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 SEPTEMBER 30, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
COMMISSION FILE NUMBER: 1-11675
TRITON ENERGY LIMITED
(Exact name of registrant as specified in its charter)
CAYMAN ISLANDS NONE
-------------------- -------------------
(State or other jurisdiction (I.R.S. Employer
of incorporation or Identification No.)
Organization)
CALEDONIAN HOUSE, JENNETT STREET, P.O. BOX 1043, GEORGE TOWN, GRAND CAYMAN,
CAYMAN ISLANDS
(Address of principal executive offices and zip code)
Registrant's telephone number, including area code: (345) 949-0050
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES X NO
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Number of Shares
Title of Each Class Outstanding at October 29, 1999
Ordinary Shares, par value $0.01 per share 35,752,920
-------------------------------
TRITON ENERGY LIMITED AND SUBSIDIARIES
INDEX
PART I. FINANCIAL INFORMATION PAGE NO.
--------
Item 1. Financial Statements
Condensed Consolidated Statements of Operations -
Three and nine months ended September 30, 1999 and 1998 2
Condensed Consolidated Balance Sheets -
September 30, 1999 and December 31, 1998 3
Condensed Consolidated Statements of Cash Flows -
Nine months ended September 30, 1999 and 1998 4
Condensed Consolidated Statement of Shareholders' Equity -
Nine months ended September 30, 1999 5
Notes to Condensed Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 21
Item 3. Quantitative and Qualitative Disclosures about Market Risk 32
PART II. OTHER INFORMATION
Item 3. Legal Proceedings 33
Item 5. Other Information 34
Item 6. Exhibits and Reports on Form 8-K 36
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------- ---------------------
1999 1998 1999 1998
-------- --------- --------- ----------
Sales and other operating revenues:
Oil and gas sales $67,295 $ 42,625 $176,087 $ 115,178
Gain on sale of oil and gas assets --- 63,237 --- 63,237
-------- --------- --------- ----------
67,295 105,862 176,087 178,415
-------- --------- --------- ----------
Costs and expenses:
Operating 20,198 18,299 58,360 55,067
General and administrative 5,587 6,405 15,365 20,589
Depreciation, depletion and amortization 14,748 13,812 45,404 38,695
Writedown of assets --- --- --- 182,672
Special charges 2,377 15,000 3,597 15,000
-------- --------- --------- ----------
42,910 53,516 122,726 312,023
-------- --------- --------- ----------
Operating income (loss) 24,385 52,346 53,361 (133,608)
Gain on sale of Triton Pipeline Colombia --- --- --- 50,227
Interest income 2,599 838 7,837 2,330
Interest expense, net (5,599) (6,785) (17,536) (17,105)
Other income, net 1,068 3,595 1,275 6,623
-------- --------- --------- ----------
(1,932) (2,352) (8,424) 42,075
-------- --------- --------- ----------
Earnings (loss) before income taxes 22,453 49,994 44,937 (91,533)
Income tax expense (benefit) 10,691 2,786 20,405 (31,591)
-------- --------- --------- ----------
Net earnings (loss) 11,762 47,208 24,532 (59,942)
Dividends on preference shares 181 181 14,126 368
-------- --------- --------- ----------
Earnings (loss) applicable to ordinary shares $11,581 $ 47,027 $ 10,406 $ (60,310)
======== ========= ========= ==========
Average ordinary shares outstanding 35,785 36,634 36,263 36,599
======== ========= ========= ==========
Basic earnings (loss) per ordinary share $ 0.32 $ 1.28 $ 0.29 $ (1.65)
======== ========= ========= ==========
Diluted earnings (loss) per ordinary share $ 0.20 $ 1.28 $ 0.29 $ (1.65)
======== ========= ========= ==========
See accompanying Notes to Condensed Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
ASSETS SEPTEMBER 30, DECEMBER 31,
1999 1998
----------------- -----------------
(UNAUDITED)
Current assets:
Cash and equivalents $ 202,518 $ 19,122
Trade receivables, net 25,360 9,554
Other receivables 25,022 48,415
Other assets 7,771 1,655
----------------- -----------------
Total current assets 260,671 78,746
Property and equipment, at cost, less accumulated depreciation
and depletion of $493,979 for 1999 and $451,986 for 1998 591,148 556,122
Deferred taxes and other assets 100,925 121,265
----------------- -----------------
$ 952,744 $ 756,133
================= =================
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term borrowings and current maturities of long-term debt $ 9,027 $ 19,027
Accounts payable and accrued liabilities 54,411 45,892
Deferred income 17,627 35,254
----------------- -----------------
Total current liabilities 81,065 100,173
Long-term debt, excluding current maturities 404,455 413,465
Deferred income taxes 7,328 4,169
Other 5,042 14,519
Shareholders' equity:
5% Preference shares, stated value $34.41 7,214 7,214
8% Preference shares, stated value $70.00 363,718 127,575
Ordinary shares, par value $0.01 358 366
Additional paid-in capital 546,243 575,863
Accumulated deficit (460,553) (485,085)
Accumulated other non-owner changes in shareholders' equity (2,126) (2,126)
----------------- -----------------
Total shareholders' equity 454,854 223,807
Commitments and contingencies (note 10) --- ---
----------------- -----------------
$ 952,744 $ 756,133
================= =================
The Company uses the full cost method to account for its oil and gas producing
activities.
See accompanying Notes to Condensed Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
(IN THOUSANDS)
(UNAUDITED)
1999 1998
--------- ----------
Cash flows from operating activities:
Net earnings (loss) $ 24,532 $ (59,942)
Adjustments to reconcile net earnings (loss) to net cash provided
by operating activities:
Depreciation, depletion and amortization 45,404 38,695
Additional proceeds from forward oil sale 30,000 ---
Amortization of deferred income (26,440) (26,440)
Gain on sale of oil and gas assets --- (63,237)
Gain on sale of Triton Pipeline Colombia --- (50,227)
Writedown of assets --- 182,672
Deferred income taxes 16,467 (34,250)
Gain on sale of other assets (605) (6,905)
Other 5,461 4,625
Changes in working capital pertaining to operating activities (26,504) 21,409
--------- ----------
Net cash provided by operating activities 68,315 6,400
--------- ----------
Cash flows from investing activities:
Capital expenditures and investments (74,315) (140,417)
Proceeds from sale of oil and gas assets --- 142,527
Proceeds from sale of Triton Pipeline Colombia --- 97,656
Proceeds from sale of other assets 2,372 21,170
Other 2,031 (2,421)
--------- ----------
Net cash provided (used) by investing activities (69,912) 118,515
--------- ----------
Cash flows from financing activities:
Proceeds from revolving lines of credit and long-term debt --- 152,531
Payments on revolving lines of credit and long-term debt (19,027) (350,178)
Issuances of 8% preference shares, net 217,805 116,825
Issuances of ordinary shares 376 2,485
Repurchase of ordinary shares (11,285) ---
Dividends paid on preference shares (3,071) (368)
Other (85) (1)
--------- ----------
Net cash provided (used) by financing activities 184,713 (78,706)
--------- ----------
Effect of exchange rate changes on cash and equivalents 280 (328)
--------- ----------
Net increase in cash and equivalents 183,396 45,881
Cash and equivalents at beginning of period 19,122 13,451
--------- ----------
Cash and equivalents at end of period $202,518 $ 59,332
========= ==========
See accompanying Notes to Condensed Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
NINE MONTHS ENDED SEPTEMBER 30, 1999
(IN THOUSANDS)
(UNAUDITED)
OWNER SOURCES OF SHAREHOLDERS' EQUITY:
5% PREFERENCE SHARES:
Balance at December 31, 1998 $ 7,214
Conversion of 5% preference shares ---
----------
Balance at September 30, 1999 7,214
----------
8% PREFERENCE SHARES:
Balance at December 31, 1998 127,575
Issuance of 3,177,500 shares at $70 per share 222,425
Stock dividend, 196,388 shares at $70 per share 13,747
Conversion of 8% preference shares (29)
----------
Balance at September 30, 1999 363,718
----------
ORDINARY SHARES:
Balance at December 31, 1998 366
Repurchase of shares (9)
Issuances under stock plans 1
----------
Balance at September 30, 1999 358
----------
ADDITIONAL PAID-IN CAPITAL:
Balance at December 31, 1998 575,863
Dividend, 8% preference shares (13,765)
Repurchase of ordinary shares (11,276)
Transaction costs for issuance of 8% preference shares (4,620)
Dividends, 5% preference shares (361)
Other 402
----------
Balance at September 30, 1999 546,243
----------
TOTAL OWNER SOURCES OF SHAREHOLDERS' EQUITY 917,533
----------
NON-OWNER SOURCES OF SHAREHOLDERS' EQUITY:
ACCUMULATED DEFICIT:
Balance at December 31, 1998 (485,085)
Net earnings 24,532
----------
Balance at September 30, 1999 (460,553)
----------
ACCUMULATED OTHER NON-OWNER CHANGES IN SHAREHOLDERS' EQUITY:
Balance at December 31, 1998 (2,126)
Other non-owner changes in shareholders' equity ---
----------
Balance at September 30, 1999 (2,126)
----------
TOTAL NON-OWNER SOURCES OF SHAREHOLDERS' EQUITY (462,679)
----------
TOTAL SHAREHOLDERS' EQUITY AT SEPTEMBER 30, 1999 $ 454,854
==========
See accompanying Notes to Condensed Consolidated Financial Statements.
TRITON ENERGY LIMITED
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS IN TABLES IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
1. GENERAL
Triton Energy Limited ("Triton") is an international oil and gas exploration and
production company. The term "Company" when used herein means Triton and its
subsidiaries and other affiliates through which the Company conducts its
business. The Company's principal properties, operations, and oil and gas
reserves are located in Colombia, Malaysia-Thailand and Equatorial Guinea. The
Company is exploring for oil and gas in these areas, as well as in southern
Europe, Africa, and the Middle East. All sales currently are derived from oil
and gas production in Colombia.
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 September 30, 1999, and the results of its operations for the three and nine
months ended September 30, 1999 and 1998, its cash flows for the nine months
ended September 30, 1999 and 1998, and shareholders' equity for the nine months
ended September 30, 1999. The results for the three and nine months ended
September 30, 1999, 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,
1998.
Certain other previously reported financial information has been reclassified to
conform to the current period's presentation.
