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)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
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)
======== ========= ========= ==========
</TABLE>
See accompanying Notes to Condensed Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
ASSETS SEPTEMBER 30, DECEMBER 31,
<S> <C> <C>
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
================= =================
</TABLE>
The Company uses the full cost method to account for its oil and gas producing
activities.
See accompanying Notes to Condensed Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
1999 1998
--------- ----------
<S> <C> <C>
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
========= ==========
</TABLE>
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)
<TABLE>
<CAPTION>
<S> <C>
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
==========
</TABLE>
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:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
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
======== ======== ======== ========
</TABLE>
<PAGE>
7. WRITEDOWN OF ASSETS
Writedown of assets in 1998 is summarized as follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, 1998
-------------------
<S> <C>
Evaluated oil and gas properties (SEC ceiling test) $ 105,354
Unevaluated oil and gas properties 73,890
Other assets 3,428
-------------------
$ 182,672
===================
</TABLE>
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.
<TABLE>
<CAPTION>
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ----------
<S> <C> <C> <C>
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
============= ==========
</TABLE>
<TABLE>
<CAPTION>
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
<S> <C> <C> <C>
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
============ ==========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ----------
<S> <C> <C> <C>
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
============= ==========
</TABLE>
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):
<TABLE>
<CAPTION>
<C> <S> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ ------------------
1999 1998 1999 1998
------- ------ ------- ------
<S> <C> <C> <C> <C>
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.
</TABLE>
<PAGE>
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."
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: The following documents are filed as part of this Quarterly
Report on Form 10-Q:
1. Exhibits required to be filed by Item 601 of Regulation S-K. (Where the
amount of securities authorized to be issued under any of Triton Energy
Limited's and any of its subsidiaries' long-term debt agreements does not exceed
10% of the Company's assets, pursuant to paragraph (b)(4) of Item 601 of
Regulation S-K, in lieu of filing such as exhibits, the Company hereby agrees to
furnish to the Commission upon request a copy of any agreement with respect to
such long-term debt.)
<TABLE>
<CAPTION>
<C> <S>
3.1 Memorandum of Association. (1)
3.2 Articles of Association. (1)
4.1 Specimen Share Certificate of Ordinary Shares, $.01 par value, of the Company. (2)
4.2 Rights Agreement dated as of March 25, 1996, between Triton and 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) <C>
</TABLE>
- ---------------
<TABLE>
<CAPTION>
<C> <C> <S>
(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.
</TABLE>
(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
Exhibit 10.77
THIS SUPPLEMENTAL LETTER AMENDMENT (THIS "AGREEMENT") is made on 28 October 1999
BETWEEN
TRITON ASIA HOLDINGS, INC., a company incorporated under the laws of the Cayman
Islands, whose principal place of business is at Caledonian House, Mary Street,
P.O. Box 1044, George Town, Grand Cayman, the Cayman Islands (TRITON);
ARCO JDA LIMITED, a company incorporated under the laws of the Commonwealth of
the Bahamas whose registered office is at #3 Magna Carta Court, P.O. Box,
N-4805, Shirley Street, Nassau, Bahamas (ARCO);
TRITON ENERGY LIMITED, a company incorporated under the laws of the Cayman
Islands, whose principal place of business is Caledonian House, Mary Street,
P.O. Box 1043, George Town, Grand Cayman, Cayman Islands (the TRITON GUARANTOR);
and
ATLANTIC RICHFIELD COMPANY, a company incorporated under the laws of the State
of Delaware, U.S.A., whose principal place of business is located at 515 S.
Flower Street, Los Angeles, California, 90071 (the ARCO GUARANTOR).
RE: SHAREHOLDERS AGREEMENT DATED 3RD AUGUST 1998
- ------------------------------------------------------
Pursuant to a Shareholders Agreement dated 3rd August 1998, ARCO and Triton are
shareholders of Triton International Oil Corporation. Triton Oil Company of
Thailand and Triton Oil Company of Thailand (JDA) Limited are wholly owned
subsidiaries of Triton International Oil Corporation.
Reference is made to the recent discussions regarding the imminent signature of
the Gas Sales Agreement. As shareholders of Triton International Oil
Corporation, ARCO and Triton wish to record their agreement to the following to
supplement the Shareholders Agreement as follows:
1. Unless otherwise defined in this Agreement, capitalized terms used herein
shall have the same meanings as the definitions specified in the Gas Sales
Agreement between Malaysia-Thailand Joint Authority and Petronas Carigali (JDA)
Sdn., Bhd. and Triton Oil Company of Thailand and Triton Oil Company of Thailand
(JDA) Limited as Sellers and the Buyers for the Supply of Gas from the Block
A-18 of the Malaysia-Thailand Joint Development Area (the "Gas Sales
Agreement").
2. Subject to the terms and conditions herein, in the event there is a delay
to the DCD caused by a delay in obtaining the EIA Approval, Triton shall pay to
ARCO an amount equal to one million two hundred and fifty thousand United States
dollars (US$1,250,000.00) for every whole calendar month that the DCD is delayed
after the EPC30 Date. The EPC30 Date is the date thirty (30) months after the
engineering, procurement and construction contract for the Cakerawala Gas Field
Development is awarded. These payments shall be capped at a maximum of thirty
million United States Dollars (US$30,000,000.00).
