8% Convertible Preference Shares before ---------- September 30, 2001. Beginning September 30, 2001, we can redeem all, but not less than all, of the outstanding 8% Convertible Preference Shares if the average market value of the ordinary shares as calculated below is above certain market values. The redemption price is equal to $70 per share, plus an amount equal to all accumulated but unpaid dividends, and is payable in cash. The average market value is determined by averaging the closing price of the ordinary shares for the 20 trading days preceding the notice of redemption. We may only redeem the 8% Convertible Preference Shares if this average market value exceeds the average market value corresponding to the six-month period set forth below: REDEMPTION NOTICE GIVEN IN THE SIX-MONTH PERIOD: AVERAGE MARKET VALUE ------------------------------------------------ --------------------- September 30, 2001 through March 31, 2002 $ 28.54 April 1, 2002 through September 30, 2002 31.14 October 1, 2002 through March 31, 2003 34.20 April 1, 2003 through September 30, 2003 37.58 October 1, 2003 through March 31, 2004 32.57 April 1, 2004 through September 30, 2004 34.97 October 1, 2004 through March 31, 2005 37.60 Beginning April 1, 2005, the minimum average market value will be increased every six months to reflect an internal rate of return of 20% assuming a holder purchased 8% Convertible Preference Shares on September 30, 1998. The minimum average prices set forth above will be adjusted in the event of any combination, subdivision or reclassification of ordinary shares, or any similar event. Liquidation Rights. The liquidation preference of the 8% Convertible ------------------- Preference Shares is $70 per share, plus accumulated and unpaid dividends. In the event we undergo a liquidation, dissolution or winding up, before any payment or distribution can be made to the holders of our ordinary shares or any other class or series of our shares ranking junior to the 8% Convertible Preference Shares as to both dividends and liquidation rights, the holders of the 8% Convertible Preference Shares will be entitled to receive their liquidation preference and any accumulated and unpaid dividends. Voting Rights. The holders of the 8% Convertible Preference Shares -------------- generally vote with the holders of the ordinary shares on all matters brought before our shareholders. When voting with the holders of the ordinary shares, the holders of the 8% Convertible Preference Shares have the number of votes for each share that they would have if they had converted their shares into ordinary shares on the related record date. In addition, the holders of the 8% Convertible Preference Shares will be entitled to elect two directors of Triton if we do not pay dividends on the 8% Convertible Preference Shares under certain circumstances. When voting as a class, the holders of the 8% Convertible Preference Shares have one vote per share. The rights of the 8% Convertible Preference Shares may not be varied without the consent of the holders of at least two-thirds of the 8% Convertible Preference Shares. We cannot create a class of equity securities ranking senior to the 8% Convertible Preference Shares as to dividend or liquidation rights, other than out of our existing authorized shares of "blank check" preference shares, or adopt charter amendments materially adversely affecting the rights of the 8% Convertible Preference Shares, without the consent of the holders of at least two-thirds of the outstanding 8% Convertible Preference Shares. In addition, we cannot increase the authorized number of 8% Convertible Preference Shares, or create a class of equity securities ranking equal to the 8% Convertible Preference Shares as to dividend or liquidation rights, other than out of our existing authorized shares of "blank check" preference shares, without the consent of the holders of at least a majority of the outstanding 8% Convertible Preference Shares. Shareholders Agreement with HM4 Triton, L.P. We have entered into a ------------------------------------------------- shareholders agreement with HM4 Triton, L.P. The shareholders agreement provides that, in general, for so long as the entire board of directors consists of 10 members, HM4 Triton, L.P. may designate four nominees for election to the board of directors, with any fractional directorship rounded up to the next whole number. If HM4 Triton, L.P. transfers its 8% Convertible Preference Shares, it may also assign its right to designate Triton directors for nomination. The number of designees HM4 Triton, L.P. may designate will increase or decrease proportionately with any change in the total number of members of the board of directors. The right of HM4 Triton, L.P. and its designated transferees to designate nominees for election to the board of directors will be reduced if the number of ordinary shares held by HM4 Triton, L.P. and its affiliates represents less than certain specified percentages of the number of shares HM4 Triton, L.P. purchased from us under the stock purchase agreement between HM4 Triton, L.P. and us. These percentages are calculated assuming HM4 Triton, L.P. converts all of its 8% Convertible Preference Shares into ordinary shares. In the shareholders agreement, we also agreed that we would not take specified fundamental corporate actions without the consent of HM4 Triton, L.P. Some of the actions that would require HM4 Triton, L.P.'s consent are listed below: - amending our Articles of Association or the terms of the 8% Convertible Preference Shares with respect to the voting powers, rights or preferences of the holders of 8% Convertible Preference Shares, - entering into a merger or similar business combination transaction, or effecting a reorganization, recapitalization or other transaction pursuant to which a majority of the outstanding ordinary shares or any 8% Convertible Preference Shares are exchanged for securities, cash or other property; - authorizing, creating or modifying the terms of any securities that would rank equal to or senior to the 8% Convertible Preference Shares; - selling assets comprising more than 50% of our market value; - paying dividends on our ordinary shares or other shares ranking junior to the 8% Convertible Preference Shares; - incurring debt over a specified amount; and - commencing a tender offer or exchange offer for any of our ordinary shares. SHAREHOLDER RIGHTS PLAN We have adopted a shareholder rights plan. Under this plan, preference share rights attach to all ordinary shares at the rate of one right for each ordinary share. Each right entitles the holder of our ordinary shares to purchase one one-thousandth of our Series A Junior Participating Preference Shares at a price of $120 per one one-thousandth of a Series A Junior Preference Share, subject to adjustment. Generally, these rights would only become distributable 10 days following a public announcement that a person has acquired beneficial ownership of 15% or more of our ordinary shares or 10 business days following commencement of a tender offer or exchange offer for 15% or more of our outstanding ordinary shares. If, among other events, any person becomes the beneficial owner of 15% or more of our ordinary shares, each right not owned by that person generally becomes the right to purchase a number of ordinary shares 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 we are subsequently merged or certain other extraordinary business transactions are consummated, each right generally becomes a right to purchase a 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. Pursuant to the terms of the plan, any acquisition of Triton shares by HM4 Triton, L.P. or its affiliates will not result in the distribution of rights unless and until HM4 Triton, L.P.'s ownership of Triton shares is reduced below certain levels. Under certain circumstances, our board of directors may determine that a tender offer or merger is fair to all our 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 and prior to the acquisition by that person or group of 50% or more of the outstanding ordinary shares, our board of directors may exchange the rights, 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 board of directors may not exchange the rights owned by the person or group who acquired 50% or more of the outstanding ordinary shares. Their rights will become void. We can amend the rights, except the redemption price, in any manner prior to the public announcement that a 15% position has been acquired or a tender offer has been commenced. We can redeem the rights at $0.01 per right at any time prior to the time that a 15% position has been acquired. The rights will expire on May 22, 2005, unless we redeem the rights before then. ITEM 6. SELECTED FINANCIAL DATA The following table sets forth certain financial and oil and gas data on a historical basis. We adopted Securities and Exchange Commission Staff Accounting Bulletin (SAB) 101, Revenue Recognition in Financial Statements, effective January 1, 2000, which requires us to record oil revenue on each sale, or tanker lifting, and our oil inventories at cost, rather than at market value as in the past. The cumulative effect of this change for periods prior to January 1, 2000 is a reduction in net earnings of $1.3 million, or $0.03 per diluted share and is shown as the cumulative effect of accounting change in the Consolidated Statements of Operations. Pro forma net earnings, adjusted for the new accounting principle, would have decreased by $.1 million for 1999 and increased by $.1 million for 1998. [Enlarge/Download Table] AS OF OR FOR YEAR ENDED DECEMBER 31, ------------------------------------------------------- 2000 1999 1998 1997 1996 ---------- --------- --------- ---------- --------- OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA): Oil and gas sales $ 328,467 $ 247,878 $ 160,881 $ 145,419 $ 129,795 Sales and other operating revenues 328,467 247,878 228,618 149,496 133,977 Earnings (loss) before extraordinary item and cumulative effect of accounting change 75,680 47,557 (187,504) 5,595 23,805 Net earnings (loss) 67,373 47,557 (187,504) (8,896) 22,609 Average ordinary shares outstanding 36,551 36,135 36,609 36,471 35,929 Basic earnings (loss) per ordinary share: Earnings (loss) before extraordinary item and cumulative effect of accounting change $ 1.27 $ 0.52 $ (5.21) $ 0.14 $ 0.64 Net earnings (loss) 1.04 0.52 (5.21) (0.26) 0.61 Diluted earnings (loss) per ordinary share: Earnings (loss) before extraordinary item and cumulative effect of accounting change $ 1.20 $ 0.52 $ (5.21) $ 0.14 $ 0.62 Net earnings (loss) 0.99 0.52 (5.21) (0.25) 0.59 BALANCE SHEET DATA (IN THOUSANDS): Net property and equipment $ 687,511 $ 524,152 $ 470,907 $ 835,506 $ 676,833 Total assets 1,194,280 974,475 754,280 1,098,039 914,524 Long-term debt, including current maturities (1) 504,696 413,487 427,492 573,687 416,630 Shareholders' equity 525,016 463,052 223,807 296,620 300,644 CERTAIN OIL AND GAS DATA (2) : Production Sales volumes (Mbbls) (3) 11,167 12,469 9,979 5,776 5,987 Forward oil sale deliveries (Mbbls) 762 3,050 3,050 2,462 701 ---------- --------- ---------- ---------- --------- Total revenue barrels (Mbbls) 11,929 15,519 13,029 8,238 6,688 ========== ========= ========== =========== ======== Gas (MMcf) 470 459 503 802 2,517 Average sales price Oil (per Bbl) (4) $ 27.48 $ 15.95 $ 12.31 $ 17.54 $ 19.61 Gas (per Mcf) $ 1.34 $ 0.88 $ 0.99 $ 1.15 $ 1.69 _________________________ (1) Includes current maturities totaling $4.6 million for 2000, $9.0 million for 1999, $14.0 million for 1998, $130.4 million for 1997 and $199.6 million for 1996. (2) Information presented includes the 49.9% equity investment in Crusader Limited until its sale in 1996. (3) Includes natural gas liquids and condensate. (4) Includes barrels delivered under the forward oil sale, which are recognized in oil and gas sales at $11.56 per barrel upon delivery.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS You should read the following discussion and analysis in conjunction with our financial information and our consolidated financial statements and notes to those statements included in this report. The following information contains forward-looking statements. For a discussion of limitations inherent in forward-looking statements, see "Disclosure Regarding Forward-Looking Information" and "Certain Factors That Could Affect Future Operations" below. LIQUIDITY AND CAPITAL REQUIREMENTS Cash and equivalents totaled $136.4 million at December 31, 2000, and $186.3 million at December 31, 1999. Working capital was $63.3 million at December 31, 2000, and $161.3 million at December 31, 1999. The following summary table reflects our cash flows for the years ended December 31, 2000, 1999 and 1998 (in thousands): [Download Table] 2000 1999 1998 --------- --------- -------- Net cash provided (used) by operating activities $ 187,224 $ 116,522 $ 1,466 Net cash provided (used) by investing activities $(321,733) $(118,530) $ 84,191 Net cash provided (used) by financing activities $ 84,710 $ 170,143 $(80,071) Net Cash Provided (Used) by Operating Activities ------------------------------------------------ Our production from the Cusiana and Cupiagua fields in Colombia was responsible for all of our cash flows provided by operating activities in 2000. Our cash flows benefited from a higher average realized oil price, but this benefit was partially offset by a decrease in production in 2000 compared with 1999. Our average realized oil price per barrel was $27.48 in 2000, compared with $15.95 in 1999 and $12.31 in 1998. Gross production from the Cusiana and Cupiagua fields averaged 339,000 barrels of oil per day ("BOPD") (32,500 net to our interest) during 2000, 430,000 BOPD (41,300 net to our interest) during 1999 and 350,000 BOPD (33,600 net to our interest) during 1998. See "Results of Operations - Oil and Gas Sales" below. Cash flows from operating activities in 2000 relative to 1999 also benefited from the expiration of our crude oil delivery requirement under a forward oil sale we entered into in 1995. In May 1995, we sold oil forward to a third party for a lump sum payment, which required us to deliver to the purchaser a fixed amount of production each month until the contract's expiration in March 2000. We recognized as revenue $11.56 per barrel delivered under the forward oil sale. We completed the deliveries at the end of the first quarter of 2000, at which time we were delivering 254,136 barrels per month. Because of the expiration of the forward oil sale, during the second, third and fourth quarters of 2000, we were able to sell all of our production at the higher market price, although we did hedge the price of some of our production. During 1999, we received substantially all of the remaining proceeds, approximately $31.9 million, from this forward oil sale.
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For 2001, our cash flows from operating activities will benefit from the sale of Ceiba field production in Equatorial Guinea. Production from the Ceiba field began in November 2000, but the first sale did not occur until January 2001. We expect gross production from the Ceiba field to average approximately 37,000 BOPD to 43,000 BOPD (26,000 to 30,000 net to us) during 2001. Based on a production forecast from the operator of the Cusiana and Cupiagua fields in Colombia, we are estimating that average gross production from these fields will be approximately 270,000 BOPD to 280,000 BOPD (26,000 to 27,000 net to us) in 2001. Our actual production rates in 2001 will depend on a number of factors and are subject to a number of uncertainties, and thus we cannot assure you that actual production rates will meet our expectations. Prices for our production in Colombia historically are based off of West Texas Intermediate ("WTI") prices. With regard to sales of our Ceiba production, through March 2001 there were only three sales, and they have been based off of the price of Dated Brent, adjusted for quality and location. The differential on our most recent sale was negative $4.60 per barrel. We believe that the discounts to date reflect the fact that, for operational reasons, we have limited sales to relatively smaller cargo vessels capable of loading quantities of 1,000,000 barrels or less. In addition, the Ceiba crude is a relatively new crude oil previously unknown to refiners, with an acid quality that certain refiners will not readily be able to process, which could discourage refiners from purchasing the crude without a price discount. We believe that, as our operational efficiency improves to permit us to market the crude to larger vessels, and therefore to a greater number of refiners, the price of Ceiba crude in relation to applicable benchmarks should improve. We cannot assure you that this price differential will improve or if it does, that it will improve by a material amount. Net Cash Provided (Used) by Investing Activities ------------------------------------------------------ Our capital expenditures and other capital investments, excluding acquisitions, were $232.7 million in 2000, $121.5 million in 1999 and $180.2 million in 1998. Capital expenditures in 2000 were primarily for development of the Ceiba field and exploration activities in Equatorial Guinea ($157.4 million) and for development of the Cusiana and Cupiagua fields in Colombia ($41.5 million). Restructuring activities undertaken in 1998 contributed to lower capital spending in 1999. Proceeds from asset sales were $2.4 million during 1999 and $267 million during 1998. See "Results of Operations" below and note 2 of Notes to Consolidated Financial Statements. In May 2000, we acquired from an unrelated third party, for $88.7 million in cash 100% of the shares of Triton Pipeline Colombia, Inc., whose sole asset is its 9.6% equity interest in Oleoducto Central S.A. ("OCENSA"). OCENSA is the Colombian pipeline company formed in 1994 by Empresa Colombiana De Petroleos ("Ecopetrol"), the Colombian national oil company, BP Amoco p.l.c. ("BP"), TotalFinaElf SA ("TOTAL"), Triton Pipeline Colombia, IPL Enterprises (Colombia) Inc. and TCPL International Investments Inc. to own and operate the pipeline and port facilities that handle and transport crude oil from the Cusiana and Cupiagua fields to the Caribbean port of Covenas. We had sold Triton Pipeline Colombia in February 1998. Net Cash Provided (Used) by Financing Activities ------------------------------------------------------ In February 2000, we entered into an unsecured two-year revolving credit facility with a group of banks, which matures in February 2002. The credit facility gives us the right to borrow from time to time up to the amount of the borrowing base determined by the banks, not to exceed $150 million. As a result of the issuance of the 8 7/8% Senior Notes and the redemption of the 8 3/4% Senior Notes, the borrowing base was adjusted to $50 million, subject to any future redetermination of the borrowing base as provided in the agreement. The credit facility contains various restrictive covenants, including covenants that require us to maintain a ratio of earnings before interest, depreciation, depletion, amortization and income taxes to net interest expense of at least 2.5 to 1 on a trailing-four-quarters basis. The restrictive covenants also prohibit us from permitting net debt to exceed the product of 3.75 times our earnings before interest, depreciation, depletion, amortization and income taxes on a trailing-four-quarters basis. As of March 6, 2001, we had no borrowings outstanding under the facility. In October 2000, we issued $300 million face value of 8 7/8% Senior Notes due 2007 for proceeds of $300 million before deducting transaction costs of approximately $6 million. Interest is payable semiannually on April 1 and October 1, commencing April 1, 2001. We have the option to redeem the 8 7/8% Senior Notes, in whole or in part, at any time on or after October 1, 2004. In addition, we can redeem up to $105 million of the 8 7/8% Senior Notes using proceeds of any equity offerings we may complete before October 1, 2003. The indenture governing the 8 7/8% Senior Notes contains various restrictive covenants that limit our ability to borrow money or guarantee other debt, create liens, make investments, use assets as security in other transactions, pay dividends on stock, enter into sale/leaseback transactions, sell assets, and merge or consolidate. The indenture provides that we may not incur additional debt unless at the time of the incurrence the ratio of our consolidated earnings before interest, income taxes, depreciation, depletion, amortization and writedowns to the sum of interest expense and capitalized interest is at least 2.5 to 1. Notwithstanding this limit, the indenture does permit us to incur certain indebtedness even if we do not meet this limitation. For example, we can incur indebtedness to financial institutions, such as our unsecured revolving credit facility described above, in an amount up to $250 million or the amount obtained by adding $100 million to 20% of our adjusted net tangible assets, whichever is greater. In November 2000, we used approximately $207 million of the net proceeds from the sale of the 8 7/8% Senior Notes to redeem all of our outstanding 8 3/4% Senior Notes due 2002 at a price, including accrued interest, of $1,038.40 for each $1,000 note outstanding. In September 2000, we called for redemption all of our outstanding 5% Convertible Preference Shares. Each 5% Convertible Preference Share was convertible into one ordinary share. A total of 107,075 shares were converted into ordinary shares, and the remaining 78,201 shares were redeemed for cash at the redemption price of $34.56 per share totaling $2.7 million. The redemption price represented the stated value of $34.41 plus the amount of dividends that accrued per share from September 30, 2000, through the redemption date of October 31, 2000. During 2000, we repaid borrowings of $9 million under a term credit facility and paid cash preference-share dividends totaling $14.9 million. Proceeds from issuances of ordinary shares under our stock compensation plans totaled $26.5 million for 2000. During 1999, we repaid borrowings totaling $19 million, including $10 million under unsecured credit facilities that were outstanding at December 31, 1998. By December 31, 1999, all of our unsecured revolving credit facilities that were outstanding at December 31, 1998, had expired. In addition, we paid cash preference-share dividends totaling $17.6 million and a dividend in additional 8% Convertible Preference Shares totaling $13.7 million. In April 1999, our Board of Directors authorized a share repurchase program enabling us to repurchase up to 10% of our then-outstanding 36.7 million ordinary shares. We purchased 948,300 ordinary shares in 1999 under this program for $11.3 million. Because of our capital needs in Equatorial Guinea, we did not repurchase any shares under the program in 2000. In addition, our revolving credit facility, entered into in February 2000, generally does not permit us to repurchase our ordinary shares without the banks' consent. In two stages, in late 1998 and early 1999, we issued $350 million of 8% Convertible Preference Shares. At the closing of the first stage in September 1998, we issued 1,822,500 shares of 8% Convertible Preference Shares for $70 per share (for proceeds of $116.8 million, net of transaction costs), all of which were purchased by HM4 Triton, L.P. At the closing of the second stage in January 1999, which was effected through a rights offering, we issued an additional 3,177,500 8% Convertible Preference Shares for proceeds totaling $217.8 million, net of closing costs, of which HM4 Triton L.P. purchased 3,114,863 shares. Each 8% Convertible Preference Share is convertible into four ordinary shares, subject to adjustment upon the occurrence of specified events. During 1998, we borrowed $162.5 million and repaid $360.1 million under revolving lines of credit, notes payable and long-term debt. We terminated a $125 million revolving credit facility during 1998 upon the repayment of the amounts then outstanding. Future Capital Needs ---------------------- Our capital spending program for the year ending December 31, 2001, is approximately $320 million, excluding capitalized interest and acquisitions, of which approximately $253 million relates to exploration and development activities in Equatorial Guinea, $39 million relates to exploration and development activities in Colombia and $28 million relates to our exploration activities in other parts of the world. In Equatorial Guinea, during 2000, we successfully implemented an accelerated appraisal and development program for the Ceiba field, drilling the Ceiba-3, -4 and -5 subsea production wells. We commenced production in November 2000, achieved production from three wells by the end of 2000, and, in February 2001, we completed and commenced production from the fourth production well. The wells are connected through flowlines to a floating production, storage and offloading vessel ("FPSO") that we lease. Based on our development plan and production history to date, we expect gross production from the Ceiba field to average approximately 37,000 BOPD to 43,000 BOPD (26,000 to 30,000 net to us) during 2001. We cannot assure you that actual production rates from this field will meet our expectations. Actual production rates will depend on well and reservoir performance, our ability to improve pressure support through water injection and other factors. The current plan for development calls for a total of 10 production wells and four water injection wells, including the production wells that already have been drilled. Our plan is to have the water injection wells and at least seven production wells drilled and completed in 2001, and the remaining production wells drilled and completed in 2002. In connection with the next phase of development, we are planning to increase the processing capacity of the FPSO from 60,000 barrels of fluids per day to approximately 160,000 barrels of fluids per day and to install onboard water-injection facilities to inject up to 135,000 barrels per day of water. We expect that the additional wells and production and water-injection facilities will enable us to increase production in 2002. We are uncertain as to what the production rate will be in this latter phase of development. The actual production rate will depend on a number of factors, including the timing of the completion of the additional production and water-injection facilities, well performance, the timing of the connection of the production and water injection wells to the FPSO, reservoir performance, our ability to improve pressure support through water injection and other factors. In order to install the necessary equipment to increase the processing capacity of the facilities, we expect that we will be required to temporarily halt production from the Ceiba field. Currently, we expect that this production halt will begin in December 2001 and will last approximately four weeks. We expect to fund 2001 capital spending with a combination of some or all of the following: cash flow from operations, cash, our unsecured revolving bank credit facility, and the issuance of debt or equity securities. To facilitate a possible future securities issuance or issuances, we have on file with the Securities and Exchange Commission a shelf registration statement under which we could issue up to an aggregate of $250 million debt or equity securities. At December 31, 2000, we had guaranteed the performance of a total of $7.3 million in future exploration expenditures to be incurred through 2001 in Greece. This commitment is backed primarily by an unsecured letter of credit In addition, at December 31, 2000, we were committed to make lease payments, including under the FPSO charter, totaling $31.4 million in 2001 and $28.9 million in 2002. RESULTS OF OPERATIONS During the three-year period ended December 31, 2000, all of our oil and gas sales were derived from our operations in Colombia, as follows: YEAR ENDED DECEMBER 31, ------------------------- 2000 1999 1998 ------- ------- ------- Sales volumes: Oil (Mbbls), excluding forward oil sale 11,167 12,469 9,979 Forward oil sale (Mbbls delivered) 762 3,050 3,050 ------- ------- ------- Total 11,929 15,519 13,029 ======= ======= ======= Gas (MMcf) 470 459 503 Weighted average price realized: Oil (per Bbl)(1) $ 27.48 $ 15.95 $ 12.31 Gas (per Mcf) $ 1.34 $ 0.88 $ 0.99 __________________________ (1) Includes the effect of barrels delivered under the forward oil sale, if applicable, that were recognized at $11.56 per barrel. 