2. 8% PREFERENCE SHARES ISSUANCE
In August 1998, the Company and HM4 Triton, L.P. ("HM4 Triton"), an affiliate
of Hicks, Muse, Tate & Furst Incorporated ("Hicks Muse"), entered into a stock
purchase agreement (the "Stock Purchase Agreement") that provided for a $350
million equity investment in the Company. The investment was effected in two
stages. At the closing of the first stage in September 1998 (the "First
Closing"), the Company issued to HM4 Triton 1,822,500 shares of 8% convertible
preference shares ("8% Preference Shares") for $70 per share (for proceeds of
$116.8 million, net of transaction costs). Pursuant to the Stock Purchase
Agreement, the second stage was effected through a rights offering for 3,177,500
shares of 8% Preference Shares at $70 per share, with HM4 Triton being obligated
to purchase any shares not subscribed. At the closing of the second stage, which
occurred on January 4, 1999 (the "Second Closing"), the Company issued an
additional 3,177,500 8% Preference Shares for proceeds totaling $217.8 million,
net of closing costs (of which, HM4 Triton purchased 3,114,863 shares).
Each 8% Preference Share is convertible at any time at the option of the holder
into four ordinary shares of the Company (subject to certain antidilution
protections). Holders of 8% Preference Shares are entitled to receive, when and
if declared by the Board of Directors, cumulative dividends at a rate per annum
equal to 8% of the liquidation preference of $70 per share, payable for each
semi-annual period ending June 30 and December 30 of each year. At the
Company's option, dividends may be paid in cash or by the issuance of additional
whole shares of 8% Preference Shares. If a dividend is to be paid in additional
shares, the number of additional shares to be issued in payment of the dividend
will be determined by dividing the amount of the dividend by $70, with amounts
in respect of any fractional shares to be paid in cash. The first dividend
period was the period from January 4, 1999, to June 30, 1999. The Company's
Board of Directors elected to pay the dividend for that period in additional
shares resulting in the issuance of 196,388 8% Preference Shares. The
declaration of a dividend in cash or additional shares for any period should not
be considered an indication as to whether the Board will declare dividends in
cash or additional shares in future periods. Holders of 8% Preference Shares
are entitled to vote with the holders of ordinary shares on all matters
submitted to the shareholders of the Company for a vote, with each 8% Preference
Share entitling its holder to a number of votes equal to the number of ordinary
shares into which it could be converted at that time.
3. FORWARD OIL SALE
In April 1999, the Company received substantially all of the remaining proceeds,
approximately $30 million, from the forward oil sale consummated in May 1995.
The delivery requirement under the forward oil sale will be completed March 31,
2000. The remaining deferred income is reported in current liabilities and will
be amortized as barrels are delivered through March 31, 2000.
4. SHARE REPURCHASE
In April 1999, the Company's Board of Directors authorized a share repurchase
program enabling the Company to repurchase up to ten percent of the Company's
36.7 million outstanding ordinary shares. Purchases of ordinary shares by the
Company began in April and may be made from time to time in the open market or
through privately negotiated transactions at prevailing market prices depending
on market conditions. The Company has no obligation to repurchase any of its
outstanding shares and may discontinue the share repurchase program at
management's discretion. As of September 30, 1999, the Company had purchased
948,300 ordinary shares for $11.3 million. The Company cancelled and returned
the repurchased ordinary shares to the status of authorized but unissued shares.
5. SPECIAL CHARGES
In September 1999, the Company recognized special charges totaling $2.4 million
related to the disposition of an asset.
In July 1998, the Company commenced a plan to restructure the Company's
operations, reduce overhead costs and substantially scale back
exploration-related expenditures. The plan contemplated the closing of foreign
offices in four countries, the elimination of approximately 105 positions, or
41% of the worldwide workforce, and the relinquishment or other disposal of
several exploration licenses. As a result of the restructuring, the Company
recognized special charges of $15 million during the third quarter of 1998 and
$3.3 million during the fourth quarter of 1998 for a total of $18.3 million. Of
the $18.3 million in special charges, $14.5 million related to the reduction in
workforce, and represented the estimated costs for severance, benefit
continuation and outplacement costs, which will be paid over a period of up to
two years according to the severance formula. A total of $2.1 million of
special charges related to the closing of foreign offices, and represented the
estimated costs of terminating office leases and the write-off of related
assets. The remaining special charges of $1.7 million primarily related to the
write-off of other surplus fixed assets resulting from the reduction in
workforce. At September 30, 1999, all of the positions had been eliminated, all
designated foreign offices had closed and twelve licenses had been relinquished,
sold or their commitments renegotiated. The Company expects to dispose of two
other licenses during 1999. Since July 1998, the Company has paid $11.8 million
in severance, benefit continuation and outplacement costs. As of September 30,
1999, no changes had been made to the Company's estimate of the total
restructuring expenditures to be incurred. At September 30, 1999, the remaining
liability related to the restructuring activities undertaken in 1998 was $2.3
million.
In March 1999, the Company accrued special charges of $1.2 million related to an
additional 15% reduction in the number of employees resulting from the
Company's continuing efforts to reduce costs. The special charges consisted of
$1 million for severance, benefit continuation and outplacement costs and $.2
million related to the write-off of surplus fixed assets. Since March 1999, the
Company has paid $.6 million in severance, benefit continuation and outplacement
costs. At September 30, 1999, the remaining liability related to the
restructuring activities undertaken in 1999 was $.4 million.
6. OTHER INCOME, NET
Other income, net is summarized as follows:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ ------------------
1999 1998 1999 1998
-------- -------- -------- --------
Change in fair market value of WTI
benchmark call options $ 4,214 $ 623 $ 6,569 $ 543
Equity swap (3,044) (2,146) (3,804) (2,900)
Foreign exchange gain (loss) 8 796 (2,657) 2,519
Gain (loss) on sale of other assets (199) 4,978 605 6,905
Other 89 (656) 562 (444)
-------- -------- -------- --------
$ 1,068 $ 3,595 $ 1,275 $ 6,623
======== ======== ======== ========
7. WRITEDOWN OF ASSETS
Writedown of assets in 1998 is summarized as follows:
NINE MONTHS ENDED
SEPTEMBER 30, 1998
-------------------
Evaluated oil and gas properties (SEC ceiling test) $ 105,354
Unevaluated oil and gas properties 73,890
Other assets 3,428
-------------------
$ 182,672
===================
In June 1998, the carrying amount of the Company's evaluated oil and gas
properties in Colombia was written down by $105.4 million ($68.5 million, net of
tax) through application of the full cost ceiling limitation as prescribed by
the Securities and Exchange Commission ("SEC"), principally as a result of a
decline in oil prices. No adjustments were made to the Company's reserves in
Colombia as a result of the decline in prices. The SEC ceiling test was
calculated using the June 30, 1998, West Texas Intermediate ("WTI") oil price of
$14.18 per barrel that, after a differential for Cusiana crude delivered at the
port of Covenas in Colombia, resulted in a net price of approximately $13 per
barrel.
In conjunction with the plan to restructure operations and scale back
exploration-related expenditures, the Company assessed its investments in
exploration licenses and determined that certain investments were impaired. As
a result, unevaluated oil and gas properties and other assets totaling $77.3
million ($72.6 million, net of tax) were expensed in June 1998. The writedown
included $27.2 million and $22.5 million related to exploration activity in
Guatemala and China, respectively. The remaining writedowns related to the
Company's exploration projects in certain other areas of the world.
8. ASSET DISPOSITIONS
In July 1998, the Company and Atlantic Richfield Company ("ARCO") signed an
agreement providing financing for the development of the Company's gas reserves
on Block A-18 of the Malaysia-Thailand Joint Development Area. Under terms of
the agreement, consummated in August 1998, the Company sold to a subsidiary of
ARCO for $150 million one-half of the shares of the subsidiary through which the
Company owned its 50% share of Block A-18. The Company received net proceeds of
$142 million and recorded a gain of $63.2 million in gain on the sale of oil and
gas assets.
The agreements also require ARCO to pay the future exploration and development
costs attributable to the Company's and ARCO's collective interest in Block
A-18, up to $377 million or until first production from a gas field, after which
the Company and ARCO would each pay 50% of such costs. Additionally, the
agreements require ARCO to pay the Company an additional $65 million each at
July 1, 2002, and July 1, 2005, if certain specific development objectives are
met by such dates, or $40 million each if the objectives are met within one year
thereafter. The agreements provide that the Company will recover its investment
in recoverable costs in the project, approximately $101 million, and that ARCO
will recover its investment in recoverable costs, on a first-in, first-out basis
from the cost-recovery portion of future production.
In February 1998, the Company sold Triton Pipeline Colombia, Inc. ("TPC"), a
wholly owned subsidiary that held the Company's 9.6% equity interest in the
Colombian pipeline company, Oleoducto Central S. A. ("OCENSA"), to an unrelated
third party (the "Purchaser") for $100 million. Net proceeds were approximately
$97.7 million. The sale resulted in a gain of $50.2 million.
In conjunction with the sale of TPC, the Company entered into an equity swap
with a creditworthy financial institution (the "Counterparty"). The equity swap
has a notional amount of $97 million and requires the Company to make quarterly
floating LIBOR-based payments on the notional amount to the Counterparty. In
exchange, the Counterparty is required to make payments to the Company
equivalent to 97% of the dividends TPC receives in respect of its equity
interest in OCENSA. The equity swap is carried in the Company's financial
statements at fair value during its term, which, as amended, will expire April
14, 2000. The value of the equity swap in the Company's financial statements is
equal to the estimated fair value of the shares of OCENSA owned by TPC. Because
there is no public market for the shares of OCENSA, the Company estimates their
value using a discounted cash flow model applied to the distributions expected
to be paid in respect of the OCENSA shares. The discount rate applied to the
estimated cash flows from the OCENSA shares is based on a combination of current
market rates of interest, a credit spread for OCENSA's debt, and a spread to
reflect the preferred stock nature of the OCENSA shares. During the nine months
ended September 30, 1999 and 1998, the Company recorded an expense of $3.8
million and $2.9 million, respectively, in other income, net, related to the net
payments made (or received) under the equity swap and its change in fair value.
Net payments made (or received) under the equity swap, and any fluctuations in
the fair value of the equity swap, in future periods, will affect other income
in such periods. There can be no assurance that changes in interest rates, or
in other factors that affect the value of the OCENSA shares and/or the equity
swap, will not have a material adverse effect on the carrying value of the
equity swap.
Upon the expiration of the equity swap in April 2000, the Company expects that
the Purchaser will sell the TPC shares. Under the terms of the equity swap with
the Counterparty, upon any sale by the Purchaser of the TPC shares, the Company
will receive from the Counterparty, or pay to the Counterparty, an amount equal
to the excess or deficiency, as applicable, of the difference between 97% of the
net proceeds from the Purchaser's sale of the TPC shares and the notional amount
of $97 million. There can be no assurance that the value the Purchaser may
realize in any sale of the TPC shares will equal the value of the shares
estimated by the Company for purposes of valuing the equity swap. The Company
has no right or obligation to repurchase the TPC shares at any time, but the
Company is not prohibited from offering to purchase the shares when the
Purchaser offers to sell them.
