10-Q 1 june200110q.txt UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ----------------------- FORM 10-Q (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2001 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 or other jurisdiction (I.R.S. Employer of incorporation or Identification No.) organization) CALEDONIAN HOUSE, JENNETT STREET, P.O. BOX 1043, GEORGE TOWN, GRAND CAYMAN, CAYMAN ISLANDS (Address of principal executive offices and zip code) Registrant's telephone number, including area code: (345) 949-0050 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 the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Number of Shares Title of Each Class Outstanding at July 25, 2001 Ordinary Shares, par value $0.01 per share 38,188,937 ------------------------------- TRITON ENERGY LIMITED AND SUBSIDIARIES INDEX

PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS TRITON ENERGY LIMITED AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)

See accompanying Notes to Condensed Consolidated Financial Statements. TRITON ENERGY LIMITED AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA) (UNAUDITED)

The Company uses the full cost method to account for its oil and gas producing activities. See accompanying Notes to Condensed Consolidated Financial Statements. TRITON ENERGY LIMITED AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SIX MONTHS ENDED JUNE 30, 2001 AND 2000 (IN THOUSANDS) (UNAUDITED)

See accompanying Notes to Condensed Consolidated Financial Statements. TRITON ENERGY LIMITED AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY SIX MONTHS ENDED JUNE 30, 2001 (IN THOUSANDS) (UNAUDITED)