2000 COMPARED WITH 1999 Oil and Gas Sales -------------------- Oil and gas sales for 2000 totaled $328.5 million, a 33% increase from 1999. The average realized oil price increased $11.53 per barrel, or 72%, resulting in an increase in revenues of $137.6 million, compared with 1999. This increase was partially offset by lower production in Colombia. Sales volumes, including barrels delivered under the forward oil sale, decreased 23% in 2000, compared with the prior year, resulting in a revenue decrease of $57.2 million. Gross production from the Cusiana and Cupiagua fields averaged 339,000 BOPD (32,500 net to us) for 2000, compared with 430,000 BOPD (41,300 net to us) for the prior year. Although the fields are maturing and are in decline, the rate of decline in 2000 was greater than the operator, we and our engineers had expected. This greater rate of decline was primarily due to factors such as mechanical difficulties in some producing wells, scale buildup in some producing wells, which inhibits oil production and requires chemical treatment, a decrease in workovers, delayed drilling of new wells and the disappointing performance of some of the new wells that were drilled. The operator has devised a plan to enhance reservoir management by implementing a more aggressive well-maintenance and workover program. Based on this plan we are estimating that average gross production from the fields will be approximately 270,000 BOPD to 280,000 BOPD (26,000 to 27,000 net to us) in 2001. We cannot assure you that these attempts to offset the decline in production will be successful or that the Colombian fields will not continue to experience significantly less production than the operator, we and our engineers project. Production from the Ceiba field began in November 2000. We achieved our first tanker loading, or lifting, of Ceiba crude in January 2001. We expect 2001 revenues will increase as a result of production from the Ceiba field, with gross production expected to average approximately 37,000 BOPD to 43,000 BOPD (26,000 to 30,000 net to us) during 2001. We cannot assure you that actual production rates from this field will meet our expectations. We adopted Securities and Exchange Commission Staff Accounting Bulletin (SAB) 101, Revenue Recognition in Financial Statements, effective January 1, 2000, which requires us to record oil revenue on each sale, or tanker lifting, and our oil inventories at cost, rather than at market value as in the past. Sales of our crude oil in both Colombia and Equatorial Guinea are made when the crude oil is "lifted," or transferred to the buyer's tanker. The number of liftings occurring on a quarter-to-quarter basis may fluctuate based upon tanker availability and lifting schedules. In addition, while we will be marketing our crude oil in Equatorial Guinea collectively with that of our partner, currently the government expects to market its crude oil separately on a periodic basis as its share of production accumulates to a marketable quantity. As a result, we expect that our revenues on a quarter-to-quarter basis will be subject to variation depending on the timing of liftings of our production. In addition, our 2001 revenues will be subject to fluctuations in the market price for oil, as well as the discounts for quality and transportation discussed above and in "Items 1. and 2. Business and Properties - Oil and Gas Operations - Markets." We have entered into financial and commodity market transactions intended primarily to reduce risk associated with changing oil prices. Our oil sales were approximately $17.6 million less in 2000 and approximately $19.8 million less in 1999 than if we had not entered into those transactions. Looking forward, we have hedged the WTI and Dated Brent price components on a portion of our 2001 production. See "Item 7.A. Quantitative and Qualitative Disclosures About Market Risk" below. Operating Expenses ------------------- Operating expenses totaled $55.2 million in 2000, compared with $68.1 million in 1999. On an oil-equivalent barrel basis, operating expenses were $4.64 in 2000 and $4.50 in 1999. The decrease in operating expenses during 2000 was primarily due to lower pipeline tariffs in Colombia. One component of operating expenses is the tariff OCENSA charges us to transport our oil through its pipeline in Colombia. OCENSA pipeline tariffs totaled $29.6 million in 2000 and $42.1 million in 1999. After we acquired Triton Pipeline Colombia in 2000, we elected to cancel the dividend we would receive as an owner of OCENSA shares to reduce our tariff. The tariff OCENSA charges us, as well as the other owners of OCENSA, is the amount OCENSA estimates it needs to recoup the total capital cost of the project, amortized over a 15-year period; its operating expenses for the year, which include all Colombian taxes; its interest expense; and the dividend it must pay to any shareholder who has elected to receive a dividend. OCENSA charges other shippers of crude oil a tariff on a per-barrel basis, and OCENSA uses the revenues from those tariffs to reduce the tariff it charges us and its other shareholders. Depreciation, Depletion and Amortization ------------------------------------------- Depreciation, depletion and amortization decreased $6.3 million, primarily due to lower production volumes, which was partially offset by a higher depletion rate per barrel. Depletion per equivalent barrel of production was $4.37 in 2000 compared with $3.80 in 1999 as calculated using the unit-of-production method. We expect operating expenses and depreciation, depletion and amortization expense will increase in 2001 as a result of production from the Ceiba field in Equatorial Guinea, which began November 2000. General and Administrative Expenses -------------------------------------- General and administrative expenses before capitalization increased $4.6 million to $35.2 million in 2000, primarily due to increased activities associated with the development of the Ceiba field. Capitalized general and administrative costs were $11.1 million in 2000 and $6.9 million in 1999. Writedown of Assets --------------------- Following the acquisition of new acreage, reviews of our capital expenditure requirements and exploration portfolio during 2000, and other information management deemed relevant, we recorded a writedown of $36.7 million ($34.8 million after-tax) related to our operations onshore Italy, offshore Madagascar and offshore Greece. We also surrendered our interest in the Aitoloakarnania lease onshore Greece after drilling two dry holes and recorded a writedown of $18.7 million ($17.2 million after-tax) during 2000.
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Interest Expense, Net ----------------------- Gross interest expense totaled $41 million for 2000 and $37.2 million for 1999, while capitalized interest for 2000 increased $9.6 million to $24.1 million. We expect that gross interest expense will increase in future periods as a result of higher outstanding debt balances following the issuance of the 8 7/8% Senior Notes due 2007. We expect that the amount of gross interest expense that is capitalized will decrease in 2001, as capitalized oil and gas assets from the Ceiba field in Equatorial Guinea are placed in service. Income Taxes ------------- Statement of Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes," requires that we 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 and income tax laws can give rise to significant adjustments to our 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. Current taxes increased to $39.9 million in 2000 from $20.8 million in 1999 due to higher pretax income from Colombian operations. The income tax provisions included deferred tax expense of $21.2 million for 2000 and $7.8 million for 1999. During 2000, our tax expense was approximately $21 million lower due to anticipated utilization of NOLs from entities that were acquired during 1999 and 2000. At December 31, 2000, we had U.S. NOLs of approximately $383 million, compared with NOLs of approximately $450.2 million at December 31, 1999. The NOLs expire from 2001 to 2021. See note 7 of Notes to Consolidated Financial Statements. At December 31, 2000, we had NOLs in Equatorial Guinea totaling $176 million with an unlimited carryforward. In other countries outside the U.S., we had NOLs and other credit carryforwards totaling $30.1 million that will expire between 2001 and 2010. We recorded a U.S. deferred tax asset of $89 million, net of a valuation allowance of $48.7 million, at December 31, 2000. The valuation allowance was primarily attributable to our assessment of the utilization of NOLs in the U.S., the expectation that other tax credits will expire without being utilized, and the expectation that certain temporary differences will reverse without a benefit to us. The minimum amount of future taxable income necessary to realize the U.S. net deferred tax asset is approximately $254 million. Although we cannot assure you that we will achieve these levels of income, we believe the deferred tax asset will be realized through income from our operations or asset sales. Extraordinary Item - Extinguishment of Debt ------------------------------------------------ In November 2000, we used approximately $207 million of the net proceeds from the sale of the 8 7/8% Senior Notes to redeem all of our outstanding 8 3/4% Senior Notes due 2002 at a price, including accrued interest, of $1,038.40 for each $1,000 note outstanding. The extinguishment of the 8 3/4% Senior Notes due 2002 resulted in an extraordinary expense of approximately $7 million. Cumulative Effect of Accounting Change ------------------------------------------ We adopted Securities and Exchange Commission Staff Accounting Bulletin (SAB) 101, Revenue Recognition in Financial Statements, effective January 1, 2000, which requires us to record oil revenue on each sale, or tanker lifting, and our oil inventories at cost, rather than at market value as in the past. The cumulative effect of this change for periods prior to January 1, 2000 is a reduction in net earnings of $1.3 million, or $0.03 per diluted share, and is shown as the cumulative effect of accounting change in the Consolidated Statements of Operations. 1999 COMPARED WITH 1998 Oil and Gas Sales -------------------- Oil and gas sales in 1999 totaled $247.9 million, a 54% increase from 1998, due to higher average realized oil prices and higher production. The average realized oil price per barrel was $15.95 in 1999 and $12.31 in 1998, an increase of 30%, resulting in higher revenues of $56.4 million compared with 1998. Total revenue barrels, including production related to barrels delivered under the forward oil sale, totaled 15.5 million barrels in 1999, an increase of 19%, compared with the prior year, resulting in an increase in revenues of $30.7 million. The increased production was due primarily to the start-up during the second half of 1998 of two new 100,000 BOPD oil-production units at the Cupiagua central processing facility. We entered into financial and commodity market transactions intended primarily to reduce risk associated with changing oil prices for our production in 1999. During 1999, our oil sales were approximately $19.8 million less than if we had not entered into those transactions. Gain on Sale of Oil and Gas Assets ----------------------------------------- In August 1998, we sold to a subsidiary of BP (formerly The Atlantic Richfield Company, or ARCO) for $150 million, one-half of the shares of the subsidiary through which we owned our 50% share of Block A-18 in the Malaysia-Thailand Joint Development Area. The sale resulted in a gain of $63.2 million. In December 1998, we sold our Bangladesh subsidiary for $4.5 million and recorded a gain of the same amount. Operating Expenses ------------------- Operating expenses decreased $5.4 million in 1999. On an oil equivalent-barrel basis, operating expenses were $4.50 in 1999 and $5.97 in 1998. We paid lifting costs, production taxes and transportation costs to the Colombian port of Covenas for barrels to be delivered under the forward oil sale. Operating expenses on an oil equivalent-barrel basis were lower primarily due to higher production volumes. OCENSA pipeline tariffs totaled $42.1 million in 1999 and $49.9 million in 1998. Pipeline tariffs for 1999 were lower primarily due to a nonrecurring credit issued by OCENSA in February 2000 totaling $4.2 million. The credit resulted from OCENSA's compliance with a Colombian government decree in December 1999 that reduced its 1999 noncash expenses. Depreciation, Depletion and Amortization ------------------------------------------- Depreciation, depletion and amortization increased $2.5 million, primarily due to higher production volumes, including barrels delivered under the forward oil sale. Offsetting the effect of higher production, full cost ceiling test writedowns taken during 1998 reduced the per barrel depletion rate in 1999. General and Administrative Expenses -------------------------------------- General and administrative expenses before capitalization decreased $16.6 million from $47.2 million in 1998 to $30.6 million in 1999, while capitalized general and administrative costs were $6.9 million in 1999 and $20.6 million in 1998. General and administrative expenses, and the portion capitalized, decreased as a result of restructuring activities undertaken during the second half of 1998 and in March 1999. Writedown of Assets --------------------- We wrote down the carrying amount of our evaluated oil and gas properties in Colombia by $105.4 million ($68.5 million, net of tax) in June 1998 and $135.6 million ($115.9 million, net of tax) in December 1998, through application of the full cost ceiling limitation as prescribed by the Securities and Exchange Commission, principally as a result of a decline in oil prices. To calculate the limitation, at June 30, 1998, we used the WTI oil price of $14.18 per barrel, or approximately $13 per barrel after taking into account the differential for Cusiana crude delivered at the port of Covenas in Colombia, and at December 31, 1998, we used the WTI oil price of $12.05 per barrel, or approximately $11 per barrel after taking into account the differential. During 1998, we evaluated the recoverability of our approximate 6.6% investment in a Colombian pipeline company, Oleoducto de Colombia S.A. ("ODC"), which was accounted for under the cost method. Based on an analysis of the future cash flows expected to be received from ODC, we expensed the carrying value of our investment totaling $10.3 million. In July 1998, we commenced a plan to restructure our operations, reduce overhead costs and substantially scale back exploration-related expenditures. The plan contemplated the closing of foreign offices in four countries, the elimination of approximately 105 positions, or 41% of the worldwide workforce, and the relinquishment or other disposal of several exploration licenses. In conjunction with the plan to restructure operations and scale back exploration-related expenditures in 1998, we assessed our investments in exploration licenses and determined that certain investments were impaired. As a result, unevaluated oil and gas properties and other assets totaling $77.3 million ($72.6 million, net of tax) were expensed. The writedown included exploration-related activities totaling $27.2 million in Guatemala and $22.5 million in China. The remaining writedowns related to our exploration projects in certain other areas of the world.
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Special Charges ---------------- As a result of the restructuring, we recognized special charges of $15 million during the third quarter of 1998 and $3.3 million during the fourth quarter of 1998 for a total of $18.3 million. Of the $18.3 million in special charges, $14.5 million related to the reduction in workforce, and represented the estimated costs for severance, benefit continuation and outplacement costs, which were paid over a period of up to two years according to the severance formula. From July 1998 through December 31, 1999, we paid $13.1 million in severance, benefit continuation and outplacement costs. A total of $2.1 million of special charges related to the closing of foreign offices, and represented the estimated costs of terminating office leases and the write-off of related assets. The remaining special charges of $1.7 million primarily related to the write-off of other surplus fixed assets resulting from the reduction in workforce. At December 31, 1999, all of the positions had been eliminated, all designated foreign offices had been closed and all licenses had been relinquished or sold, or their commitments renegotiated. During the fourth quarter of 1999, we reversed $.7 million of the accrual associated with the substantial completion of restructuring activities. In March 1999, we accrued special charges of $1.2 million related to an additional 15% reduction in the number of employees resulting from our continuing efforts to reduce costs. The special charges consisted of $1 million for severance, benefit continuation and outplacement costs and $.2 million related to the write-off of surplus fixed assets. From March 1999 through December 31, 1999, we paid $.9 million in severance, benefit continuation and outplacement costs. In September 1999, we recognized special charges totaling $2.4 million related to the transfer of our working interest in Ecuador to a third party. Gain on Sale of Triton Pipeline Colombia ---------------------------------------------- In February 1998, we sold Triton Pipeline Colombia to an unrelated third party for $100 million. Net proceeds were approximately $97.7 million. The sale resulted in a gain of $50.2 million. Interest Expense, Net ----------------------- Gross interest expense totaled $37.2 million for 1999 and $46.4 million for 1998, while capitalized interest for 1999 decreased $8.7 million to $14.5 million. The decrease in capitalized interest is due primarily to the writedown of unevaluated oil and gas properties in June 1998 and a sale of 50% of our Block A-18 project in August 1998. Other Income (Expense), Net ------------------------------ Other income (expense), net, included a foreign exchange loss of $2.7 million in 1999 and a foreign exchange gain of $2.1 million in 1998. We recorded gains of $6.2 million in 1999 and $.4 million in 1998, representing the changes in the fair value of the call options we purchased in anticipation of the 1995 forward oil sale. In addition, we recorded an expense of $6.9 million in 1999 and $3.3 million in 1998 in other income (expense), net, related to the net payments made under and the change in the fair value of the equity swap entered into in conjunction with the sale of Triton Pipeline Colombia. We recorded loss provisions of $2.3 million in 1999 and $.8 million in 1998 for certain legal matters. In 1998, we recognized gains of $7.6 million on the sale of corporate assets in addition to the ARCO and Triton Pipeline Colombia transactions. RECENT ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board issued Statement No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities." This Statement was amended in June 2000 by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an Amendment of SFAS No. 133." The new statements establish accounting and reporting standards for derivative instruments and for hedging activities. The standards require us to recognize all derivatives as either assets or liabilities in our balance sheet and measure those instruments at fair value. The requisite accounting for changes in the fair value of a derivative will depend on the intended use of the derivative and the resulting designation. We have adopted the statements effective January 1, 2001, and thus the new accounting and reporting standards will be reflected for the first time in our financial statements for the first quarter of 2001. For financial and commodity market transactions in which we are hedging the variability of cash flows associated with our forecasted crude oil sales, the effective portion of changes in the fair value of the derivative instrument will be reported in comprehensive income in the period changes in fair value occur. These gains and losses will be recognized in earnings in the periods in which the related hedged sale of crude oil occurs. All changes in the value of derivative instruments not designated as hedges and the ineffective portion of changes in fair value of hedging transactions will be recognized in earnings in the period changes in fair value occur. In January 2001, we expect to record a net-of-tax cumulative effect adjustment of $1.2 million gain to earnings and $2.9 million gain to comprehensive income to recognize the fair value of all derivative instruments as a result of adopting SFAS 133. We believe the recognition of unrecognized gains and losses from the changes in fair value of all derivative instruments in accordance with SFAS 133 will increase the volatility of our future results of operations and shareholders equity. The amount of volatility will depend on several factors, including the volume and type of derivative transactions we enter into and the volatility of crude oil prices. DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION Some statements in this report and the documents we refer you to, as well as written and oral statements made from time to time by us and our representatives in other reports, filings with the Securities and Exchange Commission, news releases, conferences, teleconferences, World Wide Web postings or otherwise, may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. This information is subject to the "Safe Harbor" provisions of those statutes. Forward-looking statements include statements concerning Triton's and management's plans, objectives, expectations, goals, budgets, strategies and future operations and performance and the assumptions underlying these forward-looking statements. We use the words "anticipates," "estimates," "expects," "believes," "intends," "plans," "budgets," "may," "will," "should" and similar expressions to identify forward-looking statements. These statements include information regarding: - drilling schedules; - expected or planned production capacity; - our interpretation of seismic data; - future production from the Cusiana and Cupiagua fields in Colombia, including the Recetor license; - future production from the Ceiba field in Equatorial Guinea, including volumes and future phases of development; - our exploration, appraisal and development activities in Equatorial Guinea; - the completion of development and commencement of production offshore Malaysia-Thailand and the realization of future incentive payments; - our capital budget, future capital requirements and ability to meet our future capital needs; - commodity prices and future revenues, costs and expenses; - our ability to realize our deferred tax asset; - the level of future expenditures for environmental costs; - the outcome of regulatory and litigation matters; - the fair value of derivative instruments; and - estimates of oil and gas reserves and discounted future net cash flows from reserves. We base these statements on our current expectations. These statements involve a number of risks and uncertainties, including those described in the context of the forward-looking statements, as well as those presented in "Certain Factors That Could Affect Future Operations" below. Actual results and developments could differ materially from those expressed in or implied by these statements. We do not undertake to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS Our business is subject to a number of risks and uncertainties, many of which could affect whether our forward-looking statements become inaccurate. These risks are summarized below.