9. EARNINGS PER ORDINARY SHARE
For the nine months ended September 30, 1998, the computation of diluted net
loss per ordinary share was antidilutive, and therefore, the amounts for basic
and diluted net loss per ordinary share were the same.
The following table reconciles the numerators and denominators of the basic and
diluted earnings per ordinary share computation for earnings from continuing
operations for the three and nine months ended September 30, 1999 and the three
months ended September 30, 1998.
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ----------
THREE MONTHS ENDED SEPTEMBER 30, 1998:
Net earnings $ 47,208
Less: Preference share dividends (181)
-----------
Earnings available to ordinary shareholders 47,027
Basic earnings per ordinary share 36,634 $ 1.28
==========
Effect of dilutive securities:
8% Preference shares --- 79
Stock options --- 59
5% Preference shares 181 212
----------- -------------
Earnings available to ordinary shareholders
and assumed conversions $ 47,208
===========
Diluted earnings per ordinary share 36,984 $ 1.28
============= ==========
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
THREE MONTHS ENDED SEPTEMBER 30, 1999:
Net earnings $ 11,762
Less: Preference share dividends (181)
-----------
Earnings available to ordinary shareholders 11,581
Basic earnings per ordinary share 35,785 $ 0.32
============= ==========
Effect of dilutive securities:
8% Preference shares --- 20,784
Stock options --- 62
----------- -------------
Earnings available to ordinary shareholders
and assumed conversions $ 11,581
===========
Diluted earnings per ordinary share 56,631 $ 0.20
============ ==========
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ----------
NINE MONTHS ENDED SEPTEMBER 30, 1999:
Net earnings $ 24,532
Less: Preference share dividends (14,126)
-----------
Earnings available to ordinary shareholders 10,406
Basic earnings per ordinary share 36,263 $ 0.29
============= ==========
Effect of dilutive securities:
Stock options --- 41
----------- -------------
Earnings available to ordinary shareholders
and assumed conversions $ 10,406
===========
Diluted earnings per ordinary share 36,304 $ 0.29
============= ==========
At September 30, 1999, 5,195,970 shares of 8% Preference Shares and
approximately 209,600 shares of 5% Preference Shares were outstanding. Each 8%
Preference Share is convertible any time into four ordinary shares, subject to
adjustment in certain events. Each 5% Preference Share is convertible any time
into one ordinary share, subject to adjustment in certain events. The 8%
Preference Shares and 5% Preference Shares were not included in the computation
of diluted earnings per ordinary share where the effect of assuming conversion
was antidilutive.
10. COMMITMENTS AND CONTINGENCIES
In January 1999, the Company approved a capital spending program for the year
ending December 31, 1999, of approximately $117 million, excluding capitalized
interest, of which approximately $83 million related to the Cusiana and Cupiagua
fields (the "Fields"), and $34 million related to the Company's exploration
activities in other parts of the world.
During the normal course of business, the Company is subject to the terms of
various operating agreements and capital commitments associated with the
exploration and development of its oil and gas properties. It is management's
belief that such commitments, including the capital requirements in Colombia and
other parts of the world discussed above, will be met without any material
adverse effect on the Company's operations or consolidated financial condition.
See Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Requirements.
GUARANTEES
At September 30, 1999, the Company had guaranteed loans of approximately $1.4
million for a Colombian pipeline company, Oleoducto de Colombia S.A., in which
the Company has an ownership interest. The Company also guaranteed performance
of $16.9 million in future exploration expenditures through September 2001 in
various countries. These commitments are backed primarily by unsecured letters
of credit.
LITIGATION
In July through October 1998, eight lawsuits were filed against the Company and
Thomas G. Finck and Peter Rugg, in their capacities as Chairman and Chief
Executive Officer and Chief Financial Officer, respectively. The lawsuits were
filed in the United States District Court for the Eastern District of Texas,
Texarkana Division, and have been consolidated and are styled In re: Triton
Energy Limited Securities Litigation. They allege violations of Sections 10(b)
and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5
promulgated thereunder, and negligent misrepresentation in connection with
disclosures concerning the Company's properties, operations, and value relating
to a prospective sale of the Company or of all or a part of its assets. The
lawsuits seek recovery of an unspecified amount of compensatory and punitive
damages and fees and costs.
On September 29, 1999, the court granted the plaintiffs' motion for appointment
as lead plaintiffs and for approval of selection of lead counsel. In addition,
the court denied the Company's motion to dismiss or transfer for improper venue.
On October 14, 1999, the Company filed a motion to dismiss the lawsuits for
failure to state a claim.
The Company believes its disclosures have been accurate and intends to
vigorously defend these actions. There can be no assurance that the litigation
will be resolved in the Company's favor. An adverse result could have a material
adverse effect on the Company's financial position or results of operations.
On August 22, 1997, the Company was sued in the Superior Court of the State of
California for the County of Los Angeles, by David A. Hite, Nordell
International Resources Ltd., and International Veronex Resources, Ltd. The
Company and the plaintiffs were adversaries in a 1990 arbitration proceeding in
which the interest of Nordell International Resources Ltd. in the Enim oil field
in Indonesia was awarded to the Company (subject to a 5% net profits interest
for Nordell) and Nordell was ordered to pay the Company nearly $1 million. The
arbitration award was followed by a series of legal actions by the parties in
which the validity of the award and its enforcement were at issue. As a result
of these proceedings, the award was ultimately upheld and enforced.
The current suit alleges that the plaintiffs were damaged in amounts aggregating
$13 million primarily because of the Company's prosecution of various claims
against the plaintiffs as well as its alleged misrepresentations, infliction of
emotional distress, and improper accounting practices. The suit seeks specific
performance of the arbitration award, damages for alleged fraud and
misrepresentation in accounting for Enim field operating results, an accounting
for Nordell's 5% net profit interest, and damages for emotional distress and
various other alleged torts. The suit seeks interest, punitive damages and
attorneys fees in addition to the alleged actual damages. On September 26, 1997,
the Company removed the action to the United States District Court for the
Central District of California. On August 31, 1998, the district court dismissed
all claims asserted by the plaintiffs other than claims for malicious
prosecution and abuse of the legal process, which the court held could not be
subject to a motion to dismiss. The abuse of process claim was later withdrawn,
and the damages sought were reduced to approximately $700,000 (not including
punitive damages). The lawsuit was tried and the jury found in favor of the
plaintiffs and assessed compensatory damages against the Company in the amount
of approximately $700,000 and punitive damages in the amount of approximately
$11 million. The Company believes it has acted appropriately and intends to
appeal the verdict.
The Company is also subject to litigation that is incidental to its business.
11. CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS
Certain information contained in this report, as well as written and oral
statements made or incorporated by reference from time to time by the Company
and its representatives in other reports, filings with the Securities and
Exchange Commission, press releases, conferences or otherwise, may be deemed to
be "forward-looking statements" within the meaning of Section 21E of the
Securities Exchange Act of 1934 and are subject to the "Safe Harbor" provisions
of that section. Forward-looking statements include statements concerning the
Company's and management's plans, objectives, goals, strategies and future
operations and performance and the assumptions underlying such forward-looking
statements. Forward-looking statements may be identified, without limitation,
by the use of the words "anticipates," "estimates," "expects," "believes,"
"intends," "plans" and similar expressions. These statements include
information regarding drilling schedules; expected or planned production
capacity; the disposal of licenses; future production of the Fields; completion
of development and commencement of production in Malaysia-Thailand; the
Company's capital budget and future capital requirements; the Company's meeting
its future capital needs; future general and administrative expense and the
portion to be capitalized; 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; the estimated
fair value of derivative instruments, including the equity swap; the impact of
the renegotiation of the production sharing contract in Equatorial Guinea; and
proven oil and gas reserves and discounted future net cash flows therefrom.
These statements are based on current expectations and involve a number of risks
and uncertainties, including those described in the context of such
forward-looking statements, as well as those presented below. Actual results
and developments could differ materially from those expressed in or implied by
such statements due to these and other factors.
CERTAIN FACTORS RELATING TO THE OIL AND GAS INDUSTRY
The 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 acquisition
and 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
acquisition and 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, 1998, including capitalized
costs by geographic area, is set forth in note 22 of Notes to Consolidated
Financial Statements in Triton's Annual Report on Form 10-K for the year ended
December 31, 1998.
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, explosions, uncontrollable flows of
oil, gas or well fluids, pollution, earthquakes, formations with abnormal
pressures, labor disruptions and fires, each of which could result in
substantial losses to the Company due to injury or loss of life and damage to or
destruction of oil and gas wells, formations, production facilities or other
properties. In accordance with customary industry practices, the Company
maintains insurance coverage limiting financial loss resulting from certain of
these operating hazards. Losses and liabilities arising from uninsured or
underinsured events would reduce revenues and increase costs to the Company.
There can be no assurance that any insurance will be adequate to cover losses or
liabilities. The Company cannot predict the continued availability of
insurance, or its availability at premium levels that justify its purchase.
The Company's oil and gas business is also subject to laws, rules and
regulations in the countries where it operates, which generally pertain to
production control, taxation, environmental and pricing concerns, and other
matters relating to the petroleum industry. Many jurisdictions have at various
times imposed limitations on the production of natural gas and oil by
restricting the rate of flow for oil and natural-gas wells below their actual
capacity. There can be no assurance that present or future regulation will not
adversely affect the operations of the Company.
The Company is subject to extensive environmental laws and regulations. These
laws regulate the discharge of oil, gas or other materials into the environment
and may require the Company to remove or mitigate the environmental effects of
the disposal or release of such materials at various sites. In addition, the
Company could be held liable for environmental damages caused by previous owners
of its properties or its predecessors. The Company does not believe that its
environmental risks are materially different from those of comparable companies
in the oil and gas industry. Nevertheless, no assurance can be given that
environmental laws and regulations will not, in the future, adversely affect the
Company's consolidated results of operations, cash flows or financial position.
Pollution and similar environmental risks generally are not fully insurable.
CERTAIN FACTORS RELATING TO INTERNATIONAL OPERATIONS
The Company derives substantially all of its consolidated revenues from
international operations. Risks inherent in international operations include
the risk of expropriation, nationalization, war, revolution, border disputes,
renegotiation or modification of existing contracts, import, export and
transportation regulations and tariffs; taxation policies, including royalty and
tax increases and retroactive tax claims; exchange controls, currency
fluctuations and other uncertainties arising out of foreign government
sovereignty over the Company's international operations; laws and policies of
the United States affecting foreign trade, taxation and investment; and the
possibility of having to be subject to the exclusive jurisdiction of foreign
courts in connection with legal disputes and the possible inability to subject
foreign persons to the jurisdiction of courts in the United States. To date,
the Company's international operations have not been materially affected by
these risks.