3. In its capacity of shareholder of a Seller under the Gas Sales Agreement,
ARCO confirms that it will continue to act in good faith and in a diligent, safe
and efficient manner in accordance with good and prudent oil field practices and
conservation principles generally followed by the international petroleum
industry under similar circumstances in proceeding with the construction and
installation of facilities enabling the production and delivery of gas to the
Buyers in order to meet with Buyers' timing of first gas delivery.
4. Where a payment by Triton to ARCO is due under this Agreement, ARCO will
issue demand notices on a monthly basis. Triton will make such payments within
thirty (30) days following the demand notices issued by ARCO by wire transfer of
immediately available funds to an account specified by ARCO.
5. No variation of this Agreement shall be effective unless in writing and
signed by or on behalf of each of the Parties.
6. This Agreement may be entered into in any number of counterparts, each of
which when executed and delivered shall be an original but all the counterparts
together shall constitute one and the same instrument.
7. This Agreement shall be governed by and construed in accordance with
English law, excluding any conflict of laws principles which would apply the
laws of another jurisdiction.
8. The parties irrevocably agree that any disputes in relation hereto shall
be submitted to binding arbitration in London conducted in the English language
in accordance with the arbitration rules of the International Chamber of
Commerce.
IN WITNESS WHEREOF the parties have executed this Agreement by their duly
authorized representatives on the date first above written.
SIGNED by )
for and on behalf of TRITON ASIA )
HOLDINGS, INC. )
SIGNED by )
for and on behalf of ARCO )
JDA LIMITED )
SIGNED by )
for and on behalf of )
TRITON ENERGY LIMITED )
SIGNED by )
for and on behalf of )
ATLANTIC RICHFIELD )
COMPANY )
Exhibit 10.78
GAS SALES AGREEMENT
BETWEEN
MALAYSIA-THAILAND JOINT AUTHORITY
AND
PETRONAS CARIGALI (JDA) SDN BHD
AND
TRITON OIL COMPANY OF THAILAND
AND
TRITON OIL COMPANY OF THAILAND (JDA) LIMITED
AS SELLERS
AND
PETROLIAM NASIONAL BERHAD
AND
PETROLEUM AUTHORITY OF THAILAND
AS BUYERS
FOR THE SUPPLY OF GAS FROM THE BLOCK A-18 OF THE
MALAYSIA-THAILAND JOINT DEVELOPMENT AREA
TABLE OF CONTENTS
ARTICLE
- -------
I DEFINITIONS 5
II SALE AND PURCHASE AND RELATED MATTERS 10
III INITIAL FIELD RESERVES 12
IV QUANTITIES 13
V SELLERS' RESERVATIONS 23
VI BUYERS' FACILITIES 24
VII EXCHANGE OF INFORMATION 25
VIII DETERMINATION OF RESERVES 26
IX PRICE AND PRICE ADJUSTMENT 27
X BILLING AND PAYMENT 32
XI QUALITY 35
XII DELIVERY PRESSURE 37
XIII MEASUREMENT 38
XIV POINT OF DELIVERY, TITLE AND RISK 41
XV DEFAULT 42
XVI FORCE MAJEURE 43
XVII TERM OF AGREEMENT 45
XVIII TERMINATION 46
XIX ASSIGNMENT 48
XX EXPERT 49
XXI ARBITRATION 52
XXII WAIVER 54
XXIII SUCCESSORS AND ASSIGNS 55
XXIV REPRESENTATIVES 56
XXV APPLICABLE LAW 57
XXVI NOTICES 58
XXVII MARGINAL HEADINGS 60
XXVIII ENTIRE AGREEMENT AND ATTACHMENTS 61
XXIX EFFECTIVE DATE 62
XXXI FINANCIAL ARRANGEMENTS 63
FIRST SCHEDULE 65
SECOND SCHEDULE 66
THIRD SCHEDULE 68
FOURTH SCHEDULE 71
THIS AGREEMENT is made in Alor Setar, Kedah in Malaysia and effective on this
30th Day of October (1999) BETWEEN :
the following Parties collectively referred to as "Sellers", of the one part,
MALAYSIA-THAILAND JOINT AUTHORITY, an authority duly established under the laws
of Malaysia and Thailand and having its office at 27th Floor, City Square
Centre, 182 Jalan Tun Razak, 50400 Kuala Lumpur, Malaysia, represented by Mr.