See accompanying Notes to Condensed Consolidated Financial Statements. TRITON ENERGY LIMITED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (AMOUNTS IN TABLES IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) 1. 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, offshore Equatorial Guinea and offshore 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. All sales prior to January 2001 were derived from oil and gas production in Colombia. Beginning in January 2001, sales are derived from oil and gas production in Colombia and oil production in Equatorial Guinea. In the opinion of management, our accompanying unaudited condensed consolidated financial statements contain all adjustments of a normal recurring nature necessary to present fairly our financial position as of June 30, 2001, and the results of our operations for the three and six months ended June 30, 2001 and 2000, our cash flows for the six months ended June 30, 2001 and 2000, and shareholders' equity for the six months ended June 30, 2001. The results for the six months ended June 30, 2001, are not necessarily indicative of the final results to be expected for the full year. The condensed consolidated financial statements should be read in conjunction with the Notes to Consolidated Financial Statements, which are included as part of our Annual Report on Form 10-K for the year ended December 31, 2000. Certain other previously reported financial information has been reclassified to conform to the current period's presentation. SUBSEQUENT EVENT - RECENT DEVELOPMENTS On July 17, 2001, a subsidiary of Amerada Hess Corporation commenced a tender offer to purchase all of our outstanding ordinary shares for $45 per share. Amerada Hess' offer is described in detail in a Schedule TO and its exhibits that Amerada Hess filed with the Securities and Exchange Commission on July 17, 2001. The tender offer is conditioned upon there being validly tendered, and not withdrawn, a number of ordinary shares that represents at least 90% in value of our outstanding ordinary shares on a fully-diluted basis. The tender offer is also subject to regulatory approvals and other customary conditions, but the tender offer is not subject to any financing condition. The tender offer is scheduled to expire at midnight, New York City time, on August 13, 2001, subject to possible extension. If the 90% condition is not satisfied, but there are tendered at least a number of ordinary shares representing a majority of the total number of votes of the outstanding ordinary shares on a fully-diluted basis, Amerada Hess at its option may purchase those shares that are tendered. If Amerada Hess terminates the offer, it may, at its option, require us to seek approval from our shareholders for a scheme of arrangement pursuant to which all ordinary shares would be acquired for $45 in cash per ordinary share and all 8% convertible preference shares would be purchased for $180, plus accrued and unpaid dividends, in cash per preference share, or it may cease the acquisition altogether. The tender offer is being made pursuant to an acquisition agreement we entered into with Amerada Hess on July 9, 2001, as amended. We also entered into a principal shareholders agreement with Amerada Hess, HM4 Triton L.P. and certain affiliates of HM4 Triton L.P. These principal shareholders together hold ordinary shares and 8% convertible preference shares representing, in the aggregate, approximately 34% of our outstanding ordinary shares, determined on a fully-diluted basis. Pursuant to the principal shareholders agreement, the principal shareholders have agreed to tender their ordinary shares (including ordinary shares issuable upon conversion of their preference shares) in the tender offer. In addition, pursuant to the principal shareholders agreement, subject to specified conditions, if the tender offer expires or is terminated, Amerada Hess has agreed to purchase, and the principal shareholders have agreed to sell to Amerada Hess, their shares at the price of $45 per ordinary share and $180.00 per 8% convertible preference share, plus accumulated and unpaid dividends. In order to effectuate these transactions, we amended our shareholders agreement with HM4 Triton, L.P. to provide that if and when Amerada Hess purchases the principal shareholders' shares pursuant to the terms of the principal shareholders agreement, Amerada Hess would become entitled to the same rights and subject to the same restrictions under the shareholders agreement to which HM4 Triton, L.P. currently is entitled or subject. These rights include, among others, the right to designate up to four directors to our board of directors and the right to approve or disapprove of certain major events or transactions. If pursuant to the tender offer Amerada Hess owns at least 90% in value of our ordinary shares, Amerada Hess and we will take all necessary action under Cayman Islands law to complete a compulsory acquisition of the ordinary shares not tendered in the tender offer as promptly as practicable following the completion of the tender offer. The purchase price for the ordinary shares in the compulsory acquisition would be the same as the price paid in the tender offer. If Amerada Hess purchases all of the tendered ordinary shares, there may be so few remaining holders of publicly held ordinary shares that (a) our ordinary shares will no longer meet the published guidelines of the New York Stock Exchange for continued listing and may be delisted from the New York Stock Exchange, (b) there may not be a public trading market for our ordinary shares, and (c) we may cease making filings with the Securities and Exchange Commission or may not be required to comply with the Securities and Exchange Commission rules relating to publicly held companies. The foregoing descriptions of the agreements are summaries and do not purport to be complete and are qualified in their entirety by reference to the full text of the agreements. The agreements and related agreements, as amended, are filed as exhibits to our Form 8-K, which was filed with the Securities and Exchange Commission on July 11, 2001, and Form 8-K/A, which was filed on July 17, 2001. You can review our filings and their exhibits, as well as the filings of Amerada Hess, at the Securities and Exchange Commission's web site at http://www.sec.gov. You can also obtain a copy of these filings from the public reference room of the Securities and Exchange Commission by calling (800) SEC-0330. 2. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES We adopted Statement of Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001. In accordance with the transition provisions of SFAS 133, we recorded a net-of-tax cumulative effect gain of $1.2 million to earnings to recognize the ineffective portion of changes in fair value of hedging positions and the time value component of option contracts. We also recorded a net-of-tax cumulative effect gain of $2.9 million to comprehensive income to recognize the fair value of the effective portion of all derivative instruments designated as cash flow hedges. Our oil sales are normally priced with reference to a defined benchmark, such as West Texas Intermediate spot ("WTI") 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, including swaps, collars and options, or combinations of these, with creditworthy counterparties to reduce risk associated with the pricing of our oil sales. We may designate certain derivative transactions as cash flow hedges based on the assessment of the expected effectiveness (as defined by SFAS 133) of the derivative transaction. For financial and commodity market transactions in which we hedge the variability of our 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, the ineffective portion of changes in fair value of hedging transactions and the time value component of option contracts designated as hedges, will be recognized in earnings in the period changes in fair value occur. There is no tax effect related to our derivative activities. Changes in fair value of derivatives reported in other income (expense), net in the Condensed Consolidated Statements of Operations is comprised of the following:

At June 30, 2001, we had an unrealized loss of $.3 million in accumulated other nonowner changes in shareholders' equity related to cash flow hedges that will expire during the next nine months as monthly settlements occur. At June 30, 2001, we recorded an asset of $3.2 million and a liability of $.6 million for the fair value of our derivative instruments. 3. SEGMENT INFORMATION Our operations are primarily related to crude oil and natural gas exploration and production. Our principal properties, operations and oil and gas reserves are located in Colombia, offshore Equatorial Guinea and offshore Malaysia-Thailand. Financial information about our operations is presented below:

4. ADVANCES FOR EQUIPMENT One of our directors is the chief executive officer of a company that is providing us with certain subsea equipment for the development of the Ceiba field offshore Equatorial Guinea. We had advanced $25.4 million at June 30, 2001, and $16.8 million at December 31, 2000 to the third party under our current contract. 5. INVENTORIES, PREPAID EXPENSES AND OTHER

6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

7. 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 three and six months ended June 30, 2001 and 2000.