CERTAIN FACTORS RELATING TO COLOMBIA
The Company is a participant in significant oil and gas discoveries in the
Fields, located approximately 160 kilometers (100 miles) northeast of Bogota,
Colombia. Development of reserves in the Fields is ongoing and will require
additional drilling. Pipelines connect the major producing fields in Colombia
to export facilities and to refineries.
From time to time, guerrilla activity in Colombia has disrupted the operation of
oil and gas projects causing increased costs. Such activity increased over the
last few years, 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. Although the President granted Colombia certification in
1999, Colombia was denied certification in the last two years and only received
a national interest waiver for one of those years. There can be no assurance
that, in the future, Colombia will receive certification or a national interest
waiver. The consequences of the failure to receive certification or a national
interest waiver generally include the following: all bilateral aid, except
anti-narcotics and humanitarian aid, would be suspended; the Export-Import Bank
of the United States and the Overseas Private Investment Corporation would not
approve financing for new projects in Colombia; U.S. representatives at
multilateral lending institutions would be required to vote against all loan
requests from Colombia, although such votes would not constitute vetoes; and the
President of the United States and Congress would retain the right to apply
future trade sanctions. Each of these consequences could result in adverse
economic consequences in Colombia and could further heighten the political and
economic risks associated with the Company's operations in Colombia. Any
changes in the holders of significant government offices could have adverse
consequences on the Company's relationship with the Colombian national oil
company and the Colombian government's ability to control guerrilla activities
and could exacerbate the factors relating to foreign operations discussed above.
CERTAIN FACTORS RELATING TO MALAYSIA-THAILAND
The Company is a partner in a significant gas exploration project located in the
Gulf of Thailand approximately 450 kilometers (280 miles) northeast of Kuala
Lumpur and 750 kilometers (470 miles) south of Bangkok as a contractor under a
production-sharing contract covering Block A-18 of the Malaysia-Thailand Joint
Development Area. On October 30, 1999, the Company and the other parties to the
production-sharing contract for Block A-18 executed a gas sales agreement
providing for the sale of the first phase of gas. First sales are scheduled to
commence approximately 20 to 24 months following completion and approval of an
environmental impact assessment associated with the buyers' pipeline and
processing facilities. No assurance can be given as to when such approval will
be obtained. A lengthy approval process, or significant opposition to the
project, could delay construction and the commencement of gas sales.
In connection with the sale to ARCO of one-half of the shares through which the
Company owned its interest in Block A-18, ARCO agreed to pay the future
exploration and development costs attributable to the Company's and ARCO's
collective interest in Block A-18, up to $377 million or until first production
from a gas field. There can be no assurance that the Company's and ARCO's
collective share of the cost of developing the project will not exceed $377
million. ARCO also agreed to pay the Company certain incentive payments if
certain criteria were met. The first $65 million in incentive payments is
conditioned upon having the production facilities for the sale of gas from Block
A-18 completed by June 30, 2002. If the facilities are completed after June 30,
2002 but before June 30, 2003, the incentive payment would be reduced to $40
million. A lengthy environmental approval process, or unanticipated delays in
construction of the facilities, could result in the Company's receiving a
reduced incentive payment or possibly the complete loss of the first incentive
payment. In addition, the Company has agreed to share with ARCO some of the risk
that the environmental approval might be delayed by agreeing to pay to ARCO
$1.25 million per month for each month, if applicable, that first gas sales are
delayed beyond 30 months following the commitment to an engineering, procurement
and construction contract for the project. The Company's obligation is capped
at 24 months of these payments.
INFLUENCE OF HICKS MUSE
In connection with the issuance of 8% Preference Shares to HM4 Triton, the
Company and HM4 Triton entered into a shareholders agreement (the "Shareholders
Agreement") pursuant to which, among other things, the size of the Company's
Board of Directors was set at ten, and HM4 Triton exercised its right to
designate four out of such ten directors. The Shareholders Agreement provides
that, in general, for so long as the entire Board of Directors consists of ten
members, HM4 Triton (and its designated transferees, collectively) may designate
four nominees for election to the Board (with such number of designees
increasing or decreasing proportionately with any change in the total number of
members of the Board and with any fractional directorship rounded up to the next
whole number). The right of HM4 Triton (and its designated transferees) to
designate nominees for election to the Board will be reduced if the number of
ordinary shares held by HM4 Triton and its affiliates (assuming conversion of
8% Preference Shares into ordinary shares) represents less than certain
specified percentages of the number of ordinary shares (assuming conversion of
8% Preference Shares into ordinary shares) purchased by HM4 Triton pursuant to
the Stock Purchase Agreement.
The Shareholders Agreement provides that, for so long as HM4 Triton and its
affiliates continue to hold a certain minimum number of ordinary shares
(assuming conversion of 8% Preference Shares into ordinary shares), the Company
may not take certain actions without the consent of HM4 Triton, including (i)
amending its Articles of Association or the terms of the 8% Preference Shares
with respect to the voting powers, rights or preferences of the holders of 8%
Preference Shares, (ii) entering into a merger or similar business combination
transaction, or effecting a reorganization, recapitalization or other
transaction pursuant to which a majority of the outstanding ordinary shares or
any 8% Preference Shares are exchanged for securities, cash or other property,
(iii) authorizing, creating or modifying the terms of any series of securities
that would rank equal to or senior to the 8% Preference Shares, (iv) selling or
otherwise disposing of assets comprising in excess of 50% of the market value of
the Company, (v) paying dividends on ordinary shares or other shares ranking
junior to the 8% Preference Shares, other than regular dividends on the
Company's 5% Preference Shares, (vi) incurring or guaranteeing indebtedness
(other than certain permitted indebtedness), or issuing preference shares,
unless the Company's leverage ratio at the time, after giving pro forma effect
to such incurrence or issuance and to the use of the proceeds, is less than 2.5
to 1, (vii) issuing additional shares of 8% Preference Shares, other than in
payment of accumulated dividends on the outstanding 8% Preference Shares, (viii)
issuing any shares of a class ranking equal or senior to the 8% Preference
Shares, (ix) commencing a tender offer or exchange offer for all or any portion
of the ordinary shares or (x) decreasing the number of shares designated as 8%
Preference Shares.
As a result of HM4 Triton's ownership of 8% Preference Shares and ordinary
shares and the rights conferred upon HM4 Triton and its designees pursuant to
the Shareholder Agreement, HM4 Triton has significant influence over the actions
of the Company and will be able to influence, and in some cases determine, the
outcome of matters submitted for approval of the shareholders. The existence of
HM4 Triton as a shareholder of the Company may make it more difficult for a
third party to acquire, or discourage a third party from seeking to acquire, a
majority of the outstanding ordinary shares. A third party would be required to
negotiate any such transaction with HM4 Triton, and the interests of HM4 Triton
as a shareholder may be different from the interests of the other shareholders
of the Company.
POSSIBLE FUTURE ACQUISITIONS
The Company's strategy includes the possible acquisition of additional reserves,
including through possible future business combination transactions. There can
be no assurance as to the terms upon which any such acquisitions would be
consummated or as to the affect any such transactions would have on the
Company's financial condition or results of operations. Such acquisitions, if
any, could involve the use of the Company's cash, or the issuance of the
Company's debt or equity securities, which could have a dilutive effect on the
current shareholders.
To facilitate a possible future securities issuance or issuances, the Company
has filed with the Securities and Exchange Commission a shelf registration
statement under which the Company could issue up to an aggregate of $250 million
debt or equity securities when the registration statement becomes effective.
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.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL REQUIREMENTS
----------------------------------
Cash and cash equivalents totaled $202.5 million and $19.1 million at
September 30, 1999, and December 31, 1998, respectively. Working capital
(deficit) was $179.6 million at September 30, 1999, compared with ($21.4
million) at December 31, 1998. Current liabilities included deferred income
totaling $17.6 million at September 30, 1999 and $35.3 million at December 31,
1998 related to a forward oil sale consummated in 1995.
The following summary table reflects cash flows for the Company for the
nine months ended September 30, 1999 (in thousands):
Net cash provided (used) by operating activities $68,315
Net cash provided (used) by investing activities $(69,912)
Net cash provided (used) by financing activities $184,713
Operating Activities
--------------------
The Company's cash flows provided by operating activities for the nine
months ended September 30, 1999, benefited from increased production from the
Cusiana and Cupiagua fields (the "Fields") in Colombia and an increased average
realized oil price. Gross production from the Fields averaged 434,000 barrels
of oil per day ("BOPD") during the first nine months of 1999, compared with
324,000 BOPD during the first nine months of 1998. The average realized oil
price increased $2.00 per barrel compared to the same period in 1998. See
"Results of Operations." For the year 2000, based on estimates of the operator
of the Cusiana and Cupiagua Fields, the Company anticipates oil production, net
to Triton, of approximately 14 million barrels.
In April 1999, the Company received substantially all of the remaining
proceeds (approximately $30 million) from the forward oil sale in May 1995,
which was included in other receivables at December 31, 1998.
Investing Activities
---------------------
The Company's capital expenditures and other capital investments were $74.3
million ($63.8 million excluding capitalized interest) for the nine months ended
September 30, 1999, primarily for development of the Fields.
Financing Activities
---------------------
In August 1998, the Company and HM4 Triton, L.P. ("HM4 Triton"), an
affiliate of Hicks, Muse, Tate & Furst Incorporated ("Hicks Muse"), entered into
a stock purchase agreement (the "Stock Purchase Agreement") that provided for a
$350 million equity investment in the Company. The investment was effected in
two stages. At the closing of the first stage in September 1998 (the "First
Closing"), the Company issued to HM4 Triton 1,822,500 shares of 8% convertible
preference shares ("8% Preference Shares") for $70 per share (for proceeds of
$116.8 million, net of transaction costs). Pursuant to the Stock Purchase
Agreement, the second stage was effected through a rights offering for 3,177,500
shares of 8% Preference Shares at $70 per share, with HM4 Triton being obligated
to purchase any shares not subscribed. At the closing of the second stage, which
occurred on January 4, 1999 (the "Second Closing"), the Company issued an
additional 3,177,500 8% Preference Shares for proceeds totaling $217.8 million,
net of closing costs (of which, HM4 Triton purchased 3,114,863 shares).