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CERTAIN FACTORS RELATING TO THE INTERNATIONAL OIL AND GAS INDUSTRY Oil prices significantly impact our operating results. Currently, we derive substantially all of our revenues and operating cash flow from the sale of oil. In general, we sell our oil production at prices based on the market price of oil on the date of sale, although from time to time we may sell production in advance at contractually fixed prices, and we may enter into hedging transactions. The market prices 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 may fluctuate 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 our control. It is impossible to predict future oil and gas price movements with any certainty. Decreases in oil and natural gas prices will adversely affect our revenues, results of operations and cash flows. Changes in the price of oil also may impact our results of operations as a result of the potential impact on the value of derivatives we may have in place from time to time. Changes in the price of oil may change the fair value of derivatives we may enter into from time to time, and these changes may increase or decrease our earnings from period to period. We adopted SFAS 133, as amended by SFAS No. 138, effective January 1, 2001, which requires us to recognize all derivatives as either assets or liabilities in our balance sheet and measure those instruments at fair value. The requisite accounting for changes in the fair value of a derivative will depend on the intended use of the derivative and the resulting designation. For financial and commodity market transactions in which we are hedging the variability of cash flows associated with our forecasted crude oil sales, the effective portion of changes in the fair value of the derivative instrument will be reported in comprehensive income in the period changes in fair value occur. These gains and losses will be recognized in earnings in the periods in which the related hedged sale of crude oil occurs. All changes in the value of derivative instruments not designated as hedges and the ineffective portion of changes in fair value of hedging transactions will be recognized in earnings in the period changes in fair value occur. Substantially all of our operations are conducted in foreign countries, and we are subject to political, economic and other uncertainties. We conduct substantially all of our exploration and production operations and derive substantially all our revenues outside the United States in countries including Colombia, Equatorial Guinea, Malaysia-Thailand, Gabon, Greece, Italy, Madagascar and Oman. International operations, particularly in the oil and gas business, are subject to political, economic and other uncertainties, which include: - the risk of expropriation, nationalization, war, revolution, border disputes, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs; - taxation policies, including royalty and tax increases and retroactive tax claims; - exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over our international operations; - laws and policies of the United States affecting foreign trade, taxation and investment; and - the possibility of being subjected to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States. Operating risks normally associated with the exploration for and production of oil and gas include blowouts and other operating hazards, as well as environmental risks and other regulatory risks. Our activities are subject to all of the operating hazards normally associated with the exploration for and production of oil and gas, including blowouts, explosions, uncontrollable flows of oil, gas or well fluids, pollution, earthquakes, formations with abnormal pressures, labor disruptions and fires, each of which could result in substantial losses due to injury or loss of life and damage to or destruction of oil and gas wells, formations, production facilities or other properties. Our activities also are subject to environmental hazards, such as oil spills, gas leaks and ruptures and discharges of toxic substances or gases. These environmental hazards could expose us to material liabilities for property damages, personal injuries or other environmental harm, including costs of investigating and remediating contaminated properties. We are subject to extensive environmental laws and regulations regarding the discharge of oil, gas or other materials into the environment, which may require us to remove or mitigate the environmental effects of the disposal or release of such materials at various sites. In addition, we could be held liable for environmental damages caused by previous owners of our properties or our predecessors. We do not believe that our environmental risks are materially different from those of comparable companies in the oil and gas industry. Nevertheless, we cannot assure you that environmental laws and regulations will not, in the future, adversely affect our results of operations, cash flows or financial position. Our activities are also subject to laws, rules and regulations in the countries where we operate, 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. We cannot assure you that present or future regulation will not adversely affect our results of operations, cash flows or financial position. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks and losses. Pollution and similar environmental risks generally are not fully insurable. If an event occurs that is not fully covered by insurance, it could result in a financial loss and reduce our resources for capital expenditures. In addition, we cannot be sure that insurance will continue to be available, or that insurance will continue to be available at premium levels that justify its purchase. Our drilling operations are subject to certain other risks that could cause us to delay or cease the drilling of wells. Numerous risks affect drilling activities, including the risk of drilling nonproductive wells or dry holes. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. Also, our drilling could be delayed or cease because of any of the following: - title problems; - weather conditions; - noncompliance with or changes in governmental requirements or regulations; - shortages or delays in the delivery or availability of equipment; and - failure to obtain permits for operations in a timely manner. Estimates of oil and gas reserves and future net revenues are based on numerous assumptions and may be determined to be inaccurate. Numerous uncertainties exist in estimating quantities of proved reserves and future net revenues from those reserves. Estimates of proved reserves and related future net revenues are based on various assumptions, which may be determined to be inaccurate. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, geologic success and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could materially affect the estimated quantities and future net revenues of our proved reserves. In addition, reserve estimates may be subject to downward or upward revisions based on production performance, purchases or sales of properties, results of future development, prevailing oil and gas prices and other factors. Therefore, the estimated future net revenues should not be construed as estimates of the current market value of our proved reserves. If we determine that exploration results on one or more properties do not justify continuing to carry their capitalized costs, we may write down the properties' carrying value and incur a charge to earnings and a reduction in shareholders' equity. We follow the full cost method of accounting for exploration and development of oil and gas reserves. Under this method of accounting, all of our costs related to acquisition, holding and initial exploration of licenses in countries where we do not have any proved reserves are initially capitalized. We then periodically make assessments of these licenses for impairment on a country-by-country basis. Based on our evaluation of drilling results, seismic data and other information we deem relevant, we may write down the carrying value of the oil and gas licenses in a particular country. A writedown constitutes a charge to earnings that does not impact our cash flow from operating activities, but does reduce our shareholders' equity. For example, in the fourth quarter of 2000, following the acquisition of new acreage, reviews of our capital expenditure requirements and exploration portfolio and other information management deemed relevant, we recorded a writedown of $36.7 million ($34.8 million after-tax) related to our operations onshore Italy, offshore Madagascar and offshore Greece, and in the third quarter of 2000, we surrendered our interest in the Aitoloakarnania lease onshore Greece after drilling two dry holes and recorded a writedown of $18.7 million ($17.2 million after-tax), and recorded corresponding reductions in shareholders' equity. In addition, in the second quarter of 1998, we recorded a $77.3 million ($72.6 million, net of tax) writedown of unevaluated oil and gas properties and other assets relating to our operations in China, Ecuador, Guatemala and other countries, and a corresponding reduction in shareholders' equity. Subject to the possible extension or modification of our commitments, we expect to complete our contractual obligations in Italy and Oman over the next 12 to 18 months. If, in the course of our exploration activities in a particular country, we determine that continuing to explore for hydrocarbons there is not justified, we may record a writedown during that period for the cost pool related to that country. Due to the unpredictable nature of exploration activities, we cannot predict the amount and timing of impairment writedowns. Financial information concerning our assets at December 31, 2000, including capitalized costs by geographic area, is in note 19 of Notes to Consolidated Financial Statements. If oil and gas prices decrease below specified levels, we may write down the carrying values of properties with proved reserves and incur a charge to earnings and a reduction in shareholders' equity. We also may be required to write down the carrying value of properties where we have proved reserves as a result of the "full cost ceiling limitation" prescribed by the Securities and Exchange Commission. Under the full cost ceiling limitation, we must write down the carrying value of properties in any country where we have proved reserves to the extent that the net capitalized costs of the properties, less related deferred income taxes, exceeds the amount given by the following formula: (1) the estimated future net revenues from the properties, discounted at 10%; plus (2) unevaluated costs not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties being amortized; minus (4) income tax effects related to differences between the financial statement basis and tax basis of oil and gas properties. The discounted future net revenues from a property are determined based on the selling price of oil or gas at the end of the accounting period, or when results of operations for that period are determined. For example, as a result of a decline in oil prices in 1998, we wrote down the carrying value of our evaluated oil and gas properties in Colombia by $105.4 million ($68.5 million, net of tax) in June 1998, and $135.6 million ($115.9 million, net of tax) in December 1998, because of the full cost ceiling limitation.
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CERTAIN FACTORS RELATING TO OUR ASSETS AND OPERATIONS Guerrilla activity in Colombia could disrupt our operations. We derive a substantial part of our revenues and operating cash flow from our interest in the Cusiana and Cupiagua fields, located approximately 160 kilometers (100 miles) northeast of Bogota, Colombia. The operator of the fields is BP. Pipelines connect the major producing fields in Colombia to export facilities and refineries. From time to time, guerrilla activity in Colombia has disrupted the operation of oil and gas projects. The guerrilla activity has increased over the last few years and appears to be increasing as political negotiations among government and various rebel groups proceed. In addition, the government of the United States has enacted a program to assist the government of Colombia in its efforts to halt the flow of illegal drugs, which may intensify the guerrillas' efforts to disrupt oil operations. Guerrilla activity has caused delays in the development of the fields in Colombia and from time to time has slowed the operator's ability to put workers in the field. For example, in one case, a bomb planted near the pipeline caused OCENSA to halt shipments, which, in turn, caused the operator of the fields to curtail production for approximately two days. The partners in the fields, together with the Colombian government, have taken steps to maintain security and favorable relations with the local population, including hiring security to patrol the facilities, and providing programs to local communities for health and educational assistance. We expect these steps will be required throughout the term of our interest there. We cannot assure you that these attempts to reduce or prevent guerrilla activity will be successful or that guerrilla activity will not disrupt our operations and cash flow in the future. We have experienced greater than expected production declines in Colombia. Gross production from the Cusiana and Cupiagua fields averaged approximately 430,000 BOPD during 1999 and approximately 339,000 BOPD during 2000. The declines in gross production rates have been greater than the operator, we and our engineers had expected. The operator has devised a plan to enhance reservoir management by implementing a more aggressive well-maintenance and workover program. This includes underbalanced drilling in existing and new wells, modifications to surface facilities, and a chemical treatment to alleviate the scale problem and improve well production. Based on this plan, we are estimating that average gross production from the fields will be approximately 270,000 BOPD to 280,000 BOPD in 2001. We cannot assure you that these attempts to offset the decline in production will be successful or that the Colombian fields will not continue to experience significantly less production than the operator, we and our engineers project. Because our contracts in Colombia give us a limited time to produce the oil, if in the future we determine that rates of production will be lower than we had previously assumed in determining proved reserves, we may be required to reduce the quantity of our proved reserves by an amount greater than production. Our property in Equatorial Guinea is in the development stage, and we may not be able to meet our targets for production levels, or for increased levels of production in future phases of development. We are a participant in a significant oil discovery, the Ceiba field, located in Block G offshore the Republic of Equatorial Guinea. The current plan for development calls for a total of 10 production wells and four water injection wells, including the production wells that already have been drilled. Based on our development plans and production history to date, we expect gross production from the Ceiba field to average approximately 37,000 BOPD to 43,000 BOPD (26,000 to 30,000 net to us) during 2001. Actual production rates will depend on well and reservoir performance, our ability to improve pressure support through water injection and other factors. In connection with the next phase of development, we are planning to increase the processing capacity of the FPSO from 60,000 barrels of fluids per day to approximately 160,000 barrels of fluids per day and to install onboard water-injection facilities to inject up to 135,000 barrels per day of water. We expect that the additional wells and production and water injection facilities will enable us to increase production in 2002. We are uncertain as to what the production rate will be in this latter phase of development. The actual production rate will depend on a number of factors, including the timing of the completion of the additional production and water-injection facilities, well performance, the timing of the connection of the production and water injection wells to the FPSO, reservoir performance, our ability to improve pressure support through water injection and other factors. Our development plans will require significant capital expenditures, the drilling and completion of additional wells, the connection of the wells to the FPSO and the installation of additional processing and water-injection facilities. We are highly dependent on third-party contractors, including the firm that owns and is maintaining and operating the FPSO vessel. Our ability to meet our targets is subject to the timely drilling and completion of development wells and the timely performance by the development contractors of their commitments, and is subject to the risks associated with oil and gas operations and international operations as discussed previously. We cannot assure you that we will meet our targets. Any phases of production beyond the initial or phase-one production level from the Ceiba field will depend on a successful delineation and appraisal program, including interpretation of seismic data and the drilling of successful appraisal wells. Our growth in Equatorial Guinea is dependent on our ability to discover additional oil or gas fields, and we have a limited time in which to explore. Under the terms of the production sharing contracts, we have the right to continue to explore the remaining acreage on our Blocks F and G through April 2003. We can extend the exploration period of each contract for up to three additional years if we agree to certain operational commitments for those periods. If we do elect to extend the exploration period beyond April 2003, we would be required to relinquish a portion of the contract area, provided that we would not be required to surrender an area that includes a commercial field or a discovery that has not then been declared commercial. We can designate the area or areas to be surrendered, provided that, where possible, each area must be of sufficient size and convenient shape to permit petroleum operations. We cannot assure you that we will be successful in future exploration efforts on the blocks. Sales of gas from our property in Malaysia-Thailand could be delayed by an environmental impact assessment, we may have to share some of the costs of development with BP, and we may not receive incentive payments from BP if delays occur. We are a partner in a significant gas exploration project located in the Gulf of Thailand approximately 450 kilometers (280 miles) northeast of Kuala Lumpur and 750 kilometers (470 miles) south of Bangkok as a contractor under a production sharing contract covering Block A-18 of the Malaysia-Thailand Joint Development Area. In October 1999, we and the other parties to the production sharing contract for Block A-18 executed a gas sales agreement providing for the sale of the first phase of gas. Under terms of the gas sales agreement, delivery of gas is scheduled to begin by the end of the second quarter of 2002, following timely completion and approval of an environmental impact assessment associated with the buyers' pipeline and processing facilities. The buyers may delay their obligation to purchase the gas if they do not receive approval of the environmental impact assessment for the pipeline and processing facilities they plan to construct and if they satisfy other specified conditions precedent. A lengthy approval process, or significant opposition to the project, as well as a number of events unrelated to the environmental approval that are beyond our control, could delay construction and the commencement of gas sales. We cannot assure you that the buyers will receive approval of the environmental impact assessment or, if they do receive approval, when that approval will occur. It is possible that if the environmental impact assessment process does result in a significant delay, the buyers could seek an alternate route for the delivery of the gas. We cannot assure you as to when any such alternate route could be completed or when gas sales could commence. Based on the delays to date in obtaining the environmental approval, for internal planning purposes we are assuming that production will begin no earlier than the fourth quarter of 2002. In connection with the sale to BP of one-half of the shares through which we owned our interest in Block A-18, BP agreed to pay the future exploration and development costs attributable to our collective interest in Block A-18, up to $377 million or until first production from a gas field, after which we and BP would each pay 50% of such costs. We cannot assure you that our and BP's collective share of the cost of developing the project through first production will not exceed $377 million. BP also agreed to pay us specified incentive payments if the requisite criteria were met. The first $65 million in incentive payments is conditioned upon having the production facilities for the sale of gas from Block A-18 completed by June 30, 2002. If the facilities are completed after June 30, 2002, but before June 30, 2003, the incentive payment would be reduced to $40 million. A lengthy environmental approval process, or delays in construction of the facilities, could result in our receiving a reduced incentive payment or possibly the complete loss of the first incentive payment. For purposes of estimating our discounted net cash inflows from our proved reserves in Block A-18, we have assumed that we would be entitled to a $40 million incentive payment. In addition, we have agreed to share some of the costs of development with BP in the event that the environmental approval process delays production by agreeing to pay BP $1.25 million per month for each month, if applicable, that first gas sales are delayed beyond 30 months following the award of an engineering, procurement and construction contract for the project in March 2000. Our obligation is capped at 24 months of these payments, or $30 million.
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INFLUENCE OF HICKS, MUSE, TATE & FURST INCORPORATED In connection with the issuance of the 8% Convertible Preference Shares to HM4 Triton, L.P., we entered into a shareholders agreement with HM4 Triton, L.P. pursuant to which, among other things, HM4 Triton, L.P. was granted the right to designate four out of 10 of the directors on our board. In addition, the shareholders agreement provides that, for so long as HM4 Triton, L.P. and its affiliates continue to hold at least a specified number of our shares, we may not take certain actions without the consent of HM4 Triton, L.P., including those described in "Item 5. Market for Registrant's Common Equity and Related Stockholder Matters - 8% Convertible Preference Shares." HM4 Triton, L.P. is a limited partnership controlled by Hicks, Muse, Tate & Furst Incorporated, a private investment firm specializing in acquisitions, recapitalizations and other principal investing activities. Thomas O. Hicks, Triton's Chairman of the Board, is the Chairman of the Board and Chief Executive Officer of Hicks, Muse, Tate & Furst Incorporated. Jack D. Furst, a director of Triton, is a partner of Hicks, Muse, Tate & Furst Incorporated. As a result of HM4 Triton, L.P.'s ownership of 8% Convertible Preference Shares and ordinary shares and the rights conferred upon HM4 Triton, L.P. and its designees pursuant to the shareholders agreement, HM4 Triton, L.P. and Hicks, Muse, Tate & Furst Incorporated have significant influence over our business, policies and affairs. The interests of HM4 Triton, L.P. and Hicks, Muse, Tate & Furst Incorporated may differ from those of our other shareholders, and the influence they have may have the effect of discouraging selected transactions involving an actual or potential change of control of Triton. POSSIBLE FUTURE ACQUISITIONS Our strategy includes the possible acquisition of additional reserves, including through possible future business combination transactions. We cannot assure you as to the terms upon which any such acquisitions would be consummated or as to the effect any such transactions would have on our financial condition or results of operations. An acquisition could involve the use of our cash, or the issuance of debt or equity securities, which could have a dilutive effect on our current shareholders. 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 we might discover and the prices we might obtain for the oil and gas depend on many factors beyond our 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. ITEM 7. A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK COMMODITY RISK Our oil sales are normally priced with reference to a defined benchmark, such as WTI spot and Dated Brent. The price we actually receive will vary from the benchmark depending on quality and location differentials. As a matter of policy, from time to time we use financial market transactions with creditworthy counterparties to reduce risk associated with the pricing of our oil sales. The policy is structured to underpin our planned revenues and results of operations. We cannot assure you that our use of financial market transactions will not result in losses. We do not enter into financial market transactions for trading purposes. The markets for crude oil historically have been volatile and are likely to continue to be volatile in the future. During the three-year period ended December 31, 2000, WTI oil prices fluctuated between a low price of $10.72 per barrel and a high price of $37.20 per barrel. During the year ended December 31, 1998, we did not have any outstanding financial market transactions to hedge against oil price fluctuations. As a result of financial and commodity market transactions settled during the years ended December 31, 2000 and 1999, our risk management program resulted in an average net realization of approximately $1.59 per barrel in 2000 and $1.65 per barrel in 1999 lower than if we had not entered into such transactions. Realized gains or losses from our price risk management activities are recognized in oil and gas sales at the time of settlement of the underlying hedged transaction. As of March 1, 2001, we had entered into derivative contracts for 3.9 million barrels of 2001 production using WTI-based oil-price collars to establish a weighted average floor price of $28.11 per barrel and a ceiling price of $31.13 per barrel. We have also entered into contracts associated with 2001 production for 450,000 barrels using WTI-based oil-price swaps and 600,000 barrels using Dated Brent-based oil-price swaps to establish weighted average fixed prices of $26.89 per barrel for WTI and $24.31 for Dated Brent. We used a sensitivity analysis technique to evaluate the hypothetical effect that changes in WTI oil prices may have on the fair value of these contracts. At December 31, 2000, the potential decrease in future earnings, assuming a 10% movement in WTI oil prices, would not have a material adverse effect on our consolidated financial position or results of operations. INDEBTEDNESS OF THE COMPANY We believe our interest rate exposure on debt is not significant since only $4.5 million out of total debt of $504.7 million at December 31, 2000, has floating interest rate obligations. FOREIGN CURRENCY RISK We derive substantially all of our 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. Our risk of realizing currency-exchange losses currently is largely mitigated because we receive U.S. dollars for our oil sales. With respect to expenditures denominated in currencies other than the U.S. dollar, we generally convert U.S. dollars to the local currency near the applicable payment dates to minimize exposure to losses caused by holding foreign currency deposits. During the three-year period ended December 31, 2000, we did not realize any material foreign exchange losses from our international operations. We have evaluated the potential effect that reasonably possible near-term changes in foreign exchange rates may have on the fair value of our assets that are denominated in a foreign currency. Based on our analysis utilizing the actual foreign currency exchange rates at December 31, 2000, and assuming a 10% adverse movement in exchange rates, the potential decrease in fair value of foreign currency denominated assets does not have a material adverse effect on our consolidated financial position or results of operations. 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.