8. COMMITMENTS AND CONTINGENCIES For internal planning purposes, our revised capital spending program for the year ending December 31, 2001, is approximately $385 million, excluding capitalized interest and acquisitions, of which approximately $318 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. During the normal course of business, we are subject to the terms of various operating agreements and capital commitments associated with the exploration and development of our 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 our operations or consolidated financial condition. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Requirements. GUARANTEES At June 30, 2001, we had guaranteed the performance of a total of $6.6 million in future exploration expenditures to be incurred in Greece through 2001. This commitment is backed primarily by an unsecured letter of credit. LITIGATION 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 all or a substantial part of our assets. The lawsuits seek recovery of an unspecified amount of compensatory damages, fees and costs. The District Court has denied our motion to dismiss the claims. 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. In addition to the matters described above, we are also subject to litigation that is incidental to our business. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Please read the following discussion and analysis in conjunction with our financial information and our condensed 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. RECENT DEVELOPMENTS ------------------- On July 17, 2001, a subsidiary of Amerada Hess Corporation commenced a tender offer to purchase all of our outstanding ordinary shares for $45 per share. Amerada Hess' offer is described in detail in a Schedule TO and its exhibits that Amerada Hess filed with the Securities and Exchange Commission on July 17, 2001. The tender offer is conditioned upon there being validly tendered, and not withdrawn, a number of ordinary shares that represents at least 90% in value of our outstanding ordinary shares on a fully-diluted basis. The tender offer is also subject to regulatory approvals and other customary conditions, but the tender offer is not subject to any financing condition. The tender offer is scheduled to expire at midnight, New York City time, on August 13, 2001, subject to possible extension. If the 90% condition is not satisfied, but there are tendered at least a number of ordinary shares representing a majority of the total number of votes of the outstanding ordinary shares on a fully-diluted basis, Amerada Hess at its option may purchase those shares that are tendered. If Amerada Hess terminates the offer, it may, at its option, require us to seek approval from our shareholders for a scheme of arrangement pursuant to which all ordinary shares would be acquired for $45 in cash per ordinary share and all 8% convertible preference shares would be purchased for $180, plus accrued and unpaid dividends, in cash per preference share, or it may cease the acquisition altogether. The tender offer is being made pursuant to an acquisition agreement we entered into with Amerada Hess on July 9, 2001, as amended. We also entered into a principal shareholders agreement with Amerada Hess, HM4 Triton L.P. and certain affiliates of HM4 Triton L.P. These principal shareholders together hold ordinary shares and 8% convertible preference shares representing, in the aggregate, approximately 34% of our outstanding ordinary shares, determined on a fully-diluted basis. Pursuant to the principal shareholders agreement, the principal shareholders have agreed to tender their ordinary shares (including ordinary shares issuable upon conversion of their preference shares) in the tender offer. In addition, pursuant to the principal shareholders agreement, subject to specified conditions, if the tender offer expires or is terminated, Amerada Hess has agreed to purchase, and the principal shareholders have agreed to sell to Amerada Hess, their shares at the price of $45 per ordinary share and $180.00 per 8% convertible preference share, plus accumulated and unpaid dividends. In order to effectuate these transactions, we amended our shareholders agreement with HM4 Triton, L.P. to provide that if and when Amerada Hess purchases the principal shareholders' shares pursuant to the terms of the principal shareholders agreement, Amerada Hess would become entitled to the same rights and subject to the same restrictions under the shareholders agreement to which HM4 Triton, L.P. currently is entitled or subject. These rights include, among others, the right to designate up to four directors to our board of directors and the right to approve or disapprove of certain major events or transactions. If pursuant to the tender offer Amerada Hess owns at least 90% in value of our ordinary shares, Amerada Hess and we will take all necessary action under Cayman Islands law to complete a compulsory acquisition of the ordinary shares not tendered in the tender offer as promptly as practicable following the completion of the tender offer. The purchase price for the ordinary shares in the compulsory acquisition would be the same as the price paid in the tender offer. If Amerada Hess purchases all of the tendered ordinary shares, there may be so few remaining holders of publicly held ordinary shares that (a) our ordinary shares will no longer meet the published guidelines of the New York Stock Exchange for continued listing and may be delisted from the New York Stock Exchange, (b) there may not be a public trading market for our ordinary shares, and (c) we may cease making filings with the Securities and