Each 8% Preference Share is convertible at any time at the option of the
holder into four ordinary shares of the Company (subject to certain antidilution
protections). Holders of 8% Preference Shares are entitled to receive, when and
if declared by the Board of Directors, cumulative dividends at a rate per annum
equal to 8% of the liquidation preference of $70.00 per share, payable for each
semi-annual period ending June 30 and December 30 of each year. At the
Company's option, dividends may be paid in cash or by the issuance of additional
whole shares of 8% Preference Shares. If a dividend is to be paid in additional
shares, the number of additional shares to be issued in payment of the dividend
will be determined by dividing the amount of the dividend by $70, with amounts
in respect of any fractional shares to be paid in cash. The first dividend
period was the period from January 4, 1999, to June 30, 1999. The Company's
Board of Directors elected to pay the dividend for that period in additional
shares resulting in the issuance of 196,388 8% Preference Shares. The
declaration of a dividend in cash or additional shares for any period should not
be considered an indication as to whether the Board will declare dividends in
cash or additional shares in future periods.
In April 1999, the Company's Board of Directors authorized a share
repurchase program enabling the Company to repurchase up to ten percent of the
Company's 36.7 million outstanding ordinary shares. Purchases of ordinary
shares by the Company began in April and may be made from time to time in the
open market or through privately negotiated transactions at prevailing market
prices depending on market conditions. The Company has no obligation to
repurchase any of its outstanding shares and may discontinue the share
repurchase program at management's discretion. As of September 30, 1999, the
Company had purchased 948,300 ordinary shares for $11.3 million.
During the nine months ended September 30, 1999, the Company repaid
borrowings totaling $19 million, including $10 million under unsecured credit
facilities that were outstanding at December 31, 1998. At September 30, 1999,
all of the Company's unsecured credit facilities had expired.
Future Capital Needs
----------------------
In January 1999, prior to a discovery in Equatorial Guinea, the Company
approved a capital spending program for the year ending December 31, 1999, of
approximately $117 million, excluding capitalized interest, of which
approximately $83 million related to the Cusiana and Cupiagua Fields ($57.2
million through September 30), and $34 million related to the Company's
exploration activities in other parts of the world ($6.6 million through
September 30). Development of the Cusiana and Cupiagua Fields, including
drilling and construction of ancillary production enhancement facilities, will
require further capital outlays. The Company expects capital spending to
increase in the fourth quarter, primarily as a result of activity in Equatorial
Guinea. The Company is continuing its efforts to reduce exploration related
capital expenditures in other areas. The Company expects to fund these capital
requirements for 1999 with cash flow from operations and cash.
On October 30, 1999, the Company and the other parties to the
production-sharing contract for Block A-18 executed a gas sales agreement
providing for the sale of the first phase of gas. First sales are scheduled to
commence approximately 20 to 24 months following completion and approval of an
environmental impact assessment associated with the buyers' pipeline and
processing facilities. No assurance can be given as to when such approval will
be obtained. In connection with the sale to ARCO of one-half of the shares
through which the Company owned its interest in Block A-18, ARCO agreed to pay
the future exploration and development costs attributable to the Company's and
ARCO's collective interest in Block A-18, up to $377 million or until first
production from a gas field. See "Certain Factors Relating to
Malaysia-Thailand" in note 11 of Notes to Condensed Consolidated Financial
Statements.
In October 1999, the Company announced that it had made a potentially
significant oil discovery with the Ceiba-1 well in Block G in Equatorial Guinea.
The Company spudded an appraisal well, Ceiba-2, in October 1999, and plans to
acquire a 3D seismic survey over 880,000 acres (3,600 square kilometers) to
define the field and prove up other exploration prospects on the licenses for
drilling next year. If the appraisal program is successful, the Company plans to
institute a strategy to develop the Ceiba Field, and further explore the
Equatorial Guinea licenses, including the drilling of additional wells and the
construction of offshore production facilities. The Company believes that its
strategy will require significant capital outlays commencing in the year 2000,
although the magnitude of the capital requirements cannot be predicted until
further appraisal is conducted.
In conjunction with the sale of Triton Pipeline Colombia, Inc. ("TPC") to
an unrelated third party (the "Purchaser") in February 1998, the Company entered
into a five year equity swap with a creditworthy financial institution (the
"Counterparty"). The issuance to HM4 Triton of the 8% Preference Shares resulted
in the right of the Counterparty to terminate the equity swap prior to the end
of its five year term. In January 1999, the Counterparty exercised its right and
designated April 2000 as the termination date of the equity swap. Upon the
expiration of the equity swap in April 2000, the Company expects that the
Purchaser will sell the TPC shares. Under the terms of the equity swap with the
Counterparty, upon any sale by the Purchaser of the TPC shares, the Company will
receive from the Counterparty, or pay to the Counterparty, an amount equal to
the excess or deficiency, as applicable, of the difference between 97% of the
net proceeds from the Purchaser's sale of the TPC shares and the notional amount
of $97 million. There can be no assurance that the value the Purchaser may
realize in any sale of the TPC shares will equal the value of the shares
estimated by the Company for purposes of valuing the equity swap. The Company
has no right or obligation to repurchase the TPC shares at any time, but the
Company is not prohibited from offering to purchase the shares if the Purchaser
offers to sell them. See "- Results of Operations - Other Income and Expenses"
below, note 8 of Notes to Condensed Consolidated Financial Statements, and "Item
7A. Quantitative and Qualitative Disclosures about Market Risk" in Triton's
Annual Report on Form 10-K for the year ended December 31, 1998.
At September 30, 1999, the Company had guaranteed loans of approximately $1.4
million, which expire September 2000, for a Colombian pipeline company,
Oleoducto de Colombia S.A., in which the Company has an ownership interest. The
Company also guaranteed performance of $16.9 million in future exploration
expenditures through September 2001 in various countries. These commitments are
backed primarily by unsecured letters of credit.
The Company expects its capital spending program in the year 2000 to exceed 1999
levels, with the majority of the funds directed towards the Ceiba Field and
exploration of the Equatorial Guinea licenses. The Company expects to fund 2000
capital spending with a combination of some or all of the following: cash flow
from operations, cash, future credit facilities to be negotiated, and the
issuance of debt or equity securities. To facilitate a possible future
securities issuance or issuances, the Company has filed with the Securities and
Exchange Commission ("SEC") a shelf registration statement under which the
Company could issue up to an aggregate of $250 million debt or equity securities
when the registration statement becomes effective.
RESULTS OF OPERATIONS
---------------------
Sales volumes and average prices realized were as follows:
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ ------------------
1999 1998 1999 1998
------- ------ ------- ------
Sales volumes:
Oil (MBbls), excluding forward oil sale 3,091 2,620 9,481 6,585
Forward oil sale (MBbls delivered) 762 762 2,287 2,287
------- ------ ------- -------
Total 3,853 3,382 11,768 8,872
======= ====== ======= =======
Gas (MMcf) 121 109 336 376
Weighted average price realized:
Oil (per Bbl) (1) $ 17.44 $12.57 $ 14.94 $ 12.94
Gas (per Mcf) $ 0.88 $ 0.91 $ 0.88 $ 1.01
<FN>
(1) Includes the effect of barrels delivered under the forward oil sale
that are recognized in revenue at $11.56 per barrel.
THREE MONTHS ENDED SEPTEMBER 30, 1999,
COMPARED WITH THREE MONTHS ENDED SEPTEMBER 30, 1998
Sales and Other Operating Revenues
--------------------------------------
Oil and gas sales for the third quarter of 1999 totaled $67.3 million, a
58% increase from the third quarter of 1998, due to higher average realized oil
prices and higher production. The average realized oil price increased $4.87
per barrel, or 39%, resulting in an increase in revenues of $18.7 million
compared to the same period in 1998. Oil production, including production
related to barrels delivered under the forward oil sale, increased 14% in third
quarter 1999, compared to the prior-year quarter, resulting in an increase in
revenues of $5.9 million. Gross production from the Fields averaged 433,000
BOPD for the third quarter 1999, compared to 359,000 BOPD for the prior-year
quarter. The increased production was primarily due to the start-up in late
1998 of two 100,000 BOPD oil-production units at the Cupiagua central processing
facility.
As a result of financial and commodity market transactions settled during
the three months ended September 30, 1999, the Company's risk management program
resulted in lower revenues of approximately $9.6 million than if the Company had
not entered into such transactions. Additionally, the Company has hedged its
WTI price on a significant portion of its remaining projected 1999 oil
production. See "Item 3. Quantitative and Qualitative Disclosures about Market
Risk."
In August 1998, the Company sold to a subsidiary of ARCO for $150 million,
one-half of the shares of the subsidiary through which the Company owned its 50%
share of Block A-18 in the Malaysia-Thailand Joint Development Area. The sale
resulted in an aftertax gain of $63.2 million.
Costs and Expenses
--------------------
Operating expenses increased $1.9 million in 1999 and depreciation,
depletion and amortization increased $.9 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, which include field
operating expenses, pipeline tariffs and production taxes, improved from $5.76
in 1998, to $5.28 in 1999, primarily due to higher production volumes.
Oleoducto Central S.A. ("OCENSA") pipeline tariffs totaled $13.9 million or
$3.66 per barrel, and $12.6 million or $3.99 per barrel in 1999 and 1998,
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.
General and administrative expense before capitalization decreased $3.8
million, or 35%, to $7.1 million in 1999. Capitalized general and
administrative costs were $1.5 million and $4.5 million in 1999 and 1998,
respectively. General and administrative expenses, and the portion capitalized,
decreased as a result of restructuring activities undertaken during the second
half of 1998 and March 1999.
In September 1999, the Company recognized special charges totaling $2.4
million related to the disposition of an asset.
In July 1998, the Company commenced a plan to restructure the Company's
operations, reduce overhead costs and substantially scale back
exploration-related expenditures. The plan contemplated the closing of foreign
offices in four countries, the elimination of approximately 105 positions, or
41% of the worldwide workforce, and the relinquishment or other disposal of
several exploration licenses. As a result of the restructuring, the Company
recognized special charges of $15 million during the third quarter of 1998 and
$3.3 million during the fourth quarter of 1998 for a total of $18.3 million. Of
the $18.3 million in special charges, $14.5 million related to the reduction in
workforce, and represented the estimated costs for severance, benefit
continuation and outplacement costs, which will be paid over a period of up to
two years according to the severance formula. A total of $2.1 million of
special charges related to the closing of foreign offices, and represented the
estimated costs of terminating office leases and the write-off of related
assets. The remaining special charges of $1.7 million primarily related to the
write-off of other surplus fixed assets resulting from the reduction in
workforce. At September 30, 1999, all of the positions had been eliminated, all
designated foreign offices had closed and twelve licenses had been relinquished,
sold or their commitments renegotiated. The Company expects to dispose of two
other licenses during 1999. Since July 1998, the Company has paid $11.8 million
in severance, benefit continuation and outplacement costs. As of September 30,
1999, no changes had been made to the Company's estimate of the total
restructuring expenditures to be incurred. At September 30, 1999, the remaining
liability related to the restructuring activities undertaken in 1998 was $2.3
million.
