SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
-----------------------
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1998
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
COMMISSION FILE NUMBER: 1-11675
TRITON ENERGY LIMITED
(Exact name of registrant as specified in its charter)
CAYMAN ISLANDS NONE
- ------------------------ --------------
(State or other jurisdiction (I.R.S. Employer
of incorporation or Identification No.)
Organization)
CALEDONIAN HOUSE, MARY STREET, P.O. BOX 1043, GEORGE TOWN,
GRAND CAYMAN, CAYMAN ISLANDS
(Address of principal executive offices and zip code)
Registrant's telephone number, including area code: (345) 949-0050
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
YES X NO
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Number of Shares
Title of Each Class Outstanding at April 30, 1998
Ordinary Shares, par value $0.01 per share 36,572,573
-----------------------------
<PAGE>
TRITON ENERGY LIMITED AND SUBSIDIARIES
INDEX
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PAGE NO.
PART I. FINANCIAL INFORMATION --------
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Item 1. Financial Statements
Condensed Consolidated Statements of Operations -
Three months ended March 31, 1998 and 1997 2
Condensed Consolidated Balance Sheets -
March 31, 1998 and December 31, 1997 3
Condensed Consolidated Statements of Cash Flows -
Three months ended March 31, 1998 and 1997 4
Condensed Consolidated Statement of Shareholders' Equity -
Three months ended March 31, 1998 5
Notes to Condensed Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 14
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K 19
</TABLE>
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 1998 AND 1997
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
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<CAPTION>
1998 1997
-------- ---------
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Oil and gas sales $ 36,175 $ 33,759
Costs and expenses:
Operating 15,687 11,221
General and administrative 7,689 5,704
Depreciation, depletion and amortization 12,079 7,443
--------- ----------
35,455 24,368
--------- ----------
Operating income 720 9,391
Gain on sale of Triton Pipeline Colombia 50,227 ---
Interest income 735 905
Interest expense, net (5,166) (5,026)
Other income (expense), net 1,492 (857)
--------- ----------
47,288 (4,978)
--------- ----------
Earnings before income taxes 48,008 4,413
Income tax expense 5,096 927
--------- ----------
Net earnings 42,912 3,486
Dividends on preference shares 187 213
--------- ----------
Earnings applicable to ordinary shares $ 42,725 $ 3,273
========= ==========
Average ordinary shares outstanding 36,566 36,375
========= ==========
Basic earnings per ordinary share $ 1.17 $ 0.09
========= ==========
Diluted earnings per ordinary share $ 1.16 $ 0.09
========= ==========
</TABLE>
See accompanying Notes to Condensed Consolidated Financial Statements.
<PAGE>
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
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ASSETS MARCH 31, DECEMBER 31,
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1998 1997
----------------- -----------------
(UNAUDITED)
Current assets:
Cash and equivalents $ 11,677 $ 13,451
Trade receivables, net 13,259 12,963
Other receivables 44,342 52,162
Inventories, prepaid expenses and other 4,455 5,219
Assets held for sale 10,816 58,178
----------------- -----------------
Total current assets 84,549 141,973
Property and equipment, at cost, less accumulated depreciation
and depletion of $100,361 for 1998 and $89,014 for 1997 879,413 835,506
Deferred taxes and other assets 118,607 120,560
----------------- -----------------
$ 1,082,569 $ 1,098,039
================= =================
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term borrowings and current maturities of long-term debt $ 96,662 $ 184,975
Accounts payable and accrued liabilities 43,363 36,964
Deferred income 35,254 35,254
----------------- -----------------
Total current liabilities 175,279 257,193
Long-term debt, excluding current maturities 473,608 443,312
Deferred income taxes 52,437 50,968
Deferred income and other 41,280 49,946
Convertible debentures due to employees --- ---
Shareholders' equity:
Preference shares 7,492 7,511
Ordinary shares, par value $0.01 366 365
Additional paid-in capital 588,906 588,454
Accumulated deficit (254,669) (297,581)
Accumulated other non-owner changes in shareholders' equity (2,126) (2,126)
----------------- -----------------
339,969 296,623
Less cost of ordinary shares in treasury 4 3
----------------- -----------------
Total shareholders' equity 339,965 296,620
Commitments and contingencies (note 7) --- ---
----------------- -----------------
$ 1,082,569 $ 1,098,039
================= =================
</TABLE>
The Company uses the full cost method to account for its oil and gas producing
activities.
See accompanying Notes to Condensed Consolidated Financial Statements.
<PAGE>
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
THREE MONTHS ENDED MARCH 31, 1998 AND 1997
(IN THOUSANDS)
(UNAUDITED)
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1998 1997
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Cash flows from operating activities:
Net earnings $ 42,912 $ 3,486
Adjustments to reconcile net earnings to net cash provided
by operating activities:
Depreciation, depletion and amortization 12,079 7,443
Amortization of deferred income (8,814) (2,026)
Amortization of debt discount --- 5,026
Gain on sale of Triton Pipeline Colombia (50,227) ---
Deferred income taxes and other 2,849 1,914
Changes in working capital pertaining to operating activities 10,482 7,431
---------- ------------
Net cash provided by operating activities 9,281 23,274
---------- ------------
Cash flows from investing activities:
Capital expenditures and investments (51,057) (46,613)
Proceeds from sale of Triton Pipeline Colombia 97,656 ---
Other 196 3,100
---------- ------------
Net cash provided (used) by investing activities 46,795 (43,513)
---------- ------------
Cash flows from financing activities:
Proceeds from revolving lines of credit and long-term debt 77,404 94,800
Payments on revolving lines of credit and long-term debt (135,565) (8,514)
Short-term notes payable, net --- 10,000
Issuances of ordinary shares 621 1,342
Other (188) (190)
---------- ------------
Net cash provided (used) by financing activities (57,728) 97,438
---------- ------------
Effect of exchange rate changes on cash and equivalents (122) 362
---------- ------------
Net increase (decrease) in cash and equivalents (1,774) 77,561
Cash and equivalents at beginning of period 13,451 11,048
---------- ------------
Cash and equivalents at end of period $ 11,677 $ 88,609
========== ============
</TABLE>
See accompanying Notes to Condensed Consolidated Financial Statements.
<PAGE>
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
THREE MONTHS ENDED MARCH 31, 1998
(IN THOUSANDS)
(UNAUDITED)
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Preference shares:
Balance at December 31, 1997 $ 7,511
Conversion of 5% preference shares (19)
--------------
Balance at March 31, 1998 7,492
--------------
Ordinary shares:
Balance at December 31, 1997 365
Issuances under stock plans 1
--------------
Balance at March 31, 1998 366
--------------
Additional paid-in capital:
Balance at December 31, 1997 588,454
Cash dividends, 5% preference shares (187)
Conversion of 5% preference shares 19
Issuances under stock plans 620
--------------
Balance at March 31, 1998 588,906
--------------
Treasury shares:
Balance at December 31, 1997 (3)
Purchase of treasury shares (1)
--------------
Balance at March 31, 1998 (4)
--------------
Accumulated deficit:
Balance at December 31, 1997 (297,581)
Net earnings 42,912
--------------
Balance at March 31, 1998 (254,669)
--------------
Accumulated other non-owner changes in
shareholders' equity:
Balance at December 31, 1997 (2,126)
Other non-owner changes in shareholders' equity ---
--------------
Balance at March 31, 1998 (2,126)
--------------
Total shareholders' equity at March 31, 1998 $ 339,965
==============
</TABLE>
See accompanying Notes to Condensed Consolidated Financial Statements.
<PAGE>
TRITON ENERGY LIMITED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS IN TABLES IN THOUSANDS)
(UNAUDITED)
1. 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 and Malaysia-Thailand. The Company is
actively exploring for oil and gas in these areas, as well as in Southern
Europe, Africa, Asia and the Middle East. All sales currently are derived
from oil and gas production in Colombia.
On March 30, 1998, the Company announced that its Board of Directors approved
the retention of CIBC World Markets Lovegrove & Associates and Lehman
Brothers, Inc. as independent advisers to assist in studying strategic
alternatives for maximizing shareholder value. The strategic alternatives
under consideration include the sale or farmout of a portion or all of the
Company's interest in Block A-18 of the Malaysia-Thailand Joint Development
Area in the Gulf of Thailand, the sale of a portion or all of the Company's
interest in the Cusiana and Cupiagua oil fields in Colombia, or both. The
Company expects to receive proposals regarding strategic alternatives during
the second quarter, but can give no assurance that it will be successful in
pursuing any of these strategic alternatives or as to the terms or timing of
any such transaction.
In the opinion of management, the accompanying unaudited condensed
consolidated financial statements of the Company contain all adjustments of a
normal recurring nature necessary to present fairly the Company's financial
position as of March 31, 1998, and the results of its operations for the three
months ended March 31, 1998 and 1997, its cash flows for the three months
ended March 31, 1998 and 1997, and shareholders' equity for the three months
ended March 31, 1998. The results for the three months ended March 31, 1998,
are not necessarily indicative of the final results to be expected for the
full year.
The condensed consolidated financial statements should be read in conjunction
with the Notes to Consolidated Financial Statements, which are included as
part of the Company's Annual Report on Form 10-K for the year ended December
31, 1997.
Certain other previously reported financial information has been reclassified
to conform to the current period's presentation.
2. COMPREHENSIVE INCOME
In June 1997, the Financial Accounting Standards Board issued Statement No.
130 ("SFAS 130"), "Reporting Comprehensive Income." SFAS 130 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 Condensed Consolidated Statement of Shareholders'
Equity. This statement does not have any effect on the Company's results of
operations or financial position.
3. ASSET DISPOSITIONS
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 after $2.3 million of expenses. The sale resulted
in an aftertax gain of $50.2 million. TPC's investment in OCENSA, totaling
$47.4 million at December 31, 1997, was included in assets held for sale.
In conjunction with the sale of TPC, the Company entered into a five-year
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 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. Upon a sale by the Purchaser of the TPC shares,
the Company will receive from the Counterparty, or make a cash payment 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. The equity swap will be carried in
the Company's financial statements at fair value during the five-year term.
Fluctuations in the fair value of the equity swap will affect other income as
noncash adjustments.
4. DEBT
During the first quarter of 1998, the Company used the proceeds from the sale
of the TPC shares and net borrowings under other unsecured credit facilities
totaling approximately $22 million to repay and terminate its $125 million
unsecured credit facility.
5. OTHER INCOME (EXPENSE), NET
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THREE MONTHS ENDED
MARCH 31,
---------------------
1998 1997
--------- ---------
Foreign exchange gain $ 1,796 $ 2,239
Change in fair value of WTI benchmark call options 36 (3,273)
Other (340) 177
---------- ----------
$ 1,492 $ (857)
========== ==========
</TABLE>
In 1998 and 1997, the Company recognized foreign exchange gains primarily
related to noncash adjustments to deferred tax liabilities in Colombia
associated with devaluation of the Colombian peso versus the U.S. dollar.
6. 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.