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PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information relating to our directors and nominees for election as directors is incorporated in this report by reference from the Proxy Statement for our 2001 Annual Meeting of Shareholders, specifically the discussion under the heading "Election of Directors." We expect that the 2001 proxy statement will be publicly available and mailed in April 2001. Certain information regarding our executive officers is included earlier in this report under Items 1 and 2, "Business and Properties - Executive Officers." The discussion under "Section 16(a) Beneficial Ownership Reporting Compliance" in the 2001 proxy statement is incorporated in this report by reference. ITEM 11. EXECUTIVE COMPENSATION The discussion under "Management Compensation" in the 2001 proxy statement is incorporated in this report by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The discussion under "Security Ownership of Management and Certain Shareholders" in the 2001 proxy statement is incorporated in this report by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The discussion under "Management Compensation - Compensation Committee Interlocks and Insider Participation and Certain Transactions" in the 2001 proxy statement is incorporated in this report 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.) [Enlarge/Download Table] 3.1 Memorandum of Association (previously filed as an exhibit to the Company's Registration Statement on Form S-3 (No 333-08005) and incorporated herein by reference) 3.2 Articles of Association (previously filed as an exhibit to the Company's Registration Statement on Form S-3 (No 333-08005) and incorporated herein by reference) 4.1 Specimen Share Certificate of Ordinary Shares, $.01 par value, of the Company (previously filed as an exhibit to the Company's Registration Statement on Form 8-A dated March 25, 1996, and incorporated herein by reference) 4.2 Unanimous Written Consent of the Board of Directors authorizing the Company's 8% Convertible Preference Shares (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and incorporated herein by reference.) 4.3 Rights Agreement dated as of March 25, 1996, between Triton and The Chase Manhattan Bank, as Rights Agent, including, as Exhibit A thereto, Resolutions establishing the Junior Preference Shares (previously filed as an exhibit to the Company's Registration Statement on Form S-3 (No 333-08005) and incorporated herein by reference) 4.4 Amendment No. 1 to Rights Agreement dated as of August 2, 1996, between Triton Energy Limited and The Chase Manhattan Bank, as Rights Agent (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) 4.5 Amendment No. 2 to Rights Agreement dated as of August 30, 1998, between Triton Energy Limited and The Chase Manhattan Bank, as Rights Agent (previously filed as an exhibit to the Company's Registration Statement on Form 8-A/A (Amendment No. 2) dated October 2, 1998, and incorporated herein by reference) 4.6 Amendment No. 3 to Rights Agreement dated as of January 5, 1999, between Triton Energy Limited and The Chase Manhattan Bank, as Rights Agent (previously filed as an exhibit to the Company's Registration Statement on Form 8-A/A (Amendment No. 3) dated January 31, 1999, and incorporated herein by reference) 10.1 Amended and Restated Retirement Income Plan (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) (1) 10.2 Amendment to the Retirement Income Plan dated August 1, 1998. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, and incorporated herein by reference.) (1) 10.3 Amendment to Amended and Restated Retirement Income Plan dated December 31, 1996 (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, and incorporated herein by reference) (1) 10.4 Amended and Restated Supplemental Executive Retirement Income Plan. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1997, and incorporated herein by reference.) (1) 10.5 Second Amended and Restated 1992 Stock Option Plan.(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.) (1) 10.6 Form of Amended and Restated Employment Agreement with Triton Energy Limited and certain officers, including Messrs. Dunlevy, Garrett and Maxted, as amended and restated June 28, 2000 (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2000, and incorporated herein by reference.) (1) 10.7 Amended and Restated Employment Agreement among Triton Energy Limited, Triton Exploration Services, Inc. and A. E. Turner III (previously filed as an exhibit to T Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and incorporated herein by reference.) (1) 10.8 Amended and Restated 1985 Restricted Stock Plan. (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 herein by reference.) (1) 10.9 First Amendment to Amended and Restated 1985 Restricted Stock Plan. (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.) (1) 10.10 Second Amendment to Amended and Restated 1985 Restricted Stock Plan. (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.) (1) 10.11 Executive Life Insurance Plan. (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.) (1) 10.12 Long-Term Disability Income Plan. (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.) (1) 10.13 Amended and Restated Retirement Plan for Directors. (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.) (1) 10.14 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. (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.) 10.15 Contract for Exploration and Exploitation for Tauramena with an effective date of July 4, 1988, between Triton Colombia, Inc., and Empresa Colombiana De Petroleos. (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.) 10.16 Summary of Assignment legalized by Public Instrument No. 1255 dated September 15, 1987 (Assignment is in Spanish language). (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 herein by reference.) 10.17 Summary of Assignment legalized by Public Instrument No. 1602 dated June 11, 1990 (Assignment is in Spanish language). (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 herein by reference.) 10.18 Summary of Assignment legalized by Public Instrument No. 2586 dated September 9, 1992 (Assignment is in Spanish language). (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 herein by reference.) 10.19 Triton Exploration Services, Inc. 401(K) Savings Plan, as amended and restated June 1, 2000. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2000, and incorporated herein by reference.) (1) 10.20 Contract between Malaysia-Thailand 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. (previously filed as an exhibit to Triton Energy Corporation's Current Report on Form 8-K dated April 21, 1994, and incorporated herein by reference.) 10.21 Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States (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.) 10.22 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. (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.) 10.23 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. (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) 10.24 Amendment No. 3 to Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, and incorporated herein by reference) 10.25 Form of Indemnity Agreement entered into with each director and officer of the Company. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and incorporated herein by reference) 10.26 Description of Performance Goals for Executive Bonus Compensation. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1996, and incorporated herein by reference) (1) 10.27 Amended and Restated 1997 Share Compensation Plan. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1998, and incorporated herein by reference) (1) 10.28 First Amendment to Amended and Restated Retirement Plan for Directors. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1997, and incorporated herein by reference) (1) 10.29 First Amendment to Second Amended and Restated 1992 Stock Option Plan. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1997, and incorporated herein by reference) (1) 10.30 Second Amendment to Second Amended and Restated 1992 Stock Option Plan. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1997, and incorporated herein by reference) (1) 10.31 Amended and Restated Indenture dated July 25, 1997, between Triton Energy Limited and The Chase Manhattan Bank. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, and incorporated herein by reference) 10.32 Amended and Restated Second Supplemental Indenture dated July 25, 1997, between Triton Energy Limited and The Chase Manhattan Bank relating to the 9 1/4% Senior Notes due 2005. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, and incorporated herein by reference) 10.33 Indenture, dated October 4, 2000, between the Company and The Chase Manhattan Bank, governing the Company's outstanding 8 7/8% Senior Notes Due 2007 (previously filed as an exhibit to the Company's Registration Statement on Form S-4 (No. 333- 48584), and incorporated herein by reference.) 10.34 Shareholders Agreement dated August 3, 1998, among Triton Energy Limited, Triton Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA Limited. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, and incorporated herein by reference) 10.35 Stock Purchase Agreement dated as of August 31, 1998, between Triton Energy Limited and HM4 Triton, L.P. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and incorporated herein by reference) 10.36 Shareholders Agreement dated as of September 30, 1998, between Triton Energy Limited and HM4 Triton, L.P. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and incorporated herein by reference) 10.37 Financial Advisory Agreement dated as of September 30, 1998, between Triton Energy Limited and Hicks, Muse & Co. Partners, L.P. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and incorporated herein by reference) 10.38 Monitoring and Oversight Agreement dated as of September 30, 1998, between Triton Energy Limited and Hicks, Muse & Co. Partners, L.P. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and incorporated herein by reference) 10.39 Severance Agreement dated April 9, 1999, made and entered into by and among Triton Energy Limited, Triton Exploration Services, Inc. and Peter Rugg. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, and incorporated herein by reference) (1) 10.40 Consulting and Non-Compete Agreement dated April 9, 1999, made and entered into by and between Triton Exploration Services, Inc. and Peter Rugg. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, and incorporated herein by reference) (1) 10.41 Third Amendment to Amended and Restated 1985 Restricted Stock Plan (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, and incorporated herein by reference) (1) 10.42 Amendment to Triton Exploration Services, Inc. Retirement Income Plan. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by reference) (1) 10.43 Amendment to the Triton Exploration Services, Inc. Supplemental Executive Retirement Plan. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by reference) (1) 10.44 Third Amendment to the Second Amended and Restated 1992 Stock Option Plan (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by reference) (1) 10.45 First Amendment to the Amended and Restated 1997 Share Compensation Plan (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by reference) (1) 10.46 Amendment dated May 11, 1999, to Amended and Restated Employment Agreement dated July 15, 1998 among Triton Exploration Services, Inc., Triton Energy Limited and A.E. Turner, III (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by reference) (1) 10.47 Second Amendment to Retirement Plan for Directors. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by reference) (1) 10.48 Amendment to Triton Exploration Services, Inc. 401 (k) Savings Plan. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by reference) (1) 10.49 Aendment No. 1 to Shareholders Agreement between Triton Energy Limited and HM4 Triton, L.P. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by reference) 10.50 Supplemental Letter Agreement dated October 28, 1999, among Triton Energy Limited, Triton Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA Limited (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, and incorporated herein by reference) 10.51 Gas Sales Agreement dated October 30, 1999 among the Malaysia-Thailand Joint Authority, and Petronas Carigali (JDA) SDN.BHD., Triton Oil Company of Thailand, Triton Oil Company of Thailand (JDA) Limited, as Sellers, and with Petroleum Authority of Thailand and Petroliam Nasional Berhad, as Buyers. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, and incorporated herein by reference) 10.52 Form of Stock Option Agreement between Triton Energy Limited and its non-employee directors (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and incorporated herein by reference) (1) 10.53 Form of Stock Option Agreement between Triton Energy Limited and its employees, including its executive officers (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and incorpoted herein by reference) (1) 10.54 Amendment to Stock Options dated as of January 3, 2000, between Triton Energy Limited and A.E. Turner. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and incorporated herein by reference.) (1) 10.55 Form of Amendment to Stock Options dated as of January 3, 2000, between Triton Energy Limited and its non-employee directors. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and incorporated herein by reference.) (1) 10.56 Production Sharing Contract between the Republic of Equatorial Guinea and Triton Equatorial Guinea, Inc. for Block F. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and incorporated herein by reference.) 10.57 Production Sharing Contract between the Republic of Equatorial Guinea and Triton Equatorial Guinea, Inc. for Block G. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and incorporated herein by reference.) 10.58 Supplementary Contract (No. 1) to the Production Sharing Contract for Block A-18 dated 21 April 1994 between Malaysia-Thailand Joint Authority and Petronas Carigali (JDA) SDN.BHD., Triton Oil Company of Thailand and Triton Oil Company of Thailand (JDA) Limited. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and incorporated herein by reference.) 10.59 Supplementary Contract (No. 2) to the Production Sharing Contract for Block A-18 dated 21 April 1994 between Malaysia-Thailand Joint Authority and Petronas Carigali (JDA) SDN.BHD., Triton Oil Company of Thailand and Triton Oil Company of Thailand (JDA) Limited. (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and incorporated herein by reference.) 10.60 Credit Agreement dated as of February 29, 2000, among Triton Energy Limited, the Lenders party thereto and The Chase Manhattan bank, as Administrative Agent (previously filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and incorporated herein by reference) 10.61 Share Purchase Agreement dated as of May 8, 2000 between Triton International Petroleum, Inc. and The Strategic Transaction Company. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, and incorporated herein by reference.) 10.62 Amendment Agreement to Credit Agreement dated as of September 25, 2000, among Triton Energy Limited, the Lenders party thereto and The Chase Manhattan Bank, as Administrative Agent. (previously filed as an exhibit to the Company's Registration Statement on Form S-4 (No. 333-48584), and incorporated herein by reference.) 10.63 Triton Energy Limited 2000 Broad Based Share Compensation Plan. (previously filed as an exhibit to the Company's Registration Statement on Form S-4 (No. 333-48584), and incorporated herein by reference.) 10.64 First Amendment to the Production Sharing Contract between the Republic of Equatorial Guinea and Triton Equatorial Guinea, Inc. for Block F. (previously filed as an exhibit to the Company's Registration Statement on Form S-4 (No. 333-48584), and incorporated herein by reference.) 10.65 Assignment of State Participating Interest in the Production Sharing Contract for Block F, Offshore Republic of Republic of Equatorial Guinea. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, and incorporated herein by reference.) 10.66 First Amendment to the Production Sharing Contract between the Republic of Equatorial Guinea and Triton Equatorial Guinea, Inc. for Block G. (previously filed as an exhibit to the Company's Registration Statement on Form S-4 (No. 333-48584), and incorporated herein by reference.) 10.67 Assignment of State Participating Interest in the Production Sharing Contract for Block G, Offshore Republic of Republic of Equatorial Guinea. (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, and incorporated herein by reference.) 10.68 Second Amendment to the Amended and Restated 1997 Share Compensation Plan. (previously filed as an exhibit to the Company's Registration Statement on Form S-4 (No. 333-48584), and incorporated herein by reference.) (1) 10.69* Form of Amendment dated December 19, 2000 to Amended and Restated Employment with Triton Energy Limited and Messrs. Dunlevy and Maxted (1) 10.70* Employment Agreement among Triton Energy Limited, Triton Exploration Services, Inc. and James C. Musselman (1) 12.1* Computation of Ratio of Earnings to Fixed Charges. 12.2* Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends. 21.1* Subsidiaries of the Company. 23.1* Consent of PricewaterhouseCoopers LLP. 23.2* Consent of DeGolyer and MacNaughton. 23.3* Consent of Netherland, Sewell & Associates, Inc. 24.1* The power of attorney of officers and directors of the Company (set forth on the signature page hereof). 99.1 Rio Chitamena Association Contract. (previously filed as an exhibit to Triton Energy Corporation's Current Report on Form 8-K/A dated July 15, 1994, and incorporated herein by reference) 99.2 Rio Chitamena Purchase and Sale Agreement. (previously filed as an exhibit to Triton Energy Corporation's Current Report on Form 8-K/A dated July 15, 1994, and incorporated herein by reference) 99.3 Integral Plan - Cusiana Oil Structure. (previously filed as an exhibit to Triton Energy Corporation's Current Report on Form 8-K/A dated July 15, 1994, and incorporated herein by reference) 99.4 Letter Agreements with co-investor in Colombia. (previously filed as an exhibit to Triton Energy Corporation's Current Report on Form 8-K/A dated July 15, 1994, and incorporated herein by reference) 99.5 Amended and Restated Oleoducto Central S.A. Agreement dated as of March 31, 1995. (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) _____________________ * Filed herewith. (1) Management contract or compensatory plan or arrangement. (b) Reports on Form 8-K. Form 8-K filed October 6, 2000 reporting under Item 5 the closing of the offering of 8 7/8% Senior Notes due 2007. Form 8-K filed November 9, 2000 furnishing under Item 9 information regarding the posting of a presentation on the Company's web site. Form 8-K filed November 14, 2000 furnishing under Item 9 information regarding the posting of a presentation on the Company's web site. Form 8-K filed December 5, 2000 furnishing under Item 9 information regarding the posting of a presentation on the Company's web site. Form 8-K filed December 11, 2000 furnishing under Item 9 information regarding the posting of a presentation on the Company's web site. Form 8-K filed December 20, 2000 furnishing under Item 9 information regarding the posting of a presentation on the Company's web site. 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 14th day of March, 2001. TRITON ENERGY LIMITED By: /s/James C. Musselman ------------------------------------- James. C. Musselman President 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 James C. Musselman, A. E. Turner, III, and W. Greg Dunlevy, 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, 2000, 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 14th day of March, 2001. Signatures Title ---------- ----- /s/W. Greg Dunlevy Senior Vice President and Chief Financial ------------------ Officer W. Greg Dunlevy (Principal Financial and Accounting Officer) /s/Thomas O. Hicks Chairman of the Board ------------------ Thomas O. Hicks /s/James C. Musselman Director, President and Chief Executive Officer --------------------- (Principal Executive Officer) James C. Musselman /s/Fitzgerald Hudson Director -------------------- Fitzgerald Hudson /s/Sheldon R. Erikson Director --------------------- Sheldon R. Erikson /s/Jack D. Furst Director ---------------- Jack D. Furst /s/John R. Huff Director --------------- John R. Huff /s/Michael E. McMahon Director --------------------- Michael E. McMahon --------------------- Director C. Lamar Norsworthy /s/C. Richard Vermillion, Jr. Director ----------------------------- C. Richard Vermillion, Jr. /s/J. Otis Winters Director ------------------ J. Otis Winters TRITON ENERGY LIMITED AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS AND SCHEDULES [Enlarge/Download Table] PAGE ---- TRITON ENERGY LIMITED AND SUBSIDIARIES: Report of Independent Accountants. . . . . . . . . . . . . . . . . . . . . . . . F-2 Consolidated Statements of Operations - Years ended December 31, 2000, 1999 and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-3 Consolidated Balance Sheets - December 31, 2000 and 1999 . . . . . . . . . . . . F-4 Consolidated Statements of Cash Flows - Years ended December 31, 2000, 1999 and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5 Consolidated Statements of Shareholders' Equity - Years ended December 31, 2000, 1999 and 1998. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-6 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . F-7 [Enlarge/Download Table] SCHEDULE: II - Valuation and Qualifying Accounts - Years ended December 31, 2000, 1999 and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-46 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 listed in the accompanying index present fairly, in all material respects, the financial position of Triton Energy Limited and its subsidiaries at December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America 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 our opinion expressed above. As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for its crude oil inventories in connection with its adoption of Staff Accounting Bulletin 101, "Revenue Recognition in Financial Statements" effective January 1, 2000. PricewaterhouseCoopers LLP Dallas, Texas January 30, 2001 TRITON ENERGY LIMITED AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) [Enlarge/Download Table] YEAR ENDED DECEMBER 31, -------------------------------- 2000 1999 1998 --------- --------- ---------- SALES AND OTHER OPERATING REVENUES: Oil and gas sales $328,467 $247,878 $ 160,881 Gain on sale of oil and gas assets --- --- 67,737 --------- --------- ---------- 328,467 247,878 228,618 --------- --------- ---------- COSTS AND EXPENSES: Operating 55,237 68,130 73,546 General and administrative 24,099 23,636 26,653 Depreciation, depletion and amortization 55,073 61,343 58,811 Writedown of assets 55,369 --- 328,630 Special charges --- 2,909 18,324 --------- --------- ---------- 189,778 156,018 505,964 --------- --------- ---------- OPERATING INCOME (LOSS) 138,689 91,860 (277,346) Gain on sale of Triton Pipeline Colombia --- --- 50,227 Interest income 9,673 10,579 3,258 Interest expense, net (16,880) (22,648) (23,228) Other income (expense), net 5,244 (3,614) 8,480 --------- --------- ---------- (1,963) (15,683) 38,737 --------- --------- ---------- EARNINGS (LOSS) BEFORE INCOME TAXES, EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE 136,726 76,177 (238,609) Income tax expense (benefit) 61,046 28,620 (51,105) --------- --------- ---------- EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE 75,680 47,557 (187,504) Extraordinary item - extinguishment of debt (6,962) --- --- Cumulative effect of accounting change (1,345) --- --- --------- --------- ---------- NET EARNINGS (LOSS) 67,373 47,557 (187,504) ACCUMULATED DIVIDENDS ON PREFERENCE SHARES 29,278 28,671 3,061 --------- --------- ---------- EARNINGS (LOSS) APPLICABLE TO ORDINARY SHARES $ 38,095 $ 18,886 $(190,565) ========= ========= ========== Average ordinary shares outstanding 36,551 36,135 36,609 ========= ========= ========== BASIC EARNINGS (LOSS) PER ORDINARY SHARE: Earnings (loss) before extraordinary item and cumulative effect of accounting change $ 1.27 $ 0.52 $ (5.21) Extraordinary item - extinguishment of debt (0.19) --- --- Cumulative effect of accounting change (0.04) --- --- --------- --------- ---------- BASIC EARNINGS (LOSS) $ 1.04 $ 0.52 $ (5.21) ========= ========= ========== Average diluted shares outstanding 38,604 36,197 36,609 ========= ========= ========== DILUTED EARNINGS (LOSS) PER ORDINARY SHARE: Earnings (loss) before extraordinary item and cumulative effect of accounting change $ 1.20 $ 0.52 $ (5.21) Extraordinary item - extinguishment of debt (0.18) --- --- Cumulative effect of accounting change (0.03) --- --- --------- --------- ---------- DILUTED EARNINGS (LOSS) $ 0.99 $ 0.52 $ (5.21) ========= ========= ========== See accompanying Notes to Consolidated Financial Statements. TRITON ENERGY LIMITED AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA) [Enlarge/Download Table] ASSETS DECEMBER 31, ------------------------ 2000 1999 ----------- ----------- CURRENT ASSETS: Cash and equivalents $ 136,361 $ 186,323 Trade receivables 25,616 17,246 Advances to third parties and other receivables 27,823 23,814 Deferred income taxes --- 20,090 Inventories, prepaid expenses and other 18,811 7,806 ----------- ----------- TOTAL CURRENT ASSETS 208,611 255,279 Property and equipment, at cost, net 687,511 524,152 Investment in affiliates 190,430 93,188 Deferred income taxes 88,973 88,228 Other assets 18,755 13,628 ----------- ----------- $1,194,280 $ 974,475 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of long-term debt $ 