In March 1999, the Company accrued special charges of $1.2 million related
to an additional 15% reduction in the number of employees resulting from the
Company's continuing efforts to reduce costs. The special charges consisted of
$1 million for severance, benefit continuation and outplacement costs and $.2
million related to the write-off of surplus fixed assets. Since March 1999, the
Company has paid $.6 million in severance, benefit continuation and outplacement
costs. At September 30, 1999, the remaining liability related to the
restructuring activities undertaken in 1999 was $.4 million.
Other Income and Expenses
----------------------------
Gross interest expense for 1999 and 1998 totaled $9.2 million and $11.9
million, respectively, while capitalized interest for 1999 decreased $1.5
million to $3.6 million. The decrease in gross interest expense is due to lower
outstanding borrowings resulting from the repayment of primarily all outstanding
borrowings under bank credit facilities in the third quarter of 1998.
Capitalized interest decreased primarily due to the writedown of unevaluated
property totaling $73.9 million in June 1998 and a sale of 50% of the Company's
Block A-18 project in August 1998.
Other income, net included an unrealized gain of $4.2 million and $.6
million in 1999 and 1998, respectively, representing the change in the fair
value of the call options purchased in 1995, in anticipation of the forward oil
sale. In 1998, the Company recognized a gain of $5 million on the sale of other
assets. In addition, the Company recorded expense of $3 million in 1999 and
$2.1 million in 1998 in other income, net, related to the net payments made
under the equity swap entered into in conjunction with the sale of TPC and the
change in its fair value. Net payments made (or received) under the equity
swap, and any fluctuations in the fair values of the call options and the equity
swap, in future periods will affect other income in such periods. See "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk" in Triton's Annual
Report on Form 10-K for the year ended December 31, 1998.
Income Taxes
-------------
The income tax provisions for 1999 and 1998 included deferred tax expense
of $9.3 million and $1.5 million, respectively. Current taxes related to the
Company's Colombian operations totaled $1.4 million and $1.3 million in 1999 and
1998, respectively.
NINE MONTHS ENDED SEPTEMBER 30, 1999,
COMPARED WITH NINE MONTHS ENDED SEPTEMBER 30, 1998
Sales and Other Operating Revenues
--------------------------------------
Oil and gas sales in 1999 totaled $176.1 million, a 53% increase from the
prior year, due to higher production and higher average realized oil prices.
Oil production, including production related to barrels delivered under the
forward oil sale, increased 33% in 1999, compared to the prior year, resulting
in an increase in revenues of $37.6 million. Gross production from the Fields
averaged 434,000 BOPD in 1999, compared to 324,000 in 1998. The average
realized oil price increased $2.00 per barrel, or 15%, resulting in an increase
in revenues of $23.4 million compared to the same period in 1998.
As a result of financial and commodity market transactions settled during
the nine months ended September 30, 1999, the Company's risk management program
resulted in lower revenues of approximately $12.1 million than if the Company
had not entered into such transactions. Additionally, the Company has hedged
its WTI price on a significant portion of its remaining projected 1999 oil
production. See "Item 3. Quantitative and Qualitative Disclosures about Market
Risk."
Costs and Expenses
--------------------
Operating expenses increased $3.3 million in 1999, and depreciation,
depletion and amortization increased $6.7 million, primarily due to higher
production volumes, including barrels delivered under the forward oil sale. The
Company's operating costs per equivalent-barrel improved from $6.44 in 1998, to
$5.11 in 1999, primarily due to higher production volumes. OCENSA pipeline
tariffs totaled $39.9 million or $3.52 per barrel, and $38.2 million or $4.51
per barrel in 1999 and 1998, respectively. This improvement to operating cost
on a per equivalent-barrel basis was partially offset by an increase in
production taxes of $2 million or $.14 per barrel in 1999.
General and administrative expense before capitalization decreased $17
million, or 45%, to $21.1 million in 1999. Capitalized general and
administrative costs were $5.8 million and $17.5 million in 1999 and 1998,
respectively. General and administrative expenses, and the portion capitalized,
decreased as a result of restructuring activities undertaken during the second
half of 1998 and March 1999.
In June 1998, the carrying amount of the Company's evaluated oil and gas
properties in Colombia was written down by $105.4 million ($68.5 million, net of
tax) through application of the full cost ceiling limitation as prescribed by
the SEC, principally as a result of a decline in oil prices. No adjustments
were made to the Company's reserves in Colombia as a result of the decline in
prices. The SEC ceiling test was calculated using the June 30, 1998, WTI oil
price of $14.18 per barrel that, after a differential for Cusiana crude
delivered at the port of Covenas in Colombia, resulted in a net price of
approximately $13 per barrel.
The Company assessed its investments in exploration licenses in conjunction
with the plan to restructure operations and scale back exploration-related
expenditures in 1998, and determined that certain investments were impaired. As
a result, unevaluated oil and gas properties and other assets totaling $77.3
million ($72.6 million, net of tax) were expensed in writedown of assets in June
1998. The writedown included $27.2 million and $22.5 million related to
exploration activity in Guatemala and China, respectively. The remaining
writedowns related to the Company's exploration projects in certain other areas
of the world.
Other Income and Expenses
----------------------------
In February 1998, the Company sold TPC, a wholly owned subsidiary that held
the Company's 9.6% equity interest in the Colombian pipeline company, OCENSA, to
an unrelated third party (the "Purchaser") for $100 million. Net proceeds were
approximately $97.7 million. The sale resulted in a gain of $50.2 million.
Gross interest expense for 1999 and 1998 totaled $28 million and $36.9
million, respectively, while capitalized interest for 1999 decreased $9.3
million to $10.5 million. The decrease in gross interest expense is due to
lower outstanding borrowings resulting from the repayment of primarily all
outstanding borrowings under bank credit facilities in the third quarter of
1998. Capitalized interest decreased primarily due to the writedown of
unevaluated property totaling $73.9 million in June 1998 and a sale of 50% of
the Company's Block A-18 project in August 1998.
Other income, net included a foreign exchange gain (loss) of ($2.7
million) and $2.5 million in 1999 and 1998, respectively. In 1998, the Company
recognized gains of $6.9 million on the sale of other assets. During 1999 and
1998, the Company recorded an unrealized gain of $6.6 million and $.5 million,
respectively, representing the change in the fair value of the call options
purchased in anticipation of a forward oil sale. In addition, during 1999 and
1998, the Company recorded expense of $3.8 million and $2.9 million,
respectively, in other income, net, related to the net payments made under the
equity swap entered into in conjunction with the sale of TPC and the change in
its fair value. Net payments made (or received) under the equity swap, and any
fluctuations in the fair values of the call options and the equity swap, in
future periods will affect other income in such periods. See "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk" in Triton's Annual
Report on Form 10-K for the year ended December 31, 1998.
Income Taxes
-------------
The income tax provisions for 1999 and 1998 included deferred tax expense
(benefit) of $16.5 million and ($34.3 million), respectively. The benefit
recognized in 1998 related to the writedown of oil and gas properties. Current
taxes related to the Company's Colombian operations totaled $3.9 million and
$2.6 million in 1999 and 1998, respectively.
Recent Accounting Pronouncements
--------------------------------
In June 1998, the Financial Accounting Standards Board issued
Statement No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and
Hedging Activities." SFAS 133 establishes accounting and reporting standards
for derivative instruments and for hedging activities. It requires enterprises
to recognize all derivatives as either assets or liabilities in the balance
sheet and measure those instruments at fair value. The requisite accounting for
changes in the fair value of a derivative will depend on the intended use of the
derivative and the resulting designation. The Company must adopt SFAS 133, as
amended, effective January 1, 2001. Based on the Company's outstanding
derivatives contracts, the impact of adopting this standard would not have a
material adverse effect on the Company's operations or consolidated financial
condition. However, no assurances can be given with regards to the level of the
Company's derivatives activities at the time SFAS 133 is adopted or the
resulting effect on the Company's operations or consolidated financial
condition.
Information Systems and the Year 2000
-------------------------------------
The Year 2000 issue involves circumstances where a computerized system may
not properly recognize or process date-sensitive information on or after January
1, 2000. The Company began a formal process in 1998 to identify those internal
computerized systems that are not Year 2000 compliant, prioritize those
business-critical computerized systems that need remediation or replacement,
test compliance once the appropriate corrective measures have been implemented,
and develop any contingency plans where considered necessary.
The Company's information technology infrastructure consists of desktop
Pentium class Intel based PC systems, servers and Sparc UNIX based computers and
off-the-shelf software packages. The systems are networked via Microsoft NT 4.0
and other telecommunications equipment. The Company does not use mini or
mainframe computer systems and uses only off-the-shelf software products. The
PBX and phone system is a standard off-the-shelf phone system with voice mail
capability. Additionally, telefax and copier machines are additional business
tools used by the Company in conducting its day-to-day activities.
The Company has completed its assessment of Year 2000 readiness of its
internal computerized systems. In addition, the Company has substantially
completed remediation procedures and the testing of newly upgraded systems to
ensure compliance with Year 2000 date recognition and has developed contingency
plans.
All of the Company's sales are derived from oil and gas production from the
Fields, which is heavily dependent upon the operation of the Fields by BP
Exploration Company (Colombia) Limited (the "Operator") and the transportation
of oil through OCENSA, a Colombian pipeline company. The Company is monitoring
progress of the Operator of the Fields and OCENSA on their activities related to
the Year 2000. At this time, the Company expects that field operations will not
be interrupted due to improper recognition of the Year 2000 by computerized
systems of the Operator of the Fields or OCENSA.
The Company also relies on other oil and gas partners, vendors, and financial
institutions in its daily operations. The Company believes it has identified
those third-party relationships that could have a material adverse effect on the
Company's results of operations and financial position should their computerized
systems not be compliant for the Year 2000. The Company has surveyed third
parties on their readiness for the Year 2000 and has established appropriate
alternatives where noncompliance may pose a risk to the Company's operations.
The Company does not believe that the costs to resolve any Year 2000 issues will
be material. To date, the Company has incurred approximately $250,000 on Year
2000 matters and it expects that the total cost, primarily consulting fees, will
not exceed $300,000.
The failure to correct a material Year 2000 problem by the Company, its partners
or other vendors could result in an interruption of the Company's normal
business activities or operations, including production in the Fields or
transportation of the Company's crude oil to the port of Covenas. Any
interruptions could result in a material adverse effect on the Company's results
of operations, cash flows and financial condition. Due to the inherent
uncertainties relating to the effect of the Year 2000 on the Company's
operations, it is difficult to predict what impact, if any, noncompliance with
the Year 2000 issue will have on the Company's results of operations, cash flows
and financial condition.