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INCOME SHARE PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
--------------- ---------------- ---------
THREE MONTHS ENDED MARCH 31, 1998:
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Net earnings $ 42,912
Less: Preference share dividends (187)
---------------
Earnings available to ordinary shareholders 42,725
Basic earnings per ordinary share 36,566 $ 1.17
========
Effect of dilutive securities
Stock options --- 119
Convertible debentures --- 29
Preference shares 187 218
--------------- ----------
Earnings available to ordinary shareholders
and assumed conversions $ 42,912
===============
Diluted earnings per ordinary share 36,932 $ 1.16
========== ========
THREE MONTHS ENDED MARCH 31, 1997:
Net earnings $ 3,486
Less: Preference share dividends (213)
---------------
Earnings available to ordinary shareholders 3,273
Basic earnings per ordinary share 36,375 $ 0.09
========
Effect of dilutive securities
Stock options --- 613
Convertible debentures --- 114
--------------- ----------
Earnings available to ordinary shareholders
and assumed conversions $ 3,273
===============
Diluted earnings per ordinary share 37,102 $ 0.09
========== ========
</TABLE>
7. COMMITMENTS AND CONTINGENCIES
Development of the Cusiana and Cupiagua fields (the "Fields"), including
drilling and construction of additional production facilities, will require
further capital outlays. Further exploration and development activities on
Block A-18 in the Malaysia-Thailand Joint Development Area in the Gulf of
Thailand, as well as exploratory drilling in other countries, also will
require substantial capital outlays. The Company's capital budget for the
year ending December 31, 1998, is approximately $176 million, excluding
capitalized interest, of which approximately $103 million relates to the
Fields, $23 million relates to Block A-18, and $50 million relates to the
Company's activities in other parts of the world. The 1998 capital budget
includes funding requirements for committed activities only.
In April 1998, the Company signed a heads of agreement for the sale of
natural-gas production from Block A-18. Substantial capital requirements for
Block A-18 will be required prior to the first deliveries of gas which are
expected to begin in 2001. The Company anticipates it may incur development
costs of up to approximately $25 million during the latter half of 1998, which
are not included in the Company's capital budget for the year ending December
31, 1998.
The Company expects to fund capital expenditures and repay debt in the future
with a combination of some or all of the following: asset sales (which may
involve interests in material assets), cash flow from operations (including
additional proceeds of $30 million from the 1995 forward oil sale), cash,
credit facilities and additional facilities to be negotiated, and the issuance
of debt and equity securities. (See Item 2. Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Requirements.)
GUARANTEES
At March 31, 1998, the Company had guaranteed loans of approximately $3.7
million for a Colombian pipeline company in which the Company has an ownership
interest. The Company also guaranteed performance of $27.9 million in future
exploration expenditures in various countries. These commitments are backed
primarily by unsecured letters of credit.
LITIGATION
The Company is subject to litigation matters, none of which is expected to
have a material, adverse effect on the Company's operations or consolidated
financial condition.
8. CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS
Certain statements in this report, including expectations, intentions, plans
and beliefs of the Company and management, including those contained in or
implied by "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and these Notes to Condensed Consolidated Financial
Statements, are forward-looking statements, as defined in Section 21D of the
Securities Exchange Act of 1934, that are dependent on certain events, risks
and uncertainties that may be outside the Company's control. These
forward-looking statements include statements of management's plans and
objectives for the Company's future operations and statements of future
economic performance; information regarding drilling schedules and schedules
for the start-up of production facilities; expected or planned production or
transportation capacity; when the Fields might become self-financing; future
production of the Fields; the negotiation of a gas-sales contract and
commencement of production in Malaysia-Thailand; the Company's capital budget
and future capital requirements; the Company's meeting its future capital
needs; the amount by which production from the Fields may increase or when
such increased production may commence; the Company's realization of its
deferred tax asset; the level of future expenditures for environmental costs;
the outcome of regulatory and litigation matters; the impact of Year 2000
issues; and proven oil and gas reserves and discounted future net cash flows
therefrom; and the assumptions described in this report underlying such
forward-looking statements. Actual results and developments could differ
materially from those expressed in or implied by such statements due to a
number of factors, including those described in the context of such
forward-looking statements, as well as those presented below.
CERTAIN FACTORS RELATING TO THE OIL AND GAS INDUSTRY
The Company's strategy is to focus its exploration activities on what the
Company believes are relatively high-potential prospects. No assurance can be
given that these prospects contain significant oil and gas reserves or that
the Company will be successful in its exploration activities thereon. The
Company follows the full cost method of accounting for exploration and
development of oil and gas reserves whereby all acquisition, exploration and
development costs are capitalized. Costs related to acquisition, holding and
initial exploration of licenses in countries with no proved reserves are
initially capitalized, including internal costs directly identified with
acquisition, exploration and development activities. The Company's
exploration licenses are periodically assessed for impairment on a
country-by-country basis. If the Company's investment in exploration licenses
within a country where no proved reserves are assigned is deemed to be
impaired, the licenses are written down to estimated recoverable value. If
the Company abandons all exploration efforts in a country where no proved
reserves are assigned, all exploration costs associated with the country are
expensed. The Company's assessments of whether its investment within a
country is impaired and whether exploration activities within a country will
be abandoned are made from time to time based on its review and assessment of
drilling results, seismic data and other information it deems relevant. Due
to the unpredictable nature of exploration drilling activities, the amount and
timing of impairment expense are difficult to predict with any certainty.
Financial information concerning the Company's assets at December 31, 1997,
including capitalized costs by geographic area, is set forth in note 21 of
Notes to Consolidated Financial Statements in Triton's Annual Report on Form
10-K for the year ended December 31, 1997.
The markets for oil and natural gas historically have been volatile and are
likely to continue to be volatile in the future. Oil and natural-gas prices
have been subject to significant fluctuations during the past several decades
in response to relatively minor changes in the supply of and demand for oil
and natural gas, market uncertainty and a variety of additional factors that
are beyond the control of the Company. These factors include the level of
consumer product demand, weather conditions, domestic and foreign government
regulations, political conditions in the Middle East and other production
areas, the foreign supply of oil and natural gas, the price and availability
of alternative fuels, and overall economic conditions. It is impossible to
predict future oil and gas price movements with any certainty.
The Company's oil and gas business is also subject to all of the operating
risks normally associated with the exploration for and production of oil and
gas, including, without limitation, blowouts, cratering, pollution,
earthquakes, labor disruptions and fires, each of which could result in
substantial losses to the Company due to injury or loss of life and damage to
or destruction of oil and gas wells, formations, production facilities or
other properties. In accordance with customary industry practices, the
Company maintains insurance coverage limiting financial loss resulting from
certain of these operating hazards. Losses and liabilities arising from
uninsured or underinsured events would reduce revenues and increase costs to
the Company. There can be no assurance that any insurance will be adequate to
cover losses or liabilities. The Company cannot predict the continued
availability of insurance, or its availability at premium levels that justify
its purchase.
The Company's oil and gas business is also subject to laws, rules and
regulations in the countries 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. The Company does not believe that its environmental risks are
materially different from those of comparable companies in the oil and gas
industry. Nevertheless, no assurance can be given that environmental laws and
regulations will not, in the future, adversely affect the Company's
consolidated results of operations, cash flows or financial position.
Pollution and similar environmental risks generally are not fully insurable.
CERTAIN FACTORS RELATING TO INTERNATIONAL OPERATIONS
The Company derives substantially all of its consolidated revenues from
international operations. Risks inherent in international operations include
loss of revenue, property and equipment from such hazards as expropriation,
nationalization, war, insurrection and other political risks; trade protection
measures; risks of increases in taxes and governmental royalties; and
renegotiation of contracts with governmental entities; as well as changes in
laws and policies governing operations of other companies. Other risks
inherent in international operations are the possibility of realizing economic
currency-exchange losses when transactions are completed in currencies other
than U.S. dollars and the Company's ability to freely repatriate its earnings
under existing exchange control laws. To date, the Company's international
operations have not been materially affected by these risks.
CERTAIN FACTORS RELATING TO COLOMBIA
The Company is a participant in significant oil and gas discoveries in the
Fields, located approximately 160 kilometers (100 miles) northeast of Bogota,
Colombia. Development of reserves in the Fields is ongoing and will require
additional drilling and completion of the production facilities currently
under construction. The Company expects that the production facilities will
be completed during 1998. 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 causing increased costs. Such activity increased over
the last year, causing delays in the development of the Cupiagua Field.
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. In 1998, the President of the United States
announced that Colombia would not be certified, but was granted a national
interest waiver. There can be no assurance that, in the future, Colombia will
receive certification or a 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 upper Malay Basin in the Gulf of Thailand approximately 450 kilometers
northeast of Kuala Lumpur and 750 kilometers south of Bangkok as a contractor
under a production-sharing contract covering Block A-18 of the
Malaysia-Thailand Joint Development Area. Test results to date indicate that
significant gas and oil deposits lie within the block. Development of gas
production is in the early planning stages but is expected to take several
years and require the drilling of additional wells and the installation of
production facilities, which will require significant additional capital
expenditures, the ultimate amount of which cannot be predicted. Pipelines
also will be required to be connected between Block A-18 and ultimate markets.
The terms under which any gas produced from the Company's contract area in
Malaysia-Thailand is sold may be affected adversely by the present monopoly,
gas-purchase and transportation conditions in both Malaysia and Thailand.
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 where the Company operates may from time to time give preferential
treatment to their nationals. The oil and gas industry as a whole also
competes with other industries in supplying the energy and fuel requirements
of industrial, commercial and individual consumers.
MARKETS
Crude oil, natural gas, condensate, and other oil and gas products generally
are sold to other oil and gas companies, government agencies and other
industries. The availability of ready markets for oil and gas that might be
discovered by the Company and the prices obtained for such oil and gas depend
on many factors beyond the Company's control, including the extent of local
production and imports of oil and gas, the proximity and capacity of pipelines
and other transportation facilities, fluctuating demands for oil and gas, the
marketing of competitive fuels, and the effects of governmental regulation of
oil and gas production and sales. Pipeline facilities do not exist in certain
areas of exploration and, therefore, any actual sales of discovered oil or gas
might be delayed for extended periods until such facilities are constructed.
LITIGATION
The outcome of litigation and its impact on the Company are difficult to
predict due to many uncertainties, such as jury verdicts, the application of
laws to various factual situations, the actions that may or may not be taken
by other parties and the availability of insurance. In addition, in certain
situations, such as environmental claims, one defendant may be responsible, or
potentially responsible, for the liabilities of other parties. Moreover,
circumstances could arise under which the Company may elect to settle claims
at amounts that exceed the Company's expected liability for such claims in
order to avoid costly litigation. Judgments or settlements could, therefore,
exceed any reserves.
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL REQUIREMENTS
----------------------------------
Cash and cash equivalents totaled $11.7 million and $13.5 million at
March 31, 1998, and December 31, 1997, respectively. Working capital deficit
was $90.7 million at March 31, 1998, compared with $115.2 million at December
31, 1997. At March 31, 1998, borrowings of $77.5 million under the Company's
bank credit facilities, which mature during the period October 1998 through
February 1999, were classified as a current liability. Current liabilities
also included deferred income totaling $35.3 million at March 31, 1998 and at
December 31, 1997 related to a forward oil sale consummated in 1995.