Exchange Commission or may not be required to comply with the Securities and Exchange Commission rules relating to publicly held companies. The foregoing descriptions of the agreements are summaries and do not purport to be complete and are qualified in their entirety by reference to the full text of the agreements. The agreements and related agreements, as amended, are filed as exhibits to our Form 8-K, which was filed with the Securities and Exchange Commission on July 11, 2001, and Form 8-K/A, which was filed on July 17, 2001. You can review our filings and their exhibits, as well as the filings of Amerada Hess, at the Securities and Exchange Commission's web site at http://www.sec.gov. You can also obtain a copy of these filings from the public reference room of the Securities and Exchange Commission by calling (800) SEC-0330. LIQUIDITY AND CAPITAL REQUIREMENTS ---------------------------------- Cash and equivalents totaled $63.1 million at June 30, 2001, and $136.4 million at December 31, 2000. Working capital was $69.9 million at June 30, 2001, compared with $63.3 million at December 31, 2000. The following summary table reflects our cash flows for the six months ended June 30, 2001 (in thousands): Net cash provided (used) by operating activities $ 79,951 Net cash provided (used) by investing activities $(134,321) Net cash provided (used) by financing activities $ (18,643) Net Cash Provided (Used) by Operating Activities ------------------------------------------------ Our cash flows for the six months ended June 30, 2001, benefited from the commencement of crude oil sales in January 2001 from the Ceiba field offshore Equatorial Guinea. Gross production from the Ceiba field averaged 40,000 barrels of oil per day ("BOPD") (28,000 BOPD net to us). Gross production from the Cusiana and Cupiagua fields in Colombia averaged 308,000 BOPD (30,000 BOPD net to us) during the first six months of 2001. The consolidated average realized oil price was $24.31 per barrel. Our cash flows were reduced by working capital changes of $68 million, primarily resulting from an increase in advances for equipment of $62 million related to the ongoing development of the Ceiba field. Net Cash Provided (Used) by Investing Activities ------------------------------------------------------ Our capital expenditures and other capital investments were $134.1 million ($125.6 million excluding capitalized interest) for the six months ended June 30, 2001, primarily for development of the Ceiba field in Equatorial Guinea. Net Cash Provided (Used) by Financing Activities ------------------------------------------------------ For the six months ended June 30, 2001, we repaid borrowings of $4.5 million under a term credit facility and paid cash preference-share dividends totaling $14.5 million. Future Capital Needs ---------------------- Our revised capital spending program for the year ending December 31, 2001, is approximately $385 million, excluding capitalized interest and acquisitions, of which approximately $318 million relates to exploration and development activities in Equatorial Guinea ($104.4 million paid through June 30 not including $55 million advanced to vendors for equipment), $39 million relates to exploration and development activities in Colombia ($18.4 million paid through June 30) and $28 million relates to our exploration activities in other parts of the world ($2.8 million paid through June 30). In addition, we have accrued capital spending of $51.7 million at June 30, 2001. In Equatorial Guinea, we are continuing to implement an accelerated appraisal and development program for the Ceiba field, as well as continuing our exploration program. The current plan for development calls for a total of 10 production wells and four water injection wells to be drilled and completed by early 2002. In connection with this phase of development, we are planning to increase the processing capacity of the floating production, storage and offloading vessel ("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. In June 2001, we announced that we made oil discoveries with the Okume-1 and Oveng-1 wells in Block G in Equatorial Guinea. We are formulating an appraisal program to confirm the Okume and Oveng discoveries and define minimum economic reserves for project development. Additionally, we are evaluating options for an early production system if warranted. In the event the Amerada Hess transaction does not close, 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. In order to install the necessary equipment to increase the processing capacity of the facilities in Equatorial Guinea, 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 January 2002 and will last approximately four weeks. The prices we realize from our sales also are subject to a number of uncertanties, such as fluctuations in benchmark prices, as well as differentials from these prices. See "Disclosure Regarding Forward-Looking Information" and "Certain Factors That Could Affect Future Operations" below. In May 2001, we extended the maturity date of our revolving credit facility with a group of banks from February 2002 to June 2003. 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 of July 30, 2001, the borrowing base was $150 million, and we had no borrowings outstanding under the facility. 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 June 30, 2001, we had guaranteed the performance of a total of $6.6 million in future exploration expenditures to be incurred in Greece through 2001. This commitment is backed primarily by an unsecured letter of credit. RESULTS OF OPERATIONS --------------------- Sales volumes and average prices realized were as follows:

(1) Includes the effect of barrels delivered under the forward oil sale that were recognized at $11.56 per barrel and settlements of derivative instruments. THREE MONTHS ENDED JUNE 30, 2001, COMPARED WITH THREE MONTHS ENDED JUNE 30, 2000 Oil and Gas Sales -------------------- Consolidated oil and gas sales for the second quarter of 2001 totaled $123.7 million, a 77% increase from the second quarter of 2000, due to the commencement of crude oil sales from the Ceiba field in Equatorial Guinea in January 2001. Consolidated sales volumes increased 77% in second-quarter 2001, compared with the prior-year quarter. Oil sales from the Ceiba field totaled $55.3 million for the second quarter of 2001. The average realized oil price was $23.25 per barrel. Gross production from the Ceiba field averaged 41,000 BOPD (29,000 BOPD net to us). Oil and gas sales from the Cusiana and Cupiagua fields in Colombia totaled $68.5 million for the second quarter of 2001 and $69.8 million for the prior-year quarter. The average realized oil price increased $2.05 per barrel to $27.33 per barrel, resulting in an increase in revenues of $5.1 million, compared with the same period in 2000. This increase was offset by lower sales volumes, resulting in a revenue decrease of $6.5 million. Gross production from the Cusiana and Cupiagua fields averaged 303,000 BOPD (29,000 BOPD net to us) for the second-quarter 2001, compared with 342,000 BOPD (33,000 BOPD net to us) for the prior-year quarter. Sales of our crude oil in both Colombia and Equatorial Guinea are recognized 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. 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. We have entered into financial and commodity market transactions intended primarily to reduce risk associated with changing oil prices. Our oil sales were approximately $.4 million more during the three months ended June 30, 2001, and approximately $7.3 million less during the three months ended June 30, 2000,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 and 2002 oil production. See "Quantitative and Qualitative Disclosures about Market Risk" below. Costs and Expenses -------------------- Operating expenses totaled $25.1 million in 2001, compared with $14.1 million in 2000. Second-quarter 2001 operating expenses included $13.5 million, or $5.67 per barrel, associated with oil sales in Equatorial Guinea. In Colombia, operating expenses were $4.60 per equivalent barrel in the second-quarter 2001, compared with $5.15 per equivalent barrel in the prior-year quarter. Depreciation, depletion and amortization increased $14.1 million, primarily due to the commencement of liftings from the Ceiba field and a higher depletion rate per barrel in Colombia. Depletion per barrel of production was $5.55 in Equatorial Guinea for second-quarter 2001, while Colombia's depletion rate per equivalent barrel of production was $4.89 in the second-quarter 2001 compared with $4.21 in the second-quarter 2000. General and administrative expenses before capitalization decreased $1 million to $7.6 million in 2001. Capitalized general and administrative costs were $1.8 million in 2001 and $2.8 million in 2000. Interest Expense, Net ----------------------- Gross interest expense increased $2.1 million, or 22%, to $11.5 million in 2001 as a result of higher outstanding debt balances following the issuance of the 8 7/8% Senior Notes due 2007 in the fourth quarter of 2000. Capitalized interest decreased $.8 million in 2001 to $4.5 million. Income Taxes ------------- Current taxes associated with our Colombian operations increased to $16.7 million in 2001, from $11.6 million in 2000. Current taxes in 2000 included a $5.3 million benefit from the utilization of our net operating losses. The income tax provisions included deferred tax expense of $6.4 million for 2001 and $1.7 million for 2000. This increase is primarily associated with the deferred taxes related to operations in Equatorial Guinea. SIX MONTHS ENDED JUNE 30, 2001, COMPARED WITH SIX MONTHS ENDED JUNE 30, 2000 Oil and Gas Sales -------------------- Consolidated oil and gas sales in 2001 totaled $267.6 million, an 86% increase from prior year due to the commencement of crude oil sales from the Ceiba field in Equatorial Guinea in January 2001. Oil sales from the Ceiba field totaled $117.7 million in 2001. The average realized oil price was $21.23 per barrel. Gross production from the Ceiba field averaged 40,000 BOPD (28,000 BOPD net to us). Oil and gas sales from the Cusiana and Cupiagua fields in Colombia totaled $149.9 million in 2001 and $144.1 million for the prior-year. The average realized oil price increased $3.36 per barrel to $27.45 per barrel, resulting in an increase in revenues of $18.3 million, compared with the same period in 2000. This increase was offset by lower sales volumes, resulting in a revenue decrease of $12.6 million. Gross production from the Cusiana and Cupiagua fields averaged 308,000 BOPD (30,000 BOPD net to us) in 2001, compared with 353,000 BOPD (34,000 BOPD net to us) in the prior-year. We have entered into financial and commodity market transactions intended primarily to reduce risk associated with changing oil prices. Our oil sales were approximately $1.1 million more during the six months ended June 30, 2001, and approximately $13.4 million less during the six months ended June 30, 2000, than if we had not entered into those