Ismail Sulaiman (hereinafter called "MTJA"),
and
(1) PETRONAS CARIGALI (JDA) SDN BHD, a company duly incorporated and existing
under the laws of Malaysia and having its registered office at Tower 1, PETRONAS
Twin Towers, Kuala Lumpur City Center, 50088, Kuala Lumpur, Malaysia,
represented by Y. Bhg. Dato' Mohamad Idris Mansor (hereinafter called
"CARIGALI"),
(2) TRITON OIL COMPANY OF THAILAND, a company duly incorporated and existing
under the laws of the State of Texas, United States of America, with its
registered office at 6688 North Central Expressway, Suite 1400, Dallas, Texas
75206, United States of America and with its local branch office at 33/95-96,
99-100 Wall Street Tower, Surawong Road, Bangrak, Bangkok 10500 Thailand,
represented by Mr. James C Musselman
and
TRITON OIL COMPANY OF THAILAND (JDA) LIMITED, a company duly incorporated and
existing under the laws of the Cayman Islands with its statutory office in
Dallas, Texas, United States of America, and with its local registered branch
office at Suite 13.01, 13th Floor, Menara Tan & Tan, 207 Jalan Tun Razak, 50400
Kuala Lumpur, Malaysia represented by Mr. James C Musselman, TRITON OIL COMPANY
OF THAILAND and TRITON OIL COMPANY OF THAILAND (JDA) LIMITED are hereinafter
referred to collectively and treated as one entity "TRITON"
AND WITH
the following Parties collectively referred to as "Buyers" and individually as
"Buyer", of the other part,
PETROLEUM AUTHORITY OF THAILAND having its principal office at 555 Vibhavadi
Rangsit Road, Ladyao Sub-district, Chatuchak District, Bangkok 10900, Thailand
represented by Mr. Viset Choopiban (hereinafter called "PTT"), and
PETROLIAM NASIONAL BERHAD having its registered office at Tower 1, PETRONAS Twin
Towers, Kuala Lumpur City Centre, 50088 Kuala Lumpur, Malaysia represented by Y.
Bhg. Tan Sri Dato' Mohd Hassan Marican (hereinafter called "PETRONAS").
Documents evidencing registration and empowering the person to sign on behalf of
each party of "Sellers" and Buyers" are attached hereto.
WHEREAS
1. MTJA, on the 21st day of April 1994, had entered into a Production
Sharing Contract (hereinafter referred to as "PSC") with CARIGALI and TRITON
sometimes hereinafter referred to as "Contractors" in respect of Block A-18
(hereinafter referred to as the "Contract Area") of the Malaysia-Thailand Joint
Development Area (hereinafter referred to as "the JDA") for the exploration and
exploitation of petroleum resources in the Contract Area.
2. CARIGALI and TRITON, as Contractors and joint operators under the PSC,
have delegated their role as operator to CARIGALI-TRITON OPERATING COMPANY SDN
BHD (hereinafter referred to as "CTOC") which has its principal place of
business at 16th Floor (East Wing), Rohas Perkasa, No. 8, Jalan Perak, 50450
Kuala Lumpur, Malaysia.
3. Natural gas reserves discovered in the Contract Area (hereinafter
referred to as "Natural Gas") are anticipated to be developed under the PSC by
second Quarter 2002. According to the PSC, CARIGALI and TRITON as Contractors
thereunder are required to negotiate for the sale of Natural Gas on a
joint-dedicated basis with MTJA.
4. As agreed between Buyers and Sellers through the Memorandum of
Understanding dated 30th May 1996 and the Heads of Agreement dated 22nd April
1998, Buyers are desirous to purchase the Natural Gas from Sellers and Sellers
are desirous of selling Natural Gas to Buyers on terms and conditions to be
agreed between the Parties.
5. As agreed between Buyers through the Heads of Agreement dated 19th
September 1997, Buyers intend to bring their respective fifty (50) percent share
of the Natural Gas purchased from Sellers back to their respective countries on
terms and conditions to be agreed between Buyers under a separate agreement, in
which Buyers will set up a Balancing Mechanism in respect of their obligations
to take Natural Gas from Sellers to provide amongst others that; if one Buyer
cannot take Natural Gas in the amount of his Net ACQ*, the other will endeavor
to take the remaining Natural Gas of the said Buyer's Net ACQ* with the view to
fulfill the said Buyer's obligation.
For and in consideration of the mutual promises contained herein, the Parties
agree as follows:
ARTICLE I
DEFINITIONS
The following words and phrases, whether in the plural or singular form, shall
have the following definitions for the purposes of this Agreement:
1.1 "Annual Contract Quantity" or "ACQ" shall mean the volume of Natural Gas
which Sellers shall deliver and Buyers shall receive in a Contract Year. Such
ACQ shall be determined by adding up all the DCQs for each day in a Contract
Year. Each Buyer shall be entitled to take and purchase its individual Annual
Contract Quantity (ACQ*) equal to the sum of its individual Daily Contract
Quantities (DCQs*).
1.2 "BTU" shall mean one (1) British Thermal Unit which is further defined
as the amount of heat required to raise the temperature of one (1) avoirdupois
pound of pure water from fifty-eight and one-half degrees (58.5o) Fahrenheit to
fifty-nine and one-half degrees (59.5o) Fahrenheit at a standard pressure of
fourteen decimal seven three (14.73) pounds per square inch absolute.
1.3 "Carry Forward Gas" shall mean Natural Gas taken in excess of the Net
ACQ for a given Contract Year (other than Natural Gas taken in accordance with
Sub-clause 4.10.3). Each Buyer may use a portion of Carry Forward gas
proportional to its DCQ* to offset against a Buyer's Take-or-Pay obligations in
subsequent Years according to Sub-clause 4.9.2.