The Company's capital expenditures and other capital investments were
$51.1 million for the three months ended March 31, 1998, primarily for
development of the Cusiana and Cupiagua fields (the "Fields") in Colombia and
exploration in Block A-18 in the Malaysia-Thailand Joint Development Area in
the Gulf of Thailand. The capital spending program for the three months ended
March 31, 1998, was funded primarily with cash flow from operations, asset
sales and borrowings under the Company's credit facilities.
Development of the Fields, including drilling and construction of
additional production facilities, will require further capital outlays.
Further exploration and development activities on Block A-18 in the
Malaysia-Thailand Joint Development Area in the Gulf of Thailand, as well as
exploratory drilling in other countries, also will require substantial capital
outlays. The Company's capital budget for the year ending December 31, 1998,
is approximately $176 million, excluding capitalized interest, of which
approximately $103 million relates to the Fields, $23 million relates to Block
A-18, and $50 million relates to the Company's activities in other parts of
the world. The 1998 capital budget includes funding requirements for committed
activities only.
In April 1998, the Company signed a heads of agreement for the
sale of natural-gas production from Block A-18. Substantial capital
requirements for Block A-18 will be required prior to the first deliveries
of gas which are expected to begin in 2001. The Company anticipates it may
incur development costs of up to approximately $25 million during the latter
half of 1998, which are not included in the Company's capital budget for the
year ending December 31, 1998.
The Company expects to fund capital expenditures and repay debt in the
future with a combination of some or all of the following: asset sales (which
may involve interests in material assets), cash flow from operations
(including additional proceeds of $30 million from the 1995 forward oil sale),
cash, credit facilities and additional facilities to be negotiated, and the
issuance of debt and equity securities. Under the most restrictive covenant
in the Company's existing credit facilities, the Company generally could not
permit total indebtedness (as defined in the various agreements) to exceed
$650 million. The limitation on total indebtedness will increase to $725
million once the Fields achieve a production level of 340,000 barrels per day.
At May 11, 1998, the Company had total indebtedness outstanding of
approximately $600 million and available cash and borrowing capacity under
unused credit facilities totaling approximately $18 million. The Company is
currently in negotiations for additional committed bank credit facilities
which will be needed to meet the Company's cash needs during 1998. The
Company is currently negotiating a revolving credit facility that would
provide an additional $30 million of borrowing capacity. There can be no
assurance that the Company will be able to successfully negotiate additional
credit facilities, and the Company may be required to seek alternative sources
of capital. To facilitate a possible future securities issuance or issuances,
the Company has on file with the Securities and Exchange Commission a shelf
registration statement under which the Company could issue up to an aggregate
of $200 million debt or equity securities.
On March 30, 1998, the Company announced that its Board of Directors
approved the retention of CIBC World Markets Lovegrove & Associates
and Lehman Brothers, Inc. as independent advisers to assist in
studying strategic alternatives for maximizing shareholder value. The
strategic alternatives under consideration include the sale or farmout of
a portion or all of the Company's interest in Block A-18 of the
Malaysia-Thailand Joint Development Area in the Gulf of Thailand, the sale
of a portion or all of the Company's interest in the Cusiana and Cupiagua
oil fields in Colombia, or both. The Company expects to receive proposals
regarding strategic alternatives during the second quarter, but can give no
assurance that it will be successful in pursuing any of these strategic
alternatives or as to the terms or timing of any such transaction.
RESULTS OF OPERATIONS
---------------------
Sales volumes and average prices realized were as follows:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
-------------------
1998 1997
----- ------
<S> <C> <C>
Sales volumes
Oil (MBbls), excluding forward oil sale 1,896 1,413
Forward oil sale (1) (MBbls delivered) 762 175
----- ------
Total 2,658 1,588
====== ======
Gas (MMcf) 165 77
Weighted average price realized:
Oil (per Bbl) $13.55 $21.19
Gas (per Mcf) $ 0.99 $ 1.36
(1) Commencing April 1, 1997, the delivery requirements under the forward
oil sale increased by 195,711 barrels of oil per month.
</TABLE>
<PAGE>
THREE MONTHS ENDED MARCH 31, 1998,
COMPARED WITH THREE MONTHS ENDED MARCH 31, 1997
Oil and Gas Sales
--------------------
Revenue increased $2.4 million in 1998, due to higher production ($22.8
million), which was offset by lower average realized oil prices ($20.4
million). The lower average realized oil price resulted from a combination of
a significant decrease in the 1998 average West Texas Intermediate oil price,
compared with the prior-year quarter and the increased deliveries under the
forward oil sale. Forward oil sale deliveries, scheduled in 1995 and recorded
at $11.56 per barrel, were 29% of sales volumes in 1998, compared with 11% of
the Company's sales volumes in 1997. In April 1997, the Company's delivery
requirements under the forward oil sale increased from 58,425 barrels per
month to 254,136 barrels per month, which had an adverse effect on the
Company's earnings and cash flows on a per-barrel basis during 1998.
Based on the operator's current projections, the Company expects gross
production capacity from the Fields to reach 500,000 barrels per day during
1998. The Company expects that the adverse effect on the Company's results of
operations and cash flows from the forward oil sale deliveries will be
mitigated by increased production from the Fields. There can be no assurance,
however, regarding the timing of any increase in production or as to future
prices.
Costs and Expenses
--------------------
First quarter operating expenses increased $4.5 million in 1998, and
depreciation, depletion and amortization increased $4.6 million, primarily due
to higher production volumes, including barrels delivered under the forward
oil sale. The Company pays lifting costs, production taxes and transportation
costs to the Colombian port of Covenas for barrels to be delivered under the
forward oil sale.
The Company's operating costs per equivalent-barrel were $5.99 and $7.14
in 1998 and 1997, respectively. Operating expenses on a per equivalent-barrel
basis were lower primarily due to a decrease in production taxes of $2.1
million. Beginning in 1998, no production taxes are assessed on production
from the Cusiana Field. The Company will be required to pay production taxes
on production from the Cupiagua Field equating to approximately 5.5%, 4% and
2.5% of gross realized oil prices during 1998, 1999 and 2000, respectively.
Oleoducto Central S.A. ("OCENSA") pipeline tariffs totaled $10.1 million
or $3.90 per barrel, and $6.1 million or $3.96 per barrel in 1998 and 1997,
respectively. OCENSA imposes a tariff on shippers from the Fields (the
"Initial Shippers"), which is estimated to recoup: the total capital cost of
the project over a 15-year period; its operating expenses, which include all
Colombian taxes; interest expense; and the dividend to be paid by OCENSA to
its shareholders. Any shippers of crude oil who are not Initial Shippers are
assessed a premium tariff on a per-barrel basis, and OCENSA will use revenues
from such tariffs to reduce the Initial Shippers' tariff.
<PAGE>
General and administrative expense before capitalization increased $1.2
million to $14.1 million in 1998 primarily due to growth of the Company's
operations. Capitalized general and administrative costs were $6.4 million
and $7.2 million in 1998 and 1997, respectively.
Other Income and Expenses
----------------------------
In 1998, the Company sold Triton Pipeline Colombia, Inc., a wholly owned
subsidiary that held the Company's 9.6% equity interest in the Colombian
pipeline company, OCENSA, for $100 million. Net proceeds were approximately
$97.7 million after $2.3 million of expenses. The sale resulted in an
aftertax gain of $50.2 million.
Other income (expense), net included foreign exchange gains of $1.8
million and $2.2 million in 1998 and 1997, respectively, primarily related to
noncash adjustments to deferred tax liabilities in Colombia associated with
devaluation of the Colombian peso versus the U.S. dollar. In 1997, other
income (expense), net included an unrealized loss of $3.3 million representing
the change in the fair market value of call options purchased in anticipation
of a forward oil sale in 1995. Other income in future periods could be
impacted by fluctuations in the fair market value of these call options, as
well as the equity swap entered into in February 1998. See note 3 of Notes to
Condensed Consolidated Financial Statements.
Income Taxes
-------------
Statement of Financial Accounting Standards No. 109 ("SFAS 109"),
"Accounting for Income Taxes," requires that the Company make projections
about the timing and scope of certain future business transactions in order to
estimate recoverability of deferred tax assets primarily resulting from the
expected utilization of net operating loss carryforwards. Changes in the
timing or nature of actual or anticipated business transactions, projections
and income tax laws can give rise to significant adjustments to the Company's
deferred tax expense or benefit that may be reported from time to time. For
these and other reasons, compliance with SFAS 109 may result in significant
differences between tax expense for income statement purposes and taxes
actually paid.
The income tax provision for 1998 included current taxes related to the
Company's Colombian operations totaling $1 million and $1.3 million in 1998
and 1997, respectively. Foreign deferred taxes totaled $3.8 million in 1998,
primarily related to the Company's Colombian operations, compared with foreign
deferred taxes of $3.3 million in 1997. Additionally, the income tax
provision included a deferred tax expense in the United States totaling $.2
million in 1998, compared with a benefit of $3.6 million in 1997.
Information Systems and the Year 2000
------------------------------------------
The Company has reviewed its operational, financial and other information
systems for potential conflicts with the Year 2000. The Company believes that
the Year 2000 will not cause any significant disruptions to its information
systems, and any costs to resolve Year 2000 issues will not be material.
The Company has begun an investigation into the potential impact to its
operations caused by Year 2000 problems that may occur at third parties,
including its oil and gas partners, financial institutions, and vendors. The
Company has identified certain third parties that may encounter Year 2000
problems, but has not yet determined the potential impact to the Company's
operations or the costs to the Company, if any, associated with these issues.
The Company intends to engage a third-party Year 2000 consultant during 1998
to validate the Company's assumptions and identify nonconformance.
Certain Factors That Could Affect Future Operations
---------------------------------------------------------
Certain statements in this report, including expectations, intentions,
plans and beliefs of the Company and management, are forward-looking
statements, as defined in Section 21D of the Securities Exchange Act of 1934,
that are dependent on certain events, risks and uncertainties that may be
outside the Company's control. These forward-looking statements include
statements of management's plans and objectives for the Company's future
operations and statements of future economic performance; information
regarding drilling schedules and schedules for the start-up of production
facilities; expected or planned production or transportation capacity; when
the Fields might become self-financing; future production of the Fields; the
negotiation of a gas-sales contract and commencement of production in
Malaysia-Thailand; the Company's capital budget and future capital
requirements; the Company's meeting its future capital needs; the amount by
which production from the Fields may increase or when such increased
production may commence; the Company's realization of its deferred tax asset;
the level of future expenditures for environmental costs; the outcome of
regulatory and litigation matters; the impact of Year 2000 issues; and proven
oil and gas reserves and discounted future net cash flows therefrom; and the
assumptions described in this report underlying such forward-looking
statements. Actual results and developments could differ materially from
those expressed in or implied by such statements due to a number of factors,
including those described in the context of such forward-looking statements
and in notes to Notes to Condensed Consolidated Financial Statements.
