UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(AMENDMENT NO. 3)
(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, 1999
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 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, 2000 (FOR SUCH PURPOSES ONLY, ALL
DIRECTORS AND EXECUTIVE OFFICERS ARE PRESUMED TO BE AFFILIATES) WAS
APPROXIMATELY $1.0 BILLION, BASED ON THE CLOSING SALES PRICE OF $30.25 ON THE
NEW YORK STOCK EXCHANGE.
AS OF MARCH 7, 2000, 35,944,174 ORDINARY SHARES OF THE REGISTRANT WERE
OUTSTANDING.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE PROXY STATEMENT PERTAINING TO THE 2000 ANNUAL MEETING OF
SHAREHOLDERS OF TRITON ENERGY LIMITED ARE INCORPORATED BY REFERENCE INTO PART
III HEREOF.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Triton Energy Limited (the "Company") hereby amends Item 8 of its Annual
Report on Form 10-K for the year ended December 31, 1999. The Company is
amending this report to reflect a revision in the method pursuant to which
the Company accounts for accumulated dividends on preference shares for
purposes of determining earnings applicable to ordinary shares and
earnings per share. The Company has included the dividends accumulated
during each quarter in respect of its preference shares, whether or not
declared for purposes of arriving at earnings applicable to ordinary
shares, rather than including accumulated dividends only in the quarter
when a dividend is declared, and is amending this report to reflect that
change. This change in accounting methodology does not affect any balance
sheet item or net earnings.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Amendment No. 3 to
Annual Report on Form 10-K to be signed by the undersigned thereunto duly
authorized on the 1st day of August, 2000.
TRITON ENERGY LIMITED
By:/s/W. Greg Dunlevy
-------------------------------------
W. Greg Dunlevy
Vice President, Finance
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Amendment No. 3 to 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 1st day of August, 2000.
Signatures Title
---------- -----
/s/W. Greg Dunlevy Vice President
-----------------------
W. Greg Dunlevy (Principal Financial Officer)
/s/Kevin B. Wilcox Controller
----------------------
Kevin B. Wilcox
* Chairman of the Board
----------------------
Thomas O. Hicks
* President and Chief Executive Officer
---------------------- (Principal Executive Officer)
James C. Musselman
* Director
----------------------
Sheldon R. Erikson
* Director
----------------------
Jack D. Furst
* Director
----------------------
Fitzgerald Hudson
* Director
----------------------
John R. Huff
* Director
----------------------
Michael E. McMahon
* Director
----------------------
C. Lamar Norsworthy
* Director
----------------------
C. Richard Vermillion
* Director
----------------------
J. Otis Winters
*By /s/ W. Greg Dunlevy
--------------------------
W. Greg Dunlevy, Attorney-in-Fact
TRITON ENERGY LIMITED AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
<TABLE>
<CAPTION>
<S> <C>
PAGE
-----
TRITON ENERGY LIMITED AND SUBSIDIARIES:
Report of Independent Accountants. . . . . . . . . . . . . . . . . . . . . . . . F-2
Consolidated Statements of Operations - Years ended December 31, 1999, 1998
and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-3
Consolidated Balance Sheets - December 31, 1999 and 1998 . . . . . . . . . . . . F-4
Consolidated Statements of Cash Flows - Years ended December 31, 1999, 1998
and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5
Consolidated Statements of Shareholders' Equity - Years ended December 31, 1999,
1998 and 1997. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-6
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . F-7
SCHEDULE:
II - Valuation and Qualifying Accounts - Years ended December 31, 1999,
1998 and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-52
</TABLE>
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, 1999 and 1998, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally
accepted in the United States which require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Dallas, Texas
February 23, 2000
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31,
--------------------------------
1999 1998 1997
--------- ---------- ---------
SALES AND OTHER OPERATING REVENUES:
Oil and gas sales $247,878 $ 160,881 $145,419
Gain on sale of oil and gas assets --- 67,737 4,077
--------- ---------- ---------
247,878 228,618 149,496
--------- ---------- ---------
COSTS AND EXPENSES:
Operating 68,130 73,546 51,357
General and administrative 23,636 26,653 28,607
Depreciation, depletion and amortization 61,343 58,811 36,828
Writedown of assets --- 328,630 ---
Special charges 2,909 18,324 ---
--------- ---------- ---------
156,018 505,964 116,792
--------- ---------- ---------
OPERATING INCOME (LOSS) 91,860 (277,346) 32,704
Gain on sale of Triton Pipeline Colombia --- 50,227 ---
Interest income 10,579 3,258 5,178
Interest expense, net (22,648) (23,228) (23,858)
Other income (expense), net (3,614) 8,480 2,872
--------- ---------- ---------
(15,683) 38,737 (15,808)
--------- ---------- ---------
EARNINGS (LOSS) BEFORE INCOME TAXES
AND EXTRAORDINARY ITEM 76,177 (238,609) 16,896
Income tax expense (benefit) 28,620 (51,105) 11,301
--------- ---------- ---------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM 47,557 (187,504) 5,595
Extraordinary item - extinguishment of debt --- --- (14,491)
--------- ---------- ---------
NET EARNINGS (LOSS) 47,557 (187,504) (8,896)
ACCUMULATED DIVIDENDS ON PREFERENCE SHARES 28,671 3,061 400
--------- ---------- ---------
EARNINGS (LOSS) APPLICABLE TO ORDINARY SHARES $ 18,886 $(190,565) $ (9,296)
========= ========== =========
Average ordinary shares outstanding 36,135 36,609 36,471
========= ========== =========
BASIC EARNINGS (LOSS) PER ORDINARY SHARE:
Earnings (loss) before extraordinary item $ 0.52 $ (5.21) $ 0.14
Extraordinary item - extinguishment of debt --- --- (0.40)
--------- ---------- ---------
BASIC EARNINGS (LOSS) $ 0.52 $ (5.21) $ (0.26)
========= ========== =========
DILUTED EARNINGS (LOSS) PER ORDINARY SHARE:
Earnings (loss) before extraordinary item $ 0.52 $ (5.21) $ 0.14
Extraordinary item - extinguishment of debt --- --- (0.39)
--------- ---------- ---------
DILUTED EARNINGS (LOSS) $ 0.52 $ (5.21) $ (0.25)
========= ========== =========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
<S> <C> <C>
ASSETS DECEMBER 31,
---------------------
1999 1998
---------- ---------
CURRENT ASSETS:
Cash and equivalents $ 186,323 $ 18,757
Trade receivables, net 17,246 9,514
Other receivables 23,814 47,756
Deferred income taxes 20,090 ---
Inventories, prepaid expenses and other 7,806 1,639
---------- ---------
TOTAL CURRENT ASSETS 255,279 77,666
Property and equipment, at cost, net 524,152 470,907
Investment in affiliate 93,188 84,735
Deferred income taxes 88,228 100,916
Other assets 13,628 20,056
---------- ---------
$ 974,475 $754,280
========== =========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt $ 9,027 $ 14,027
Short-term borrowings --- 5,000
Accounts payable and accrued liabilities 62,576 44,973
Deferred income and other 22,347 35,254
---------- ---------
TOTAL CURRENT LIABILITIES 93,950 99,254
Long-term debt, excluding current maturities 404,460 413,465
Deferred income taxes 6,677 3,235
Other liabilities 6,336 14,519
SHAREHOLDERS' EQUITY:
5% preference shares, par value $.01; authorized 420,000
shares; issued 209,639 shares at December 31, 1999 and
1998, respectively, stated value $34.41 7,214 7,214
8% preference shares, par value $.01; authorized 11,000,000
shares; issued 5,193,643 and 1,822,500 shares at
December 31, 1999 and 1998, respectively, stated value $70 363,555 127,575
Ordinary shares, par value $.01; authorized 200,000,000
shares; issued 35,763,728 and 36,643,478 shares at
December 31, 1999 and 1998, respectively 358 366
Additional paid-in capital 531,904 575,863
Accumulated deficit (437,528) (485,085)
Accumulated other non-owner changes in shareholders' equity (2,451) (2,126)
---------- ---------
TOTAL SHAREHOLDERS' EQUITY 463,052 223,807
Commitments and contingencies (note 20) --- ---
---------- ---------
$ 974,475 $754,280
========== =========
</TABLE>
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)
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31,
----------------------------------
1999 1998 1997
---------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ 47,557 $(187,504) $ (8,896)
Adjustments to reconcile net earnings to net cash provided (used)
by operating activities:
Depreciation, depletion and amortization 61,343 58,811 36,828
Proceeds from forward oil sale 31,932 1,770 830
Amortization of deferred income (35,254) (35,254) (28,467)
Gain on sale of oil and gas assets --- (67,737) (4,077)
Gain on sale of Triton Pipeline Colombia --- (50,227) ---
Writedown of assets --- 328,630 ---
Payment of accreted interest on extinguishment of debt --- --- (124,794)
Extraordinary loss on extinguishment of debt, net of tax --- --- 14,491
Amortization of debt discount --- --- 7,949
Deferred income taxes 7,827 (55,592) 8,078
Gain on sale of other assets (677) (7,590) (1,409)
Other, net 8,921 3,962 6,100
Changes in working capital:
Trade and other receivables (16,131) 6,300 (3,238)
Inventories, prepaid expenses and other (3,577) 918 1,794
Accounts payable and accrued liabilities 14,581 4,979 (2,605)
---------- ---------- ----------
Net cash provided (used) by operating activities 116,522 1,466 (97,416)
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures and investments (121,483) (180,215) (219,216)
Proceeds from sale of oil and gas assets --- 147,027 4,077
Proceeds from sale of Triton Pipeline Colombia --- 97,656 ---
Proceeds from sales of other assets 2,353 22,353 1,822
Other 600 (2,630) 617
---------- ---------- ----------
Net cash provided (used) by investing activities (118,530) 84,191 (212,700)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving lines of credit and long-term debt --- 162,530 620,413
Payments on revolving lines of credit and long-term debt (19,028) (350,511) (321,515)
Short-term notes payable, net --- (9,600) 9,600
Issuance of 8% preference shares, net 217,805 115,329 ---
Issuances of ordinary shares 419 2,544 5,260
Repurchase of ordinary shares (11,285) --- ---
Dividends paid on preference shares (17,617) (368) (400)
Other (151) 5 10
---------- ---------- ----------
Net cash provided (used) by financing activities 170,143 (80,071) 313,368
---------- ---------- ----------
Effect of exchange rate changes on cash and equivalents (569) (280) (849)
---------- ---------- ----------
Net increase in cash and equivalents 167,566 5,306 2,403