4,648 $ 9,027 Accounts payable and accrued liabilities 140,700 62,576 Deferred income and other --- 22,347 ----------- ----------- TOTAL CURRENT LIABILITIES 145,348 93,950 Long-term debt, excluding current maturities 500,048 404,460 Deferred income taxes 17,108 6,677 Other liabilities 6,760 6,336 SHAREHOLDERS' EQUITY: 5% preference shares, par value $.01; issued nil and 209,639 shares at December 31, 2000 and 1999, respectively, stated value $34.41 --- 7,214 8% preference shares, par value $.01; authorized 11,000,000 shares; issued 5,181,033 and 5,193,643 shares at December 31, 2000 and 1999, respectively, stated value $70 362,672 363,555 Ordinary shares, par value $.01; authorized 200,000,000 shares; issued 37,426,404 and 35,763,728 shares at December 31, 2000 and 1999, respectively 374 358 Additional paid-in capital 534,480 531,904 Accumulated deficit (370,155) (437,528) Accumulated other nonowner changes in shareholders' equity (2,355) (2,451) ----------- ----------- TOTAL SHAREHOLDERS' EQUITY 525,016 463,052 Commitments and contingencies (note 18) --- --- ----------- ----------- $1,194,280 $ 974,475 =========== =========== 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) [Enlarge/Download Table] YEAR ENDED DECEMBER 31, ---------------------------------- 2000 1999 1998 ---------- ---------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES: Net earnings (loss) $ 67,373 $ 47,557 $(187,504) Adjustments to reconcile net earnings to net cash provided by operating activities: Writedown of assets 55,369 --- 328,630 Depreciation, depletion and amortization 55,073 61,343 58,811 Deferred income taxes 21,187 7,827 (55,592) Extraordinary loss on extinguishment of debt, net of tax 6,962 --- --- Cumulative effect of accounting change 1,345 --- --- Gain on sale of other assets 656 (677) (7,590) Amortization of deferred income (8,814) (35,254) (35,254) Proceeds from forward oil sale --- 31,932 1,770 Gain on sale of oil and gas assets --- --- (67,737) Gain on sale of Triton Pipeline Colombia --- --- (50,227) Other, net (2,296) 8,921 3,962 Changes in working capital: Trade and other receivables (6,245) (16,131) 6,300 Inventories, prepaid expenses and other (15,052) (3,577) 918 Accounts payable and accrued liabilities 11,666 14,581 4,979 ---------- ---------- ---------- Net cash provided by operating activities 187,224 116,522 1,466 ---------- ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures and investments (232,711) (121,483) (180,215) Investment in affiliate (88,656) --- --- Proceeds from sale of oil and gas assets --- --- 147,027 Proceeds from sale of Triton Pipeline Colombia --- --- 97,656 Proceeds from sales of other assets 1,398 2,353 22,353 Other (1,764) 600 (2,630) ---------- ---------- ---------- Net cash provided (used) by investing activities (321,733) (118,530) 84,191 ---------- ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving lines of credit and long-term debt 293,351 --- 162,530 Payments on revolving lines of credit and long-term debt (215,909) (19,028) (350,511) Short-term notes payable, net --- --- (9,600) Issuance of 8% preference shares, net --- 217,805 115,329 Issuances of ordinary shares under stock compensation plans 26,546 419 2,544 Repurchase of ordinary shares --- (11,285) --- Redemption of 5% preference shares (2,691) --- --- Dividends paid on preference shares (14,853) (17,617) (368) Other (1,734) (151) 5 ---------- ---------- ---------- Net cash provided (used) by financing activities 84,710 170,143 (80,071) ---------- ---------- ---------- Effect of exchange rate changes on cash and equivalents (163) (569) (280) ---------- ---------- ---------- Net increase (decrease) in cash and equivalents (49,962) 167,566 5,306 CASH AND EQUIVALENTS AT BEGINNING OF YEAR 186,323 18,757 13,451 ---------- ---------- ---------- CASH AND EQUIVALENTS AT END OF YEAR $ 136,361 $ 186,323 $ 18,757 ========== ========== ========== See accompanying Notes to Consolidated Financial Statements. TRITON ENERGY LIMITED AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (IN THOUSANDS) [Enlarge/Download Table] YEAR ENDED DECEMBER 31, --------------------------------------------------------------- 2000 1999 1998 ------------------- ------------------- -------------------- OWNER SOURCES OF SHAREHOLDERS' EQUITY: 5% PREFERENCE SHARES: Balance at beginning of period $ 7,214 $ 7,214 $ 7,511 Conversion of 5% preference shares (4,523) --- (297) Redemption of 5% preference shares (2,691) --- --- ---------- ---------- ---------- Balance at end of period --- 7,214 7,214 ---------- ---------- ---------- 8% PREFERENCE SHARES: Balance at beginning of period 363,555 127,575 --- Issuances of 8% preference shares at $70 per share --- 222,425 127,575 Conversion of 8% preference shares (883) (192) --- Stock dividends, 8% preference shares --- 13,747 --- ---------- ---------- ---------- Balance at end of period 362,672 363,555 127,575 ---------- ---------- ---------- ORDINARY SHARES: Balance at beginning of period 358 366 365 Conversion of preference shares 2 --- --- Repurchase of ordinary shares --- (9) --- Issuances under stock compensation plans 14 1 1 ---------- ---------- ---------- Balance at end of period 374 358 366 ---------- ---------- ---------- ADDITIONAL PAID-IN CAPITAL: Balance at beginning of period 531,904 575,863 588,454 Dividends, 5% preference shares (334) (361) (368) Dividends, 8% preference shares (29,026) (28,310) (2,693) Issuances under stock compensation plans 26,532 418 2,548 Conversion of 5% preference shares 4,522 --- 297 Conversion of 8% preference shares 882 192 --- Transaction costs for issuance of 8% preference shares --- (4,620) (12,370) Repurchase of ordinary shares --- (11,276) --- Other, net --- (2) (5) ---------- ---------- ---------- Balance at end of period 534,480 531,904 575,863 ---------- ---------- ---------- TOTAL OWNER SOURCES OF SHAREHOLDERS' EQUITY 897,526 903,031 711,018 ---------- ---------- ---------- NONOWNER SOURCES OF SHAREHOLDERS' EQUITY: ACCUMULATED DEFICIT: Balance at beginning of period (437,528) (485,085) (297,581) Net earnings (loss) 67,373 $ 67,373 47,557 $47,557 (187,504) $(187,504) ---------- ---------- ---------- Balance at end of period (370,155) (437,528) (485,085) ---------- ---------- ---------- ACCUMULATED OTHER NONOWNER CHANGES IN SHAREHOLDERS' EQUITY: Balance at beginning of period (2,451) (2,126) (2,126) Adjustment for minimum pension liability 96 96 (325) (325) --- --- ---------- -------- ---------- -------- ---------- --------- Comprehensive income (loss) $ 67,469 $47,232 $(187,504) ======== ======== ========= Balance at end of period (2,355) (2,451) (2,126) ---------- ---------- ---------- TOTAL NONOWNER SOURCES OF SHAREHOLDERS' EQUITY (372,510) (439,979) (487,211) ---------- ---------- ---------- TOTAL SHAREHOLDERS' EQUITY $525,016 $ 463,052 $ 223,807 ========== ========== ========== 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, PER SHARE AND PER BARREL DATA) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GENERAL Triton Energy Limited ("Triton") is an international oil and gas exploration and production company. The term "Company" in this report 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, offshore Malaysia-Thailand and offshore Equatorial Guinea. The Company is exploring for oil and gas in these areas, as well as in southern Europe, Africa and the Middle East. All sales for the three-year period ended December 31, 2000, were derived from oil and gas production in Colombia. First sales from oil production in Equatorial Guinea occurred in January 2001. Triton, a Cayman Islands company, was incorporated in 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 Triton ordinary share, par value $.01, and one 5% Triton preference share, respectively. The Reorganization was accounted for as a combination of entities under common control. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Triton and its majority-owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. Investments in 20%- to 50%-owned affiliates whose operating and financial polices the Company exercises significant influence over are accounted for using the equity method. Investments in less than 20%-owned affiliates are accounted for using the cost method. CASH EQUIVALENTS Cash equivalents are highly liquid investments purchased with an original maturity of three months or less. INVENTORIES The Company adopted Securities and Exchange Commission ("SEC") Staff Accounting Bulletin (SAB) 101, "Revenue Recognition in Financial Statements," effective January 1, 2000, which requires the Company to record oil revenue on each sale, or tanker lifting, and oil inventories at cost, rather than at market value as in the past. The cumulative effect of the change for periods prior to January 1, 2000, is a reduction in net earnings of $1.3 million, or $0.03 per diluted share, and is shown as the cumulative effect of accounting change in the Consolidated Statement of Operations. Pro forma unaudited net earnings for the years ended December 31, 1999 and 1998, assuming the new accounting principle is applied retroactively, would have increased (decreased) by ($.1 million) and $.1 million, respectively. Inventories related to materials and supplies are stated at the lower of cost or market. Crude oil and materials and supplies inventories totaled $12.6 million at December 31, 2000, and $3.9 million at December 31, 1999. 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 estimated 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 would significantly alter the relationship between capitalized costs and proved oil and gas 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 and leasehold improvements are depreciated principally on a straight-line basis over estimated useful lives ranging from 3 to 10 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 are deemed probable, and the costs can be reasonably estimated. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. 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 year-end. 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 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. The cumulative translation adjustment represents the cumulative effect of translating the balance sheet accounts of Triton Colombia, Inc. from the functional currency into U.S. dollars during the period when the Colombian peso was the functional currency. Accumulated other nonowner changes in shareholders' equity included a cumulative translation adjustment of ($2.1 million) at December 31, 2000, 1999 and 1998.
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RISK MANAGEMENT Oil sold by the Company is normally priced with reference to a defined benchmark, such as West Texas Intermediate spot ("WTI") and Dated Brent. Actual prices received vary from the benchmark depending on quality and location differentials. From time to time, it is the Company's policy to use financial market transactions, including swaps, collars and options, or combinations of these, with creditworthy counterparties to reduce risk associated with the pricing of the oil that it sells. The Company does not enter into financial market transactions for trading purposes. 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 (expense), 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. STOCK-BASED COMPENSATION The Company applies 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. EARNINGS PER ORDINARY SHARE Basic 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 shares outstanding during the period. Diluted earnings (loss) per ordinary share assumes the conversion of all securities that are exercisable or convertible into ordinary shares that would dilute the basic earnings per ordinary share during the period. COMPREHENSIVE INCOME Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income," established standards for the reporting and display of comprehensive income and its components, specifically net income and all other changes in shareholders' equity except those resulting from investments by and distributions to shareholders. The Company has elected to display comprehensive income in the Consolidated Statement of Shareholders' Equity. RECENT ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board issued Statement No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities." This Statement was amended in June 2000 by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an Amendment of SFAS No. 133." The new statements establish accounting and reporting standards for derivative instruments and for hedging activities. The standards require the Company to recognize all derivatives as either assets or liabilities in its balance sheet and measure those instruments at fair value. The requisite accounting for changes in the fair value of a derivative will depend on the intended use of the derivative and the resulting designation. The Company adopted the statements effective January 1, 2001, and thus the new accounting and reporting standards will be reflected for the first time in its financial statements for the first quarter of 2001. For financial and commodity market transactions in which the Company hedges the variability of cash flows associated with its forecasted crude oil sales, the effective portion of changes in the fair value of the derivative instrument will be reported in comprehensive income in the period changes in fair value occur. These gains and losses will be recognized in earnings in the periods in which the related hedged sale of crude oil occurs. All changes in the value of derivative instruments not designated as hedges and the ineffective portion of changes in fair value of hedging transactions will be recognized in earnings in the period changes in fair value occur. In January 2001, the Company expects to record a net-of-tax cumulative effect adjustment of $1.2 million gain to earnings and $2.9 million gain to comprehensive income to recognize the fair value of all derivative instruments as a result of adopting SFAS 133. 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. Actual results could differ from these estimates. RECLASSIFICATIONS Certain previously reported financial information has been reclassified to conform to the current period's presentation.
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2. ASSET ACQUISITION AND DISPOSITIONS In May 2000, the Company acquired from an unrelated third party for $88.7 million in cash 100% of the shares of Triton Pipeline Colombia, Inc. ("TPC"), a formerly wholly owned subsidiary up to its disposal on February 2, 1998. TPC's sole asset is its 9.6% equity interest in the Colombian pipeline company, Oleoducto Central S.A. ("OCENSA"). OCENSA owns and operates the pipeline and port facilities that handle and transport crude oil from the Cusiana and Cupiagua fields to the Caribbean port of Covenas. The investment in OCENSA totaling $88.7 million at December 31, 2000, is accounted for under the cost method and is presented in the Consolidated Balance Sheets as investment in affiliates. In December 1998, the Company sold its Bangladesh subsidiary for cash proceeds of $4.5 million and recognized a gain of $4.5 million in gain on sale of oil and gas assets. In July 1998, the Company and Atlantic Richfield Company, now BP Amoco p.l.c. ("BP"), signed an agreement providing financing for the development of the Company's gas reserves on Block A-18 of the Malaysia-Thailand Joint Development Area. Under terms of the agreement, consummated in August 1998, the Company sold to BP for $150 million one-half of the shares of the subsidiary through which the Company owned its then 50% share of Block A-18. The Company received net proceeds of $142 million and recorded a gain of $63.2 million in gain on the sale of oil and gas assets. After the sale, the Company's remaining 50% ownership of the entity is accounted for using the equity method. This investment in Block A-18, totaling $101.7 million and $93.2 million at December 31, 2000 and 1999, respectively, is presented in the Consolidated Balance Sheets as investment in affiliates. In February 1998, the Company sold TPC, a wholly owned subsidiary that held the Company's 9.6% equity interest in OCENSA, to an unrelated third party for $100 million. Net proceeds were approximately $97.7 million. The sale resulted in a gain of $50.2 million. In conjunction with the sale of TPC, the Company entered into an equity swap with a creditworthy financial institution (the "Counterparty"). The equity swap had a notional amount of $97 million and required the Company to make quarterly floating LIBOR-based payments on the notional amount to the Counterparty. In exchange, the Counterparty was required to make payments to the Company equivalent to 97% of the dividends TPC received in respect of its equity interest in OCENSA. The equity swap was carried in the Company's financial statements at fair value during its term, which, as amended, expired in May 2000. The value of the equity swap in the Company's financial statements was equal to 97% of the estimated fair value of the shares of OCENSA owned by TPC. Because there was no public market for the shares of OCENSA, the Company estimated their value using a discounted cash flow model applied to the distributions expected to be paid in respect of the OCENSA shares. The discount rate applied to the estimated cash flows from the OCENSA shares was based on a combination of current market rates of interest, a credit spread for OCENSA's debt, and a spread to reflect the preferred stock nature of the OCENSA shares. During the years ended December 31, 2000, 1999 and 1998, the Company recorded an expense of $2.1 million, $6.9 million and $3.3 million, respectively, in other income (expense), net, related to the net payments made under the equity swap and its change in fair value. Upon expiration of the equity swap, the Company paid the counterparty $12 million in accordance with the terms of the agreement. 3. ADVANCES TO THIRD PARTIES AND OTHER RECEIVABLES DECEMBER 31, ---------------- 2000 1999 ------- ------- Advance to third party for equipment $16,791 $ --- Receivables from and advances to partners 7,053 10,684 Receivable from insurance 1,190 2,300 Receivable from financial and commodity market transactions 173 4,861 Other 2,616 5,969 ------- ------- $27,823 $23,814 ======= ======= A director of the Company is the chief executive officer of a company that is providing certain subsea equipment for the Company's offshore development in Equatorial Guinea. At December 31, 2000, the Company had advanced $16.8 million to the third party under its current contract. See note 17 - Related Party Transactions. 4. PROPERTY AND EQUIPMENT DECEMBER 31, -------------------- 2000 1999 ---------- -------- Oil and gas properties, full cost method: Evaluated $ 829,188 $560,949 Unevaluated 67,893 78,527 Support equipment and facilities 311,632 303,244 Other 21,574 17,535 ---------- -------- 1,230,287 960,255 Less accumulated depreciation and depletion 542,776 436,103 ---------- -------- $ 687,511 $524,152 ========== ======== The Company capitalized general and administrative expenses related to exploration and development activities of $11.1 million, $6.9 million and $20.6 million during the years ended December 31, 2000, 1999 and 1998, respectively.
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5. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES DECEMBER 31, ----------------- 2000 1999 -------- ------- Accrued exploration and development $ 58,655 $ 9,762 Colombian income taxes 29,877 14,471 Dividends payable 14,507 --- Taxes other than income 10,761 7,713 Accrued interest payable 10,498 7,864 Accounts payable, principally trade 5,402 1,242 Litigation and environmental matters 3,694 3,872 Equity swap --- 8,435 Other 7,306 9,217 -------- ------- $140,700 $62,576 ======== ======= 6. DEBT DECEMBER 31, ------------------- 2000 1999 -------- -------- Senior Notes due 2007 $300,000 $ --- Senior Notes due 2005 200,000 200,000 Senior Notes due 2002 --- 199,947 Term credit facility maturing 2001 4,513 13,540 Capitalized lease obligations 183 --- -------- -------- 504,696 413,487 Less current maturities 4,648 9,027 -------- -------- $500,048 $404,460 ======== ======== In October 2000, the Company issued $300 million face value of 8 7/8% Senior Notes due 2007 ( the "2007 Notes") for proceeds of $300 million before deducting transaction costs of approximately $6 million. Interest is payable semiannually on April 1 and October 1, commencing April 1, 2001. The 2007 Notes are redeemable, in whole or in part, at any time on or after October 1, 2004, at the option of the Company. Up to $105 million may be redeemed using proceeds of future equity offerings completed before October 1, 2003. The 2007 Notes contain various restrictive covenants that limit the Company's ability to borrow money or guarantee other indebtedness, create liens, make investments, use assets as security in other transactions, pay dividends on stock, enter into sale/leaseback transactions, sell assets, and merge or consolidate. Subject to certain exceptions, the indenture governing the 2007 Notes provides that the Company may not incur additional indebtedness unless, at the time of the incurrence, the ratio of consolidated earnings before interest, income taxes, depreciation, depletion, amortization and writedowns to the sum of interest expense and capitalized interest, as those terms are defined in the indenture, is at least 2.5 to 1. One of the exceptions would permit the Company to incur additional indebtedness under certain credit arrangements with financial institutions, so long as the total amount of indebtedness outstanding under this exception does not exceed the greater of (i) $250 million or (ii) an amount equal to the sum of $100 million plus 20% of the adjusted net tangible assets as defined in the indenture, on the date of such incurrence. In April 1997, the Company issued $400 million aggregate face value of senior indebtedness to refinance other indebtedness. The senior indebtedness consisted of $200 million face amount of 8 3/4% Senior Notes due April 15, 2002 (the "2002 Notes") at 99.942% of the principal amount (resulting in $199.9 million aggregate net proceeds) and $200 million face amount of 9 1/4% Senior Notes due April 15, 2005 (the "2005 Notes") at 100% of the principal amount for total aggregate net proceeds of $399.9 million before deducting transaction costs of approximately $1 million. The Company used approximately $207 million of the net proceeds from the sale of the 2007 Notes to redeem all of the Company's outstanding 2002 Notes at a price, including accrued interest, of $1,038.40 for each $1,000 note outstanding which resulted in an extraordinary extinguishment expense for the quarter ended December 31, 2000, of approximately $7 million. Interest on the 2005 Notes is payable semiannually on April 15 and October 15. The 2005 Notes are redeemable at any time at the option of the Company, in whole or in part, and contain certain covenants limiting the incurrence of certain liens, sale/leaseback transactions, and mergers and consolidations. In November 1995, a subsidiary 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 matured and was fully paid in January 2001. Principal and interest payments were due semiannually on January 15 and July 15, and borrowings bore interest at LIBOR plus .25%, adjusted on a semiannual basis. At December 31, 2000, the Company had outstanding borrowings of $4.5 million under the facility. In February 2000, the Company entered into an unsecured two-year revolving credit facility with a group of banks, which matures in February 2002. The credit facility gives the Company the right to borrow from time to time up to the amount of the borrowing base determined by the banks, not to exceed $150 million. As a result of the issuance of the 2007 Notes and the redemption of the 2002 Notes, the borrowing base was adjusted to $50 million, subject to any future redetermination of the borrowing base as provided in the agreement. The credit facility contains various restrictive covenants, including covenants that require the Company to maintain a ratio of earnings before interest, depreciation, depletion, amortization and income taxes to net interest expense of at least 2.5 to 1, and that prohibit the Company from permitting net debt to exceed the product of 3.75 times the Company's earnings before interest, depreciation, depletion, amortization and income taxes, in each case, on a trailing-four-quarters basis. At December 31, 2000, the Company had no outstanding borrowings under the facility. The Company capitalizes interest on qualifying assets, principally unevaluated oil and gas properties, major development projects in progress and investments accounted for by the equity method, while the investee has activities in progress necessary to commence its principal operations. Capitalized interest amounted to $24.1 million, $14.5 million and $23.2 million in the years ended December 31, 2000, 1999 and 1998, respectively. 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 $1.2 million, $.5 million and $2.9 million in the years ended December 31, 2000, 1999 and 1998, respectively. The aggregate maturities of long-term debt for the five years during the period ending December 31, 2005, are as follows: 2001 -- $4.6 million; 2002 -- nil; 2003 -- nil; 2004 -- nil; and 2005 -- $200 million. 7. INCOME TAXES The components of earnings (loss) from continuing operations before income taxes, extraordinary item and cumulative effect of accounting change were as follows: YEAR ENDED DECEMBER 31, ------------------------------------ 2000 1999 1998 --------- --------- ---------- Cayman Islands $(30,712) $(35,907) $ 82,995 United States (12,720) (7,810) (24,003) Foreign - other 180,158 119,894 (297,601) --------- --------- ---------- $136,726 $ 76,177 $(238,609) ========= ========= ========== 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, a 0% taxing jurisdiction.