<PAGE>
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: The following documents are filed as part of this Quarterly
Report on Form 10-Q:
1. Exhibits required to be filed by Item 601 of Regulation S-K. (Where
the amount of securities authorized to be issued under any of Triton Energy
Limited's and any of its subsidiaries' long-term debt agreements does not
exceed 10% of the Company's assets, pursuant to paragraph (b)(4) of Item 601
of Regulation S-K, in lieu of filing such as exhibits, the Company hereby
agrees to furnish to the Commission upon request a copy of any agreement with
respect to such long-term debt.)
<TABLE>
<CAPTION>
<C> <S>
3.1 Memorandum of Association. (1)
3.2 Articles of Association. (1)
4.1 Specimen Share Certificate of Ordinary Shares, $.01 par value, of the Company. (2)
4.2 Rights Agreement dated as of March 25, 1996, between Triton and Chemical Bank, as
Rights Agent, including, as Exhibit A thereto, Resolutions establishing the Junior
Preference Shares. (1)
4.3 Resolutions Authorizing the Company's 5% Convertible Preference Shares. (3)
4.4 Amendment No. 1 to Rights Agreement dated as of August 2, 1996, between Triton and
Chemical Bank, as Rights Agent. (4)
10.1 Amended and Restated Retirement Income Plan. (5)
10.2 Amended and Restated Supplemental Executive Retirement Income Plan. (6)
10.3 1981 Employee Non-Qualified Stock Option Plan. (7)
10.4 Amendment No. 1 to the 1981 Employee Non-Qualified Stock Option Plan. (8)
10.5 Amendment No. 2 to the 1981 Employee Non-Qualified Stock Option Plan. (7)
10.6 Amendment No. 3 to the 1981 Employee Non-Qualified Stock Option Plan. (5)
10.7 1985 Stock Option Plan. (9)
10.8 Amendment No. 1 to the 1985 Stock Option Plan. (7)
10.9 Amendment No. 2 to the 1985 Stock Option Plan. (5)
10.10 Amended and Restated 1986 Convertible Debenture Plan. (5)
10.11 1988 Stock Appreciation Rights Plan. (10)
10.12 1989 Stock Option Plan. (11)
10.13 Amendment No. 1 to 1989 Stock Option Plan. (7)
10.14 Amendment No. 2 to 1989 Stock Option Plan. (5)
10.15 Second Amended and Restated 1992 Stock Option Plan. (13)
10.16 Form of Amended and Restated Employment Agreement with Triton Energy Limited
and its executive officers. (6)
10.17 Form of Amended and Restated Employment Agreement with Triton Energy Limited
and certain officers. (6)
10.18 Amended and Restated 1985 Restricted Stock Plan. (5)
10.19 First Amendment to Amended and Restated 1985 Restricted Stock Plan. (12)
10.20 Second Amendment to Amended and Restated 1985 Restricted Stock Plan. (13)
10.21 Executive Life Insurance Plan. (14)
10.22 Long Term Disability Income Plan. (14)
10.23 Amended and Restated Retirement Plan for Directors. (9)
10.24 Amended and Restated Indenture dated as of March 25, 1996 between Triton and
Chemical Bank, with respect to the issuance of Senior Subordinated Discount Notes
due 1997. (13)
10.25 Amended and Restated Senior Subordinated Indenture by and between the Company and
United States Trust Company of New York, dated as of March 25, 1996. (13)
10.26 Contract for Exploration and Exploitation for Santiago de Atalayas I with an effective
date of July 1, 1982, between Triton Colombia, Inc., and Empresa Colombiana
De Petroleos. (9)
10.27 Contract for Exploration and Exploitation for Tauramena with an effective date of July
4, 1988, between Triton Colombia, Inc., and Empresa Colombiana De Petroleos. (10)
10.28 Summary of Assignment legalized by Public Instrument No. 1255 dated September 15,
1987 (Assignment is in Spanish language). (10)
10.29 Summary of Assignment legalized by Public Instrument No. 1602 dated June 11, 1990
(Assignment is in Spanish language). (10)
10.30 Summary of Assignment legalized by Public Instrument No. 2586 dated September 9,
1992 (Assignment is in Spanish language). (10)
10.31 401(K) Savings Plan. (5)
10.32 Contract between Malaysia-Thailand and Joint Authority and Petronas Carigali
SDN.BHD.and Triton Oil Company of Thailand relating to Exploration and Production
of Petroleum for Malaysia-Thailand Joint Development Area Block A-18.(15)
10.33 Triton Crude Purchase Agreement between Triton Colombia, Inc. and Oil Co., LTD.
dated May 25, 1995. (16)
10.34 Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation,
NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States. (12)
10.35 Amendment No. 1 to Credit Agreement among Triton Colombia, Inc., Triton Energy
Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
States. (12)
10.36 Amendment No. 2 to Credit Agreement among Triton Colombia, Inc., Triton Energy
Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
States. (13)
10.37 Amendment No. 3 to Credit Agreement among Triton Colombia, Inc., Triton Energy
Limited, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
States. (24)
10.38 Agreement and Plan of Merger among Triton Energy Corporation, Triton Energy
Limited and TEL Merger Corp. (12)
10.39 Credit Agreement among Triton Energy Limited and Triton Energy Corporation, as
Borrowers, and NationsBank of Texas, N.A., Barclays Bank PLC, Meespierson N.V.,
The Chase Manhattan Bank and Societe Generale, Southwest Agency dated
August 30, 1996. (17)
10.40 Form of Indemnity Agreement entered into with each director and officer of the
Company. (17)
10.41 Restated Employment Agreement between John Tatum and the Company. (20)
10.42 Description of Performance Goals for Executive Bonus Compensation. (20)
10.43 Stock Purchase Agreement dated September 2, 1997 between the Strategic
Transaction Company and Triton International Petroleum, Inc. (6)
10.44 Fourth Amendment to Stock Purchase Agreement dated February 2, 1998 between
The Strategic Transaction Company and Triton International Petroleum, Inc. (6)
10.45 Supplemental Indenture dated April 17, 1997 among Triton Energy Corporation, Triton
Energy Limited and The Chase Manhattan Bank (formerly known as Chemical Bank)
amending Amended and Restated Indenture dated as of March 25, 1996 relating to
the Senior Subordinated Discount Notes due 1997. (21)
10.46 Supplemental Indenture dated April 17, 1997 among Triton Energy Corporation, Triton
Energy Limited and United States Trust Company of New York amending Amended
and Restated Senior Subordinated Indenture dated as of March 25, 1996 relating to the
9 3/4% Senior Subordinated Discount Notes due 2000. (21)
10.47 Senior Indenture dated April 10, 1997 among Triton Energy Corporation, Triton
Energy Limited and The Chase Manhattan Bank. (21)
10.48 First Supplemental Indenture dated April 10, 1997 among Triton Energy Corporation,
Triton Energy Limited and The Chase Manhattan Bank amending Senior Indenture
dated as of April 10, 1997 relating to the 8 3/4% Senior Notes due 2002. (21)
10.49 Second Supplemental Indenture dated April 10, 1997 among Triton Energy Corporation,
Triton Energy Limited and The Chase Manhattan Bank amending Senior Indenture
dated as of April 10, 1997 relating to the 9 1/4% Senior Notes due 2005. (21)
10.50 First Amendment to Credit Agreement dated as of April 4, 1997 among Triton Energy
Limited and Triton Energy Corporation, as Borrowers, and NationsBank of Texas, N.A.,
Barclays Bank PLC, Meespierson N.V., The Chase Manhattan Bank and Societe
Generale, Southwest Agency. (21)
10.51 1997 Share Compensation Plan. (21)
10.52 First Amendment to 1997 Share Compensation Plan. (6)
10.53 First Amendment to Amended and Restated Retirement Plan for Directors. (6)
10.54 First Amendment to Second Amended and Restated 1992 Stock Option Plan. (21)
10.55 Second Amendment to Second Amended and Restated 1992 Stock Option Plan. (6)
10.56 Agreement to Release Triton Energy Corporation and Second Amendment to Credit
Agreement dated as of July 21, 1997 among Triton Energy Limited and Triton Energy
Corporation, as Borrowers, and NationsBank of Texas, N.A., Barclays Bank PLC,
MeesPierson N.V., The Chase Manhattan Bank and Societe Generale, Southwest
Agency. (22)
10.57 Amended and Restated Indenture dated July 25, 1997 between Triton Energy Limited
and The Chase Manhattan Bank. (22)
10.58 Amended and Restated First Supplemental Indenture dated July 25, 1997 between Triton
Energy Limited and The Chase Manhattan Bank relating to the 8 3/4% Senior Notes
due 2002. (22)
10.59 Amended and Restated Second Supplemental Indenture dated July 25, 1997 between
Triton Energy Limited and The Chase Manhattan Bank relating to the 9 1/4% Senior
Notes due 2005. (22)
10.60 Third Amendment to Credit Agreement dated as of September 30, 1997 among Triton
Energy Limited, NationsBank of Texas, N.A., Barclays Bank PLC, MeesPierson N.V.,
The Chase Manhattan Bank and Societe Generale, Southwest Agency. (23)
10.61 Amendment to Amended and Restated Retirement Income Plan dated
December 31, 1996. (24)
10.62 Amendment to 401(K) Savings Plan dated December 31, 1996. (24)
12.1 Computation of Ratio of Earnings to Fixed Charges. (24)
12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preference
Dividends. (24)
27.1 Financial Data Schedule.(24)
99.1 Heads of Agreement for the Supply of Gas from the Block A-18 of the Malaysia-
Thailand Joint Development Area. (24)
99.2 Rio Chitamena Association Contract. (19)
99.3 Rio Chitamena Purchase and Sale Agreement. (19)
99.4 Integral Plan - Cusiana Oil Structure. (19)
99.5 Letter Agreements with co-investor in Colombia. (19)
99.6 Colombia Pipeline Memorandum of Understanding. (19)
99.7 Amended and Restated Oleoducto Central S.A. Agreement dated as of March 31,
1995. (18)
_______________________________
(1) Previously filed as an exhibit to the Company's Registration Statement on Form S-3
(No 333-08005) and incorporated herein by reference.
(2) Previously filed as an exhibit to the Company's Registration Statement on Form 8-A
dated March 25, 1996 and incorporated herein by reference.
(3) Previously filed as an exhibit to the Company's and Triton Energy Corporation's
Registration Statement on Form S-4 (No. 333-923) and incorporated herein
by reference.
(4) Previously filed as an exhibit to the Company's Registration Statement on Form 8-A/A
(Amendment No. 1) dated August 14, 1996 and incorporated herein by reference.
(5) Previously filed as an exhibit to Triton Energy Corporation's Quarterly Report on Form
10-Q for the quarter ended November 30, 1993 and incorporated by reference herein.
(6) Previously filed as an exhibit to the Company's Annual Report on Form 10-K for
the year ended December 31, 1997 and incorporated herein by reference.
(7) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended May 31, 1992 and incorporated herein by reference.
(8) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended May 31, 1989 and incorporated by reference herein.