CASH AND EQUIVALENTS AT BEGINNING OF YEAR 18,757 13,451 11,048
---------- ---------- ----------
CASH AND EQUIVALENTS AT END OF YEAR $ 186,323 $ 18,757 $ 13,451
========== ========== ==========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1999 1998 1997
-------------------- ---------------------- --------------------
OWNER SOURCES OF SHAREHOLDERS' EQUITY:
5% PREFERENCE SHARES:
Balance at beginning of period $ 7,214 $ 7,511 $ 8,515
Conversion of 5% preference shares --- (297) (1,004)
---------- ---------- ----------
Balance at end of period 7,214 7,214 7,511
---------- ---------- ----------
8% PREFERENCE SHARES:
Balance at beginning of period 127,575 --- ---
Issuances of 8% preference shares at $70 per share 222,425 127,575 ---
Conversion of 8% preference shares (192) --- ---
Stock dividends, 8% preference shares 13,747 --- ---
---------- ---------- ----------
Balance at end of period 363,555 127,575 ---
---------- ---------- ----------
ORDINARY SHARES:
Balance at beginning of period 366 365 363
Stock repurchase (9) --- ---
Exercise of employee stock options and debentures 1 1 2
---------- ---------- ----------
Balance at end of period 358 366 365
---------- ---------- ----------
ADDITIONAL PAID-IN CAPITAL:
Balance at beginning of period 575,863 588,454 582,581
Dividends, 5% preference shares (361) (368) (400)
Dividends, 8% preference shares (28,310) (2,693) ---
Exercise of employee stock options and debentures 418 2,548 3,831
Conversion of 5% preference shares --- 297 1,004
Conversion of 8% preference shares 192 --- ---
Transaction costs for issuance of
8% preference shares (4,620) (12,370) ---
Stock repurchase (11,276) --- ---
Other, net (2) (5) 1,438
---------- ---------- ----------
Balance at end of period 531,904 575,863 588,454
---------- ---------- ----------
TREASURY SHARES:
Balance at beginning of period --- (3) (2)
Retirement and other, net --- 3 (1)
---------- ---------- ----------
Balance at end of period --- --- (3)
---------- ---------- ----------
TOTAL OWNER SOURCES OF SHAREHOLDERS' EQUITY 903,031 711,018 596,327
---------- ---------- ----------
NON-OWNER SOURCES OF SHAREHOLDERS' EQUITY:
ACCUMULATED DEFICIT:
Balance at beginning of period (485,085) (297,581) (288,685)
Net earnings (loss) 47,557 $47,557 (187,504) $(187,504) (8,896) $(8,896)
---------- ---------- ----------
Balance at end of period (437,528) (485,085) (297,581)
---------- ---------- ----------
ACCUMULATED OTHER NON-OWNER CHANGES IN
SHAREHOLDERS' EQUITY:
Balance at beginning of period (2,126) (2,126) (2,128)
Valuation reserve on marketable securities --- --- 2
Adjustment for minimum pension liability (325) --- ---
-------- ---------- --------
Other non-owner changes in shareholders' equity (325) (325) --- --- 2 2
---------- -------- ---------- ---------- ---------- --------
Non-owner changes in shareholders' equity $47,232 $(187,504) $(8,894)
======== ========== ========
Balance at end of period (2,451) (2,126) (2,126)
---------- ---------- ----------
TOTAL NON-OWNER SOURCES OF
SHAREHOLDERS' EQUITY (439,979) (487,211) (299,707)
---------- ---------- ----------
TOTAL SHAREHOLDERS' EQUITY $ 463,052 $ 223,807 $ 296,620
========== ========== ==========
</TABLE>
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" when used herein means Triton and its
subsidiaries and other affiliates through which the Company conducts its
business. The Company's principal properties, operations, and oil and gas
reserves are located in Colombia, 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. All sales are currently derived from oil
and gas production in Colombia.
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 has been
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
which the Company exercises significant influence over operating and financial
policies are accounted for using the equity method. Investments in less than
20%-owned affiliates are accounted for using the cost method.
CASH EQUIVALENTS
Cash equivalents are highly liquid investments purchased with an original
maturity of three months or less.
INVENTORIES
Inventories consist principally of oil produced but not sold, stated at market
value, and materials and supplies, stated at the lower of cost or market.
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 involves significant reserves.
Costs related to acquisition, holding and initial exploration of licenses in
countries with no proved reserves are initially capitalized, including internal
costs directly identified with acquisition, exploration and development
activities. Costs related to production, general overhead or similar activities
are expensed. The Company's exploration licenses are periodically assessed for
impairment on a country-by-country basis. If the Company's investment in
exploration licenses within a country where no proved reserves are assigned is
deemed to be impaired, the licenses are written down to estimated recoverable
value. If the Company abandons all exploration efforts in a country where no
proved reserves are assigned, all acquisition and exploration costs associated
with the country are expensed. Due to the unpredictable nature of exploration
drilling activities, the amount and timing of impairment expense are difficult
to predict with any certainty.
The net capitalized costs of oil and gas properties for each cost center, less
related deferred income taxes, cannot exceed the sum of (i) the estimated future
net revenues from the properties, discounted at 10%; (ii) unevaluated costs not
being amortized; and (iii) the lower of cost or estimated fair value of unproved
properties being amortized; less (iv) income tax effects related to differences
between the financial statement basis and tax basis of oil and gas properties.
The estimated costs, net of salvage value, of dismantling facilities or projects
with limited lives or facilities that are required to be dismantled by contract,
regulation or law, and the estimated costs of restoration and reclamation
associated with oil and gas operations are included in estimated future
development costs as part of the amortizable base.
Support equipment and facilities are depreciated using the unit-of-production
method based on total reserves of the field related to the support equipment and
facilities. Other property and equipment, which includes furniture and
fixtures, vehicles and leasehold improvements, are depreciated principally on a
straight-line basis over estimated useful lives ranging from 3 to 20 years.
Repairs and maintenance are expensed as incurred, and renewals and improvements
are capitalized.
ENVIRONMENTAL MATTERS
Environmental costs are expensed or capitalized depending on their future
economic benefit. Costs that relate to an existing condition caused by past
operations and have no future economic benefit are expensed. Liabilities for
future expenditures of a noncapital nature are recorded when future
environmental expenditures and/or remediation is deemed probable, and the costs
can be reasonably estimated. 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.
RISK MANAGEMENT
Oil and natural gas sold by the Company are normally priced with reference to a
defined benchmark, such as light, sweet crude oil traded on the New York
Merchantile Exchange (West Texas Intermediate or "WTI"). Actual prices received
vary from the benchmark depending on quality and location differentials. From
time to time, it is the Company's policy to use financial market transactions,
including swaps, collars and options, with creditworthy counterparties,
primarily to reduce risk associated with the pricing of a portion of the oil and
natural gas 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
Statement of Financial Accounting Standards No. 123 ("SFAS 123"), "Accounting
for Stock-Based Compensation," encourages, but does not require, the adoption of
a fair value-based method of accounting for employee stock-based compensation
transactions. The Company has elected to apply the provisions of Accounting
Principles Board Opinion No. 25 ("Opinion 25"), "Accounting for Stock Issued to
Employees," and related interpretations, in accounting for its stock-based
compensation plans. Under Opinion 25, compensation cost is measured as the
excess, if any, of the quoted market price of the Company's stock at the date of
the grant above the amount an employee must pay to acquire the stock.
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, which adopted the standard
beginning January 1, 1998, has elected to display comprehensive income (or
non-owner changes in shareholders' equity) 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."
SFAS 133 establishes accounting and reporting standards for derivative
instruments and for hedging activities. It requires enterprises to recognize
all derivatives as either assets or liabilities in the 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 must adopt SFAS 133 effective January 1,
2001. Based on the Company's outstanding derivatives contracts, the Company
believes that the impact of adopting this standard would not have a material
adverse effect on the Company's operations or consolidated financial condition.
However, no assurances can be given with regard to the level of the Company's
derivatives activities at the time SFAS 133 is adopted or the resulting effect
on the Company's operations or consolidated financial condition.
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.
2. ASSET DISPOSITIONS
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 ("ARCO") 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 a subsidiary of
ARCO for $150 million one-half of the shares of the subsidiary through which the
Company owned its 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, 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
investment in affiliate at December 31, 1999 and 1998.
The agreements also require ARCO to pay the future exploration and development
costs attributable to the Company's and ARCO's collective interest in Block
A-18, up to $377 million or until first production from a gas field, after which
the Company and ARCO would each pay 50% of such costs. There can be no
assurance that the Company's and ARCO's collective share of the cost of
developing the project will not exceed $377 million. Additionally, the
agreements require ARCO 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. There can be no assurance that the Company will receive any
incentive payments. The agreements provide that the Company will recover its
investment in recoverable costs in the project, approximately $100 million, and
that ARCO will recover its investment in recoverable costs, on a first-in,
first-out basis from the cost-recovery portion of future production.