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The components of the provision for income taxes on continuing operations were as follows: YEAR ENDED DECEMBER 31, ----------------------------- 2000 1999 1998 -------- -------- --------- Current: Cayman Islands $ --- $ --- $ --- United States --- --- --- Foreign - other 39,859 20,793 4,487 -------- -------- --------- Total current 39,859 20,793 4,487 -------- -------- --------- Deferred: Cayman Islands --- --- --- United States (826) (1,410) 1,457 Foreign - other 22,013 9,237 (57,049) -------- -------- --------- Total deferred 21,187 7,827 (55,592) -------- -------- --------- Total $61,046 $28,620 $(51,105) ======== ======== ========= A reconciliation of the differences between the Company's applicable statutory tax rate and the Company's effective income tax rate follows: [Download Table] YEAR ENDED DECEMBER 31, -------------------------- 2000 1999 1998 ------- ------- ------- Tax provision at statutory tax rate 0.0 % 0.0 % 0.0 % Increase (decrease) resulting from: Net change in valuation allowance (7.5)% (15.7)% 3.9 % Foreign items without tax benefit 21.8 % 18.9 % (34.9)% Income subject to tax in excess of statutory rate 38.9 % 36.6 % 32.6 % Current year change in NOL/credit carryforwards (17.1)% (7.6)% (4.8)% Temporary differences: Oil and gas basis adjustments 7.6 % 3.3 % 25.7 % Reimbursement of pre-commerciality costs 0.7 % 2.3 % (1.1)% Other 0.2 % (0.2)% --- % ------- ------- ------- 44.6 % 37.6 % 21.4 % ======= ======= =======
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The components of the net deferred tax asset and liability were as follows: [Enlarge/Download Table] DECEMBER 31, 2000 DECEMBER 31, 1999 ------------------------------ ------------------------------- OTHER OTHER U.S. COLOMBIA FOREIGN U.S. COLOMBIA FOREIGN --------- -------- --------- ---------- -------- --------- Deferred tax asset: Net operating loss carryforwards $134,046 $ --- $ 50,355 $ 157,558 $20,090 $ 9,832 Depreciable/depletable property 1,527 --- --- 1,748 8,778 --- Credit carryforwards 1,851 --- --- 2,048 --- --- Other 813 --- --- 995 --- --- --------- -------- --------- ---------- -------- --------- Gross deferred tax asset 138,237 --- 50,355 162,349 28,868 9,832 Valuation allowances (48,695) --- --- (72,908) (8,778) --- --------- -------- --------- ---------- -------- --------- Net deferred tax asset 89,542 --- 50,355 89,441 20,090 9,832 --------- -------- --------- ---------- -------- --------- Deferred tax liability: Depreciable/depletable property --- (9,956) (57,507) --- --- (16,509) Other (569) --- --- (1,213) --- --- --------- -------- --------- ---------- -------- --------- Net deferred tax asset (liability) 88,973 (9,956) (7,152) 88,228 20,090 (6,677) Less current deferred tax asset (liability) --- --- --- --- 20,090 --- --------- -------- --------- ---------- -------- --------- Noncurrent deferred tax asset (liability) $ 88,973 $(9,956) $ (7,152) $ 88,228 $ --- $ (6,677) ========= ======== ========= ========== ======== ========= At December 31, 2000, the Company had net operating losses ("NOLs") and depletion carryforwards for U.S. tax purposes of $383 million and $20.3 million, respectively. The U.S. NOLs expire from 2001 through 2021 as follows: NOLS EXPIRING BY YEAR --------- May 2001 $ 21,417 May 2002 22,702 May 2003 20,569 May 2004 8,552 May 2005 6,858 May 2006 - May 2021 302,895 --------- $ 382,993 =========
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The Company's Equatorial Guinea operations had NOLs totaling $176 million with an unlimited carryforward. In other countries outside the U.S., the Company had NOLs and other credit carryforwards totaling $30.1 million, which expire from 2001 through 2010. During 2000, the Company's tax expense was approximately $21 million lower due to anticipated utilization of NOLs from entities that were acquired during 1999 and 2000. The deferred tax valuation allowance of $48.7 million at December 31, 2000, is primarily attributable to management's assessment of the utilization of NOLs in the U.S., the expectation that other tax credits will expire without being utilized, and the expectation that certain temporary differences will reverse without a benefit to the Company. The minimum amount of future taxable income necessary to realize the U.S. net deferred tax asset is approximately $254 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 income from its operations or sales of assets. If certain changes in the Company's ownership should occur, there would be an annual limitation on the amount of U.S. NOLs 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. 8. EMPLOYEE BENEFITS PENSION PLANS The Company has a defined benefit pension plan covering substantially all of its employees in the U.S. Plan 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.
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The funding status of the plans follows: [Enlarge/Download Table] DECEMBER 31, ---------------------------------------- 2000 1999 ------------------- ------------------- DEFINED DEFINED BENEFIT SERP BENEFIT SERP PLAN PLAN PLAN PLAN --------- -------- --------- -------- Change in benefit obligation: Benefit obligation at beginning of year $ 5,967 $ 7,631 $ 6,435 $ 6,579 Service cost 295 496 392 537 Interest cost 447 575 421 435 Actuarial loss/(gain) 179 155 (750) 1,465 Benefits paid (379) (410) (531) (1,385) --------- -------- --------- -------- Benefit obligation at end of year 6,509 8,447 5,967 7,631 --------- -------- --------- -------- Change in plan assets: Fair value of plan assets at beginning of year 8,988 --- 7,068 --- Actual return on plan assets (238) --- 1,971 --- Company contribution --- 410 480 1,385 Benefits paid (379) (410) (531) (1,385) --------- -------- --------- -------- Fair value of plan assets at end of year 8,371 --- 8,988 --- --------- -------- --------- -------- Reconciliation: Funded status 1,862 (8,447) 3,021 (7,631) Unrecognized actuarial (gain)/loss (1,660) 2,012 (2,999) 1,945 Unrecognized transition (asset)/obligation (4) 359 (6) 527 Unrecognized prior service cost 260 199 317 226 --------- -------- --------- -------- Prepaid/(accrued) pension cost 458 (5,877) 333 (4,933) --------- -------- --------- -------- Adjustment for minimum liability --- (912) --- (1,255) --------- -------- --------- -------- Adjusted prepaid/(accrued) pension cost $ 458 $(6,789) $ 333 $(6,188) ========= ======== ========= ======== The adjustment required to recognize the minimum liability for the SERP plan at December 31, 2000, resulted in the recognition of $.6 million as an intangible asset and $.4 million ($.2 million net of tax) as a charge against comprehensive income. A summary of the components of pension expense follows: [Download Table] YEAR ENDED DECEMBER 31, ------------------------------------- 2000 1999 1998 ------- ------- ------- Components of net periodic pension cost: Service cost $ 792 $ 929 $1,359 Interest cost 1,022 856 1,045 Expected return on plan assets (791) (618) (481) Recognized net actuarial loss/(gain) (43) (12) --- Amortization of transition obligation 166 166 591 Amortization of prior service cost 83 83 538 ------- ------- ------- Net periodic pension cost $1,229 $1,404 $3,052 ======= ======= ======= The projected benefit obligations at both December 31, 2000 and 1999, assume a discount rate of 7.75%, 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 based on actual amounts contributed to the Plan. The cost recognized for the Plan was $.5 million, $.2 million and $.6 million for the years ended December 31, 2000, 1999 and 1998, respectively. 9. SHAREHOLDERS' EQUITY 5% CONVERTIBLE PREFERENCE SHARES On September 8, 2000, the Company called all of the outstanding 5% Convertible Preference Shares for redemption. Each 5% Convertible Preference Share was convertible into one ordinary share of the Company. A total of 107,075 shares were converted into ordinary shares, and the remaining 78,201 shares were redeemed for cash at the redemption price of $34.56 per share totaling $2.7 million. The redemption price represented the stated value of $34.41 plus the amount of dividends that accrued per share from September 30, 2000, through the redemption date of October 31, 2000. The 5% Convertible Preference Shares were canceled and returned to the status of authorized but unissued preference shares. 8% CONVERTIBLE PREFERENCE SHARES In August 1998, the Company and HM4 Triton, L.P., an affiliate of Hicks, Muse, Tate & Furst Incorporated ("Hicks Muse"), entered into a stock purchase agreement (the "Stock Purchase Agreement") that provided for a $350 million equity investment in the Company. The investment was effected in two stages. At the closing of the first stage in September 1998 (the "First Closing"), the Company issued to HM4 Triton, L.P. 1,822,500 shares of 8% Convertible Preference Shares for $70 per share (for proceeds of $116.8 million, net of transaction costs). Pursuant to the Stock Purchase Agreement, the second stage was effected through a rights offering for 3,177,500 shares of 8% Convertible Preference Shares at $70 per share, with HM4 Triton, L.P. being obligated to purchase any shares not subscribed. At the closing of the second stage, which occurred on January 4, 1999 (the "Second Closing"), the Company issued an additional 3,177,500 8% Convertible Preference Shares for proceeds totaling $217.8 million, net of closing costs (of which, HM4 Triton, L.P. purchased 3,114,863 shares). Each 8% Convertible Preference Share is convertible at any time at the option of the holder into four ordinary shares of the Company (subject to certain antidilution protections). Holders of 8% Convertible Preference Shares are entitled to receive, when and if declared by the Board of Directors, cumulative dividends at a rate per annum equal to 8% of the liquidation preference of $70 per share, payable for each semiannual period ending June 30 and December 30 of each year. At the Company's option, dividends may be paid in cash or by the issuance of additional whole shares of 8% Convertible Preference Shares. If a dividend is to be paid in additional shares, the number of additional shares to be issued in payment of the dividend will be determined by dividing the amount of the dividend by $70, with amounts in respect of any fractional shares to be paid in cash. The first dividend period was from January 4, 1999, to June 30, 1999. The Company's Board of Directors elected to pay the dividend for that period in additional shares resulting in the issuance of 196,388 8% Convertible Preference Shares. Dividends for periods subsequent to June 30, 1999, have been paid in cash. The declaration of a dividend in cash or additional shares for any period should not be considered an indication as to whether the Board will declare dividends in cash or additional shares in future periods. Holders of 8% Convertible Preference Shares are entitled to vote with the holders of ordinary shares on all matters submitted to the shareholders of the Company for a vote, with each 8% Convertible Preference Share entitling its holder to a number of votes equal to the number of ordinary shares into which it could be converted at that time. At December 31, 2000 and 1999, 5,181,033 and 5,193,643 8% Convertible Preference Shares were outstanding, respectively. Beginning September 30, 2001, the Company can redeem all, but not less than all, of the outstanding 8% Convertible Preference Shares if the average market value of the ordinary shares is above certain market values. The redemption price is equal to $70 per share, plus an amount equal to all accumulated but unpaid dividends, and is payable in cash. ORDINARY SHARES Changes in issued ordinary shares were as follows: [Download Table] YEAR ENDED DECEMBER 31, ------------------------------------ 2000 1999 1998 ---------- ----------- ----------- Balance at beginning of year 35,763,728 36,643,478 36,541,064 Exercise of employee stock options 1,427,462 8,213 47,238 Conversion of 5% preference shares 131,438 --- 8,646 Issuances under stock purchase plan 53,336 49,367 46,648 Conversion of 8% preference shares 50,440 10,980 --- Repurchase of shares --- (948,300) --- Other, net --- (10) (118) ---------- ----------- ----------- Balance at end of year 37,426,404 35,763,728 36,643,478 ========== =========== =========== SHARE REPURCHASE In April 1999, the Company's Board of Directors authorized a share repurchase program enabling the Company to repurchase up to 10% of the Company's then-outstanding 36.7 million ordinary shares. During 1999, the Company purchased 948,300 ordinary shares for $11.3 million. The Company canceled and returned the repurchased ordinary shares to the status of authorized but unissued shares. The Company's revolving credit facility entered into in February 2000 generally does not permit the Company to repurchase its ordinary shares without the banks' consent. 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. 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 a 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, any acquisition of Triton shares by HM4 Triton, L.P. or its affiliates, including Hicks Muse will not result in the distribution of rights unless and until HM4 Triton, L.P.'s ownership of Triton shares is reduced below certain levels. 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 HM4 Triton, L.P.), each right not owned by such person generally becomes the right to purchase a 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 a 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 HM4 Triton, L.P.) 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 Company has the ability to amend the rights (except the redemption price) in any manner prior to the public announcement that a 15% position has been acquired or a tender offer has been commenced. The Company will be entitled to redeem the rights at $0.01 a right at any time prior to the time that a 15% position has been acquired. The rights will expire on May 22, 2005, unless earlier redeemed by the Company. 10. STOCK COMPENSATION PLANS STOCK OPTION PLANS Options to purchase ordinary shares of the Company may be granted to directors, officers and employees under various stock option plans. The exercise price of each option is equal to or greater than the market price of the Company's ordinary shares on the date of grant. Grants generally become exercisable in 25% or 33% cumulative annual increments beginning one year from the date of issuance and generally expire during a period from 5 to 10 years after the date of grant, depending on terms of the grant. In addition, each nonemployee director receives an option to purchase 15,000 shares each year. These grants become exercisable at the date of the grant and expire at the end of 10 years. At December 31, 2000 and 1999, options to purchase ordinary shares available for grant were 650,521 and 1,019,021, respectively. A summary of the status of the Company's stock option plans is presented below: [Enlarge/Download Table] DECEMBER 31, 2000 DECEMBER 31, 1999 DECEMBER 31, 1998 --------------------- -------------------- -------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE Outstanding at beginning of year 5,847,856 $21.78 4,057,207 $26.51 4,449,435 $39.05 Granted 1,750,500 37.28 2,150,000 14.03 2,894,603 20.56 Exercised (1,427,462) 18.16 (8,213) 10.57 (47,238) 29.30 Canceled (252,448) 39.36 (351,138) 29.24 (3,239,593) 38.39 ------------ ----------- ------------ Outstanding at end of year 5,918,446 26.48 5,847,856 21.78 4,057,207 26.51 ============ =========== ============ Options exercisable at year-end 2,751,439 3,121,601 2,804,584 Weighted average fair value of options: Granted at market prices $ 12.35 $ 2.71 $ 6.12 Granted at greater than market prices 15.26 4.93 2.84
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The following table summarizes information about stock options outstanding at December 31, 2000: [Download Table] 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, 2000 LIFE PRICE DEC. 31, 2000 PRICE -------------- -------------- ----------- --------- -------------- --------- 6.94 - 14.50 2,363,437 4.0 years $ 14.19 1,049,271 $ 13.81 14.51 - 25.00 512,553 3.8 years 17.85 279,212 17.97 25.01 - 35.00 839,404 3.4 years 29.47 772,404 29.51 35.01 - 40.00 1,702,500 4.5 years 38.94 150,000 37.90 40.01 - 52.00 500,552 3.9 years 46.00 500,552 46.00 -------------- -------------- 5,918,446 2,751,439 ============== ============== EMPLOYEE STOCK PURCHASE PLAN The Company has an employee stock purchase plan that provides for the award of ordinary shares to employees. Under the terms of the plan, employees can choose each semiannual 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 53,336 shares and 49,367 shares to employees for the years ended December 31, 2000 and 1999, respectively. FAIR VALUE OF STOCK COMPENSATION The Company applies Opinion 25 in accounting for its plans. Accordingly, no compensation cost has been recognized for its fixed stock option plans and stock purchase plan. Had the Company elected to recognize compensation expense consistent with the fair value-based methodology in Statement of Financial Accounting Standards No. 123, the Company's net earnings (loss) applicable to ordinary shares and earnings (loss) per ordinary share would have been as follows: [Download Table] YEAR ENDED DECEMBER 31, ---------------------------- 2000 1999 1998 ------- ------- ---------- Net earnings (loss) applicable to ordinary shares: As reported $38,095 $18,886 $(190,565) Pro forma 27,888 12,579 (200,147) Basic earnings (loss) per ordinary share: As reported $ 1.04 $ 0.52 $ (5.21) Pro forma 0.73 0.35 (5.47) Diluted earnings (loss) per ordinary share: As reported $ 0.99 $ 0.52 $ (5.21) Pro forma 0.70 0.35 (5.47) The fair value of each option 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 2000, 1999 and 1998: dividend yield of 0%; expected volatility of approximately 64%, 54% and 40%, respectively; risk-free interest rates of approximately 6%, 6% and 5%, respectively; and an expected life of approximately three to four years. 11. FAIR VALUE OF FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CREDIT RISK CONCENTRATIONS FAIR VALUE OF FINANCIAL INSTRUMENTS At December 31, 2000 and 1999, the Company's financial instruments included cash and equivalents, short-term receivables, 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 long-term receivables and financial market transactions, based on broker quotes 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 $514 million (carrying value - $505 million) and $416 million (carrying value - $413 million) at December 31, 2000 and 1999, respectively. RISK MANAGEMENT Oil sold by the Company is normally priced with reference to a defined benchmark, such as WTI spot and Dated Brent. Actual prices received vary from the benchmark depending on quality and location differentials. From time to time, it is the Company's policy to use financial market transactions, including swaps, collars and options, or combinations of these, with creditworthy counterparties to reduce risk associated with the pricing of the oil that it sells. The policy is structured to underpin the Company's planned revenues and results of operations. The Company does not enter into financial market transactions for trading purposes. There can be no assurance that the use of financial market transactions will not result in losses. As a result of financial and commodity market transactions settled during the years ended December 31, 2000 and 1999, the Company's oil sales were approximately $17.6 million and $19.8 million, respectively, lower than if the Company had not entered into such transactions. CONCENTRATION OF CREDIT RISK Financial instruments potentially subject to concentrations of credit risk consist of cash equivalents, receivables and financial market transactions. The Company places its cash equivalents and financial market transactions with high credit-quality financial institutions. The Company believes the risk of incurring losses related to credit risk is remote. The Company sells its crude oil production from the Cusiana and Cupiagua fields in Colombia through an agreement with a third party to approximately 10 to 15 buyers 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. [Download Table] 12. WRITEDOWN OF ASSETS YEAR ENDED DECEMBER 31, ---------------------------- 2000 1999 1998 -------- -------- -------- Evaluated oil and gas properties $ --- $ --- $241,005 Unevaluated oil and gas properties 54,186 --- 73,890 Other assets 1,183 --- 13,735 -------- -------- -------- $ 55,369 $ --- $ 328,630 ======== ======== ======== Following the acquisition of new acreage, reviews of the Company's capital expenditure requirements and exploration portfolio during 2000, and other information management deemed relevant, the Company recorded a writedown of $36.7 million ($34.8 million after-tax) related to its operations onshore Italy, offshore Madagascar and offshore Greece. The Company also surrendered its interest in the Aitoloakarnania lease onshore Greece after drilling two dry holes and recorded a writedown of $18.7 million ($17.2 million after-tax) during 2000. In June and December 1998, the carrying amount of the Company's evaluated oil and gas properties in Colombia was written down by $105.4 million ($68.5 million, net of tax) and $135.6 million ($115.9 million, net of tax), respectively, through application of the full cost ceiling limitation as prescribed by the SEC, principally as a result of a decline in oil prices. The SEC ceiling test was calculated using the June 30, and December 31, 1998, WTI oil prices of $14.18 per barrel and $12.05 per barrel, respectively, that, after a differential for Cusiana crude delivered at the port of Covenas in Colombia, resulted in a net price of approximately $13 per barrel and $11 per barrel, respectively. In conjunction with the plan to restructure operations and scale back exploration-related expenditures in 1998, the Company assessed its investments in exploration licenses and determined that certain investments were impaired. As a result, unevaluated oil and gas properties and other assets totaling $77.3 million ($72.6 million, net of tax) were expensed in June 1998. The writedown included $27.2 million and $22.5 million related to exploration activity in Guatemala and China, respectively. The remaining writedowns related to the Company's exploration projects in certain other areas of the world. During 1998, the Company evaluated the recoverability of its approximate 6.6% investment in a Colombian pipeline company, Oleoducto de Colombia S.A. ("ODC"), which was accounted for under the cost method. Based on an analysis of the future cash flows expected to be received from ODC, the Company expensed the carrying value of its investment totaling $10.3 million. 