transactions. Costs and Expenses -------------------- Operating expenses totaled $58.8 million in 2001, compared with $29.9 million in 2000. Operating expenses for the six months ended June 30, 2001 included $30.8 million, or $5.56 per barrel, associated with oil sales in Equatorial Guinea. In Colombia, operating expenses were $5.12 per equivalent barrel in 2001, compared with $5.02 per equivalent barrel in the prior-year. Depreciation, depletion and amortization increased $33.1 million, primarily due to the commencement of liftings from the Ceiba field and a higher depletion rate per barrel in Colombia. Depletion per barrel of production was $5.55 in Equatorial Guinea for 2001, while Colombia's depletion rate per equivalent barrel of production was $4.89 in 2001 compared with $4.21 in 2000. General and administrative expenses before capitalization increased $.9 million to $16.1 million in 2001. Capitalized general and administrative costs were $4 million in 2001 and $4.8 million in 2000. Interest Expense, Net ----------------------- Gross interest expense increased $4.2 million, or 23%, to $22.9 million in 2001 as a result of higher outstanding debt balances following the issuance of the 8 7/8% Senior Notes due 2007 in the fourth quarter of 2000. Capitalized interest decreased $1.4 million in 2001 to $8.5 million. Income Taxes ------------- Current taxes associated with our Colombian operations increased to $36.3 million in 2001, from $20 million in 2000. Current taxes in 2000 included a $10 million benefit from the utilization of our net operating losses. The income tax provisions included deferred tax expense of $12.6 million for 2001 and $4 million for 2000. This increase is primarily associated with the deferred taxes related to operations in Equatorial Guinea. Cumulative Effect of Accounting Change ------------------------------------------ We adopted Statement of Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities," on January 1, 2001. In accordance with the transition provision of SFAS 133, we recorded a net-of-tax cumulative effect gain of $1.2 million, or $0.02 per diluted share, to earnings to recognize the ineffective portion of changes in fair value of hedging positions and the time value component of option contracts. We also recorded a net-of-tax cumulative effect gain of $2.9 million to comprehensive income to recognize the fair value of the effective portion of all derivative instruments designated as cash flow hedges. 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, was a reduction in net earnings of $1.3 million, or $0.02 per diluted share. 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, cash flows, 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 then 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 our Annual Report on Form 10-K for the year ended December 31, 2000, and 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. You should not put undue reliance on any forward-looking 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 include, but are not limited to, the following: Commodity Prices. Currently, we derive substantially all of our revenues and operating cash flow from the sale of oil. The market prices for oil and natural gas historically have been volatile and are likely to continue to be volatile in the future. 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 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. International Operations. We conduct substantially all of our exploration and production operations and derive substantially all our revenues from outside of the United States. 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. Our activities are subject to all of the operating risks and 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; - environmental hazards, such as oil spills, gas leaks and ruptures and discharges of toxic substances or gases; - the risk of drilling nonproductive wells or dry holes; and - the risk that drilling is delayed or halted because of such events as title problems, weather conditions and shortages or delays in the delivery or availability of equipment. 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. Environmental and Other Government Regulation. 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. 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. Reserve Estimates. Numerous uncertainties exist in estimating quantities of oil and gas reserves and future net revenues from those reserves. Estimates of oil and gas 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 oil and gas 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. Possible Writedowns of Capitalized Costs. 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. 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 of our Annual Report on Form 10-K for the year ended December 31, 2000. Possible Ceiling Test Writedowns. 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. Operations in Colombia. We derive a substantial part of our revenues and operating cash flow from our interest in the Cusiana and Cupiagua fields in Colombia. The operator of the fields is BP p.l.c. ("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 fields. The partners in the fields, together with the Colombian government, have taken steps to maintain security and favorable relations with the local population. 