In February 1998, the Company sold Triton Pipeline Colombia, Inc. ("TPC"), a
wholly owned subsidiary that held the Company's 9.6% equity interest in the
Colombian pipeline company, Oleoducto Central S.A. ("OCENSA"), to an unrelated
third party (the "Purchaser") 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
has a notional amount of $97 million and requires the Company to make quarterly
floating LIBOR-based payments on the notional amount to the Counterparty. In
exchange, the Counterparty is required to make payments to the Company
equivalent to 97% of the dividends TPC receives in respect of its equity
interest in OCENSA. The equity swap is carried in the Company's financial
statements at fair value during its term, which, as amended, will expire April
14, 2000. The value of the equity swap in the Company's financial statements is
equal to 97% of the estimated fair value of the shares of OCENSA owned by TPC.
Because there is no public market for the shares of OCENSA, the Company
estimates 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 is 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, 1999 and 1998, the Company recorded an
expense of $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. Net payments made (or received) under the equity swap, and
any fluctuations in the fair value of the equity swap, in future periods, will
affect other income in such periods. There can be no assurance that changes in
interest rates, or in other factors that affect the value of the OCENSA shares
and/or the equity swap, will not have a material adverse effect on the carrying
value of the equity swap.
Upon the expiration of the equity swap in April 2000, the Company expects that
the Purchaser will sell the TPC shares. Under the terms of the equity swap with
the Counterparty, upon any sale by the Purchaser of the TPC shares, the Company
will receive from the Counterparty, or pay to the Counterparty, an amount equal
to the excess or deficiency, as applicable, of the difference between 97% of the
net proceeds from the Purchaser's sale of the TPC shares and the notional amount
of $97 million. For example, if the Purchaser sold the TPC shares for an amount
equal to the value the Company has estimated for purposes of preparing its
balance sheet as of December 31, 1999, the Company would have to make a payment
to the Counterparty under the equity swap of approximately $8.4 million. There
can be no assurance that the value the Purchaser may realize in any sale of the
TPC shares will equal the value of the shares estimated by the Company for
purposes of valuing the equity swap. The Company has no right or obligation to
repurchase the TPC shares at any time, but the Company is not prohibited from
offering to purchase the shares if the Purchaser offers to sell them.
In June 1997, the Company sold its Argentine subsidiary for cash proceeds of
$4.1 million and recognized a gain of $4.1 million in gain on sale of oil and
gas assets.
3. WRITEDOWN OF ASSETS
Writedown of assets in 1998 is summarized as follows:
<TABLE>
<CAPTION>
<S> <C>
YEAR ENDED
DECEMBER 31,
1998
-----------
Evaluated oil and gas properties (SEC ceiling test) $ 241,005
Unevaluated oil and gas properties 73,890
Other assets 13,735
-----------
$ 328,630
===========
</TABLE>
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 Securities and Exchange Commission ("SEC"), principally as a
result of a decline in oil prices. No adjustments were made to the Company's
reserves in Colombia as a result of the decline in 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, 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 is 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.
4. 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 will be paid over a period of up to
two years according to the severance formula. Since July 1998, the Company has
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 closed and all licenses had been
relinquished, sold or their commitments renegotiated. During the fourth quarter
of 1999, the Company reversed $.7 million of the accrual associated with the
completion of restructuring activities. The remaining liability related to the
restructuring activities undertaken in 1998 was $1 million at December 31, 1999.
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. Since March 1999, the
Company has paid $.9 million in severance, benefit continuation and outplacement
costs. At December 31, 1999, the remaining liability related to the
restructuring activities undertaken in 1999 was $.1 million.
5. OTHER RECEIVABLES
Other receivables consisted of the following:
<TABLE>
<CAPTION>
<S> <C> <C>
DECEMBER 31,
----------------
1999 1998
------- -------
Receivables from and advances to partners and others $10,684 $ 2,007
Receivable from financial market transactions 4,861 180
Receivable from insurance 2,300 7,800
Receivable from the forward oil sale 1,081 31,932
Other 4,888 5,837
------- -------
$23,814 $47,756
======= =======
</TABLE>
<PAGE>
6. PROPERTY AND EQUIPMENT
Property and equipment, at cost, are summarized as follows:
<TABLE>
<CAPTION>
<S> <C> <C>
DECEMBER 31,
------------------
1999 1998
-------- --------
Oil and gas properties, full cost method:
Evaluated $560,240 $543,514
Unevaluated 78,527 70,836
Support equipment and facilities 303,953 289,659
Other 17,535 18,790
-------- --------
960,255 922,799
Less accumulated depreciation and depletion 436,103 451,892
-------- --------
$524,152 $470,907
======== ========
</TABLE>
The Company capitalized general and administrative expenses related to
exploration and development activities of $6.9 million, $20.6 million and $32.4
million in the years ended December 31, 1999, 1998 and 1997, respectively.
7. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Accounts payable and accrued liabilities are summarized as follows:
<TABLE>
<CAPTION>
<S> <C>
DECEMBER 31,
----------------
1999 1998
------- -------
Colombian income taxes $14,471 $ ---
Accrued exploration and development 9,762 3,774
Equity swap 8,435 ---
Accrued interest payable 7,864 8,160
Taxes other than income 7,713 2,970
Litigation and environmental matters 3,872 2,064
Accrued special charges 1,246 7,869
Accounts payable, principally trade 1,242 9,136
Dividends payable --- 2,693
Other 7,971 8,307
------- -------
$62,576 $44,973
======= =======
</TABLE>
8. DEFERRED INCOME AND OTHER
In May 1995, the Company sold 10.4 million barrels of oil from the Cusiana and
Cupiagua fields in Colombia in a forward oil sale. Under the terms of the sale,
the Company received approximately $87 million of the approximately $124 million
net proceeds. In 1999, the Company received substantially all of the remaining
proceeds totaling approximately $31.9 million. The Company has recorded the net
proceeds as deferred income and recognizes such revenue when the barrels of oil
are delivered during the five-year period that began in June 1995. Under the
terms of the agreement, the Company must deliver to the buyer 58,425 barrels per
month through March 1997 and 254,136 barrels per month from April 1997 to March
2000. At December 31, 1999 and 1998, $8.8 million and $35.3 million,
respectively, were recorded as deferred income and included in current
liabilities.
During 1999, the Company acquired the Colombian entity of its former partner in
the El Pinal field. In addition to the working interest in the El Pinal field,
the acquired entity has tax basis and net operating loss carryforwards ("NOLs")
totaling approximately $40 million, which the Company expects to utilize in
2000. At December 31, 1999, the tax affected amount of the tax basis and NOLs
($14.2 million) was included in current assets as a deferred tax asset. In
addition, the Company recorded deferred income of $10.6 million, representing
the difference between the value of the deferred tax asset and the purchase
price. During 2000, the deferred tax asset and the deferred income will be
reduced as the tax basis and NOLs are utilized.
9. DEBT
A summary of long-term debt follows:
<TABLE>
<CAPTION>
<S> <C> <C>
DECEMBER 31,
------------------
1999 1998
-------- --------
Senior Notes due 2005 $200,000 $200,000
Senior Notes due 2002 199,947 199,924
Term credit facility maturing 2001 13,540 22,568
Revolving credit facility maturing 1999 --- 5,000
-------- --------
413,487 427,492
Less current maturities 9,027 14,027
-------- --------
$404,460 $413,465
======== ========
</TABLE>
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 dueApril 15, 2005 (the "2005 Notes" and, together with the 2002 Notes,
the "SeniorNotes"), at 100% of the principal amount, for total aggregate net
proceeds of$399.9 million before deducting transaction costs of approximately
$1 million.
Interest on the Senior Notes is payable semi-annually on April 15 and October
15. The Senior 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 matures in January 2001. Principal and
interest payments are due semi-annually on January 15 and July 15 and borrowings
bear interest at LIBOR plus .25%, adjusted on a semi-annual basis. At December
31, 1999, the Company had outstanding borrowings of $13.5 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 of February 2000, the borrowing base was $150 million. 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.
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 principle operations. Capitalized interest amounted
to $14.5 million, $23.2 million and $25.8 million in the years ended December
31, 1999, 1998 and 1997, 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 $.5
million, $2.9 million and $2 million in the years ended December 31, 1999, 1998
and 1997, respectively. The aggregate maturities of long-term debt for the five
years during the period ending December 31, 2004, are as follows: 2000 -- $9
million; 2001 -- $4.5 million; 2002 -- $199.9 million; 2003 -- nil; and 2004 --
nil.
<PAGE>
10. INCOME TAXES
The components of earnings (loss) from continuing operations before income taxes
and extraordinary item were as follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1999 1998 1997
--------- ---------- ---------
Cayman Islands $(35,907) $ 82,995 $(12,969)
United States (7,810) (24,003) (31,694)
Foreign - other 119,894 (297,601) 61,559
--------- ---------- ---------
$ 76,177 $(238,609) $ 16,896
========= ========== =========
</TABLE>
Pursuant to the Reorganization in March 1996, Triton, a Cayman Islands company,
became the parent holding company of TEC, a Delaware corporation. As a result,
the Company's corporate domicile became the Cayman Islands.