Certain Factors That Could Affect Future Operations
---------------------------------------------------
Certain information contained in this report, as well as written and oral
statements made or incorporated by reference from time to time by the Company
and its representatives in other reports, filings with the Securities and
Exchange Commission, press releases, conferences or otherwise, may be deemed to
be "forward-looking statements" within the meaning of Section 21E of the
Securities Exchange Act of 1934 and are subject to the "Safe Harbor" provisions
of that section. Forward-looking statements include statements concerning the
Company's and management's plans, objectives, goals, strategies and future
operations and performance and the assumptions underlying such forward-looking
statements. Forward-looking statements may be identified, without limitation,
by the use of the words "anticipates," "estimates," "expects," "believes,"
"intends," "plans" and similar expressions. These statements include
information regarding drilling schedules; expected or planned production
capacity; the disposal of licenses; future production of the Fields; completion
of development and commencement of production in Malaysia-Thailand; the
Company's capital budget and future capital requirements; the Company's meeting
its future capital needs; future general and administrative expense and the
portion to be capitalized; 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; the estimated
fair value of derivative instruments, including the equity swap; the impact of
the renegotiation of the production sharing contract in Equatorial Guinea; and
proven oil and gas reserves and discounted future net cash flows therefrom.
These statements are based on current expectations and involve a number of risks
and uncertainties, including those described in the context of such
forward-looking statements, and in notes of Notes to Condensed Consolidated
Financial Statements. Actual results and developments could differ materially
from those expressed in or implied by such statements due to these and other
factors.
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT
MARKET RISK
Oil sold by the Company is normally priced with reference to a defined
benchmark, such as light sweet crude oil traded on the New York Mercantile
Exchange. Actual prices received vary from the benchmark depending on quality
and location differentials. It is the Company's policy to use financial market
transactions with creditworthy counterparties from time to time, primarily to
reduce risk associated with the pricing of a portion of the oil and natural gas
that it sells. The policy is structured to underpin the Company's planned
revenues and results of operations. The Company also may enter into financial
market transactions to benefit from its assessment of the future prices of its
production relative to other benchmark prices. The Company does not hold or
issue derivative instruments for trading purposes. There can be no assurance
that the use of financial market transactions will not result in losses.
With respect to the sale of oil to be produced by the Company, the Company
has entered into an oil price collar with a creditworthy counterparty to
establish a weighted average minimum WTI benchmark price of $14.25 per barrel
and a maximum of $15.40 per barrel on 300,000 barrels per month during the
period from October through December 1999, for an aggregate of 900,000 barrels.
As a result, to the extent the average monthly WTI price exceeds $15.40, the
Company will pay the counterparty the difference between the average monthly WTI
price and $15.40, and to the extent that the average monthly WTI price is below
$14.25, the counterparty will pay the Company the difference between the average
monthly WTI price and $14.25. In addition, the Company established a weighted
average WTI fixed price of $16.92 for an aggregate of 600,000 barrels of
production during the period from October through December 1999, under its
marketing agreement with a third party.
The Company entered into oil price collars with creditworthy counterparties
for January 2000 through June 2000. The collars establish a weighted average
minimum WTI benchmark price of $18.80 per barrel and a maximum of $24.05 per
barrel for an aggregate of 3,000,000 barrels during the period from January 2000
through June 2000.
During the nine months ended September 30, 1999, markets provided the
Company the opportunity to realize WTI benchmark oil prices on average $4.57 per
barrel (excluding forward oil sale and Ecopetrol reimbursement barrels) above
the WTI benchmark oil price the Company set as part of its 1999 annual plan. As
a result of financial and commodity market transactions settled during the nine
months ended September 30, 1999, the Company's risk management program resulted
in an average net realization of approximately $1.45 per barrel lower than if
the Company had not entered into such transactions.
PART II. OTHER INFORMATION
ITEM 3. LEGAL PROCEEDINGS
In July through October 1998, eight lawsuits were filed against the Company
and Thomas G. Finck and Peter Rugg, in their capacities as Chairman and Chief
Executive Officer and Chief Financial Officer, respectively. The lawsuits were
filed in the United States District Court for the Eastern District of Texas,
Texarkana Division, and have been consolidated and are styled In re: Triton
Energy Limited Securities Litigation. They allege violations of Sections 10(b)
and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5
promulgated thereunder, and negligent misrepresentation in connection with
disclosures concerning the Company's properties, operations, and value relating
to a prospective sale of the Company or of all or a part of its assets. The
lawsuits seek recovery of an unspecified amount of compensatory and punitive
damages and fees and costs.
On September 29, 1999, the court granted the plaintiffs' motion for
appointment as lead plaintiffs and for approval of selection of lead counsel. In
addition, the court denied the Company's motion to dismiss or transfer for
improper venue. On October 14, 1999 the Company filed a motion to dismiss the
lawsuits for failure to state a claim.
The Company believes its disclosures have been accurate and intends to
vigorously defend these actions. There can be no assurance that the litigation
will be resolved in the Company's favor. An adverse result could have a material
adverse effect on the Company's financial position or results of operations.
On August 22, 1997, the Company was sued in the Superior Court of the State
of California for the County of Los Angeles, by David A. Hite, Nordell
International Resources Ltd., and International Veronex Resources, Ltd. The
Company and the plaintiffs were adversaries in a 1990 arbitration proceeding in
which the interest of Nordell International Resources Ltd. in the Enim oil field
in Indonesia was awarded to the Company (subject to a 5% net profits interest
for Nordell) and Nordell was ordered to pay the Company nearly $1 million. The
arbitration award was followed by a series of legal actions by the parties in
which the validity of the award and its enforcement were at issue. As a result
of these proceedings, the award was ultimately upheld and enforced.
The current suit alleges that the plaintiffs were damaged in amounts
aggregating $13 million primarily because of the Company's prosecution of
various claims against the plaintiffs as well as its alleged misrepresentations,
infliction of emotional distress, and improper accounting practices. The suit
seeks specific performance of the arbitration award, damages for alleged fraud
and misrepresentation in accounting for Enim field operating results, an
accounting for Nordell's 5% net profit interest, and damages for emotional
distress and various other alleged torts. The suit seeks interest, punitive
damages and attorneys fees in addition to the alleged actual damages. On
September 26, 1997, the Company removed the action to the United States
District Court for the Central District of California. On August 31, 1998, the
district court dismissed all claims asserted by the plaintiffs other than claims
for malicious prosecution and abuse of the legal process, which the court held
could not be subject to a motion to dismiss. The abuse of process claim was
later withdrawn, and the damages sought were reduced to approximately $700,000
(not including punitive damages). The lawsuit was tried and the jury found in
favor of the plaintiffs and assessed compensatory damages against the Company
in the amount of approximately $700,000 and punitive damages in the amount of
approximately $11 million. The Company believes it has acted appropriately and
intends to appeal the verdict.
The Company is also subject to litigation that is incidental to its
business.
ITEM 5. OTHER INFORMATION
Equatorial Guinea
------------------
The Company is a party to two production-sharing contracts covering
contiguous blocks (Blocks F and G) with the Republic of Equatorial Guinea. The
Company is the operator, with an 85% contract interest, and Energy Africa
Equatorial Guinea Limited has the remaining 15% contract interest. The Blocks
cover approximately 1.3 million acres located offshore and southwest of the town
of Bata in water depths of up to 5,200 feet.
Recent Drilling Results
In October 1999, the Company announced that it had made a potentially
significant oil discovery in the Ceiba Field in Block G. On test, the Ceiba-1
(formerly Mbini-1) well flowed 12,401 barrels of oil per day (BOPD) of 30 degree
oil from one zone over an interval of 160 feet with a flowing tubing pressure of
897 pounds per square inch. Test results were constrained by the capacity of
surface testing equipment. Analysis of wireline logs and core data indicates a
gross oil column of 742 feet in the well with net oil-bearing pay of 314 feet in
four zones. The Ceiba-1 well was drilled to a total depth of approximately 9,700
feet in approximately 2,200 feet of water, located 22 miles off the continental
coast in Block G. The well will be maintained as a potential future producer.
In October 1999, the Company spudded the Ceiba-2 appraisal well. The well
is located approximately one mile to the southwest of the Ceiba-1 discovery
well, and is expected to take approximately one month to complete. The Ceiba-2
well is designed to confirm the Ceiba-1 discovery, better define the Ceiba Field
and its commercial viability, and provide technical information to support early
development of the Ceiba Field. Acquisition of a regional 3D seismic survey
covering approximately 880,000 acres (3,600 square kilometers) is scheduled to
commence immediately following completion of the Ceiba-2 well and continue into
early 2000. Seismic acquisition will initially be focussed on the Ceiba Field
area. If the appraisal program is successful, the Company plans to institute a
strategy to develop the Ceiba Field, and further explore the Equatorial Guinea
licenses, including the drilling of additional wells and the construction of
offshore production facilities.
Contract Terms
The contracts provide that if there is a commercial discovery of an oil or
gas field on a Block, the contract will remain in existence as to that field for
a period of 30 years, in the case of oil, or 40 years, in the case of gas, from
the date the Ministry of Mines and Energy approves the discovery as commercial.
Any further discoveries of formations that underlie or overlie that field, or
other deposits found within the extension of that field, will be included with
that field and be subject to the original 30 or 40 year term, as applicable.
The Company will be required to relinquish 30% of each contract's original
area by the end of the third year of the contract, and an additional 20% of the
remaining contract area by the end of the fifth year of the contract, provided
that the Company will not be required to surrender an area that includes a
commercial field or a discovery that has not then been declared commercial.
The Company can extend the exploration period of each contract for
additional one-year periods, up to a total of eight years from the effective
date of the contract, if it agrees to certain operational commitments for those
periods.
Under the current terms of the Company's Production Sharing Contracts, the
Republic of Equatorial Guinea is entitled to a royalty as to each field. The
royalty is 10% for up to the first 100 million barrels of oil produced, 12.5%
for greater than 100 million barrels of oil up to 300 million barrels of oil
produced, and 15% for greater than 300 million barrels of oil produced. After
making the royalty payments, the Company is entitled to receive the production
until it recovers its costs, such capital costs to be depreciated and recovered
over a four year period. After the Company recovers its costs, the Republic of
Equatorial Guinea is entitled to receive a share of production based on the rate
of return realized by the Company under the contract. The contracts provide that
the government's share of production will vary from 0%, where the Company's rate
of return is less than 18%, to 55% where the Company's rate of return is greater
than or equal to 40%. The Republic of Equatorial Guinea has notified the Company
that the government would like to renegotiate certain terms of the contracts,
but the Company does not expect any material adverse economic impact on the
Company.
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.)