1.4 "Contract Area" shall mean the JDA Block A-18 contract area retained by
the Contractors from time to time in accordance with the PSC.
1.5 "Contract Delivery Pressure" shall mean the delivery pressure as
required by Buyer or Buyers at the Delivery Point(s) pursuant to Clause 12.1.
1.6 "Contract Period" shall mean the period of time from the Contractual
Delivery Date to the date on which this Agreement shall expire or be earlier
terminated by any of the means herein provided.
1.7 "Contract Price" shall be the Current Price and the adjusted Current
Price as applicable and shown in Sub-clause 9.3.3.
1.8 "Contract Year" shall mean a period beginning at six (6) o'clock a.m. on
the first Day of January in any Year after the First Contract Year during the
continuance of this Agreement and ending at six (6) o'clock a.m. on the first
Day of January in the next succeeding year. The term "Contract Year" shall
include the First Contract Year when the context so requires.
1.9 "Contractual Delivery Date" or "CDD" shall mean the Day on which Sellers
shall first be obligated to deliver and sell, and Buyers shall first be
obligated to accept and purchase Natural Gas in accordance with the terms and
conditions of this Agreement.
1.10 "Contractual Delivery Capacity" or "CDC" and "Individual Contractual
Delivery Capacity" or "CDC*" shall mean the quantity of Natural Gas equal to one
hundred and ten (110) percent of the DCQ and DCQ* respectively, except as
otherwise provided herein.
1.11 "Cubic Foot" or "SCF" shall mean the volume of Natural Gas which,
being saturated with water, occupies one (1) cubic foot of space measured at
fourteen decimal seven three (14.73) pounds per square inch absolute pressure at
a temperature of sixty degrees (60o) Fahrenheit.
1.12 "Current Price" shall have a meaning as defined in Article IX.
1.13 "Daily Contract Quantity" or "DCQ" shall mean the daily rate of
delivery of Natural Gas in each Contract Year by Sellers to Buyers determined in
accordance with Clauses 4.4 and 4.6. Each Buyer shall be entitled to an
individual Daily Contract Quantity ("DCQ*") determined in accordance with Clause
4.4.
1.14 "Date of Commencement of Delivery" or "DCD" shall mean the date of
first delivery of Natural Gas by Sellers to Buyer or Buyers under this Agreement
pursuant to Sub-clause 4.2.1.
1.15 "Day" or "D" shall mean a period of twenty four (24) hours beginning at
six (6) o'clock a.m. on each Day and ending at six (6) o'clock a.m. on the
following Day.
1.16 "Debit Year" shall mean any Contract Year during which a Buyer did not
take its Net ACQ* volume and as a result of which such Buyer shall be obligated
to pay for the volume not taken as referred to in Sub-clause 4.9.2.
1.17 "Delivery Point(s)" shall mean the point of delivery and sale of
Natural Gas by Sellers to Buyers where the title and risk in the Natural Gas
passes to Buyers as provided in Clause 14.1.
1.18 "Effective Date" shall mean the date of this Agreement and as described
in Article XXIX.
1.19 "Field Reserves" means at any time the estimated total quantity of
Proved and Probable Natural Gas in the Reservoir on the date of the last
determination or redetermination of reserves made in accordance with Article III
or Article VIII which may be commercially and reasonably recovered by Sellers
using prudent oil and gas industry practices plus the total quantity of Natural
Gas theretofore taken from the Reservoir.
1.20 "First Contract Year" shall mean a period, which may be more or less
than a year but in no case less than six (6) Months, beginning at six (6)
o'clock a.m. on the Contractual Delivery Date and ending at six (6) o'clock a.m.
on the first Day of January next following the Contractual Delivery Date.
However, if the resulting First Contract Year would be less than six (6) Months,
then the First Contract Year shall be the period beginning at six (6) o'clock
a.m. on the Contractual Delivery Date and ending at six (6) o'clock a.m. on the
first Day of January one year from the first Day of January next following the
Contractual Delivery Date. For example, if the Contractual Delivery Date were
1st October, 1999, then the end of the First Contract Year would be 1st January
2001.
1.21 "Foot" shall mean zero decimal three zero four eight (0.3048) metres as
defined by the eleventh Conference Generale des Poids et Measures at Paris,
France in 1960.
1.22 "Gross Calorific Value" shall mean that number of BTU produced by the
complete combustion at a constant pressure of thirty (30) inches of mercury at
thirty two degrees (32o) Fahrenheit and under standard gravitational force
(acceleration thirty two decimal one seven four (32.174) feet per second per
second) of one (1) cubic foot of the Natural Gas at sixty degrees (60o)
Fahrenheit with excess air at the same temperature and pressure as the Natural
Gas when the products of combustion are cooled to sixty degrees (60o) Fahrenheit
and when the water formed by combustion is condensed to the liquid state and the
products of combustion contain the same total mass of water vapor as the Natural
Gas and air before combustion.
1.23 "Inch Water Gauge" shall mean that differential pressure equal to zero
decimal zero three six one two seven three (0.0361273) pounds force per square
inch.
1.24 "M" shall mean one thousand.
1.25 "MM" shall mean one million.