(9) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended May 31, 1990 and incorporated herein by reference.
(10) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended May 31, 1993 and incorporated by reference herein.
(11) Previously filed as an exhibit to Triton Energy Corporation's Quarterly Report on Form
10-Q for the quarter ended November 30, 1988 and incorporated herein by reference.
(12) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended December 31, 1995 and incorporated herein by
reference.
(13) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1996 and incorporated herein by reference.
(14) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended May 31, 1991 and incorporated herein by reference.
(15) Previously filed as an exhibit to Triton Energy Corporation's current report on Form
8-K dated April 21, 1994 and incorporated by reference herein.
(16) Previously filed as an exhibit to Triton Energy Corporation's Current Report on Form
8-K dated May 26, 1995 and incorporated herein by reference.
(17) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1996 and incorporated herein by reference.
(18) Previously filed as an exhibit to Triton Energy Corporation's Quarterly Report on Form
10-Q for the quarter ended June 30, 1995 and incorporated herein by reference.
(19) Previously filed as an exhibit to Triton Energy Corporation's current report on Form
8-K/A dated July 15, 1994 and incorporated by reference herein.
(20) Previously filed as an exhibit to Triton Energy Limited's Annual Report on Form 10-K
For the fiscal year ended December 31, 1996 and incorporated herein by reference.
(21) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1997 and incorporated herein by reference.
(22) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1997 and incorporated herein by reference.
(23) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997 and incorporated herein by reference.
(24) Filed herewith.
</TABLE>
(b) Reports on Form 8-K
On February 13, 1998, the Company filed a Current Report on Form 8-K reporting
(i) the Company's announcement of the sale of its equity interest in Oleoducto
Central S.A. and (ii) the Company's financial results for the year ended
December 31, 1997.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
TRITON ENERGY LIMITED
By: /s/ Peter Rugg
----------------------------
Peter Rugg
Senior Vice President and
Chief Financial Officer
Date: May 13, 1998
EXHIBIT 10.37
AMENDMENT NO. 3 TO CREDIT AGREEMENT
This Amendment No. 3, dated as of September 2, 1997, is made by and among
TRITON COLOMBIA, INC., a corporation duly existing under the laws of the
Cayman Islands, as Borrower, TRITON ENERGY CORPORATION, a corporation duly
organized and existing under the laws of the State of Delaware, TRITON ENERGY
LIMITED, a holding company duly organized and existing under the laws of the
Cayman Islands, NATIONSBANK, N.A., as successor in interest to NationsBank, N.
A. (Carolinas), as Lender, and the EXPORT-IMPORT BANK OF THE UNITED STATES, an
agency of the United States of America ("Eximbank").
WHEREAS:
(A) the Borrower, the Lender, Triton Energy Corporation ("TEC") and
Eximbank are parties to the Credit Agreement, dated as of November 21, 1995
(together with exhibits, schedules, attachments and appendices thereto, the
"Credit Agreement");
(B) TEC, Triton Energy Limited ("TEL") and TEL Merger Corporation
entered into an Agreement and Plan of Merger, dated as of February 8, 1996,
(the "Merger Agreement") providing for the merger of TEL Merger Corporation
into TEC as the surviving corporation and establishing TEL as the parent
holding company; and
(C) the Borrower, the Lender, TEC, TEL and Eximbank desire to amend
the Credit Agreement to substitute TEL for TEC as the guarantor and to make
other amendments to the Credit Agreement;
NOW THEREFORE, in consideration of the premises and the mutual covenants
herein contained, and for other good and valuable consideration, the receipt
and sufficiency of which are hereby acknowledged, the parties hereto agree as
follows:
Section 1. Definitions and References.Capitalized terms not otherwise
-----------------------------
defined herein shall have the meanings attributed thereto in the Credit
Agreement.
Section 2. Amendments.
-----------
(a) The definition of "Borrower" in the Preamble shall be amended to read
"Triton Colombia, Inc., a corporation existing under the laws of the Cayman
Islands".
(b) The definition of "Guarantor" in the Preamble shall be amended to
read "Triton Energy Limited".
(c) The definition of "Governmental Authority" shall be amended and
restated in its entirety as follows:
"Governmental Authority" shall mean the Government of Colombia, the
Government of the Cayman Islands, the Government of the United States, any
agency, department or any other administrative authority or instrumentality of
the Government of Colombia, the Government of the Cayman Islands or the
Government of the United States, and any local or other governmental authority
with Colombia, the Cayman Islands or the United States."
(d) Section 6.01(b) is hereby amended and restated in its entirety as
follows:
"(i) Evidence that the Borrower is duly and validly existing under the
laws of the Cayman islands with full power, authority and legal right to own
its property and carry on its business as now conducted. (ii) Evidence that
the Guarantor is duly organized and validly existing under the laws of the
Cayman Islands with full power, authority and legal right to own its property
and carry on its business as now conducted "
(e) Section 9.01(a) is hereby amended and restated in its entirety as
follows:
"The Borrower is duly and validly existing under the laws of the Cayman
Islands, with full power, authority and legal right to own its property and
carry on its business as now conducted. The Borrower has taken all actions
necessary or advisable to authorize it to execute, deliver, perform and
observe the terms and conditions of this Agreement and the Note(s)."
(f) Section 9.04(a) is hereby amended and restated in its entirety as
follows:
"The Guarantor is duly organized and validly existing under the laws of
the Cayman islands, with full power, authority and legal right to own its
property and carry on its business as now conducted. The Guarantor has taken
all actions necessary or advisable to authorize it to execute, deliver,
perform and observe the terms and conditions of this Agreement and the
Note(s)."
(g) Section 9.060d is hereby amended and restated in its entirety as
follows:
"Except as permitted by the Amended and Restated Senior Indenture dated
as of July 25, 1997, as amended and supplemented by Amended and Restated
Second Supplemental Indenture dated as of July 25, 1997, between the Borrower
and The Chase Manhattan Bank, as trustee, merge or consolidate with any other
entity; dissolve or terminate its legal existence, sell, lease, transfer or
otherwise dispose of any substantial part of its properties or any of its
properties essential to the conduct of its business or operations, as now or
hereafter conducted; or enter into any agreement to do any of the foregoing,
without the prior written consent of the Lender and Eximbank."
Section 3. Assumption. TEL hereby assumes each and every obligation and
-----------
covenant of TEC under the Credit Agreement as if it were the original party
thereto and agrees that it will fully, promptly and faithfully perform its
obligations thereunder.
Section 4. Borrower Representations True; No Default. The Borrower
---------------------------------------------
represents and warrants that:
(a) The representations and warranties contained in Section 9.01 are
correct on and as of the date of this Amendment No. 3 as though made on and as
of the date hereof
(b) No event has occurred and is continuing, or would result from the
execution and delivery of this Amendment No. 3, which constitutes an Event of
Default or which, with the giving of notice and/or the passage of time, would
constitute an Event of Default.
Section 5. TEL Representations True. No Default. (a) TEL represents and
------------------------------------
warrants that:
(a) The representations and warranties contained in Section 9.04 are
correct on and as of the date of this Amendment No. 3 as though made on and as
of the date hereof.
(b) No event has occurred and is continuing, or would result from the
execution and delivery of this Amendment No. 3, which constitutes an Event of
Default or which, with the giving of notice and/or the passage of time, would
constitute an Event of Default.
Section 6. Legal Obligation.Each of the Borrower, TEC and TEL represents
-----------------
and warrants to the Lender and Eximbank that this Amendment No. 3 has been
duly authorized, executed and delivered on its behalf, and that the Credit
Agreement, as amended hereby, constitutes a legal, valid and binding
obligation of the Borrower, TEC and TEL in accordance with its terms.
Section 7. Conditions Precedent.This Amendment No. 3 shall be effective
---------------------
upon the satisfaction of the following conditions:
(a) This Amendment No. 3 shall have been duly executed by the authorized
representatives of the parties hereto.
(b) Eximbank shall have received evidence that each of the Borrower and
TEL is duly existing under the laws of the Cayman Islands, with full power,
authority and legal right to own its property and carry on its business as now
conducted.
(c) Eximbank shall have received evidence of the authority of the
Borrower, TEL and TEC to enter into this Amendment No. 3, and the names of,
and specimen signatures and evidence of authority for, the persons who will
execute this Amendment No. 3, sign or endorse the Note(s), as the case may be,
or otherwise act as the Borrower's or TEL's representative in the operation of
the Credit.
(d) Delivery of an opinion of legal counsel to the Borrower and TEL in
substantially the form of Annex C and Annex D, respectively, to the Credit
Agreement.
(e) Eximbank shall have received evidence that TEL has irrevocably
appointed as its agent for service of process the Person or Persons so
specified in Section 11.03(a) of the Credit Agreement, and that such agent has
accepted the appointment and has agreed to forward forthwith to TEL all legal
process addressed to TEL received by such agent.
(f) The original Note shall have been canceled by the Lender and a new
Note in the principal amount of the Credit shall have been fully executed by
the Borrower, endorsed by the Guarantor, and delivered to the Lender, with a
copy to Eximbank.
Section 8. Ratification.Except as expressly amended hereby, the Credit
-------------
Agreement and all other documents executed in connection therewith shall
remain in full force and effect. The Credit Agreement, as amended hereby, and
all rights and powers created thereby or thereunder and under the other
documents executed in connection therewith are in all respects ratified and
confirmed.
Section 9. Miscellaneous.
--------------
(a) The Credit Agreement and this Amendment No. 3 shall be read, taken
and construed as one and the same instrument.
(b) This Amendment No. 3 shall be governed by, and construed in
accordance with, the laws of the State of New York.
(c) Any references in the Credit Agreement to "this Agreement",
"hereunder", "herein" or words of like import referring to the Credit
Agreement, and each reference in any other document executed in connection
with the Credit Agreement (including the Credit Guarantee Agreement and each
Note), to the Credit Agreement, shall mean and be a reference to the Credit
Agreement as amended hereby.
(d) This Amendment No. 3 may be executed in any number of counterparts
and by different parties hereto in separate counterparts, each of which when
so executed shall be deemed an original and all of which taken together shall
constitute one and the same instrument.
IN WITNESSETH WHEREOF, the parties hereto have caused this Amendment No.
3 to be duly executed and delivered by as of the date first above written.
TRITON COLOMBIA, INC.
By: _____________________
Name:___________________
Title: ____________________
TRITON ENERGY CORPORATION
By: _____________________
Name:___________________
Title: ____________________
<PAGE>
TRITON ENERGY LIMITED
By: _____________________
Name:___________________
Title: ____________________
NATIONSBANK N.A., as successor in interest to NATIONSBANK, N.A. (CAROLINAS)
By: _____________________
Name:___________________
Title: ____________________
EXPORT-IMPORT BANK OF THE UNITED STATES
By: _____________________
Name:___________________
Title: ____________________
EXHIBIT 10.62
AMENDMENT TO TRITON EXPLORATION SERVICES, INC.