The components of the provision for income taxes on continuing operations were
as follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
-------- --------- --------
Current:
Cayman Islands $ --- $ --- $ ---
United States --- --- (7)
Foreign - other 20,793 4,487 3,230
-------- --------- --------
Total current 20,793 4,487 3,223
-------- --------- --------
Deferred:
Cayman Islands --- --- ---
United States (1,410) 1,457 (7,929)
Foreign - other 9,237 (57,049) 16,007
-------- --------- --------
Total deferred 7,827 (55,592) 8,078
-------- --------- --------
Total $28,620 $(51,105) $11,301
======== ========= ========
</TABLE>
<PAGE>
A reconciliation of the differences between the Company's applicable statutory
tax rate and the Company's effective income tax rate follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- ---------
Tax provision at statutory tax rate 0.0 % 0.0 % 0.0 %
Increase (decrease) resulting from:
Net change in valuation allowance (15.7)% 3.9 % 263.0 %
Foreign items without tax benefit 18.9 % (34.9)% 77.8 %
Income subject to tax in excess of statutory rate 36.6 % 32.6 % 36.9 %
Current year change in NOL/credit carryforwards (7.6)% (4.8)% (356.7)%
Temporary differences:
Oil and gas basis adjustments 3.3 % 25.7 % 32.5 %
Reimbursement of pre-commerciality costs 2.3 % (1.1)% 13.2 %
Other (0.2)% --- % 0.2 %
------- ------- --------
37.6 % 21.4 % 66.9 %
======= ======= =========
</TABLE>
The components of the net deferred tax asset and liability were as follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
DECEMBER 31, 1999 DECEMBER 31, 1998
------------------------------ -------------------------------
OTHER OTHER
U.S. COLOMBIA FOREIGN U.S. COLOMBIA FOREIGN
--------- -------- --------- --------- --------- ---------
Deferred tax asset:
Net operating loss carryforwards $157,558 $20,090 $ 9,832 $145,475 $ 7,992 $ 7,219
Depreciable/depletable property 1,748 8,778 --- 1,252 27,730 ---
Credit carryforwards 2,048 --- --- 1,731 6,813 ---
Reserves 819 --- --- 2,502 --- ---
Other 176 --- --- 1,505 --- ---
--------- -------- --------- --------- --------- ---------
Gross deferred tax asset 162,349 28,868 9,832 152,465 42,535 7,219
Valuation allowances (72,908) (8,778) --- (65,881) (27,730) ---
--------- -------- --------- --------- --------- ---------
Net deferred tax asset 89,441 20,090 9,832 86,584 14,805 7,219
--------- -------- --------- --------- --------- ---------
Deferred tax liability:
Depreciable/depletable property --- --- (16,509) --- --- (10,454)
Other (1,213) --- --- (473) --- ---
--------- -------- --------- --------- --------- ---------
Net deferred tax asset (liability) 88,228 20,090 (6,677) 86,111 14,805 (3,235)
Less current deferred tax asset (liability) --- 20,090 --- --- --- ---
--------- -------- --------- --------- --------- ---------
Noncurrent deferred tax asset (liability) $ 88,228 $ --- $ (6,677) $ 86,111 $ 14,805 $ (3,235)
========= ======== ========= ========= ========= =========
</TABLE>
At December 31, 1999, the Company had NOLs and depletion carryforwards for U.S.
tax purposes of $450.2 million and $20.3 million, respectively. The U.S. NOLs
expire from 2000 through 2020 as follows:
<TABLE>
<CAPTION>
<S> <C>
NOLS
EXPIRING
BY YEAR
---------
May 2000 $ 19,571
May 2001 30,389
May 2002 22,702
May 2003 20,566
May 2004 8,263
May 2005 - May 2020 348,675
---------
$ 450,166
=========
</TABLE>
At December 31, 1999, the Company's Colombian operations and other foreign
operations had NOLs and other credit carryforwards totaling $57.4 million and
$40.7 million, respectively. The NOLs expire from 2001 through 2004.
The deferred tax valuation allowance of $81.7 million at December 31, 1999, 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 certain temporary differences will reverse without a benefit to
the Company. The minimum amount of future taxable income necessary to realize
the deferred tax asset is approximately $252 million and $57 million in the U.S.
and Colombia, respectively. 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.
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.
11. EMPLOYEE BENEFITS
PENSION PLANS
The Company has a defined benefit pension plan covering substantially all
employees in the United States. The benefits are based on years of service and
the employee's final average monthly compensation. Contributions are intended
to provide for benefits attributed to past and future services. The Company
also has a Supplemental Executive Retirement Plan ("SERP") that is unfunded and
provides supplemental pension benefits to a select group of management and key
employees.
The funding status of the plans follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
DECEMBER 31,
----------------------------------------
1999 1998
------------------- -------------------
DEFINED DEFINED
BENEFIT SERP BENEFIT SERP
PLAN PLAN PLAN PLAN
--------- -------- --------- --------
Change in benefit obligation:
Benefit obligation at beginning of year $ 6,435 $ 6,579 $ 6,008 $ 6,621
Service cost 392 537 560 799
Interest cost 421 435 438 607
Amendments --- --- --- 434
Actuarial loss/(gain) (750) 1,465 472 913
Benefits paid (531) (1,385) (377) (1,617)
Curtailment gain --- --- (666) (1,178)
--------- -------- --------- --------
Benefit obligation at end of year 5,967 7,631 6,435 6,579
--------- -------- --------- --------
Change in plan assets:
Fair value of plan assets at beginning of year 7,068 --- 5,531 ---
Actual return on plan assets 1,971 --- 1,446 ---
Company contribution 480 1,385 468 1,617
Benefits paid (531) (1,385) (377) (1,617)
--------- -------- --------- --------
Fair value of plan assets at end of year 8,988 --- 7,068 ---
--------- -------- --------- --------
Reconciliation:
Funded status 3,021 (7,631) 633 (6,579)
Unrecognized actuarial (gain)/loss (2,999) 1,945 (908) 480
Unrecognized transition (asset)/obligation (6) 527 (8) 695
Unrecognized prior service cost 317 226 373 253
--------- -------- --------- --------
Prepaid/(accrued) pension cost 333 (4,933) 90 (5,151)
--------- -------- --------- --------
Adjustment for minimum liability --- (1,255) --- ---
--------- -------- --------- --------
Adjusted prepaid/(accrued) pension cost $ 333 $(6,188) $ 90 $(5,151)
========= ======== ========= ========
</TABLE>
The adjustment required to recognize the minimum liability for the SERP plan at
December 31, 1999, resulted in the recognition of $.8 million as an intangible
asset and $.5 million ($.3 million, net of tax) as a charge to accumulated
other non-owner changes in shareholder's equity.
<PAGE>
A summary of the components of pension expense follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31,
-------------------------
1999 1998 1997
------- ------- -------
Components of net periodic pension cost:
Service cost $ 929 $1,359 $ 832
Interest cost 856 1,045 783
Expected return on plan assets (618) (481) (416)
Recognized net actuarial loss/(gain) (12) --- ---
Amortization of transition obligation 166 591 166
Amortization of prior service cost 83 538 67
------- ------- -------
Net periodic pension cost $1,404 $3,052 $1,432
======= ======= =======
</TABLE>
The projected benefit obligations at December 31, 1999 and 1998, assume a
discount rate of 7.75% and 6.75%, respectively, 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. During 1998, work-force reductions resulted in
the recognition of additional prior service cost of $.2 million each for the
defined benefit plan and the SERP plan and additional transition obligation of
$.4 million for the SERP 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 $.2 million, $.6 million and $.6 million for the years ended
December 31, 1999, 1998 and 1997, respectively.
12. SHAREHOLDERS' EQUITY
5% CONVERTIBLE PREFERENCE SHARES
In connection with the acquisition of the minority interest in Triton Europe in
1994, the Company designated a series of 550,000 preferred shares (522,460
shares issued) as 5% Preferred Stock, no par value, with a stated value of
$34.41 per share. Pursuant to the Reorganization, Triton converted each share
of 5% Preferred Stock into one 5% Convertible Preference Share, par value $.01.
Each share of the Company's 5% Convertible Preference Shares is convertible into
one Triton ordinary share and bears a cash dividend, which has priority over
dividends on Triton's ordinary shares, equal to 5% per annum on the redemption
price of $34.41 per share, payable semi-annually on March 30 and September 30 of
each year. The 5% Convertible Preference Shares have priority over Triton
ordinary shares upon liquidation, and may be redeemed at Triton's option at any
time on or after March 30, 1998, for cash equal to the redemption price. Any
shares that remain outstanding on March 30, 2004, must be redeemed at the
redemption price, either for cash or, at the Company's option, for Triton
ordinary shares. At December 31, 1999 and 1998, there were 209,639 5%
Convertible Preference Shares outstanding and at December 31, 1997, there were
218,285 shares outstanding.
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 semi-annual 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 the period 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. The dividend for the period July 1, 1999 to
December 31, 1999 was 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, 1999 and 1998, 5,193,643 and
1,822,500 8% Convertible Preference Shares were outstanding, respectively.
<PAGE>
ORDINARY SHARES
Changes in issued ordinary shares were as follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31,
------------------------------------
1999 1998 1997
----------- ----------- ----------
Balance at beginning of year 36,643,478 36,541,064 36,342,181
Share repurchase (948,300) --- ---
Issuances under stock plans 49,367 46,648 35,961
Conversion of 8% preference shares 10,980 --- ---
Exercise of employee stock options 8,213 47,238 83,736
Conversion of 5% preference shares --- 8,646 29,184
Other, net (10) (118) 50,002
----------- ----------- ----------
Balance at end of year 35,763,728 36,643,478 36,541,064
=========== =========== ==========
</TABLE>
Changes in ordinary shares held in treasury were as follows:
<TABLE>
<CAPTION>
<S> <C> <C>
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997
------ ------
Balance at beginning of year 73 40
Purchase of treasury shares 64 33
Retirement of treasury shares (137) ---
----- ------
Balance at end of year --- 73
====== ======
</TABLE>
SHARE REPURCHASE
In April 1999, the Company's Board of Directors authorized a share repurchase
program enabling the Company to repurchase up to ten percent of the Company's
then outstanding 36.7 million ordinary shares. Purchases of ordinary shares by
the Company began in April and may be made from time to time in the open market
or through privately negotiated transactions at prevailing market prices
depending on market conditions. The Company has no obligation to repurchase any
of its outstanding shares and may discontinue the share repurchase program at
management's discretion. As of December 31, 1999, the Company had 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 bank's
consent.