13. SPECIAL CHARGES In September 1999, the Company recognized special charges totaling $2.4 million related to the transfer of its working interest in Ecuador to a third party. In July 1998, the Company commenced a plan to restructure the Company's operations, reduce overhead costs and substantially scale back exploration-related expenditures. The plan contemplated the closing of foreign offices in four countries, the elimination of approximately 105 positions, or 41% of the worldwide workforce, and the relinquishment or other disposal of several exploration licenses. As a result of the restructuring, the Company recognized special charges of $15 million during the third quarter of 1998 and $3.3 million during the fourth quarter of 1998 for a total of $18.3 million. Of the $18.3 million in special charges, $14.5 million related to the reduction in workforce, and represented the estimated costs for severance, benefit continuation and outplacement costs, which were paid over a period of up to two years according to the severance formula. During the fourth quarter of 1999, the Company reversed $.7 million of the accrual through special charges in the Consolidated Statement of Operations associated with the substantial completion of restructuring activities. During 2000, all amounts outstanding were paid, therefore at December 31, 2000, there is no liability remaining related to the restructuring activities undertaken in 1998. In March 1999, the Company accrued special charges of $1.2 million related to an additional 15% reduction in the number of employees resulting from the Company's continuing efforts to reduce costs. The special charges consisted of $1 million for severance, benefit continuation and outplacement costs and $.2 million related to the write-off of surplus fixed assets. During 2000, all amounts outstanding were paid, therefore at December 31, 2000, there is no liability remaining related to the restructuring activities undertaken in 1999. 14. OTHER INCOME (EXPENSE), NET [Download Table] YEAR ENDED DECEMBER 31, ---------------------------- 2000 1999 1998 -------- -------- -------- Foreign exchange gain (loss) $ 4,685 $(2,674) $ 2,113 Change in fair market value of financial and commodity market transactions 2,374 6,150 366 Equity swap (2,147) (6,858) (3,283) Loss provisions --- (2,250) (750) Gain on sale of corporate assets --- 443 7,593 Other 332 1,575 2,441 -------- -------- -------- $ 5,244 $(3,614) $ 8,480 ======== ======== ======== The net foreign exchange gain (loss) consists primarily of noncash adjustments related to deferred taxes in Colombia associated with valuation of the Colombian peso versus the U.S. dollar. 15. EARNINGS PER ORDINARY SHARE The following table reconciles the numerators and denominators of the basic and diluted earnings per ordinary share computation for earnings from continuing operations for the years ended December 31, 2000 and 1999. [Enlarge/Download Table] INCOME SHARES PER-SHARE (NUMERATOR) (DENOMINATOR) AMOUNT ----------- ------------- --------- YEAR ENDED DECEMBER 31, 2000: Net earnings before extraordinary item and cumulative effect of accounting change $ 75,680 Less: Accumulated dividends on preference shares (29,278) ----------- Earnings available to ordinary shareholders 46,402 Basic earnings per ordinary share 36,551 $ 1.27 ========= Effect of dilutive securities Stock options --- 2,053 ----------- ------------- Earnings available to ordinary shareholders and assumed conversions $ 46,402 =========== Diluted earnings per ordinary share 38,604 $1.20 ============= ========= YEAR ENDED DECEMBER 31, 1999: Net earnings $ 47,557 Less: Accumulated dividends on preference shares (28,671) ----------- Earnings available to ordinary shareholders 18,886 Basic earnings per ordinary share 36,135 $ 0.52 ========= Effect of dilutive securities Stock options --- 62 ----------- ------------- Earnings available to ordinary shareholders and assumed conversions $ 18,886 =========== Diluted earnings per ordinary share 36,197 $ 0.52 ============= ========= For the year ended December 31, 1998, the computation of diluted net loss per ordinary share was antidilutive, and therefore, the amounts reported for basic and diluted net loss per ordinary share were the same. At December 31, 2000 and 1999, 5,181,033 shares and 5,193,643 shares of 8% Convertible Preference Shares, respectively, were outstanding. Each 8% Convertible Preference Share is convertible any time into four ordinary shares, subject to adjustment in certain events. The 8% Convertible Preference Shares were not included in the computation of diluted earnings per ordinary share because the effect of assuming conversion was antidilutive. 16. STATEMENTS OF CASH FLOWS Supplemental disclosures of cash payments and noncash investing and financing activities follow: [Download Table] YEAR ENDED DECEMBER 31, ------------------------- 2000 1999 1998 ------- ------- ------- Cash paid during the year for: Interest (net of amounts capitalized) $14,158 $22,810 $24,517 Income taxes 19,004 5,564 4,339 Noncash financing activities: 8% Convertible Preference Shares issued in lieu of cash dividend $ --- $13,747 $ --- Conversion of preference shares into ordinary shares 5,406 192 297 At December 31, 2000, the Company had an accrual of $14.5 million for dividends declared with respect to the 8% Convertible Preference Shares which was paid in 2001. 17. RELATED PARTY TRANSACTIONS Pursuant to a financial advisory agreement (the "Financial Advisory Agreement") between Triton and Hicks, Muse & Co. Partners L.P. ("Hicks Muse Partners"), an affiliate of Hicks Muse, the Company paid Hicks Muse Partners transaction fees aggregating approximately $9.6 million and $4.4 million for services as financial advisor to the Company in connection with the First Closing and Second Closing, respectively, contemplated by the Stock Purchase Agreement. In accordance with the terms of the Financial Advisory Agreement, the Company has retained Hicks Muse Partners as its exclusive financial advisor in connection with any Sale Transaction (defined below) unless Hicks Muse Partners and the Company agree to retain an additional financial advisor in connection with any particular Sale Transaction. The Financial Advisory Agreement requires the Company to pay a fee to Hicks Muse Partners in connection with any Sale Transaction (unless the Chief Executive Officer of the Company elects not to retain a financial advisor) in an amount equal to the lesser of (i) the amount of fees then charged by first-tier investment banking firms for similar advisory services rendered in similar transactions or (ii) 1.5% of the Transaction Value (as defined in the Financial Advisory Agreement); provided that such fee will be divided equally between Hicks Muse Partners and any additional financial advisor which the Company and Hicks Muse Partners agree will be retained by the Company with respect to any such transaction. A "Sale Transaction" is defined as any merger, sale of securities representing a majority of the combined voting power of the Company, sale of assets of the Company representing more than 50% of the total market value of the assets of the Company and its subsidiaries or other similar transaction. The Company is also required to reimburse Hicks Muse Partners for reasonable disbursements and out-of-pocket expenses of Hicks Muse Partners incurred in connection with its advisory services. Pursuant to a monitoring agreement (the "Monitoring Agreement") between Triton and Hicks Muse Partners, Hicks Muse Partners will provide financial oversight and monitoring services as requested by the Company and the Company will pay to Hicks Muse Partners an annual fee of $.5 million. In addition, the Company will reimburse Hicks Muse Partners for reasonable disbursements and out-of-pocket expenses incurred by Hicks Muse Partners or its affiliates for the account of the Company or in connection with the performance of its services. During the years ended December 31, 2000 and 1999, the Company paid Hicks Muse Partners $.5 million and $.6 million, respectively, under the terms of the Monitoring Agreement. The Financial Advisory Agreement and the Monitoring Agreement will remain in effect until the earlier of (i) September 30, 2008, or (ii) the date on which HM4 Triton, L.P. and its affiliates cease to own beneficially, directly or indirectly, at least 5% of the Company's outstanding ordinary shares (determined after giving effect to the conversion of all 8% Convertible Preference Shares held by HM4 Triton, L.P. and its affiliates). The Company has agreed to indemnify Hicks Muse Partners with respect to liabilities incurred as a result of Hicks Muse Partners' performance of services for the Company pursuant to the Financial Advisory Agreement and the Monitoring Agreement. In 1999, the Company sold its hunting lease and related facilities to HMTF Operating, L.P., an affiliate of Hicks Muse, for proceeds of $.9 million and recognized a gain of $.4 million in other income (expense), net. From time to time HMTF Operating, L.P. permits the Company to use this facility for business purposes for a fee. During 2000, the Company paid approximately $.1 million to HMTF Operating, L.P. in connection with the use of this facility. Both Cooper Cameron Corporation ("Cooper Cameron") and Oceaneering International, Inc. ("Oceaneering") were winning bidders to provide services as subcontractors for the Company's offshore development program in Equatorial Guinea. Cooper Cameron has provided, and is continuing to provide, certain subsea equipment and related services. During 2000, the Company paid Cooper Cameron approximately $44 million. The Company expects the amounts to be paid under Cooper Cameron's current contracts will amount to approximately $40 million during 2001. Oceaneering also has provided, and is continuing to provide, certain subsea equipment and related services. During 2000, the Company paid Oceaneering approximately $2.6 million. The Company expects the amounts to be paid under Oceaneering's current contracts will amount to approximately $7 million during 2001. Mr. Erikson, a director of Triton, is the Chairman, President and Chief Executive Officer of Cooper Cameron Corporation, and Mr. Huff, a director of Triton, is the Chairman and Chief Executive Officer of Oceaneering International. In November 2000, the Company purchased from a subsidiary of Holly Corporation a one-half interest in a business aircraft for a purchase price of approximately $1.1 million, which was based on an independent appraisal of the aircraft. In addition, the Company agreed to reimburse that entity for its pro rata share of the costs of maintaining and operating the aircraft. Mr. Norsworthy, a director of Triton, is the Chairman and Chief Executive Officer of Holly Corporation. 18. COMMITMENTS AND CONTINGENCIES For internal planning purposes, the Company's capital spending program for the year ending December 31, 2001, is approximately $320 million, excluding capitalized interest and acquisitions, of which approximately $253 million relates to exploration and development activities in Equatorial Guinea, $39 million relates to exploration and development activities in Colombia and $28 million relates to the Company's exploration activities in other parts of the world. 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. Management believes that such commitments, including the capital requirements in Colombia, Equatorial Guinea and other parts of the world, as discussed previously, will be met without any material adverse effect on the Company's operations or consolidated financial condition. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Requirements. The Company leases office space, other facilities and equipment under various operating leases that expire through 2005. Total rental expense was $1.3 million, $1.3 million and $2.1 million for the years ended December 31, 2000, 1999 and 1998, respectively. At year-end 2000, the Company leased a floating production, storage and offloading vessel ("FPSO") as the cornerstone of the first phase of development in the Ceiba field. The FPSO lease has a two-year minimum lease period. At the completion of the minimum lease period, the Company can purchase the FPSO at a fixed price negotiated at inception of the lease that is not considered a bargain purchase option, terminate the lease, or elect to extend the lease for one or more one-year secondary terms up to a maximum of five additional years. At December 31, 2000, the minimum payments required under terms of the leases are as follows: 2001 -- $31.4 million; 2002 -- $28.9 million; 2003 -- $1.9 million; 2004 -- $1.7 million; and 2005 -- $1 million. GUARANTEES At December 31, 2000, the Company had guaranteed the performance of a total of $7.3 million in future exploration expenditures to be incurred through 2001 in Greece. This commitment is backed primarily by an unsecured letter of credit. 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. The Company believes that the level of future expenditures for environmental matters, including cleanup 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 During July through October 1998, eight lawsuits were filed against the Company and Thomas G. Finck and Peter Rugg, in their capacities as officers of the Company. The lawsuits were filed in the United States District Court for the Eastern District of Texas, Texarkana Division, and have been consolidated and are styled In re: Triton Energy Limited Securities Litigation. The consolidated complaint alleges violations of Sections 10(b) and 20(a) of the Exchange Act, and Rule 10b-5 promulgated thereunder, in connection with disclosures concerning the Company's properties, operations and value relating to a prospective sale in 1998 of the Company or of all or a part of its assets. The lawsuits seek recovery of an unspecified amount of compensatory damages, fees and costs. The Company has filed a motion to dismiss the claims, which is pending. The Company believes its disclosures have been accurate and intends to vigorously defend these actions. There can be no assurance that the litigation will be resolved in the Company's favor. An adverse result could have a material adverse effect on the Company's financial position or results of operations. In November 1999, a lawsuit was filed against the Company, one of its subsidiaries and Thomas G. Finck and Peter Rugg, in their capacities as former officers of the Company, in the District Court of the State of Texas for Dallas County. The lawsuit is styled Aaron Sherman, et al. vs. Triton Energy Corporation et al. and, as amended, alleges as causes of action fraud, negligent misrepresentation and violations of the Texas Securities fraud statutes in connection with the Company's 1996 reorganization as a Cayman Islands corporation and disclosures concerning the prospective sale by the Company of all or a substantial part of its assets announced in March 1998. In their most recent filing, the plaintiffs asserted actual damages of up to $10 million and sought punitive damages of up to $50 million. The Company has filed various motions to dispose of the lawsuit on the grounds that the plaintiffs do not have standing and have not plead causes of action cognizable in law. The Court has dismissed all claims of certain plaintiffs and some claims of the remaining plaintiffs for failure to plead viable causes of action. The Court entered an order for proceedings in connection with further examination of plaintiffs' claims. In August 1997, the Company was sued in the Superior Court of the State of California for the County of Los Angeles, by David A. Hite, Nordell International Resources Ltd., and International Veronex Resources, Ltd. The action was removed to the United States District Court for the Central District of California. The Company and the plaintiffs were adversaries in a 1990 arbitration proceeding in which the interest of Nordell International Resources Ltd. in the Enim oil field in Indonesia was awarded to the Company (subject to a 5% net profits interest for Nordell), and Nordell was ordered to pay the Company nearly $1 million. The arbitration award was followed by a series of legal actions by the parties in which the validity of the award and its enforcement were at issue. As a result of these proceedings, the award was ultimately upheld and enforced. The current suit alleges that the plaintiffs were damaged in amounts aggregating $13 million primarily because of the Company's prosecution of various claims against the plaintiffs, as well as alleged misrepresentations, infliction of emotional distress and improper accounting practices. The suit seeks specific performance of the arbitration award, damages for alleged fraud and misrepresentation in accounting for Enim field operating results, an accounting for Nordell's 5% net profit interest, and damages for emotional distress and various other alleged torts. The suit seeks interest, punitive damages and attorneys fees in addition to the alleged actual damages. In August 1998, the district court dismissed all claims asserted by the plaintiffs other than claims for malicious prosecution and abuse of the legal process, which the court held could not be subject to a motion to dismiss. The abuse of process claim was later withdrawn, and the damages sought were reduced to approximately $700,000 (not including punitive damages). The lawsuit was tried and the jury found in favor of the plaintiffs and assessed compensatory damages against the Company in the amount of approximately $700,000 and punitive damages in the amount of approximately $11 million. The Company believes it has acted appropriately and has appealed the verdict. Nordell has cross-appealed from the dismissal of its claims for an audit and an accounting related to the 5% net profits interest. Enforcement of the judgment has been stayed without a bond pending the outcome of the appeal. The Company is subject to certain other litigation matters, none of which is expected to have a material adverse effect on the Company's operations or consolidated financial condition.