1.26 "Month" shall mean the Gregorian month which for the purpose of this
Agreement is a period beginning at six (6) o'clock a.m. on the first Day of any
calendar Month and ending at six (6) o'clock a.m. on the first Day of the next
succeeding calendar Month.
1.27 "Natural Gas" shall mean all kinds of gaseous hydrocarbons and varying
quantities of non-hydrocarbons whether wet or dry, produced from gas wells,
including the residue gas remaining after extraction of liquid hydrocarbons or
by-products from wet gas.
1.28 "Net Annual Contract Quantity" or "Net ACQ" shall mean the volume of
Natural Gas which Buyers were obligated to take during the applicable Contract
Year as described in Sub-clause 4.9.1. The individual Net Annual Contract
Quantity or "Net ACQ*" shall mean the volume of Natural Gas which each Buyer
shall be obligated to take or pay for if not taken during the applicable
Contract Year as referred to in Sub-clause 4.9.1.
1.29 "Party" shall mean either any of Sellers or either Buyer, "Parties"
means all Sellers and Buyers.
1.30 "Probable Natural Gas Reserves" means the estimated additional
quantities of Natural Gas in the Reservoir, beyond those defined as Proved
Natural Gas Reserves, which from time to time geological and engineering data
indicate to have a fair to good probability of being commercially recovered in
future Years from already discovered deposits with price movements consistent
with Article IX and forecast investment and operating costs. For the purpose of
this definition there is a fifty (50) percent chance that the actual quantity
will be more than the amount estimated as Proved Natural Gas plus Probable
Natural Gas reserves and a fifty (50) percent chance that it will be less.
1.31 "Proved Natural Gas Reserves" means the estimated quantities of Natural
Gas which from time to time geological and engineering data demonstrate with
reasonable certainty to be commercially recoverable in future Years from the
Reservoir under existing economic and operating conditions, prices and costs as
of the date the estimate is made. Prices include consideration of changes in
existing prices provided only by this Agreement. For the purpose of this
definition there is a ninety (90) percent chance that the actual quantity will
be more than the amount estimated as Proved reserves and a ten (10) percent
chance that it will be less.
1.32 "PSIA" shall mean pounds per square inch absolute.
1.33 "PSIG" shall mean pounds per square inch gauge.
1.34 "Reasonable and Prudent Operator" when used to describe the standard of
care to be exercised by a Party in performing its obligations hereunder shall
mean the degree of diligence, prudence and foresight reasonably and ordinarily
exercised by experienced operators, complying with applicable laws, engaged in
the same line of business under the same or similar circumstances and
conditions.
1.35 "Reservoir" shall mean those parts of the geologic formations
underlying the Contract Area in which there exists Natural Gas whether or not in
communication with the Natural Gas encountered in a test well or wells on that
geological feature.
1.36 "Run-in-Period" or "RIP" shall mean the period of time as described in
Sub-clause 4.2.2.
1.37 "Shortfall" shall mean that volume of properly nominated Natural Gas
which Sellers have failed to deliver on any Day as provided in Clause 15.2.
1.38 "Sellers' Equipment" shall mean Sellers' Natural Gas measuring and
testing equipment and the necessary appurtenances thereto as described in
Sub-clause 13.1.2.
1.39 "Specific Gravity" shall mean the weight of a volume of dry Natural Gas
divided by the weight expressed in the same units of an equal volume of dry
carbon dioxide free air both gases being at sixty degrees (60o) Fahrenheit and
an absolute pressure of thirty (30) inches of mercury at thirty-two degrees
(32o) Fahrenheit and under standard gravitational force (acceleration thirty-two
decimal one seven four (32.174) feet per second per second).
1.40 "Take-or-Pay obligation" shall mean a Buyer's obligation to take, or
pay for if not taken, a volume of Natural Gas at least equal to the Net ACQ* in
a Contract Year. A Buyer shall be obligated to pay Sellers for the volume of
Natural Gas not taken pursuant to Sub-clause 4.9.2.
1.41 "Take-or-Pay Gas" shall mean the volume of Natural Gas which a Buyer
fails to take in any Contract Year but has paid for, and is entitled to take
free of charge in any subsequent Contract Year pursuant to Sub-clause 4.9.3.
1.42 "Test Period" shall mean a period of time within the RIP when Sellers
shall use reasonable endeavours to deliver Natural Gas at the DCQ for a
continuous seventy two (72) hour period as described in Sub-clause 4.2.3.
1.43 "Time" or any reference to Time shall be construed as whatever Time as
shall be in force in Thailand.
1.44 "Trillion" or "T" shall mean one trillion (1,000,000,000,000).
1.45 "Week" shall mean a period of seven (7) Days beginning at six (6)
o'clock a.m. on Sunday and ending at six (6) o'clock a.m. on the following
Sunday.
1.46 "Year" shall mean a Gregorian Year which is a period of twelve (12)
calendar Months beginning at six (6) o'clock a.m. on any Day of any calendar
Year and ending at six (6) o'clock a.m. on the same Day in the next succeeding
calendar Year.