<PAGE>
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 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, Tate & Furst Incorporated, 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.
<PAGE>
13. STOCK COMPENSATION PLANS
STOCK OPTION PLANS
Options to purchase ordinary shares of the Company may be granted to officers
and employees under various stock option plans. The exercise price of each
option 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 non-employee 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, 1999 and 1998, shares available for grant were 1,019,021 and
2,521,133, respectively.
A summary of the status of the Company's stock option plans is presented below:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
DECEMBER 31, 1999 DECEMBER 31, 1998 DECEMBER 31, 1997
-------------------- --------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
----------- ------- ------------ ------- ---------- -------
Outstanding at beginning of year 4,057,207 $26.51 4,449,435 $39.05 3,854,046 $38.81
Granted 2,150,000 14.03 2,894,603 20.56 744,250 39.99
Exercised (8,213) 10.57 (47,238) 29.30 (83,736) 30.76
Canceled (351,138) 29.24 (3,239,593) 38.39 (65,125) 46.09
----------- ------------ -----------
Outstanding at end of year 5,847,856 21.78 4,057,207 26.51 4,449,435 39.05
=========== ============ ===========
Options exercisable at year-end 3,121,601 2,804,584 2,728,254
Weighted average fair value of options:
Granted at market prices $ 2.71 $ 6.12 $ 16.37
Granted at greater than market prices 4.93 2.84 ---
</TABLE>
On December 2, 1998, the Compensation Committee approved the grant of new stock
options totaling 440,103 shares with an exercise price of $14.50 to
substantially all of its employees. Each participating employee was granted
options in an amount equal to one-half of any options then held by the employees
with an exercise price greater than $30.00 per share and the options with an
exercise price greater than $30.00 per share expired.
<PAGE>
The following table summarizes information about stock options outstanding at
December 31, 1999:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
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, 1999 LIFE PRICE DEC. 31, 1999 PRICE
-------------- -------------- ----------- --------- -------------- ---------
$ 6.94 - 14.50 2,904,852 4.9 years $ 14.10 657,773 $ 12.75
16.81 - 29.50 1,607,932 3.9 years 20.52 1,150,006 21.64
31.75 - 39.63 667,072 2.4 years 34.10 667,072 34.10
40.25 - 52.25 668,000 3.6 years 45.86 646,750 46.04
-------------- --------------
5,847,856 3,121,601
============== ==============
</TABLE>
EMPLOYEE STOCK PURCHASE PLAN
The Company has an employee stock purchase plan that provides for the award of
ordinary shares to officers and employees. Under the terms of the plan,
employees can choose each semi-annual period to have up to 15% of their annual
gross or base compensation withheld to purchase the Company's ordinary shares.
The purchase price of the stock is 85% of the lower of its beginning of period
or end of period market price. Under the plan, the Company sold 49,367 shares
and 46,648 shares to employees for the years ended December 31, 1999 and 1998,
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 SFAS 123, the Company's net
income (loss) and earnings (loss) per share would have been as follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
------- ---------- ---------
Net earnings (loss) applicable to ordinary shares:
As reported $18,886 $(190,565) $ (9,296)
Pro forma 12,579 (200,147) (16,802)
Basic earnings (loss) per ordinary share:
As reported $ 0.52 $ (5.21) $ (0.26)
Pro forma 0.35 (5.47) (0.46)
Diluted earnings (loss) per ordinary share:
As reported $ 0.52 $ (5.21) $ (0.25)
Pro forma 0.35 (5.47) (0.46)
</TABLE>
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 1999, 1998 and 1997: dividend yield of 0%;
expected volatility of approximately 54%, 40% and 26%, respectively; risk-free
interest rates of approximately 6%, 5% and 6%, respectively; and an expected
life of approximately three to seven years.
STOCK APPRECIATION RIGHTS PLAN
The Company had a stock appreciation rights ("SARs") plan which granted SARs to
non-employee directors of the Company. Upon exercise, SARs allow the holder to
receive the difference between the SARs' exercise price and the fair market
value of the ordinary shares covered by SARs on the exercise date and expire at
the earlier of 10 years or a date based on the termination of the holder's
membership on the board of directors. At December 31, 1999, SARs covering
20,000 ordinary shares, with an exercise price of $8.00 per share, were
outstanding.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS, RISK MANAGEMENT
AND CREDIT RISK CONCENTRATIONS
FAIR VALUE OF FINANCIAL INSTRUMENTS
At December 31, 1999 and 1998, 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 $416 million (carrying value - $413 million)
and $397 million (carrying value - $428 million) at December 31, 1999 and 1998,
respectively.
RISK MANAGEMENT
Oil and natural gas sold by the Company are normally priced with reference to a
defined benchmark, such as light, sweet crude oil traded on the New York
Mercantile Exchange (WTI). 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, with creditworthy counterparties primarily to reduce risk
associated with the pricing of a portion of the oil and natural gas that it
sells. The policy is structured to underpin the Company's planned revenues and
results of operations. The Company 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.
During the years ended December 31, 1999 and 1997, markets provided the Company
the opportunity to realize WTI benchmark oil prices on average $6.37 per barrel
and $2.35 per barrel, respectively, above the WTI benchmark oil price the
Company set as part of its annual plan for the period. During the year ended
December 31, 1998, the Company 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,
1999 and 1997, the Company's risk management program resulted in an average net
realization of approximately $1.65 per barrel and $.11 per barrel, respectively,
lower than if the Company had not entered into such transactions.
In anticipation of entering into the forward oil sale, in 1995 the Company
purchased WTI benchmark call options to retain the ability to benefit from WTI
price increases above a weighted average price of $20.42 per barrel. The
volumes and expiration dates on the call options coincide with the volumes and
delivery dates of the forward oil sale which will be completed in March 2000.
During the years ended December 31, 1999, 1998 and 1997, the Company recorded a
gain (loss) of $6.1 million, $.4 million, and ($9.7 million), respectively, in
other income (expense), net, related to the change in the fair market value of
the call options. In November 1999, the Company sold WTI benchmark call options
with the same notional quantities, strike price and contract period as the
remaining call option contracts outstanding for a premium of $4.4 million for
the purpose of realizing the fair value of the purchased call options. As a
result, the Company has eliminated its exposure to future changes in value of
the call options caused by fluctuations in oil prices.
CONCENTRATION OF CREDIT RISK
Financial instruments that are 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
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.
<PAGE>
15. OTHER INCOME (EXPENSE), NET
Other income (expense), net is summarized as follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31,
----------------------------
1999 1998 1997
-------- -------- --------
Equity swap $(6,858) $(3,283) $---
Change in fair market value of WTI
benchmark call options 6,150 366 (9,689)
Foreign exchange gain (loss) (2,674) 2,113 9,549
Loss provisions (2,250) (750) ---
Gain on sale of corporate assets 443 7,593 1,414
Other 1,575 2,441 1,598
-------- -------- --------
$(3,614) $ 8,480 $ 2,872
======== ======== ========
</TABLE>
In 1999, 1998 and 1997, the Company recognized a net foreign exchange gain
(loss) of ($2.7 million), $2.1 million and $9.5 million, respectively,
consisting primarily of noncash adjustments related to deferred taxes in
Colombia associated with devaluation of the Colombian peso versus the U.S.
dollar.
16. 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, 1999 and 1997.
<TABLE>
<CAPTION>
<S> <C> <C>
<C>
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------ ------------ ------------
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
============ ============
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
YEAR ENDED DECEMBER 31, 1997:
Earnings before extraordinary item $ 5,595
Less: Accumulated dividends on
preference shares (400)
-----------
Earnings available to ordinary shareholders 5,195
Basic earnings per ordinary share 36,471 $ 0.14
=========
Effect of dilutive securities
Stock options --- 457
Convertible debentures --- 80
----------- -------------
Earnings available to ordinary shareholders and
assumed conversions $ 5,195
===========
Diluted earnings per ordinary share 37,008 $ 0.14
============= =========
</TABLE>
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, 1999, 5,193,643 shares of 8% Convertible Preference Shares and
209,639 shares of 5% Convertible Preference Shares were outstanding. Each 8%
Convertible Preference Share is convertible any time into four ordinary shares,
subject to adjustment in certain events. Each 5% Convertible Preference Share is
convertible any time into one ordinary share, subject to adjustment in certain
events. The 8% Convertible Preference Shares and 5% Convertible Preference
Shares were not included in the computation of diluted earnings per ordinary
share because the effect of assuming conversion was antidilutive.
17. STATEMENTS OF CASH FLOWS
Supplemental disclosures of cash payments and noncash investing and financing
activities follow:
<TABLE>
<CAPTION>
<S> <C> <C>
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
-------- ------- --------
Cash paid during the year for:
Interest (net of amount capitalized) $22,810 $24,517 $133,265
Income taxes 5,564 4,339 4,666
Noncash financing activities:
8% Convertible preference shares issued
in lieu of cash dividend $13,747 $ --- $ ---
Conversion of preference shares into
ordinary shares 192 297 1,004
</TABLE>
Cash paid for interest in 1997 included $124.8 million of interest accreted with
respect to the Senior Subordinated Discount Notes due November 1, 1997 and the
9 3/4% Senior Subordinated Discount Notes due September 15, 2000 through the
dates of retirement.
18. 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, 1999 and 1998, the Company paid Hicks Muse Partners $.6
million and $.1 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.
19. CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS
Certain information contained in this report, as well as written and oral
statements made or incorporated by reference from time to time by the Company
and its representatives in other reports, filings with the Securities and
Exchange Commission, press releases, conferences, teleconferences, or otherwise,
may be deemed to be "forward-looking statements" within the meaning of Section
21E of the Securities Exchange Act of 1934 and are subject to the "Safe Harbor"
provisions of that section. Forward-looking statements include statements
concerning the Company's and management's plans, objectives, goals, strategies
and future operations and performance and the assumptions underlying such
forward-looking statements. When used in this document, the words
"anticipates," "estimates," "expects," "believes," "intends," "plans," and
similar expressions are intended to identify such forward-looking statements.
These statements include information regarding:
- drilling schedules;
- expected or planned production capacity;
- future production from the Cusiana and Cupiagua fields in Colombia, including
from the Recetor license;
- the completion of development and commencement of production in
Malaysia-Thailand;
- future production of the Ceiba field in Equatorial Guinea, including volumes
and timing of first production;
- the acceleration of the Company's exploration, appraisal and development
activities in Equatorial Guinea;
- the Company's capital budget and future capital requirements;
- the Company's meeting its future capital needs;
- the Company's utilization of net operating loss carryforwards and realization
of its deferred tax asset;
- the level of future expenditures for environmental costs;
- the outcome of regulatory and litigation matters;
- the estimated fair value of derivative instruments, including the equity
swap; and
- proven oil and gas reserves and discounted future net cash flows therefrom.
These statements are based on current expectations and involve a number of risks
and uncertainties, including those described in the context of such
forward-looking statements, as well as those presented below. Actual results
and developments could differ materially from those expressed in or implied by
such statements due to these and other factors.
CERTAIN FACTORS RELATING TO THE OIL AND GAS INDUSTRY
The markets for oil and natural gas historically have been volatile and are
likely to continue to be volatile in the future. Oil and natural gas prices
have been subject to significant fluctuations during the past several decades in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond the control of the Company. These factors include the level of consumer
product demand, weather conditions, domestic and foreign government regulations,
political conditions in the Middle East and other production areas, the foreign
supply of oil and natural gas, the price and availability of alternative fuels,
and overall economic conditions. It is impossible to predict future oil and gas
price movements with any certainty.
The Company follows the full cost method of accounting for exploration and
development of oil and gas reserves, whereby all acquisition, exploration and
development costs are capitalized. Costs related to acquisition, holding and
initial exploration of licenses in countries with no proved reserves are
initially capitalized, including internal costs directly identified with
acquisition, exploration and development activities. The Company's exploration
licenses are periodically assessed for impairment on a country-by-country basis.
If the Company's investment in exploration licenses within a country where no
proved reserves are assigned is deemed to be impaired, the licenses are written
down to estimated recoverable value. If the Company abandons all exploration
efforts in a country where no proved reserves are assigned, all acquisition and
exploration costs associated with the country are expensed. The Company's
assessments of whether its investment within a country is impaired and whether
exploration activities within a country will be abandoned are made from time to
time based on its review and assessment of drilling results, seismic data and
other information it deems relevant. Due to the unpredictable nature of
exploration drilling activities, the amount and timing of impairment expense are
difficult to predict with any certainty. Financial information concerning the
Company's assets at December 31, 1999, including capitalized costs by geographic
area, is set forth in note 21.
The Company's oil and gas business is also subject to all of the operating risks
normally associated with the exploration for and production of oil and gas,
including, without limitation, blowouts, explosion, 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 to
the Company due to injury or loss of life and damage to or destruction of oil
and gas wells, formations, production facilities or other properties. In
accordance with customary industry practices, the Company maintains insurance
coverage limiting financial loss resulting from certain of these operating
hazards. Losses and liabilities arising from uninsured or underinsured events
would reduce revenues and increase costs to the Company. There can be no
assurance that any insurance will be adequate to cover losses or liabilities.
The Company cannot predict the continued availability of insurance, or its
availability at premium levels that justify its purchase.
The Company's oil and gas business is also subject to laws, rules and
regulations in the countries where it operates, which generally pertain to
production control, taxation, environmental and pricing concerns, and other
matters relating to the petroleum industry. Many jurisdictions have at various
times imposed limitations on the production of natural gas and oil by
restricting the rate of flow for oil and natural gas wells below their actual
capacity. There can be no assurance that present or future regulation will not
adversely affect the operations of the Company.
The Company is subject to extensive environmental laws and regulations. These
laws regulate the discharge of oil, gas or other materials into the environment
and may require the Company to remove or mitigate the environmental effects of
the disposal or release of such materials at various sites. In addition, the
Company could be held liable for environmental damages caused by previous owners
of its properties or its predecessors. The Company does not believe that its
environmental risks are materially different from those of comparable companies
in the oil and gas industry. Nevertheless, no assurance can be given that
environmental laws and regulations will not, in the future, adversely affect the
Company's consolidated results of operations, cash flows or financial position.
Pollution and similar environmental risks generally are not fully insurable.
CERTAIN FACTORS RELATING TO INTERNATIONAL OPERATIONS
The Company derives substantially all of its consolidated revenues from
international operations. Risks inherent in international operations include
risk of expropriation, nationalization, war, revolution, border disputes,
renegotiation or modification of existing contracts, 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 the Company's international operations; laws and policies of
the United States affecting foreign trade, taxation and investment; and the
possibility of having to be subject 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. To date,
the Company's international operations have not been materially affected by
these risks.
CERTAIN FACTORS RELATING TO COLOMBIA
The Company is a participant in significant oil and gas discoveries in the
Cusiana and Cupiagua fields, located approximately 160 kilometers (100 miles)
northeast of Bogota, Colombia. Development of reserves in the Cusiana and
Cupiagua fields is ongoing and will require additional drilling. Pipelines
connect the major producing fields in Colombia to export facilities and to
refineries.
From time to time, guerrilla activity in Colombia has disrupted the operation of
oil and gas projects. Such activity increased over the last year and appears to
be increasing as political negotiations among government and various rebel
groups proceed. In one recent 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. Although the Colombian
government, the Company and its partners have taken steps to maintain security
and favorable relations with the local population, there can be no assurance
that attempts to reduce or prevent guerrilla activity will be successful or that
guerrilla activity will not disrupt operations in the future.
Colombia is among several nations whose progress in stemming the production and
transit of illegal drugs is subject to annual certification by the President of
the United States. Although the President granted Colombia certification in
1999, Colombia was denied certification the last two years and only received a
national interest waiver for one of those years. There can be no assurance
that, in the future, Colombia will receive certification or a national interest
waiver. The consequences of the failure to receive certification or a national
interest waiver generally include the following: all bilateral aid, except
anti-narcotics and humanitarian aid, would be suspended; the Export-Import Bank
of the United States and the Overseas Private Investment Corporation would not
approve financing for new projects in Colombia; U.S. representatives at
multilateral lending institutions would be required to vote against all loan
requests from Colombia, although such votes would not constitute vetoes; and the
President of the United States and Congress would retain the right to apply
future trade sanctions. Each of these consequences could result in adverse
economic consequences in Colombia and could further heighten the political and
economic risks associated with the Company's operations in Colombia. Any
changes in the holders of significant government offices could have adverse
consequences on the Company's relationship with the Colombian national oil
company and the Colombian government's ability to control guerrilla activities
and could exacerbate the factors relating to foreign operations discussed above.
CERTAIN FACTORS RELATING TO MALAYSIA-THAILAND
The Company is a partner in a significant gas exploration project located in the
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. On October 30, 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. 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. No assurance can be given as to when such approval will be obtained.
A lengthy approval process, or significant opposition to the project, could
delay construction and the commencement of gas sales.
In connection with the sale to ARCO of one-half of the shares through which the
Company owned its interest in Block A-18, ARCO agreed to pay the future
exploration and development costs attributable to the Company's and ARCO's
collective interest in Block A-18, up to $377 million or until first production
from a gas field, after which the Company and ARCO would each pay 50% of such
costs. There can be no assurance that the Company's and ARCO's collective share
of the cost of developing the project will not exceed $377 million. ARCO also
agreed to pay the Company certain incentive payments if certain 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 unanticipated delays in construction of the
facilities, could result in the Company's receiving a reduced incentive payment
or possibly the complete loss of the first incentive payment. In addition, the
Company has agreed to share with ARCO some of the risk that the environmental
approval might be delayed by agreeing to pay to ARCO $1.25 million per month for
each month, if applicable, that first gas sales are delayed beyond 30 months
following the commitment to an engineering, procurement and construction
contract for the project. The Company's obligation is capped at 24 months of
these payments.
INFLUENCE OF HICKS MUSE
In connection with the issuance of 8% Convertible Preference Shares to HM4
Triton, L.P., the Company and HM4 Triton, L.P. entered into a shareholders
agreement (the "Shareholders Agreement") pursuant to which, among other things,
the size of the Company's Board of Directors was set at ten, and HM4 Triton,
L.P. exercised its right to designate four out of such ten directors. The
Shareholders Agreement provides that, in general, for so long as the entire
Board of Directors consists of ten members, HM4 Triton, L.P. (and its designated
transferees, collectively) may designate four nominees for election to the Board
of Directors. The right of HM4 Triton, L.P. (and its designated transferees) to
designate nominees for election to the Board will be reduced if the number of
ordinary shares held by HM4 Triton, L.P. and its affiliates (assuming conversion
of 8% Convertible Preference Shares into ordinary shares) represents less than
certain specified percentages of the number of ordinary shares (assuming
conversion of 8% Convertible Preference Shares into ordinary shares) purchased
by HM4 Triton, L.P. pursuant to the Stock Purchase Agreement.