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. The Cusiana and Cupiagua fields are in natural decline. The operator has devised a plan to enhance reservoir management by implementing a more aggressive well-maintenance and workover program. We cannot assure you that these attempts to offset the decline in production will be successful. 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. We are highly dependent on the performance by the operator to enhance production. We cannot assure you that we will meet our production targets. Operations in Equatorial Guinea. We derive a substantial part of our revenues and operating cash flow from our interest in the Ceiba field offshore the Republic of Equatorial Guinea, and we are in an early stage of appraisal and development of the field. Production rates from the first phase of development of the field 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 drill additional production and water injection wells, increase the processing capacity of the FPSO and install onboard water-injection facilities on the FPSO. Production rates from the field in future phases of development will depend on a number of additional factors, including the drilling and completion of successful development and water injection wells, timing of the completion of the additional production and water-injection facilities, the timing of the connection of the production and water injection wells to the FPSO, our ability to maintain pressure support through water injection and other factors. We cannot assure you that we will meet our production targets. We are highly dependent on third-party contractors, including the firm that owns and is maintaining and operating the FPSO vessel. Operations in the Gulf of Thailand. Through a company we own with BP, we are a partner in a significant gas exploration project located in Block A-18 of the Malaysia-Thailand Joint Development Area in the Gulf of Thailand. We and our partners have been successful in discovering eight natural gas fields to date, and 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 following timely completion and approval of an environmental impact assessment associated with the buyers' pipeline and processing facilities. 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. Significant Shareholder. HM4 Triton, L.P., an affiliate of Hicks, Muse, Tate & Furst Incorporated, owns 8% Convertible Preference Shares representing a significant portion of our voting shares. In addition, HM4 Triton, L.P. is a party to a Shareholders Agreement with us that gives it the right to designate four out of 10 of the directors on our board and requires us to obtain its consent before we can take specified corporate actions. As a result, 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. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET 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. We have entered into derivative contracts for 2.4 million barrels of oil production during the period from July to March 2002 using WTI-based oil-price collars to establish a weighted average floor price of $25.92 per barrel and a ceiling price of $28.96 per barrel, and 600,000 barrels of oil production using Dated Brent-based oil-price collars to establish a weighted average floor price of $25.13 per barrel and a ceiling price of $27.79 per barrel. In addition, we have entered into contracts for 1.2 million barrels of oil production using WTI-based oil-price swaps and 600,000 barrels of oil production using Dated Brent-based oil-price swaps to establish weighted average fixed prices of $26.36 per barrel for WTI and $24.31 for Dated Brent during the period from July to December 2001. PART II. OTHER INFORMATION ITEM 4. SUBMISSION OF MATTERS FOR VOTE OF SECURITY HOLDERS We held our Annual Meeting of Shareholders on May 15, 2001. At the meeting, our shareholders voted on the election of three directors for a term expiring in 2004, and on a proposal to adopt our 2001 Share Incentive Plan. The directors elected and the votes cast for or withheld were as follows: FOR WITHHELD --- -------- Tom C. Davis 55,305,763 443,102 James C. Musselman 55,315,991 432,874 C. Lamar Norsworthy 54,663,806 1,085,059 The following directors continued in office: Sheldon R. Erikson, Jack D. Furst, Thomas O. Hicks, John R. Huff, Michael E. McMahon, C. Richard Vermillion, Jr. and J. Otis Winters. The shareholders also approved the adoption of the 2001 Share Incentive Plan, with 51,102,896 shares being voted for adoption, 4,500,934 shares being voted against adoption and 145,035 shares abstaining. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits: The following documents are filed as part of this Quarterly Report on Form 10-Q: 1. 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.)

----------------------------- * Filed herewith (b) Reports on Form 8-K Form 8-K filed on April 25, 2001 furnishing information under Item 9. Form 8-K filed on May 14, 2001 furnishing information under Item 9. Form 8-K filed on June 20, 2001 furnishing information under Item 9. Form 8-K filed on July 11, 2001 filing information under Items 5 and 7, as . amended by Form 8-K/A filed July 17, 2001. Form 8-K filed on July 17, 2001 furnishing information under Item 9. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. TRITON ENERGY LIMITED By:/s/W. Greg Dunlevy ------------------------- W. Greg Dunlevy Senior Vice President and Chief Financial Officer Date: July 31, 2001

TRITON ENERGY LTD 10-Q