<PAGE>
ARTICLE II
SALE AND PURCHASE AND RELATED MATTERS
2.1 Subject to the reservations set forth in Article V and unless otherwise
excused under the provisions of this Agreement, Sellers shall produce Natural
Gas from the Field Reserves in the Contract Area and sell such Natural Gas to
Buyers and Buyers shall accept and purchase such Natural Gas produced from the
Field Reserves in the manner and on the terms of this Agreement. It is agreed
that Sellers shall fully dedicate such Field Reserves for the purpose of
production and delivery of Natural Gas to Buyer or Buyers under this Agreement.
2.2 Sellers warrant that they have the right to sell and dispose all Natural
Gas to be delivered by them under this Agreement and that the same shall be free
from all liens and adverse claims of every kind.
Sellers shall indemnify each Buyer for any damages arising out of claims by
any persons claiming entitlement to Natural Gas delivered to each Buyer. In the
case of any such adverse title claims, each Buyer shall continue to make
payments hereunder to Sellers and Sellers shall furnish a bond to each Buyer to
retain as security for the performance of Sellers' obligations until such
adverse title claims are resolved.
2.3 Sellers shall indemnify Buyers for all costs, taxes, royalties, levies,
imposts, charges or any other such costs or expenses imposed on or attributable
to the Natural Gas before Buyers take custody and title of the Natural Gas.
Subject to Articles XI and XIV, each Buyer shall indemnify Sellers for costs,
taxes, royalties, levies, imposts, charges or any other costs or expenses
imposed on or attributable to its share of the Natural Gas after Buyer takes
custody and title to its share of the Natural Gas.
2.4 Except as otherwise provided in this Agreement, Sellers shall, so long
as there are Field Reserves remaining to be produced for the purpose of
delivering Natural Gas to Buyer or Buyers hereunder, use their best efforts to
maintain the Contract Area so far as is necessary for this Agreement and
discharge all their obligations thereunder and shall indemnify and save harmless
Buyer or Buyers in respect of all loss, damage and expense of every character
associated with production of Natural Gas arising before delivery of the Natural
Gas to each Buyer; provided that nothing in this Clause shall affect any claim
of Sellers against Buyer or Buyers if such loss, damage or expense is/are caused
by Buyer's or Buyers' own default or negligence.
2.5 Sellers shall be jointly and severally liable for all Sellers'
obligations under this Agreement. Each Buyer shall be severally liable for
fifty (50) percent of all Buyers' obligations under this Agreement.
Without prejudice to each Buyer's obligation and liability to Sellers as
described in this Clause 2.5, it is recognised and agreed between Buyers that if
one Buyer is unable to take wholly or partially it's portion of the Natural Gas
from Sellers, the other Buyer shall be allowed to take and purchase such
equivalent portion from Sellers under this Agreement.
2.6 Buyer or Buyers shall maintain any license, permit, agreement or other
authorization which is or may be necessary to enable it or them to fulfill all
of its or their obligations under this Agreement.
<PAGE>
ARTICLE III
INITIAL FIELD RESERVES
3.1 The initial Field Reserves as of December 31, 1997 are certified and
agreed to be two decimal nine five (2.95) Trillion Cubic Feet inclusive of up to
twenty three (23) percent of carbon dioxide which is calculated based on the
certified reserves by third party of two decimal three six (2.36) Trillion Cubic
Feet (Proved Natural Gas Reserves).
<PAGE>
ARTICLE IV
QUANTITIES
4.1 Commencing from the Effective Date of this Agreement, Sellers shall at
their own expense, proceed with the construction and installation of facilities
enabling them to produce and deliver to Buyers the Contractual Delivery Capacity
as described in Sub-clause 4.7.1 hereafter.
4.2.1 (a) The Date of Commencement of Delivery ("DCD") shall be the date
of first delivery of Natural Gas from Sellers to Buyer or Buyers under this
Agreement and shall occur between April 1, 2002 and June 30, 2002. Prior to
November 1, 2000, the Parties shall mutually agree to a specific Day within the
above ninety one (91) Day period for the DCD. In the event the Parties cannot
agree on a mutually acceptable date, the DCD shall, for all intents and
purposes, be deemed to be June 30, 2002.
Any deferment of the DCD due to an event constituting Force Majeure in
accordance with Article XVI shall be limited to the number of Days and part Days
actually lost in consequence of the occurrence of such an event.
(b) Buyers undertake to use their best efforts to prevent any delays and
meet the above DCD date. In this regard, the Parties recognize Buyers'
obligations to obtain the necessary and required approvals from the Office of
Environmental Policy and Planning of Thailand ("EIA Approval") for the
installation and construction of facilities downstream of the Delivery Point(s).
These facilities are the Gas Separation Plant ("GSP") and the "Pipeline System"
consisting of the gas transportation pipelines from the Delivery Point(s) up to
the Malaysian Border, the carbon dioxide removal facilities, the slug catcher,
the dew point control facilities, and the mercury removal unit if required.