The Shareholders Agreement provides that, for so long as HM4 Triton, L.P. and
its affiliates continue to hold a certain minimum number of ordinary shares
(assuming conversion of 8% Convertible Preference Shares into ordinary shares),
the Company may not take certain actions without the consent of HM4 Triton,
L.P., including (i) amending its 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, (ii) 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, (iii) authorizing,
creating or modifying the terms of any series of securities that would rank
equal to or senior to the 8% Convertible Preference Shares, (iv) selling or
otherwise disposing of assets comprising in excess of 50% of the market value of
the Company, (v) paying dividends on ordinary shares or other shares ranking
junior to the 8% Convertible Preference Shares, other than regular dividends on
the Company's 5% Convertible Preference Shares, (vi) incurring or guaranteeing
indebtedness (other than certain permitted indebtedness), or issuing preference
shares, unless the Company's leverage ratio at the time, after giving pro forma
effect to such incurrence or issuance and to the use of the proceeds, is less
than 2.5 to 1, (vii) issuing additional shares of 8% Convertible Preference
Shares, other than in payment of accumulated dividends on the outstanding 8%
Convertible Preference Shares, (viii) issuing any shares of a class ranking
equal or senior to the 8% Convertible Preference Shares, (ix) commencing a
tender offer or exchange offer for all or any portion of the ordinary shares or
(x) decreasing the number of shares designated as 8% Convertible Preference
Shares.
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 Shareholder Agreement, HM4 Triton, L.P. has
significant influence over the actions of the Company and will be able to
influence, and in some cases determine, the outcome of matters submitted for
approval of the shareholders. The existence of HM4 Triton, L.P. as a
shareholder of the Company may make it more difficult for a third party to
acquire, or discourage a third party from seeking to acquire, a majority of the
outstanding ordinary shares. A third party would be required to negotiate any
such transaction with HM4 Triton, L.P. and the interests of HM4 Triton, L.P. as
a shareholder may be different from the interests of the other shareholders of
the Company.
POSSIBLE FUTURE ACQUISITIONS
The Company's strategy includes the possible acquisition of additional reserves,
including through possible future business combination transactions. There can
be no assurance as to the terms upon which any such acquisitions would be
consummated or as to the affect any such transactions would have on the
Company's financial condition or results of operations. Such acquisitions, if
any, could involve the use of the Company's cash, or the issuance of the
Company's debt or equity securities, which could have a dilutive effect on the
current shareholders.
COMPETITION
The Company encounters strong competition from major oil companies (including
government-owned companies), independent operators and other companies for
favorable oil and gas concessions, licenses, production-sharing contracts and
leases, drilling rights and markets. Additionally, the governments of certain
countries in which the Company operates may, from time to time, give
preferential treatment to their nationals. The oil and gas industry as a whole
also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual consumers. The Company
believes that the principal means of competition in the sale of oil and gas are
product availability, price and quality.
MARKETS
Crude oil, natural gas, condensate, and other oil and gas products generally are
sold to other oil and gas companies, government agencies and other industries.
The availability of ready markets for oil and gas that might be discovered by
the Company and the prices obtained for such oil and gas depend on many factors
beyond the Company's control, including the extent of local production and
imports of oil and gas, the proximity and capacity of pipelines and other
transportation facilities, fluctuating demands for oil and gas, the marketing of
competitive fuels, and the effects of governmental regulation of oil and gas
production and sales. Pipeline facilities do not exist in certain areas of
exploration and, therefore, any actual sales of discovered oil or gas might be
delayed for extended periods until such facilities are constructed.
LITIGATION
The outcome of litigation and its impact on the Company are difficult to predict
due to many uncertainties, such as jury verdicts, the application of laws to
various factual situations, the actions that may or may not be taken by other
parties and the availability of insurance. In addition, in certain situations,
such as environmental claims, one defendant may be responsible for the
liabilities of other parties. Moreover, circumstances could arise under which
the Company may elect to settle claims at amounts that exceed the Company's
expected liability for such claims in an attempt to avoid costly litigation.
Judgments or settlements could, therefore, exceed any reserves.
20. COMMITMENTS AND CONTINGENCIES
For internal planning purposes, the Company's capital spending program for the
year ending December 31, 2000, is approximately $191 million, excluding
capitalized interest and acquisitions, of which approximately $122 million
relates to exploration and development activities in Equatorial Guinea, $58
million relates to the Cusiana and Cupiagua fields in Colombia and $11 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. It is management's
belief that such commitments, including the capital requirements in Colombia,
Equatorial Guinea and other parts of the world discussed above, will be met
without any material adverse effect on the Company's operations or consolidated
financial condition.
The Company leases office space, other facilities and equipment under various
operating leases expiring through 2005. Total rental expense was $1.3 million,
$2.1 million and $2 million for the years ended December 31, 1999, 1998 and
1997, respectively. At December 31, 1999, the minimum payments required under
terms of the leases are as follows 2000 -- $1.5 million; 2001 -- $1.6 million;
2002 -- $1.6 million; 2003 -- $1.6 million; 2004 -- $1.6 million; and thereafter
$1 million.
GUARANTEES
At December 31, 1999, the Company had guaranteed the performance of a total of
$16.4 million in future exploration expenditures to be incurred through
September 2001 in various countries. A total of approximately $6 million of the
exploration expentitures are included in the 2000 capital spending program
related to a commitment for two onshore exploratory wells in Greece. These
commitments are backed primarily by unsecured letters of credit. The Company
also had guaranteed loans of approximately $1.4 million, which expire September
2000, for a Colombian pipeline company, ODC, in which the Company has an
ownership interest.
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
clean-up obligations, is impracticable to determine with a precise and reliable
degree of accuracy. Management believes that such costs, when finally
determined, will not have a material adverse effect on the Company's operations
or consolidated financial condition.
LITIGATION
In July through October 1998, eight lawsuits were filed against the Company and
Thomas G. Finck and Peter Rugg, in their capacities as Chairman and Chief
Executive Officer and Chief Financial Officer, respectively. 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. In November 1999, the plaintiffs filed a
consolidated complaint. It alleges violations of Sections 10(b) and 20(a) of the
Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated
thereunder, in connection with disclosures concerning the Company's properties,
operations, and value relating to a prospective sale 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. In the consolidated complaint, the
plaintiffs abandoned a claim for negligent misrepresentation and punitive
damages that had previously been asserted in one of the eight individual suits.
In September 1999, the court granted the plaintiffs' motion for appointment
as lead plaintiffs and for approval of selection of lead counsel. In October
1999, the defendants filed a motion to dismiss the claims alleged in the eight
individual suits, and in December 1999, the defendants filed a supplement to
their motion to dismiss to address the plaintiffs' consolidated complaint. The
Company's motion, as supplemented, is currently 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, and one of its
subsidiaries and Thomas G. Finck, Peter Rugg and Robert B. Holland, III, in
their capacities as 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 seeks an unspecified amount of compensatory
and punitive damages and interest. The lawsuit alleges as causes of action fraud
and negligent misrepresentation in connection with disclosures concerning the
prospective sale by the Company of all or a substantial part of its assets
announced in March 1998. The Company's date to answer has not yet run. Its
subsidiary has filed various motions to dispose of the lawsuit on the grounds
that the plantiffs do not have standing. The Court has ordered the plantiffs to
replead and has stayed discovery pending its further orders.
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 has since been 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 its
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 intends to appeal the verdict.
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.
21. 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. All sales are currently derived
from oil and gas production in Colombia. Financial information about the
Company's operations by geographic area is presented below:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
CORPORATE
MALAYSIA- EQUATORIAL AND
COLOMBIA THAILAND GUINEA EXPLORATION OTHER TOTAL
--------- --------- ---------- ----------- --------- ----------
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
YEAR ENDED DECEMBER 31, 1997:
Sales and other operating revenues $ 145,419 $ --- $ --- $ 4,077 $ --- $ 149,496
Operating income (loss) 59,719 (536) (42) (6,270) (20,167) 32,704
Depreciation, depletion and amortization 31,186 60 --- 505 5,077 36,828
Capital expenditures and investments 129,589 37,328 4,471 43,371 4,457 219,216
Assets 712,512 148,780 4,841 105,720 126,186 1,098,039
</TABLE>
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 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
at December 31, 1999 and 1998.
Colombia operating income (loss) for the year ended December 31, 1998, included
a 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, 1999, corporate assets were principally cash and equivalents and
the U.S. deferred tax asset. Exploration assets included $41.6 million, $17.6
million, $16.5 million and $8.4 million in Italy, Greece, Oman and Madagascar,
respectively.
22. QUARTERLY FINANCIAL DATA (UNAUDITED)
The Company has revised its method pursuant to which it accounts for
accumulated dividends on preference shares for purposes of determining earnings
applicable to ordinary shares and earnings per share. The Company has included
the dividends accumulated during each quarter in respect of its preference
shares, whether or not declared for purposes of arriving at earnings applicable
to ordinary shares, rather than including accumulated dividends only in the
quarter when a dividend is declared. This revision does not affect any balance
sheet item or net earnings. The basic earnings (loss) per ordinary share amounts
previously reported were $0.05, $(0.08), $0.32 and $0.24 for the first, second,
third and fourth quarters in 1999, respectively. The diluted earnings (loss)
per ordinary share amounts previously reported were $0.03, $(0.08), $0.20 and
$0.23 for the first, second, third and fourth quarters in 1999, respectively.