----------------------------------------------
RETIREMENT INCOME PLAN
----------------------
This Amendment to Triton Exploration Services, Inc. Retirement Income
Plan (this "Amendment") is executed by Triton Exploration Services, Inc., a
Delaware corporation (the "Company"), on March 27, 1998 to be effective as of
December 31, 1996.
R E C I T A L S:
---------------
A. The Company has assumed the sponsorship of the Triton Exploration
Services, Inc. Retirement Income Plan, as amended and/or restated (the
"Plan"); and
B. The Board of Directors has adopted certain amendments to the Plan
effective as of December 31, 1996.
NOW, THEREFORE, the Plan is amended in the following respects:
1. Section 1.40 of the Plan be and it is hereby amended so that (1)
the reference to "Triton Energy Corporation" in the fourth paragraph thereof
shall instead be a reference to Triton Energy Limited, a Cayman Islands
company, and (2) each reference to "Employer" in clauses (a) through (d) in
the fourth paragraph thereof shall instead be a reference to Triton Energy
Limited, a Cayman Islands company.
2. Except as amended by the provisions of this Amendment, all other
provisions of the Plan remain in full force and effect.
IN WITNESS WHEREOF, Triton Exploration Services, Inc. has caused this
Amendment to be executed by its duly authorized officer effective as of
December 31, 1996.
TRITON EXPLORATION SERVICES, INC.
By:_________________________________
Robert B. Holland, III, Senior Vice
President
EXHIBIT 10.63
AMENDMENT TO TRITON EXPLORATION SERVICES, INC.
----------------------------------------------
401(K) SAVINGS PLAN
-------------------
This Amendment to Triton Exploration Services, Inc. 401(k) Savings Plan
(this "Amendment") is executed by Triton Exploration Services, Inc., a
Delaware corporation (the "Company"), on March 27, 1998 to be effective as of
December 31, 1996.
R E C I T A L S:
---------------
A. The Company has assumed the sponsorship of the Triton Exploration
Services, Inc. 401(k) Savings Plan, as amended and/or restated (the "Plan");
and
B. The Board of Directors has adopted certain amendments to the Plan
effective as of December 31, 1996.
NOW, THEREFORE, the Plan is amended in the following respects:
1. Section 1.40 of the Plan be and it is hereby amended so that (1) the
reference to "Triton Energy Corporation" in the second paragraph thereof shall
instead be a reference to Triton Energy Limited, a Cayman Islands company, and
(2) each reference to "Employer" in clauses (a) through (d) in the fourth
paragraph thereof shall instead be a reference to Triton Energy Limited, a
Cayman Islands company.
2. Except as amended by the provisions of this Amendment, all other
provisions of the Plan remain in full force and effect.
IN WITNESS WHEREOF, Triton Exploration Services, Inc. has caused this
Amendment to be executed by its duly authorized officer effective as of
December 31, 1996.
TRITON EXPLORATION SERVICES, INC.
By:_________________________________
Robert B. Holland, III, Senior Vice
President
EXHIBIT 12.1
TRITON ENERGY LIMITED AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(IN THOUSANDS, EXCEPT RATIOS)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, YEAR ENDED DECEMBER 31,
------------------------ ---------------------------------
1998 1997 1997 1996 1995
----------- ----------- ---------- ---------- ---------
<S> <C> <C> <C> <C> <C>
Fixed charges, as defined
Interest charges $ 12,546 $ 11,641 $ 50,625 $ 43,884 $ 41,305
Preferred dividend requirements of
subsidiaries adjusted to pre-tax basis --- --- --- --- ---
----------- ----------- ---------- ---------- ---------
Total fixed charges $ 12,546 $ 11,641 $ 50,625 $ 43,884 $ 41,305
=========== =========== ========== ========== =========
Earnings, as defined (2):
Earnings (loss) from continuing operations
before income taxes, minority interest,
extraordinary item and cumulative effect of
accounting change $ 48,008 $ 4,413 $ 16,896 $ 20,945 $ 16,600
Fixed charges, above 12,546 11,641 50,625 43,884 41,305
Less interest capitalized (7,137) (6,361) (25,818) (27,102) (16,211)
Plus undistributed (earnings) loss of affiliates --- --- --- (118) 2,249
Less preferred dividend requirements of
subsidiaries adjusted to pre-tax basis --- --- --- --- ---
----------- ----------- ---------- ---------- ---------
$ 53,417 $ 9,693 $ 41,703 $ 37,609 $ 43,943
=========== =========== ========== ========== =========
RATIO OF EARNINGS TO FIXED CHARGES (1) (2) 4.3 0.8 0.8 0.9 1.1
=========== =========== ========== ========== =========
SEVEN MONTHS
ENDED
DEC. 31, YEAR ENDED MAY 31,
----------------------
1994 1994 1993
---------- ---------- ----------
<S> <C> <C> <C>
Fixed charges, as defined
Interest charges $ 20,285 $ 26,951 $ 16,336
Preferred dividend requirements of
subsidiaries adjusted to pre-tax basis --- 364 1,551
---------- ---------- ----------
Total fixed charges $ 20,285 $ 27,315 $ 17,887
========== ========== ==========
Earnings, as defined (2):
Earnings (loss) from continuing operations
before income taxes, minority interest,
extraordinary item and cumulative effect of
accounting change $ (22,834) $ (23,104) $(147,445)
Fixed charges, above 20,285 27,315 17,887
Less interest capitalized (11,833) (16,863) (6,407)
Plus undistributed (earnings) loss of affiliates 4,102 (645) 3,012
Less preferred dividend requirements of
subsidiaries adjusted to pre-tax basis --- (364) (1,551)
---------- ---------- ----------
$ (10,280) $ (13,661) $(134,504)
========== ========== ==========
RATIO OF EARNINGS TO FIXED CHARGES (1) (2) --- --- ---
========== ========== ==========
____________________
</TABLE>
(1) Earnings were inadequate to cover fixed charges for the three months
ended March 31, 1997 by $1,948,000, for the years ended December 31, 1997 and
1996 by $8,922,000 and $6,275,000, respectively, for the seven months ended
December 31, 1994 by $30,565,000 and for the years ended May 31, 1994 and 1993
by $40,976,000 and $152,391,000, respectively.
(2) Earnings reflect nonrecurring writedowns and loss provisions of
$46,153,000 and $1,058,000 for the years ended December 31, 1996 and 1995,
respectively, $984,000 for the seven months ended December 31, 1994 and
$45,754,000 and $99,883,000 for the years ended May 31, 1994 and 1993,
respectively. Nonrecurring gains from the sale of assets and other gains
aggregated $50,227,000 for the three months ended March 31, 1998, $6,253,000,
$22,189,000, $13,617,000 and $56,193,000 for the years ended December 31,
1997, 1996 and 1995 and May 31, 1994, respectively. The ratio of earnings to
fixed charges if adjusted to remove nonrecurring items, would have been 0.3
for the three months ended March 31, 1998, 0.7, 1.4 and 0.8 for the years
ended December 31, 1997, 1996 and 1995, respectively. Without nonrecurring
items, earnings would have been inadequate to cover fixed charges for the
three months ended March 31, 1998 by $9,356,000, for the years ended December
31, 1997 and 1995 by $15,175,000 and $9,921,000, respectively, for the seven
months ended December 31, 1994 by $29,581,000 and for the years ended May 31,
1994 and 1993 by $51,415,000 and $45,183,000, respectively.
EXHIBIT 12.2
TRITON ENERGY LIMITED AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERENCE
DIVIDENDS
(IN THOUSANDS, EXCEPT RATIOS)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, YEAR ENDED DECEMBER 31,
----------------------- -------------------------
1998 1997 1997 1996 1995
---------- ----------- ---------- ----------- ---------
<S> <C> <C> <C> <C> <C>
Fixed charges, as defined:
Interest charges $ 12,546 $ 11,641 $ 50,625 $ 43,884 $ 41,305
Preference dividend requirements of the Company 187 213 400 985 802
Preferred dividend requirements of subsidiaries
adjusted to pre-tax basis --- --- --- --- ---
---------- ----------- ---------- ----------- ---------
Total fixed charges $ 12,733 $ 11,854 $ 51,025 $ 44,869 $ 42,107
========== =========== ========== =========== =========
Earnings, as defined (2):
Earnings (loss) from continuing operations
before income taxes, minority interest,
extraordinary item and cumulative effect of
accounting change $ 48,008 $ 4,413 $ 16,896 $ 20,945 $ 16,600
Fixed charges, above 12,733 11,854 51,025 44,869 42,107
Less interest capitalized (7,137) (6,361) (25,818) (27,102) (16,211)
Plus undistributed (earnings) loss of affiliates --- --- --- (118) 2,249
Less preference dividend requirements of the
Company and its subsidiaries adjusted to
pre-tax basis (187) (213) (400) (985) (802)
---------- ----------- ---------- ----------- ---------
$ 53,417 $ 9,693 $ 41,703 $ 37,609 $ 43,943
========== =========== ========== =========== =========
RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERENCE DIVIDENDS (1) (2) 4.2 0.8 0.8 0.8 1.0
========== =========== ========== =========== =========
____________________
SEVEN MONTHS
ENDED YEAR ENDED MAY 31,
DEC. 31, -----------------------
1994 1994 1993
---------- ---------- -----------
<S> <C> <C> <C>
Fixed charges, as defined:
Interest charges $ 20,285 $ 26,951 $ 16,336
Preference dividend requirements of the Company 449 --- ---
Preferred dividend requirements of subsidiaries
adjusted to pre-tax basis --- 364 1,551
---------- ---------- -----------
Total fixed charges $ 20,734 $ 27,315 $ 17,887
========== ========== ===========
Earnings, as defined (2):
Earnings (loss) from continuing operations
before income taxes, minority interest,
extraordinary item and cumulative effect of
accounting change $ (22,834) $ (23,104) $ (147,445)
Fixed charges, above 20,734 27,315 17,887
Less interest capitalized (11,833) (16,863) (6,407)
Plus undistributed (earnings) loss of affiliates 4,102 (645) 3,012
Less preference dividend requirements of the
Company and its subsidiaries adjusted to
pre-tax basis (449) (364) (1,551)
---------- ---------- -----------
$ (10,280) $ (13,661) $ (134,504)
========== ========== ===========
RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERENCE DIVIDENDS (1) (2) --- --- ---
========== ========== ===========
____________________
</TABLE>
(1) Earnings were inadequate to cover combined fixed charges and
preference dividends for the three months ended March 31, 1997 by $2,161,000,
for the years ended December 31, 1997 and 1996 by $9,322,000 and $7,260,000,
respectively, for the seven months ended December 31, 1994 by $31,014,000 and
for the years ended May 31, 1994 and 1993 by $40,976,000 and $152,391,000,
respectively.