Accordingly, to ensure that the EIA Approval is obtained in good time for the
GSP and the Pipeline System, Buyers shall undertake the following:
(i) develop plans and key milestones of the EIA Approval process with the
aim of obtaining the same no later than September 30, 2000 ("Target Date");
(ii) ensure that all the requirements are fulfilled and complied with, that
the necessary follow-up steps including but not limited to, discussions and
dialogues with the relevant governmental authority, are taken to expedite the
approval process, and that Sellers shall be allowed to participate in such
sessions together with Buyers;
(iii) closely monitor the progress of the EIA Approval process; and provide
monthly updates to Sellers on the matter; and
(iv) ensure that Sellers are given notification as soon as practicable of
all public meetings concerning the EIA Approval.
However, in the event that by January 2, 2000 Buyers anticipate that the EIA
Approval would likely be delayed beyond the Target Date, Buyers shall
immediately notify Sellers of such anticipated delay. Such notice shall include
full information about the circumstances for the delay and a statement of steps
and time believed necessary to obtain the EIA Approval and the effect on the
DCD.
If Buyers have taken the necessary steps to obtain the EIA Approval (including
all the steps described in (i) to (iv) above), then Buyers' inability to meet
the deemed DCD date as a direct result of the delay in obtaining the EIA
Approval for the Pipeline System shall, notwithstanding anything to the contrary
under Article XVI on the definition of Force Majeure, be treated as a Force
Majeure event under this Agreement to the extent it delays the completion of
the Pipeline System .
(c) Notwithstanding the declaration of Force Majeure pursuant to Sub-clause
4.2.1(b) above, Buyers shall exercise their reasonable endeavours and take the
necessary steps to mitigate the adverse impact to Sellers that could reasonably
be attributed to the delay caused by such event and shall undertake to discuss
with Sellers on appropriate remedial arrangements.
4.2.2 The Run-in-Period shall mean the period of time between the DCD and
the CDD, and shall extend for ninety (90) Days, which includes a period of time
for the Test Period.
4.2.3 For the purpose of testing the facilities required for the performance
of obligations of Buyer or Buyers and Sellers during the RIP there shall be a
Test Period of seventy-two (72) hours starting from or after the DCD until
Natural Gas has flowed continuously at the DCQ of one hundred ninety five (195)
million Cubic Feet per Day for a total of seventy-two (72) hours in conformance
with the quality specifications and pressure requirements. If Sellers are unable
to complete the continuous seventy-two (72) hour Test Period, for whatever
reason other than due to Buyer or Buyers' inability to take Natural Gas, the
test shall be restarted. If within the seventy-two (72) hour Test Period, Buyer
or Buyers is/are unable to take Natural Gas, for whatever reason, the test shall
be suspended and restarted at the end of the interruption, but only for the
number of hours necessary to make up the total period of seventy-two (72) hours.
4.2.4 During the RIP and the Test Period Sellers and Buyers shall use their
reasonable endeavors to deliver and accept Natural Gas respectively; but the
Take-or-Pay provisions of Sub-clauses 4.9.2 and 4.9.3 and the default provisions
of Article XV shall not apply. Payment for such Natural Gas delivered to Buyer
or Buyers shall be in accordance with Clause 9.7.
During the RIP, Sellers shall use their reasonable endeavors to deliver
Natural Gas in accordance with the quality specifications set out in Second
Schedule and at the Contract Delivery Pressure referred to in Clause 12.1.
However, if at any time or from time to time during the RIP the Natural Gas
offered fails to conform with the quality specifications or delivery pressure, a
Buyer after using its reasonable endeavors to accept as much of such deficient
Natural Gas offered as is possible, may either reject or accept the delivery in
whole or in part. In any event, the penalty provisions of Articles XI and XII
shall not apply for any quality or pressure deficient gas delivered and Sellers
shall not be liable for any other damages during the RIP.
4.3 The Contractual Delivery Date ("CDD") shall occur at the completion of
the RIP.
4.4 For each Contract Year there shall be determined, in the manner
hereinafter provided, a daily rate for delivery of Natural Gas in that Contract
Year which shall be expressed as a quantity of Natural Gas in Cubic Feet and
shall hereinafter be called the Daily Contract Quantity ("DCQ"). Each Buyer
shall have an individual Daily Contract Quantity ("DCQ*") equal to fifty (50)
percent of the DCQ.
4.5 That amount of Natural Gas equivalent to the sum of the DCQs in effect
on each Day during the Contract Year shall hereinafter be called the Annual
Contract Quantity ("ACQ") and each Buyer shall have an individual Annual
Contract Quantity ("ACQ*") which shall be the sum of their DCQs*.
4.6.1 (a) The DCQ at the DCD shall be one hundred and ninety-five (195)
MMSCFD and will increase to three hundred and ninety (390) MMSCFD by a date not
later than one hundred and eighty (180) Days after the DCD.
(b) Such DCQ of three hundred and ninety (390) MMSCFD shall apply and be
maintained effective from the date of increase from one hundred and ninety-five
(195) MMSCFD to three hundred and ninety (390) MMSCFD pursuant to Sub-clause
4.6.1(a) above for a period of twenty (20) Contract Years.
4.6.2 From the date of the first Field Reserves redetermination described in
Article VIII and thereafter, unless revised pursuant to Clause 4.8 or Sub-clause
18.3.1, the DCQ shall not exceed the Field Reserves as last determined pursuant
to Article VIII, divided by six thousand (6,000). The Sellers may notify and
offer Buyers an increase in the available DCQ if such is supported by a Field
Reserves redetermination pursuant to Article VIII and the above maximum
limitation of the Field Reserves divided by six thousand (6,000). Buyers may
accept all, part or none of such increase pursuant to Sub-clause 4.6.3.