The basic earnings (loss) per ordinary share amounts previously reported were
$1.29 and $(3.55) for the third and fourth quarters in 1998. The diluted
earnings (loss) per ordinary share amount previously reported was $(3.55) for
the fourth quarter in 1998. There were no changes to earnings per ordinary
share for other periods presented.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
QUARTER
-------------------------------------------
FIRST SECOND THIRD FOURTH
--------- ---------- -------- ----------
YEAR ENDED DECEMBER 31, 1999:
Sales and other operating revenues $ 49,170 $ 59,622 $ 67,295 $ 71,791
Gross profit 14,823 25,151 32,349 46,082
Net earnings 1,887 10,883 11,762 23,025
Basic earnings (loss) per ordinary share (0.14) 0.11 0.12 0.44
Diluted earnings (loss) per ordinary share (0.14) 0.11 0.12 0.40
Investment in affiliate 86,704 88,179 91,008 93,188
YEAR ENDED DECEMBER 31, 1998:
Sales and other operating revenues $ 36,175 $ 36,378 $105,862 $ 50,203
Gross profit (loss) 8,409 (180,179) 73,751 (134,350)
Net earnings (loss) 42,912 (150,062) 47,208 (127,562)
Basic earnings (loss) per ordinary share 1.17 (4.10) 1.29 (3.56)
Diluted earnings (loss) per ordinary share 1.16 (4.10) 1.28 (3.56)
Investment in affiliate --- --- 82,511 84,735
</TABLE>
Gross profit (loss) is comprised of sales and other operating revenues less
operating expenses, depreciation, depletion and amortization, and writedowns
pertaining to operating assets. Gross profit for the fourth quarter of 1999
included a non-recurring 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.
23. 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:
<TABLE>
<CAPTION>
<S> <C>
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
========
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
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)
========== ========= ========== ==========
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C>
TOTAL
COLOMBIA OTHER WORLDWIDE
-------- ------- ---------
YEAR ENDED DECEMBER 31, 1997:
Revenues $145,419 $ 4,077 $ 149,496
Costs:
Production costs 51,357 --- 51,357
General operating expenses 2,886 --- 2,886
Depletion 30,729 --- 30,729
Income tax expense 22,167 1,223 23,390
-------- ------- ---------
Results of operations $ 38,280 $ 2,854 $ 41,134
</TABLE> ======== ======= =========
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 years ended December 31, 1998 and 1997, included gains of $4.5 million, and
$4.1 million from the sale of the Company's Bangladesh subsidiary and Argentine
subsidiary, respectively.
Depletion includes depreciation on support equipment and facilities calculated
on the unit-of-production method.
<PAGE>
COSTS INCURRED AND CAPITALIZED COSTS
The costs incurred in oil and gas acquisition, exploration and development
activities and related capitalized costs follow:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
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 $28,613 $ 680 $560,240
======== ======= ======= ========
Support equipment and
facilities $303,244 $ 709 $ --- $303,953
======== ======= ======= ========
Accumulated depletion and
depreciation at year-end $419,651 $ --- $ 680 $420,331
======== ======= ======= ========
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
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
======== ========= ========== ======= ========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
MALAYSIA- EQUATORIAL TOTAL
COLOMBIA THAILAND GUINEA OTHER WORLDWIDE
-------- --------- ---------- ------ ---------
DECEMBER 31, 1997:
Costs incurred:
Property acquisition $ --- $ --- $ 1,500 $ 1,628 $ 3,128
Exploration 7,583 36,373 2,971 44,893 91,820
Development 62,251 187 --- --- 62,438
Depletion per equivalent
barrel of production 3.67 --- --- --- 3.67
Cost of properties at year-end:
Unevaluated $ 2,172 $ 30,327 $ 4,841 $93,286 $130,626
======== ========= ========== ======= ========
Evaluated $396,774 $ 114,243 $ --- $ 7,563 $518,580
======== ========= ========== ======= ========
Support equipment and
facilities $250,193 $ --- $ --- $ --- $250,193
======== ========= ========== ======= ========
Accumulated depletion and
depreciation at year-end $ 66,250 $ --- $ --- $ 7,563 $ 73,813
======== ========= ========== ======= ========
</TABLE>
A summary of costs excluded from depletion at December 31, 1999,
by year incurred follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
DECEMBER 31,
----------------------------------------
TOTAL 1999 1998 1997 1996 AND PRIOR
-------- ------- ------- ------- --------------
Property acquisition $ 2,820 $ 20 $ 500 $ 1,700 $ 600
Exploration 93,258 29,697 34,394 16,008 13,159
Capitalized interest 11,062 6,587 2,971 1,383 121
-------- ------- ------- ------- ------------
Total worldwide $107,140 $36,304 $37,865 $19,091 $ 13,880
======== ======= ======= ======= ============
</TABLE>
The Company excludes from its depletion computation property acquisition and
exploration costs of unevaluated properties and major development projects in
progress. The excluded costs include $34.4 million ($28.6 million and $5.8
million classified as evaluated and unevaluated, respectively) which relate
primarily to the Ceiba field in Equatorial Guinea that will become depletable
once production begins, currently estimated for year end 2000. Additionally,
excluded costs include exploration costs of $34.6 million, $16.8 million, $11.8
million and $8.4 million in Italy, Greece, Oman and Madagascar, respectively,
where there are no proved reserves at December 31, 1999. At this time, 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 $8.2 million and $3.2
million for the years ended December 31, 1999 and 1998, respectively. Net
capitalized costs were $90.2 million and $85.2 million at December 31, 1999 and
1998, respectively.
<PAGE>
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
estimates for the proved reserves in the Liebre field in Colombia were prepared
by the Company's internal petroleum reservoir engineers. 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.
As of December 31, 1999, 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.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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, 1998 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 --- ---
======== ======= ====== ======== ======== ======= ====== =========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C>
EQUITY INVESTMENT
COLOMBIA MALAYSIA-THAILAND 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 --- ---
======== ======= ======== ========== ======== ========== ===== =========
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
COLOMBIA MALAYSIA-THAILAND TOTAL WORLDWIDE
----------------- ------------------- --------------------
OIL GAS OIL GAS OIL GAS
-------- ------- ------- ---------- -------- ----------
PROVED DEVELOPED AND
UNDEVELOPED RESERVES AS OF
DECEMBER 31, 1996 135,310 14,651 24,700 871,100 160,010 885,751
Revisions 14,157 770 (2,000) (7,600) 12,157 (6,830)
Extensions and discoveries 2,308 --- 7,100 360,300 9,408 360,300
Production (5,776) (802) --- --- (5,776) (802)
-------- ------- ------- ---------- -------- ----------
AS OF DECEMBER 31, 1997 145,999 14,619 29,800 1,223,800 175,799 1,238,419
======== ======= ======= ========== ======== ==========
PROVED DEVELOPED RESERVES AT
DECEMBER 31, 1997 81,931 14,619 --- --- 81,931 14,619
======== ======= ======= ========== ======== ==========
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH INFLOWS AND CHANGES THEREIN
The following table presents for the net quantities of proved oil and gas
reserves a standardized measure of discounted future net cash inflows discounted
at an annual rate of 10%. The future net cash inflows were calculated in
accordance with Securities and Exchange Commission guidelines. Future cash
inflows were computed by applying 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 1999 attributable to oil
reserves were based on the year end WTI crude oil price of $25.60 per barrel for
the Company's reserves in Colombia and Malaysia-Thailand, and the year end Brent
crude oil price of $24.89 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 ARCO of one-half of the shares through which the
Company owned its interest in Block A-18, ARCO 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, 1999, the Company
assumed that it would receive an incentive payment of $65 million in July 2002.
There can be no assurances that the Company will receive any incentive payments.
See note 19, "Certain Factors that Could Affect Future Operations - Certain
Factors Related to Malaysia-Thailand."
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
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
========== ========== ========== ==========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
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
========== ==========
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C>
MALAYSIA- TOTAL
COLOMBIA THAILAND WORLDWIDE
---------- ---------- ----------
DECEMBER 31, 1997:
Future cash inflows $2,524,291 $4,078,609 $6,602,900
Future production and
development costs 1,142,382 1,883,881 3,026,263
---------- ---------- ----------
Future net cash inflows before
income taxes $1,381,909 $2,194,728 $3,576,637
========== ========== ==========
Future net cash inflows before
income taxes discounted at 10%
per annum $ 852,421 $ 427,463 $1,279,884
Future income taxes discounted at
10% per annum 173,785 36,756 210,541
---------- ---------- ----------
Standardized measure of discounted
future net cash inflows $ 678,636 $ 390,707 $1,069,343
========== ========== ==========
</TABLE>
Changes in the standardized measure of discounted future net cash inflows
follow:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
DECEMBER 31,
-------------------------------------
1999 1998 1997
----------- ----------- -----------
Total worldwide:
Beginning of year $ 411,218 $1,069,343 $1,292,195
Sales, net of production costs (179,748) (87,335) (94,062)
Sales of reserves --- (70,543) ---
Equity investment --- (244,618) ---
Revisions of quantity estimates (6,546) (29,321) 75,253
Net change in prices and production costs 1,105,963 (579,212) (552,863)
Extensions, discoveries and improved recovery 206,260 6,516 42,918
Change in future development costs (61,728) (46,633) (5,936)
Purchases of reserves 6,400 --- ---
Development and facilities costs incurred 70,828 105,808 53,199
Accretion of discount 74,704 120,270 160,406
Changes in production rates and other (10,567) (30,772) (3,089)
Net change in income taxes (387,887) 197,715 101,322
----------- ----------- -----------
End of year $1,228,897 $ 411,218 $1,069,343
=========== =========== ===========
</TABLE>
SCHEDULE II
TRITON ENERGY LIMITED AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
ADDITIONS
---------
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
BALANCE AT CHARGED TO BALANCE
BEGINNING CHARGED TO OTHER AT CLOSE
CLASSIFICATIONS OF YEAR EARNINGS ACCOUNTS DEDUCTIONS OF YEAR
------------------------- ----------- ------------ ----------- ------------ ---------
Year ended Dec. 31, 1997:
Allowance for doubtful
receivables $ 76 $ --- $ --- $ (35) $ 41
=========== ============ =========== ============ =========
Allowance for deferred
tax asset $ 30,657 $ 44,435 $ --- $ --- $ 75,092
=========== ============ =========== ============ =========
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
=========== ============ =========== ============ =========
</TABLE>