(2) Earnings reflect nonrecurring writedowns and loss provisions of
$46,153,000 and $1,058,000 for the years ended December 31, 1996 and 1995,
respectively, $984,000 for the seven months ended December 31, 1994 and
$45,754,000 and $99,883,000 for the years ended May 31, 1994 and 1993,
respectively. Nonrecurring gains from the sale of assets and other gains
aggregated $50,227,000 for the three months ended March 31, 1998, $6,253,000,
$22,189,000, $13,617,000 and $56,193,000 for the years ended December 31,
1997, 1996 and 1995 and May 31, 1994, respectively. The ratio of earnings to
combined fixed charges and preference dividends if adjusted to remove
nonrecurring items, would have been 0.3 for the three months ended March 31,
1998, 0.7, 1.4 and 0.7 for the years ended December 31, 1997, 1996 and 1995,
respectively. Without nonrecurring items, earnings would have been inadequate
to cover combined fixed charges and preference dividends for the three months
ended March 31, 1998 by $9,543,000, for the years ended December 31, 1997 and
1995 by $15,175,000 and $10,723,000, respectively, for the seven months ended
December 31, 1994 by $30,030,000 and for the years ended May 31, 1994 and 1993
by $51,415,000 and $45,183,000, respectively.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM MARCH 31,
1998 FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> MAR-31-1998
<CASH> 11,677
<SECURITIES> 0
<RECEIVABLES> 13,259
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 84,549
<PP&E> 979,774
<DEPRECIATION> 100,361
<TOTAL-ASSETS> 1,082,569
<CURRENT-LIABILITIES> 175,279
<BONDS> 473,608
0
7,492
<COMMON> 366
<OTHER-SE> 332,107
<TOTAL-LIABILITY-AND-EQUITY> 1,082,569
<SALES> 36,175
<TOTAL-REVENUES> 36,175
<CGS> 15,687
<TOTAL-COSTS> 15,687
<OTHER-EXPENSES> 12,079
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 5,166
<INCOME-PRETAX> 48,008
<INCOME-TAX> 5,096
<INCOME-CONTINUING> 42,912
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 42,912
<EPS-PRIMARY> 1.17
<EPS-DILUTED> 1.16
</TABLE>
EXHIBIT 99.1
HEADS OF AGREEMENT
BETWEEN
MALAYSIA-THAILAND JOINT AUTHORITY
AND
PETRONAS CARIGALI (JDA) SDN BHD
AND
TRITON OIL COMPANY OF THAILAND
AND
TRITON OIL COMPANY OF THAILAND (JDA) LIMITED
AS SELLERS
AND
PETROLIAM NASIONAL BERHAD
AND
PETROLEUM AUTHORITY OF THAILAND
AS BUYERS
FOR THE SUPPLY OF GAS
FROM THE BLOCK A-18 OF THE
MALAYSIA-THAILAND JOINT DEVELOPMENT AREA
April 1, 1998
PREAMBLE
--------
This Heads of Agreement (hereinafter referred to as "this GSA-HOA") is made
this 22nd day of April 1998 BETWEEN
the following parties collectively referred to as "the SELLERS".
1. MALAYSIA-THAILAND JOINT AUTHORITY with its principal office at 27th
Floor, City Square Centre, 182 Jalan Tun Razak, 50400 Kuala Lumpur, Malaysia,
(hereinafter referred to as "MTJA"),
2. PETRONAS CARIGALI (JDA) SDN BHD with its registered office at Tower 1,
PETRONAS Twin Towers, Persiaran KLCC, 50450 Kuala Lumpur, Malaysia
(hereinafter referred to as "CARIGALI"),
3. TRITON OIL COMPANY OF THAILAND with its principal place of business at
7th. Fl. Kian Gwan Bldg. 1, 140 Wireless Road, Bangkok 10330, Thailand, and
4. TRITON OIL COMPANY OF THAILAND (JDA) LIMITED with its registered
address at Suite 13.01, Menara Tan & Tan, 207, Jalan Tun Razak, 50400 Kuala
Lumpur, Malaysia, (Triton Oil Company of Thailand and Triton Oil Company of
Thailand (JDA) Limited are hereinafter referred to collectively and treated as
one entity "TRITON")
AND WITH
The following parties of the other part who are collectively referred to as
"the BUYERS" and individually as "a BUYER"
1. PETROLIAM NASIONAL BERHAD with its principal office at Tower 1,
PETRONAS Twin Towers, Persiaran KLCC, 50450 Kuala Lumpur, Malaysia
(hereinafter referred to as "PETRONAS") and
2. PETROLEUM AUTHORITY OF THAILAND with its principal office at Head
Office Building, 555 Vibhavadi Rangsit Road, Chatuchak, Bangkok 10900,
Thailand or its successors or legal assigns (hereinafter referred to as
"PTT"),
MTJA, PETRONAS, PTT, CARIGALI and TRITON are hereinafter collectively referred
to as "Parties" and individually as "Party" as the context may require.
WHEREAS
1. MTJA on the 21st day of April 1994 entered into a Production Sharing
Contract (hereinafter referred to as "PSC") with CARIGALI and TRITON in
respect of Block A-18 (hereinafter referred to as the "Contract Area") of the
Malaysia-Thailand Joint Development Area (hereinafter referred to as "the
JDA") for the exploration and exploitation of petroleum resources in the
Contract Area.
2. CARIGALI and TRITON as joint operators have delegated their role as
operator to CARIGALI-TRITON OPERATING COMPANY SDN BHD (hereinafter referred to
as "CTOC") which has its principal place of business at Suite 5.01-5.03, 5th
Floor, Wisma Inai, Jalan Tun Razak, 50400 Kuala Lumpur, Malaysia.
3. Natural Gas reserves discovered in the Contract Area (hereinafter
referred to as "Gas") are anticipated to be developed under the PSC by 1st
quarter 2001 . According to the PSC, CARIGALI and TRITON as contractors
(hereinafter referred to as "PS Contractors") thereunder are required to
negotiate for the sale of the Gas on a joint-dedicated basis with MTJA.
4. As agreed between the BUYERS and the SELLERS through the Memorandum of
Understanding dated Thursday 30th May 1996, the BUYERS are desirous to
purchase the Gas from the SELLERS and the SELLERS are desirous of selling the
Gas to the BUYERS on terms and conditions to be agreed between the Parties on
the mutual understanding as set forth herein.
5. As agreed between the BUYERS through the Head of Agreement dated 19th
September 1997, the BUYERS intend to bring their respective 50% share of the
Gas purchased from the SELLERS back to their respective countries on terms and
conditions to be agreed between the BUYERS under a separate agreement.
NOW THE PARTIES HEREBY AGREE as follows:-
ARTICLE 1
---------
STATEMENT OF INTENT
-------------------
1.1 This GSA-HOA summarizes the understanding and intent of the SELLERS to
sell to the BUYERS and the intent of the BUYERS to purchase and receive from
the SELLERS, the Gas on terms and conditions to be agreed in accordance with
the main principles as set forth herein.
1.2 The Parties agree in good faith to take the actions outlined in this
GSA-HOA and subject to the mutual agreement of the Parties to enter into a gas
sales agreement or agreements ("the GSA") and any other documents necessary
for the sale and purchase of the Gas from the Contract Area.
END OF ARTICLE 1
----------------
<PAGE>
ARTICLE 2
---------
TERM OF THIS GSA-HOA
--------------------
2.1 This GSA-HOA shall become effective on the date of execution of this
GSA-HOA ("Effective Date") and shall, subject to the provisions of Article 2.2
continue in effect thereafter until June 1, 1998, unless extended by the
mutual agreement of the Parties.
.2.2 Any Party may withdraw from this GSA-HOA by giving the other Party
not less than thirty (30) days written notice without liability to the other
Parties.
END OF ARTICLE 2
----------------
<PAGE>
ARTICLE 3
---------
MAIN PRINCIPLES
---------------
It is agreed that the GSA will include the following main principles:
3.1.1 GAS SUPPLY
-----------
(a) Reserve Dedication
-------------------
The SELLERS agree to dedicate the entire gas reserves in the
Contract Area to be sold to the BUYERS for the duration of the GSA.
(b) Daily Contract Quantity (DCQ)
-------------------------------
and Contractual Delivery Capacity (CDC)
------------------------------------------
The SELLERS shall develop sufficient gas reserves in the Contract
Area to deliver Gas at a Daily Contract Quantity ("DCQ") and to maintain a
Contractual Delivery Capacity ("CDC") of 110 per cent of the DCQ for the
duration of the GSA. As between the BUYERS, it is intended that each BUYER
shall have an individual DCQ (DCQ*) and an individual CDC (CDC*) equal to
fifty (50) percent of the DCQ and CDC respectively.
(c) Start-Up Date
--------------
It is anticipated that deliveries of the Gas by the SELLERS to the
BUYERS will commence between March 1, 2001 and June 30, 2001 ("Start-Up
Date"). The Parties will establish a procedure in the GSA to determine the
timing of the Start-Up Date. The Parties shall use all commercially reasonable
efforts to cause the commencement of deliveries on the Start-Up Date.
(d) Supply Profile
---------------
(i) The Contract Area will be developed in a number of phases. The
initial DCQ will be fixed as set out in this paragraph (i). The DCQ at the
Contractual Delivery Date (CDD) will be 195 Million standard cubic feet per
day (Mmscf/d) and will increase in six or fewer months to 390 Mmscf/d and will
be maintained at that rate until the end of the 20th Contract Year.
(ii) The DCQ will be revised as set out in this paragraph (ii).
Pursuant to procedures to be detailed in the GSA, SELLERS will notify BUYERS
of a possible increase in DCQ and, subject to terms and timing to be defined
in the GSA, the Parties will mutually agree on the effective date for the
increased DCQ. The DCQ shall be determined by dividing the Field Reserves
(defined in Article 3.1.6) as last calculated by six thousand (6,000).
(iii) In the event the BUYERS do not wish to accept a possible
increase in the DCQ notified by the SELLERS to the BUYERS, the SELLERS shall
be free to sell Gas to third parties from that quantity of the Field Reserves
in excess of the quantity of Field Reserves needed to support the DCQ agreed
and accepted for the purpose of sale and purchase of Gas between the BUYERS
and SELLERS. Such release shall be subject to the SELLERS ensuring that the
DCQ agreed and accepted between the BUYERS and the SELLERS can be maintained
for the duration of the GSA.
(iv) SELLERS certify that as of December 31, 1997 the Field
Reserves are two decimal nine five (2.95) trillion standard cubic feet (Tscf)
inclusive of up to 23% Carbon Dioxide which is calculated based on the
certified reserves by third party of two decimal three six (2.36) Tscf
(Proved)
(e) Shortfall and Take-or-Pay Obligations
----------------------------------------
The SELLERS and BUYERS will within the GSA agree to a run-in period,
starting on the Start-Up Date, to test facilities before the CDD. The
"shortfall" obligations of the SELLERS and the "take or pay" obligations of
the BUYERS (hereinafter described) will commence in all events on the CDD.
The sum of a BUYER'S DCQ* in effect for each day in a year,
multiplied by zero decimal nine zero (0.90), reduced by agreed annual
maintenance, failure by SELLERS to deliver, and Force Majeure shall be called
the Net Annual Contract Quantity ("Net ACQ*") and the BUYER will be obligated
to take or pay for the Net ACQ* each year. The BUYER will have the right to
take free of charge quantities of the Gas paid for but not taken in subsequent
contract years after the BUYER has taken the Net ACQ* for that contract year
and will be subject to carry forward provisions.