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19. GEOGRAPHIC INFORMATION Triton's operations are primarily related to crude oil and natural gas exploration and production. The Company's principal properties, operations and oil and gas reserves are located in Colombia, Malaysia-Thailand and Equatorial Guinea. The Company is exploring for oil and gas in these areas, as well as in southern Europe, Africa and the Middle East. During the three-year period ended December 31, 2000, all sales were derived from oil and gas production in Colombia. Financial information about the Company's operations by geographic area is presented below: [Enlarge/Download Table] CORPORATE MALAYSIA- EQUATORIAL AND COLOMBIA THAILAND GUINEA EXPLORATION OTHER TOTAL -------- --------- ---------- ----------- --------- ----------- YEAR ENDED DECEMBER 31, 2000: Sales and other operating revenues $328,467 $ --- $ --- $ --- $ --- $ 328,467 Operating income (loss) 216,574 --- (2,418) (57,512) (17,955) 138,689 Depreciation, depletion and amortization 52,774 --- 266 72 1,961 55,073 Writedown of assets --- --- --- 55,369 --- 55,369 Capital expenditures and investments 41,454 8,577 157,388 23,461 1,831 232,711 Assets 526,908 101,765 270,885 53,024 241,698 1,194,280 YEAR ENDED DECEMBER 31, 1999: Sales and other operating revenues $ 247,878 $ --- $ --- $ --- $ --- $ 247,878 Operating income (loss) 115,877 --- (469) (7,214) (16,334) 91,860 Depreciation, depletion and amortization 59,728 --- 16 144 1,455 61,343 Capital expenditures and investments 79,889 8,453 19,968 12,419 754 121,483 Assets 476,543 93,188 37,229 85,250 282,265 974,475 YEAR ENDED DECEMBER 31, 1998: Sales and other operating revenues $ 160,881 $ 63,237 $ --- $ 4,500 $ --- $ 228,618 Operating income (loss) (220,697) 62,538 (124) (79,703) (39,360) (277,346) Depreciation, depletion and amortization 53,641 49 1 175 4,945 58,811 Writedown of assets 251,312 --- --- 76,664 654 328,630 Capital expenditures and investments 106,624 25,319 5,913 41,603 756 180,215 Assets 468,533 84,735 10,766 78,086 112,160 754,280 During 1998, the Company sold one-half of the shares of the subsidiary through which the Company owned its 50% share of Block A-18 resulting in a gain of $63.2 million which is included in Malaysia-Thailand sales and other operating revenues and operating income (loss). See note 2 - Asset Acquisition and Dispositions. After the sale, which resulted in a 50% ownership in the previously wholly owned subsidiary, the Company's remaining ownership is accounted for using the equity method. This investment in Block A-18 is presented in Malaysia-Thailand assets. Exploration operating income (loss) included writedowns of oil and gas properties and other assets totaling $55.4 million for the year ended December 31, 2000. Colombia operating income (loss) for the year ended December 31, 1998, included an SEC full cost ceiling limitation writedown of $241 million. Additionally, exploration operating income (loss) included writedowns of oil and gas properties and other assets totaling $76.7 million for the year ended December 31, 1998. At December 31, 2000, corporate assets were principally cash and equivalents and the U.S. deferred tax asset. Exploration assets included $32.2 million, $14.1 million and $6.4 million in Italy, Oman and Gabon, respectively. 20. QUARTERLY FINANCIAL DATA (UNAUDITED) The Company adopted SEC Staff Accounting Bulletin (SAB)101, "Revenue Recognition in Financial Statements," effective January 1, 2000, which requires the Company to record oil revenue on each sale, or tanker lifting, and oil inventories at cost, rather than at market value as in the past. The schedule below includes quarterly information as previously reported on Form 10-Q during 2000 and revised to reflect the change in accounting policy. Additionally, the pro forma effect of this change in accounting principle on the quarter ended December 31, 1999, is presented below. [Download Table] QUARTER ---------------------------------- FIRST SECOND THIRD FOURTH ------- ------- ------- ------- YEAR ENDED DECEMBER 31, 2000: Sales and other operating revenues As reported $ 74,505 $79,496 $89,096 $89,784 Revised 74,334 69,790 94,559 Gross profit As reported 44,665 50,634 44,682 26,091 Revised 44,617 43,350 48,730 Net earnings before extraordinary item and cumulative effect of accounting change As reported 26,524 28,793 17,649 4,679 Revised 26,367 22,706 21,928 Net earnings (loss) As reported 26,524 28,793 17,649 (2,283) Revised 25,022 22,706 21,928
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QUARTER ---------------------------------- FIRST SECOND THIRD FOURTH ------- ------- ------- ------- Basic earnings (loss) per ordinary share Before extraordinary item and cumulative effect of accounting change As reported 0.53 0.59 0.28 (0.07) Revised 0.53 0.42 0.40 Net earnings (loss) As reported 0.53 0.59 0.28 (0.26) Revised 0.49 0.42 0.40 Diluted earnings (loss) per ordinary share Before extraordinary item and cumulative effect of accounting change As reported 0.45 0.48 0.26 (0.07) Revised 0.45 0.38 0.36 Net earnings (loss) As reported 0.45 0.48 0.26 (0.26) Revised 0.43 0.38 0.36
[Enlarge/Download Table] QUARTER ----------------------------------------------- PRO FORMA FIRST SECOND THIRD FOURTH FOURTH -------- ------- ------- ------- ---------- YEAR ENDED DECEMBER 31, 1999: Sales and other operating revenues $49,170 $59,622 $67,295 $71,791 $ 74,082 Gross profit 14,823 25,151 32,349 46,082 47,443 Net earnings 1,887 10,883 11,762 23,025 24,676 Basic earnings (loss) per ordinary share (0.14) 0.11 0.12 0.44 0.48 Diluted earnings (loss) per ordinary share (0.14) 0.11 0.12 0.40 0.43 Gross profit comprises sales and other operating revenues less operating expenses, depreciation, depletion and amortization, and writedowns pertaining to operating assets. Gross profit for the third and fourth quarter of 2000 included writedowns totaling $18.7 million and $36.7 million, respectively. See note 12 - Writedown of Assets. Net earnings (loss) for the fourth quarter of 2000 included an approximate $7 million extraordinary charge for the early extinguishment of the 2002 Notes. Gross profit for the fourth quarter of 1999 included a nonrecurring credit issued by OCENSA in February 2000 totaling $4.2 million. The credit to pipeline tariffs resulted from OCENSA's compliance with a Colombian government decree in December 1999 that reduced its 1999 noncash expenses. 21. OIL AND GAS DATA (UNAUDITED) The following tables provide additional information about the Company's oil and gas exploration and production activities. The oil and gas data reflect the Company's proportionate interest in Block A-18 on an equity investment basis since the sale of one-half of the subsidiary through which the Company owned its 50% share of Block A-18 in August 1998. RESULTS OF OPERATIONS The results of operations for oil and gas producing activities, considering direct costs only, follow: [Download Table] TOTAL COLOMBIA OTHER WORLDWIDE -------- --------- --------- YEAR ENDED DECEMBER 31, 2000: Revenues $328,467 $ --- $ 328,467 Costs: Production costs 55,237 --- 55,237 General operating expenses 4,035 --- 4,035 Depletion 52,679 --- 52,679 Writedown of assets --- 54,186 54,186 Income tax expense (benefit) 63,288 (3,386) 59,902 -------- --------- --------- Results of operations $153,228 $(50,800) $ 102,428 ======== ========= ========= [Download Table] COLOMBIA -------- YEAR ENDED DECEMBER 31, 1999: Revenues $247,878 Costs: Production costs 68,130 General operating expenses 3,954 Depletion 59,512 Income tax expense 42,083 -------- Results of operations $ 74,199 ======== [Download Table] MALAYSIA- TOTAL COLOMBIA THAILAND OTHER WORLDWIDE ---------- -------- --------- ---------- YEAR ENDED DECEMBER 31, 1998: Revenues $ 160,881 $63,237 $ 4,500 $ 228,618 Costs: Production costs 73,546 --- --- 73,546 General operating expenses 2,460 --- --- 2,460 Depletion 53,304 --- --- 53,304 Writedown of assets 251,312 --- 76,664 327,976 Income tax benefit (76,048) --- (22,527) (98,575) ---------- -------- --------- ---------- Results of operations $(143,693) $63,237 $(49,637) $(130,093) ========== ======== ========= ========== Production from the Ceiba field in Equatorial Guinea began in November 2000, but the first sale did not occur until January 2001. Malaysia-Thailand revenues for the year ended December 31, 1998, included a gain of $63.2 million from the sale of one-half of the shares of the subsidiary through which the Company owned its 50% share of Block A-18. Other revenues for the year ended December 31, 1998, included a gain of $4.5 million from the sale of the Company's Bangladesh subsidiary. Depletion includes depreciation on support equipment and facilities calculated on the unit-of-production method. COSTS INCURRED AND CAPITALIZED COSTS The costs incurred in oil and gas acquisition, exploration and development activities and related capitalized costs follow: [Download Table] EQUATORIAL TOTAL COLOMBIA GUINEA OTHER WORLDWIDE -------- ---------- ------- --------- DECEMBER 31, 2000: Costs incurred: Property acquisition $ --- $ --- $ 4,750 $ 4,750 Exploration --- 25,643 26,776 52,419 Development 52,326 169,899 --- 222,225 Depletion per equivalent barrel of production 4.37 --- --- 4.37 Cost of properties at year-end: Unevaluated $ --- $ 18,207 $49,686 $ 67,893 ======== ========== ======= ========= Evaluated $562,598 $ 212,428 $54,162 $ 829,188 ======== ========== ======= ========= Support equipment and facilities $311,632 $ --- $ --- $ 311,632 ======== ========== ======= ========= Accumulated depletion and depreciation at year-end $471,563 $ --- $54,162 $ 525,725 ======== ========== ======= ========= [Download Table] EQUATORIAL TOTAL COLOMBIA GUINEA OTHER WORLDWIDE -------- ---------- ------- --------- DECEMBER 31, 1999: Costs incurred: Property acquisition $ 6,400 $ --- $ 20 $ 6,420 Exploration 155 23,631 13,051 36,837 Development 80,782 --- --- 80,782 Depletion per equivalent barrel of production 3.80 --- --- 3.80 Cost of properties at year-end: Unevaluated $ --- $ 5,772 $72,755 $ 78,527 ======== ========== ======= ========= Evaluated $530,947 $ 29,322 $ 680 $ 560,949 ======== ========== ======= ========= Support equipment and facilities $303,244 $ --- $ --- $ 303,244 ======== ========== ======= ========= Accumulated depletion and depreciation at year-end $419,651 $ --- $ 680 $ 420,331 ======== ========== ======= =========
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[Download Table] MALAYSIA- EQUATORIAL TOTAL COLOMBIA THAILAND GUINEA OTHER WORLDWIDE -------- --------- ---------- ------- --------- DECEMBER 31, 1998: Costs incurred: Property acquisition $ --- $ --- $ --- $ 500 $ 500 Exploration 2,886 17,739 5,913 43,153 69,691 Development 83,088 1,026 --- --- 84,114 Depletion per equivalent barrel of production 4.07 --- --- --- 4.07 Cost of properties at year-end: Unevaluated $ --- $ --- $ 10,754 $60,082 $ 70,836 ======== ========= ========== ======= ========= Evaluated $467,147 $ --- $ --- $76,367 $ 543,514 ======== ========= ========== ======= ========= Support equipment and facilities $289,659 $ --- $ --- $ --- $ 289,659 ======== ========= ========== ======= ========= Accumulated depletion and depreciation at year-end $360,324 $ --- $ --- $76,367 $ 436,691 ======== ========= ========== ======= ========= Development costs include additions to production facilities and equipment, additions to development wells, including those in progress, and depreciation of support equipment and related facilities. A summary of costs excluded from depletion at December 31, 2000, by year incurred follows: [Download Table] DECEMBER 31, -------------------------------------------------- TOTAL 2000 1999 1998 1997 AND PRIOR ------- ------- ------- ------- -------------- Property acquisition $ 1,850 $ --- $ --- $ 500 $ 1,350 Exploration 51,519 15,766 8,194 15,475 12,084 Capitalized interest 14,524 10,744 2,763 718 299 ------- ------- ------- ------- -------------- Total worldwide $67,893 $26,510 $10,957 $16,693 $ 13,733 ======= ======= ======= ======= ============== The Company excludes from its depletion computation property acquisition and exploration costs of unevaluated properties and major development projects in progress. Excluded costs include exploration costs of $28.1 million, $13.6 million and $6.4 million in Italy, Oman and Gabon, respectively, where there are no proved reserves at December 31, 2000. Subject to the possible extension or modification of the Company's commitments, the Company expects to complete its contractual obligations in Italy and Oman over the next 12 to 18 months. With respect to the remaining excluded costs, the Company is unable to predict either the timing of the inclusion of these costs and any 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 share of costs incurred for Block A-18 were $8.6 million and $8.2 million for the years ended December 31, 2000 and 1999, respectively. Net capitalized costs were $101.8 million and $90.2 million at December 31, 2000 and 1999, respectively. OIL AND GAS RESERVE DATA (OIL RESERVES ARE STATED IN THOUSANDS OF BARRELS AND GAS RESERVES ARE STATED IN MILLIONS OF CUBIC FEET.) The following tables present the Company's estimates of its proved oil and gas reserves. The estimates for the proved reserves in the Cusiana and Cupiagua fields in Colombia and the Ceiba field in Equatorial Guinea were prepared by the Company's independent petroleum engineers, DeGolyer and MacNaughton and Netherland, Sewell & Associates, Inc., respectively. The estimates for proved reserves in Malaysia-Thailand were prepared by the internal petroleum engineers of the operating company, Carigali-Triton Operating Company (CTOC). The Company emphasizes that reserve estimates are approximate 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, and there can be no assurance that the proved undeveloped reserves will be developed within the periods anticipated. Production from the Ceiba field in Equatorial Guinea began in November 2000, but the first sale did not occur until January 2001. As of December 31, 2000, gas sales had not yet commenced from the Company's 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 the base price in the gas sales agreement of $2.30. The base price is subject to annual adjustments based on various indices. There can be no assurance as to what the actual price will be when gas sales commence. [Enlarge/Download Table] EQUITY INVESTMENT COLOMBIA EQUATORIAL GUINEA TOTAL WORLDWIDE MALAYSIA-THAILAND -------------------- -------------------- -------------------- -------------------- OIL GAS OIL GAS OIL GAS OIL GAS --------- --------- --------- --------- --------- --------- --------- --------- PROVED DEVELOPED AND UNDEVELOPED RESERVES AS OF DECEMBER 31, 1999 125,571 11,566 32,033 --- 157,604 11,566 13,223 553,862 Revisions (8,000) (231) --- --- (8,000) (231) (99) 27,846 Purchases --- --- --- --- --- --- --- --- Extensions and discoveries --- --- 43,134 --- 43,134 --- --- --- Production (11,167) (470) --- --- (11,167) (470) --- --- --------- -------- ---------- --------- --------- --------- --------- --------- AS OF DECEMBER 31, 2000 106,404 10,865 75,167 --- 181,571 10,865 13,124 581,708 ========= ======== ========== ========= ========= ========= ========= ========= PROVED DEVELOPED RESERVES AT DECEMBER 31, 2000 81,101 10,865 24,663 --- 105,764 10,865 --- --- ========= ======== ========== ========= ========= ========= ========= ========= [Enlarge/Download Table] EQUITY INVESTMENT COLOMBIA EQUATORIAL GUINEA TOTAL WORLDWIDE MALAYSIA-THAILAND ------------------ ------------------ ------------------ ------------------ OIL GAS OIL GAS OIL GAS OIL GAS -------- -------- -------- -------- -------- -------- -------- -------- PROVED DEVELOPED AND UNDEVELOPED RESERVES AS OF DECEMBER 31, 199 135,327 12,284 --- --- 135,327 12,284 8,017 570,312 Revisions (567) (259) --- --- (567) (259) 5,206 (16,450) Purchases 3,280 --- --- --- 3,280 --- --- --- Extensions and discoveries --- --- 32,033 --- 32,033 --- --- --- Production (12,469) (459) --- --- (12,469) (459) --- --- -------- -------- -------- -------- -------- -------- -------- -------- AS OF DECEMBER 31, 1999 125,571 11,566 32,033 --- 157,604 11,566 13,223 553,862 ======== ======== ======== ======== ======== ======== ======== ======== PROVED DEVELOPED RESERVES AT DECEMBER 31, 1999 91,859 11,566 --- --- 91,859 11,566 --- --- ======== ======== ======== ======== ======== ======== ======== ======== [Enlarge/Download Table] EQUITY INVESTMENT COLOMBIA EQUATORIAL GUINEA TOTAL WORLDWIDE MALAYSIA-THAILAND ----------------- -------------------- -------------------- ------------------ OIL GAS OIL GAS OIL GAS OIL GAS -------- ------- -------- ---------- -------- ---------- -------- -------- PROVED DEVELOPED AND UNDEVELOPED RESERVES AS OF DECEMBER 31, 1997 145,999 14,619 29,800 1,223,800 175,799 1,238,419 --- --- Revisions (693) (1,832) (6,583) (41,588) (7,276) (43,420) --- --- Sales --- --- (15,200) (625,400) (15,200) (625,400) --- --- Equity investment --- --- (8,017) (570,312) (8,017) (570,312) 8,017 570,312 Extensions and discoveries --- --- --- 13,500 --- 13,500 --- --- Production (9,979) (503) --- --- (9,979) (503) --- --- -------- ------- -------- ---------- -------- ---------- -------- -------- AS OF DECEMBER 31, 1998 135,327 12,284 --- --- 135,327 12,284 8,017 570,312 ======== ======= ======== ========== ======== ========== ======== ======== PROVED DEVELOPED RESERVES AT DECEMBER 31, 1998 86,039 12,284 --- --- 86,039 12,284 --- --- ======== ======= ======== ========== ======== ========== ======== ======== 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 future net cash inflows discounted at an annual rate of 10%. The future net cash inflows were calculated in accordance with SEC guidelines. Future cash inflows were computed by applying year-end prices of oil and gas relating to the Company's proved reserves to the estimated year-end quantities of those reserves. The future cash inflow estimates for 2000 attributable to oil reserves were based on the year-end WTI crude oil price of $26.80 per barrel for the Company's reserves in Colombia and Malaysia-Thailand, and the year-end Dated Brent crude oil price of $22.54 per barrel for the Company's reserves in Equatorial Guinea, in each case before adjustments for oil quality and transportation costs. In 1999, the Company and the other parties to the production-sharing contract for Block A-18 executed a gas sales agreement providing for the sale of the first phase of gas. In estimating discounted future net cash inflows attributable to such interest, the Company assumed that production from the interest would be sold at the base price in the gas sales agreement of $2.30. The base price is subject to annual adjustments based on various indices. There can be no assurance as to what the actual price will be when gas sales commence. 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 year-end 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 based. Actual future cash inflows may vary materially. In connection with the sale to BP of one-half of the shares through which the Company owned its interest in Block A-18, BP agreed to pay the Company an additional $65 million each at July 1, 2002, and July 1, 2005, if certain specific development objectives are met by such dates, or $40 million each if the objectives are met within one year thereafter. For purposes of calculating future cash inflows for Malaysia-Thailand at December 31, 2000, the Company assumed that it would receive an incentive payment of $40 million. There can be no assurances that the Company will receive any incentive payments. [Enlarge/Download Table] EQUITY INVESTMENT EQUATORIAL TOTAL MALAYSIA- COLOMBIA GUINEA WORLDWIDE THAILAND ---------- ---------- ---------- ---------- DECEMBER 31, 2000: Future cash inflows $2,683,051 $1,356,027 $4,039,078 $1,686,677 Future production and development costs 646,930 573,511 1,220,441 634,547 ---------- ---------- ---------- ---------- Future net cash inflows before income taxes $2,036,121 $ 782,516 $2,818,637 $1,052,130 ========== ========== ========== ========== Future net cash inflows before income taxes discounted at 10% per annum $1,261,684 $ 594,589 $1,856,273 $ 283,694 Future income taxes discounted at 10% per annum 382,699 98,903 481,602 17,521 ---------- ---------- ---------- ---------- Standardized measure of discounted future net cash inflows $ 878,985 $ 495,686 $1,374,671 $ 266,173 ========== ========== ========== ==========
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[Enlarge/Download Table] EQUITY INVESTMENT EQUATORIAL TOTAL MALAYSIA- COLOMBIA GUINEA WORLDWIDE THAILAND ---------- ---------- ---------- ---------- DECEMBER 31, 1999: Future cash inflows $3,152,352 $ 765,275 $3,917,627 $1,649,881 Future production and development costs 817,065 399,365 1,216,430 703,419 ---------- ---------- ---------- ---------- Future net cash inflows before income taxes $2,335,287 $ 365,910 $2,701,197 $ 946,462 ========== ========== ========== ========== Future net cash inflows before income taxes discounted at 10% per annum $1,414,433 $ 263,849 $1,678,282 $ 266,631 Future income taxes discounted at 10% per annum 391,796 57,589 449,385 15,845 ---------- ---------- ---------- ---------- Standardized measure of discounted future net cash inflows $1,022,637 $ 206,260 $1,228,897 $ 250,786 ========== ========== ========== ========== [Download Table] EQUITY INVESTMENT MALAYSIA- COLOMBIA THAILAND ---------- ---------- DECEMBER 31, 1998: Future cash inflows $1,481,065 $1,555,929 Future production and development costs 734,025 695,575 ---------- ---------- Future net cash inflows before income taxes $ 747,040 $ 860,354 ========== ========== Future net cash inflows before income taxes discounted at 10% per annum $ 415,127 $ 253,535 Future income taxes discounted at 10% per annum 3,909 8,917 ---------- ---------- Standardized measure of discounted future net cash inflows $ 411,218 $ 244,618 ========== ==========
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Changes in the standardized measure of discounted future net cash inflows follow: [Enlarge/Download Table] DECEMBER 31, ------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Total worldwide: Beginning of year $1,228,897 $ 411,218 $1,069,343 Sales, net of production costs (273,230) (179,748) (87,335) Sales of reserves --- --- (70,543) Equity investment --- --- (244,618) Revisions of quantity estimates (129,433) (6,546) (29,321) Net change in prices and production costs (98,228) 1,105,963 (579,212) Extensions, discoveries and improved recovery 414,829 206,260 6,516 Change in future development costs (175,430) (61,728) (46,633) Purchases of reserves --- 6,400 --- Development and facilities costs incurred 209,658 70,828 105,808 Accretion of discount 270,120 74,704 120,270 Changes in production rates and other (40,295) (10,567) (30,772) Net change in income taxes (32,217) (387,887) 197,715 ----------- ----------- ----------- End of year $1,374,671 $1,228,897 $ 411,218 =========== =========== =========== SCHEDULE II TRITON ENERGY LIMITED AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS (IN THOUSANDS) [Enlarge/Download Table] ADDITIONS ------------------------- BALANCE AT CHARGED TO BALANCE BEGINNING CHARGED TO OTHER AT CLOSE CLASSIFICATIONS OF YEAR EARNINGS ACCOUNTS DEDUCTIONS OF YEAR ------------------------- ----------- ------------ ----------- ------------ --------- Year ended Dec. 31, 1998: Allowance for doubtful receivables $ 41 $ --- $ --- $ (41) $ --- =========== ============ =========== ============ ========= Allowance for deferred tax asset $ 75,092 $ 18,519 $ --- $ --- $ 93,611 =========== ============ =========== ============ ========= Year ended Dec. 31, 1999: Allowance for deferred tax asset $ 93,611 $ (11,925) $ --- $ --- $ 81,686 =========== ============ =========== ============ ========= Year ended Dec. 31, 2000: Allowance for doubtful receivables $ --- $ 1,183 $ --- $ --- $ 1,183 =========== ============ =========== ============ ========= Allowance for deferred tax asset $ 81,686 $ (32,991) $ --- $ --- $ 48,695 =========== ============ =========== ============ =========

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10/1/031021
6/30/03516
4/1/0310
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7/1/0229
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4/1/02510
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4/1/011221
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6/30/001810-Q
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1/1/001027
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9/30/991810-Q,  10-Q/A
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5/11/9918DEF 14A
4/9/9918
3/31/991810-Q,  10-Q/A
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1/5/9918SC 13D/A
1/4/9925
12/31/98113110-K405,  11-K
10/2/9818
9/30/98101810-Q
8/31/98188-K
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