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 The Chase
Manhattan 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
Energy Limited and The Chase Manhattan Bank, as Rights Agent. (4)
4.5 Amendment No. 2 to Rights Agreement dated as of August 30, 1998, between Triton
Energy Limited and The Chase Manhattan Bank, as Rights Agent. (5)
4.6 Unanimous Written Consent of the Board of Directors authorizing a Series of
Preference Shares. (6)
4.7 Amendment No. 3 to Rights Agreement dated as of January 5, 1999, between Triton
Energy Limited and The Chase Manhattan Bank, as Rights Agent. (7)
10.1 Amended and Restated Retirement Income Plan. (8)
10.2 Amendment to the Retirement Income Plan dated August 1, 1998. (9)
10.3 Amendment to Amended and Restated Retirement Income Plan dated
December 31, 1996. (10)
10.4 Amended and Restated Supplemental Executive Retirement Income Plan. (11)
10.5 1981 Employee Non-Qualified Stock Option Plan. (12)
10.6 Amendment No. 1 to the 1981 Employee Non-Qualified Stock Option Plan. (13)
10.7 Amendment No. 2 to the 1981 Employee Non-Qualified Stock Option Plan. (12)
10.8 Amendment No. 3 to the 1981 Employee Non-Qualified Stock Option Plan. (8)
10.9 1985 Stock Option Plan. (14)
10.10 Amendment No. 1 to the 1985 Stock Option Plan. (12)
10.11 Amendment No. 2 to the 1985 Stock Option Plan. (8)
10.12 Amended and Restated 1986 Convertible Debenture Plan. (8)
10.13 1988 Stock Appreciation Rights Plan. (15)
10.14 1989 Stock Option Plan. (16)
10.15 Amendment No. 1 to 1989 Stock Option Plan. (12)
10.16 Amendment No. 2 to 1989 Stock Option Plan. (8)
10.17 Second Amended and Restated 1992 Stock Option Plan.(17)
10.18 Form of Amended and Restated Employment Agreement with
Triton Energy Limited and certain officers. (11)
10.19 Amended and Restated Employment Agreement among Triton Energy Limited, Triton
Exploration Services, Inc. and Robert B. Holland, III. (6)
10.20 Form of Amended and Restated Employment Agreement among Triton Energy Limited,
Triton Exploration Services, Inc. and each of Peter Rugg and Al E. Turner. (6)
10.21 Letter Agreement among Triton Energy Limited, Triton Exploration Services, Inc.
and Robert B. Holland, III dated December 17, 1998. (27)
10.22 Letter Agreement among Triton Energy Limited, Triton Exploration Services, Inc.
and Peter Rugg dated December 10, 1998. (27)
10.23 Form of Bonus Agreement between Triton Exploration Services, Inc. and each of
Al E. Turner, Robert B. Holland, III, and Peter Rugg dated July 15, 1998. (27)
10.24 Amended and Restated 1985 Restricted Stock Plan. (8)
10.25 First Amendment to Amended and Restated 1985 Restricted Stock Plan. (18)
10.26 Second Amendment to Amended and Restated 1985 Restricted Stock Plan. (17)
10.27 Executive Life Insurance Plan. (19)
10.28 Long Term Disability Income Plan. (19)
10.29 Amended and Restated Retirement Plan for Directors. (14)
10.30 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. (14)
10.31 Contract for Exploration and Exploitation for Tauramena with an effective date of July
4, 1988, between Triton Colombia, Inc., and Empresa Colombiana De Petroleos. (14)
10.32 Summary of Assignment legalized by Public Instrument No. 1255 dated September 15,
1987 (Assignment is in Spanish language). (15)
10.33 Summary of Assignment legalized by Public Instrument No. 1602 dated June 11, 1990
(Assignment is in Spanish language). (15)
10.34 Summary of Assignment legalized by Public Instrument No. 2586 dated September 9,
1992 (Assignment is in Spanish language). (15)
10.35 401(K) Savings Plan. (8)
10.36 Amendment to the 401(k) Savings Plan dated August 1, 1998. (9)
10.37 Amendment to 401(k) Savings Plan dated December 31, 1996. (10)
10.38 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. (20)
10.39 Triton Crude Purchase Agreement between Triton Colombia, Inc. and Oil Co., LTD.
dated May 25, 1995. (21)
10.40 Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation,
NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States. (18)
10.41 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. (18)
10.42 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. (17)
10.43 Amendment No. 3 to Credit Agreement among Triton Colombia, Inc., Triton Energy
Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
States. (10)
10.44 Form of Indemnity Agreement entered into with each director and officer of the
Company. (6)
10.45 Description of Performance Goals for Executive Bonus Compensation. (22)
10.46 Stock Purchase Agreement dated September 2, 1997, between The Strategic
Transaction Company and Triton International Petroleum, Inc. (11)
10.47 Fourth Amendment to Stock Purchase Agreement dated February 2, 1998, between
The Strategic Transaction Company and Triton International Petroleum, Inc. (11)
10.48 Amended and Restated 1997 Share Compensation Plan. (27)
10.49 First Amendment to Amended and Restated Retirement Plan for Directors. (11)
10.50 First Amendment to Second Amended and Restated 1992 Stock Option Plan. (23)
10.51 Second Amendment to Second Amended and Restated 1992 Stock Option Plan. (11)
10.52 Amended and Restated Indenture dated July 25, 1997, between Triton Energy
Limited and The Chase Manhattan Bank. (24)
10.53 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. (24)
10.54 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. (24)
10.55 Share Purchase Agreement dated July 17, 1998 ,among Triton Energy Limited, Triton
Asia Holdings, Inc., Atlantic Richfield Company and ARCO JDA Limited. (9)
10.56 Shareholders Agreement dated August 3, 1998, among Triton Energy Limited, Triton
Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA Limited. (9)
10.57 Stock Purchase Agreement dated as of August 31, 1998, between Triton Energy
Limited and HM4 Triton, L.P. (6)
10.58 Shareholders Agreement dated as of September 30, 1998, between Triton Energy
Limited and HM4 Triton, L.P. (6)
10.59 Financial Advisory Agreement dated as of September 30, 1998, between Triton Energy
Limited and Hicks, Muse & Co. Partners, L.P. (6)
10.60 Monitoring and Oversight Agreement dated as of September 30, 1998, between Triton
Energy Limited and Hicks, Muse & Co. Partners, L.P. (6)
10.61 Severance Agreement dated as of July 15, 1998, between Thomas G. Finck and Triton
Energy Limited. (6)
10.62 Severance Agreement dated April 9, 1999, made and entered into by and among Triton
Energy Limited, Triton Exploration Services, Inc. and Peter Rugg. (28)
10.63 Consulting and Non-Compete Agreement dated April 9, 1999, made and entered into
by and between Triton Exploration Services, Inc. and Peter Rugg. (28)
10.64 Third Amendment to Amended and Restated 1985 Restricted Stock Plan. (28)
10.65 Amendment to Triton Exploration Services, Inc. Retirement Income Plan. (29)
10.66 Amendment to the Triton Exploration Services, Inc. Supplemental Executive
Retirement Plan. (29)
10.67 Third Amendment to the Second Amended and Restated 1992 Stock Option Plan. (29)
10.68 First Amendment to the Amended and Restated 1997 Share Compensation Plan. (29)
10.69 Amended and Restated Employment Agreement dated July 15, 1998 among
Triton Exploration Services, Inc., Triton Energy Limited and A.E. Turner, III. (29)
10.70 Amended Employment Agreement among Triton Exploration Services, Inc.,
Triton Energy Limited and certain officers. (29)
10.71 Second Amendment to Retirement Plan for Directors. (29)
10.72 Amendment to Triton Exploration Services, Inc. 401 (k) Savings Plan. (29)
10.73 Amendment No. 1 to Shareholders Agreement between Triton Energy Limited
And HM4 Triton. (29)
10.74 Amendment No. 4 to the 1981 Employee Nonqualified Stock Option Plan. (29)
10.75 Amendment No. 3 to the 1985 Stock Option Plan. (29)
10.76 Amendment No. 3 to the 1989 Stock Option Plan. (29)
10.77 Supplemental Letter Agreement dated October 28, 1999, among Triton Energy
Limited, Triton Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA
Limited. (30)
10.78 Gas Sales Agreement dated October 30, 1999 among the Malaysia-Thailand Joint
Authority, and Petronas Carigali (JDA) Sdn Bhd, Triton Oil Company of Thailand,
Triton Oil Company of Thailand (JDA) Limited, as Sellers, and with Petroleum
Authority of Thailand and Petroliam Nasional Berhad, as Buyers. (30)
12.1 Computation of Ratio of Earnings to Fixed Charges. (30)
12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preference
Dividends. (30)
27.1 Financial Data Schedule. (30)
99.1 Heads of Agreement for the Supply of Gas from Block A-18 of the Malaysia-Thailand
Joint Development Area. (10)
99.2 Rio Chitamena Association Contract. (25)
99.2 Rio Chitamena Purchase and Sale Agreement. (25)
99.3 Integral Plan - Cusiana Oil Structure. (25)
99.4 Letter Agreements with co-investor in Colombia. (25)
99.5 Colombia Pipeline Memorandum of Understanding. (25)
99.6 Amended and Restated Oleoducto Central S.A. Agreement dated as of March 31,
1995. (26)
- ---------------
(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 the Company's Registration Statement on Form 8-A/A
(Amendment No. 2) dated October 2, 1998, and incorporated herein by reference.
(6) Previously filed as an exhibit to Triton Energy Corporation's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1998, and incorporated herein by
reference.
(7) Previously filed as an exhibit to the Company's Registration Statement on Form 8-A/A
(Amendment No. 3) dated January 31, 1999, and incorporated herein by reference.
(8) 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.
(9) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1998, and incorporated herein by reference.
(10) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1998, and incorporated herein by reference.
(11) Previously filed as an exhibit to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1997, and incorporated herein by reference.
(12) 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.
(13) 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.
(14) 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.
(15) 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.
(16) 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.
(17) 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.
(18) 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.
(19) 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.
(20) 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.
(21) 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.
(22) Previously filed as an exhibit to the Company's Annual Report on Form
10-K for the fiscal year ended December 31, 1996, and incorporated herein by
reference.
(23) 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.
(24) 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.
(25) 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.
(26) 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.
(27) Previously filed as an exhibit to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1998, and incorporated herein by reference
(28) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q
for the quarter ended March 31, 1999, and incorporated herein by reference.
(29) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q
for the quarter ended June 30, 1999, and incorporated herein by reference.
(30) Filed herewith.
(b) Reports on Form 8-K
Form 8-K dated September 29, 1999 and filed October 8, 1999 regarding
oil discovery in Equatorial Guinea and litigation update.
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/ Bernard Gros-Dubois
-----------------------------
Bernard Gros-Dubois
Vice President
(Principal Accounting and
Financial Officer)
Date: November 12, 1999