In any Contract Year the BUYERS will set up a balancing mechanism in
respect of their obligations to take Gas from the SELLERS provided that; if
one BUYER cannot take Gas in the amount of the Net ACQ*, another will endeavor
to take the remaining Gas of the said BUYER'S Net ACQ* in order to fulfill
BUYERS' obligation.
The SELLERS will be obligated to be able to deliver Gas each day to
each BUYER up to the CDC* notwithstanding that the aggregate of such
requirements may exceed the Net ACQ*.
Failure to deliver the quantity of Gas properly notified by the
BUYERS, up to the CDC, on any day will result in a shortfall to supply the
Gas ("Shortfall") and default provisions will apply where BUYERS can recoup
such Shortfall from the next available deliveries at a discounted price
(Shortfall Price).
3.1.2 FACILITIES
----------
The SELLERS shall be committed to drill the necessary wells and design,
construct and operate those producing, handling and transporting facilities
necessary to deliver the Gas from the Contract Area to the outlet flange of a
metering station on the Central Processing Platform (CPP) in the Contract Area
(the "Delivery Point"). The SELLERS shall complete these activities in
sufficient time to commence deliveries of Gas at the Delivery Point conforming
to the quality specifications appended hereto as Appendix "A" by the Start-Up
Date.
The BUYERS shall complete the laying of the pipeline in sufficient time
to accept deliveries of Gas at the CDC rates and at a maximum delivery
pressure of 2000 psig by the Start-Up Date and shall install individual meters
to measure the receipt of Gas for each BUYER at the Delivery Point.
3.1.3 POINT OF SALE
---------------
(a) The Gas will be delivered and sold by the SELLERS at the Delivery
Point and custody, risk and title shall pass to the BUYERS at that point for
the Gas attributable to each BUYER.
(b) SELLERS shall indemnify BUYERS for all costs, taxes, royalties,
levies, imposts, charges or any other such costs or expenses imposed on or
attributable to the Gas before the BUYERS take custody and title of the Gas.
Each BUYER shall indemnify SELLERS for costs, taxes, royalties, levies,
imposts, charges or any other costs or expenses imposed on or attributable to
his share of the Gas after the BUYER takes custody and title to his share of
the Gas.
(c) The Gas delivered by the SELLERS to the BUYERS shall meet quality
and delivery pressure specifications. The BUYERS shall have the right to
reject Gas failing to meet Gas specifications and to recoup limited costs for
damages in the event off specification Gas is accepted or the SELLERS fail to
remedy the situation.
3.1.4 PRICE
-----
The Initial Base Price ("IBP") to be paid to the SELLERS for the Gas
received by the BUYERS at the points of sale will be 2.30 US dollars for each
one million Btu's of gross heating value of such Gas. Effective October 1st
immediately preceding the Start-Up Date and each October 1st throughout the
duration of the GSA, the IBP shall be adjusted by the following formula to
calculate the Current Price:
Normal Price (By) = IBP [0.25(CPIy/CPI)+0.25(OMy/OM)+0.35(Fy/F)+0.15]
Ceiling Price (Ay) = 1.1(IBP)(Fy/F)
Floor Price (Cy)=(IBP-$0.125)[0.25(CPIy/CPI)+0.25(OMy/OM)+0.2(Fy/F)+ 0.3]
Special Floor Price (Dy) = (Ay + Cy)/2
The Current Price shall be:
(i) By if Ay is greater than By and By is greater than Cy
(ii) Ay if By is greater than Ay and Ay is greater than Cy
(iii) Cy if Ay is greater than Cy and Cy is greater than By
(iv) Dy if Cy is greater than Ay
The price paid to the SELLERS by the BUYERS shall be the Current Price
until a cumulative zero decimal five (0.5) Tscf of Gas has been delivered from
the Contract Area by the SELLERS and paid for by the BUYERS. For deliveries
in excess of zero decimal five (0.5) Tscf of Gas until a cumulative one
decimal three (1.3) Tscf of Gas is delivered from the Contract Area and paid
for by the BUYERS, the Current Price will be multiplied by zero decimal nine
five (0.95) to obtain the price to be paid to the SELLERS by the BUYERS. For
deliveries from the Contract Area in excess of a cumulative one decimal three
(1.3) Tscf of Gas the Current Price shall be multiplied by zero decimal nine
zero (0.90) to obtain the price to be paid to the SELLERS by the BUYERS.
Fy = the arithmetic average of the figures last published for each month
of the calendar year immediately preceding the year in which prices have to
be adjusted in United States Dollars per barrel of medium fuel oil ex
Singapore from Shell Eastern Petroleum PTE Ltd., Esso Singapore PTE Ltd.,
Mobil Sales and Supply Corporation, Caltex Petroleum Corporation, BP Oil
International and Singapore Petroleum Corporation PTE Ltd. as published in
"Platts Oilgram Price Service".
F is agreed to be US$14.500000 per barrel
CPI = the arithmetic average of the figures published for each month of
the twelve (12) month period, inclusive, for the Consumer Price Index number
in the United States of America, all items, all urban consumers (CPI-U) on 100
basis for the calendar year 1982-1984 as published by the United States
Department of Labor, Bureau of Labor Statistics. "CPI" is agreed to be one
hundred forty seven decimal three six six six six seven (147.366667) for the
time period October 1, 1993 to September 30, 1994.
CPIy = the arithmetic average of the figures published as for CPI above
in respect of the twelve (12) Month period ending twelve (12) months prior to
the date on which the prices will be adjusted.
OM = the arithmetic average of the figures published for each month of
the twelve (12) Month period, inclusive, for the Producer Price Index for Oil
Field and Gas Field Machinery and Tools, Commodity Code No. 1191, based on
100 for the calendar year 1982 as published by the United States Department of
Labor, Bureau of Labor Statistics. OM is agreed to be one hundred ten decimal
zero eight three three three three (110.083333) for the base period October 1,
1993 through September 30, 1994.
OMy = the arithmetic average of the figures published as for OM above for
each Month of the twelve (12) Month period ending twelve (12) Months prior to
the date on which the prices will be adjusted.
3.1.5 DURATION
--------
The duration of the GSA shall be co-terminous with the duration remaining
in the PSC as at the Effective Date or any extension to the PSC unless
otherwise mutually agreed by the Parties.
3.1.6 REDETERMINATION OF RESERVES
-----------------------------
There will be a procedure in the GSA for determining initial and future
reserves ("Field Reserves") certified by independent expert for purposes of
establishing whether there are adequate reserves to meet the obligations of
the SELLERS and to establish second and subsequent phase DCQ and CDC in the
event the Parties do not mutually agree. In any redetermination, the
calculation of Field Reserves shall contain all proved reserves and no more
than 20% of the total Field Reserves shall be probable reserves.
3.1.7 FORCE MAJEURE
--------------
A Force Majeure clause will be included incorporating the concept of a
BUYER'S right to Force Majeure relief if Force Majeure events affect BUYER'S
customers and if the BUYER pro-rates the amount of relief required among all
of his relevant suppliers.
3.1.8 DISPUTES
--------
The GSA shall include provisions for resolving disputes by the use of
Experts or by Arbitration according to UNCITRAL rules.
3.2 GAS SALES AGREEMENT
---------------------
As soon as possible after the Effective Date the Parties shall in good
faith exercise their best endeavours to conclude the GSA setting forth all the
terms and conditions governing the sale and purchase of the Gas recognising
the rights and obligations of each BUYER with respect to fifty (50) percent of
the Gas. The Parties agree that the GSA shall include the terms of this
GSA-HOA, and such other terms and conditions customary for similar gas
purchase and sale transactions, including the following:
(i) Billing and Payment
(ii) Default
(iii) Force Majeure
(iv) Assignment
(v) Measurement
(vi) Commercial Dispute Arbitration
(vii) Technical Dispute Resolution
(viii) Applicable Law
(ix) Representatives
(x) Exchange of Information
(xi) Liabilities
END OF ARTICLE 3
----------------
<PAGE>
ARTICLE 4
---------
CONDITION PRECEDENT
-------------------
It is fully understood that this GSA-HOA is subject to:-
(a) A full and binding agreement being reached by the Parties on the full
GSA by June 1, 1998 unless mutually extended by the Parties.
(b) Confirmation and acceptance of this GSA-HOA by the Board, and where
required by Government, of each of the Parties by confirmed signature below.
END OF ARTICLE 4
----------------
<PAGE>
IN WITNESS WHEREOF, the Parties hereto have executed this HOA on 22nd day of
April 1998.
For: MALAYSIA-THAILAND JOINT AUTHORITY Date:
{Authorized Signature} {Witness}
For: PETRONAS CARIGALI (JDA) SDN BHD Date:
{Authorized Signature} {Witness}
For: TRITON OIL COMPANY OF THAILAND Date:
{Authorized Signature} {Witness}
For: TRITON OIL COMPANY OF THAILAND (JDA) LIMITED Date:
{Authorized Signature} {Witness}
For: PETROLEUM AUTHORITY OF THAILAND Date:
{Authorized Signature} {Witness}
For: PETROLIAM NASIONAL BERHAD Date:
{Authorized Signature} {Witness}
<PAGE>
Appendix A
Quality Specifications
1. Gas delivered under this Agreement shall at the Delivery Points:
(1) GENERAL - be commercially free from materials and dust or other
solid matter, liquid matter, waxes, gums and gumforming constituents which
might cause injury to or interference with proper operations of the lines,
meters, regulators or other appliances through which natural gas flows.
Sellers shall furnish, install, maintain and operate such drips, separators,
heaters and other devices as Sellers deem necessary or desirable to effect
compliance with this specification.
(2) WATER CONTENT - contain not more than seven pounds of water vapor
per one million (1,000,000) cubic feet (7 lbs/MMCF) of Gas.
(3) SULFUR - contain not more than five decimal one seven (5.17)
grains total sulfur per one hundred (100) cubic feet of Gas.
(4) HYDROGEN SULFIDE - contain not more than three decimal four five
(3.45) grains of hydrogen sulfide per one hundred (100) cubic feet of Gas, as
determined by the weighted average at all applicable delivery points.
(5) CARBON DIOXIDE - contain not more than twenty-three (23) mole
percent of carbon dioxide, as determined by the weighted average at all
applicable delivery points.
(6) OXYGEN - contain not more than zero decimal one (0.1) mole
percent of oxygen.
(7) HEATING VALUE - have a Gross Calorific Value not less than eight
hundred fifty (850) BTU per cubic foot and not more than eleven hundred fifty
(1,150) BTU per cubic foot.
(8) TEMPERATURE - shall have a temperature which is not less than
sixty degrees (60 degrees) Fahrenheit and not more than one hundred forty
degrees (140 degrees) Fahrenheit.
(9) MERCURY - contain not more than 50 micrograms per cubic meter, as
determined by the weighted average at all applicable delivery points.
2. Suitable standard test method and measuring instruments of
standard manufacture acceptable to both parties together with procedures for
checking and/or verification of the instruments shall be agreed between the
parties or be determined by an expert.