4.6.3 With respect to the proposed increase in DCQ under Sub-clause 4.6.2,
the Parties hereby agree that for and in relation to the DCQ to be delivered and
sold by Sellers and to be taken and purchased by Buyers for the second and
subsequent phases under this Agreement:
(a) Sellers' delivery obligations and facility installation shall be based
on the Parties' agreed forecast of gas demand realistically expected to
occur and from which Natural Gas produced from the Contract Area can be
supplied to meet such demand.
Such forecast of gas demand shall take into account the relevant delivery
and take obligations in Buyers' gas supply contract(s) with their
end-users and also, where appropriate, shall take into account any then
existing and planned Buyers' facilities expansion.
Accordingly, following a Field Reserve determination pursuant to
Sub-clause 8.1(i), the Parties shall meet and jointly determine and agree
by end of March in each Calendar Year during the term of this Agreement a
detailed estimate of daily average gas demand for which the Natural Gas
produced from the Contract Area can be supplied to meet such demand for
the remaining duration of the term of this Agreement. Where appropriate,
such estimate shall also identify any allowance for anticipated market
growth and Buyers' new customer(s).
The above forecasts and estimates shall be based on market data developed
by Buyers (which as such may include Buyers' estimates and forecasts) and
shall be established in light of the best market information available
taking into account among other things, the accuracy of previous
forecasts and rate of actual growth in gas demand and other commercial
considerations. The Parties will establish the DCQ(s) and the timing
necessary to supply the above forecasts and estimates over the balance
of the term of this Agreement.
(b) Based on the estimated DCQ(s) established pursuant to paragraph (a)
above, the Parties by end of June of the same Calendar Year shall
jointly determine and agree on the CDC(s) which shall equal one hundred
and ten (110) percent of such DCQ(s) and which shall be the daily
obligation of Sellers to supply Natural Gas to Buyers.
(c) The Parties shall formalize and execute the documents incorporating the
Parties' agreed DCQ and CDC by September 1st of the same Calendar Year.
Such DCQ and CDC to be effective on a date mutually agreed by the Parties.
4.7.1 Sellers shall, during the term of this Agreement, maintain the
Contractual Delivery Capacity ("CDC") of one hundred and ten (110) percent of
the DCQ. Buyers may require Natural Gas from Sellers up to that maximum rate of
CDC at any time during the term of this Agreement notwithstanding that the
aggregate of such daily requirements may exceed the ACQ. Each Buyer shall have
an individual Contractual Delivery Capacity ("CDC*") equal to fifty (50) percent
of the CDC.
4.7.2 Notwithstanding the provisions of Clause 4.6 and Sub-clause 4.7.1 but
subject to Sub-clause 4.12.1 (b), on each scheduled maintenance Day, as referred
to in Sub-clause 4.12.1, Sellers shall deliver and Buyers shall accept delivery
of a minimum volume equal to fifty (50) percent of the applicable DCQ, and such
minimum volume shall, for that Day, be deemed to constitute and be counted as
the CDC for the purpose of determining any Shortfall on Sellers' part and as the
deemed DCQ* for the purpose of determining Buyer's or Buyers' Take-or-Pay
obligation.
4.8.1 If at any time or from time to time after the fifteenth (15th)
Contract Year, part of Sellers' production facilities is damaged by an event
beyond the control of Sellers acting in accordance with the standards of a
Reasonable and Prudent Operator, and
(i) it would be necessary for Sellers to incur any expenditure in order
to repair the damage; and
(ii) a Reasonable and Prudent Operator would not make such additional
expenditure,
then Sellers may serve upon each Buyer notice of a decrease in DCQ* which
notice shall specify the said decreased DCQ* which shall not be less than that
which a Reasonable and Prudent Operator could maintain without making such
expenditure.
4.8.2 If within sixty (60) Days following the receipt of such notice under
Sub-clause 4.8.1, Buyer or Buyers have informed Sellers that it or they
consider(s) the DCQ* or DCQ which a Reasonable and Prudent Operator could
maintain without making such additional expenditure as aforesaid is greater than
the DCQ* or DCQ specified in the notice, or that a Reasonable and Prudent
Operator would make such additional expenditure and the Parties are unable to
agree then either Party may require the matter to be submitted for determination
to an expert to be appointed under the provisions of Article XX and the expert
shall be given access to all material data including raw data available to
Sellers. The DCQ or DCQs* determined by the expert shall be the new DCQ or DCQs*
in effect. However, in no event shall the new DCQ or DCQs* be greater than the
DCQ or DCQs* applicable at the time of the notice as a result of the
determination by the expert.
4.9.1 During each Contract Year each Buyer shall purchase and take
itsindividual Net Annual Contract Quantity ("Net ACQ*") being the sum of the
applicable DCQs* for each Day in the Contract Year multiplied by zero decimal
nine zero (0.90) reduced by one half (1/2) of:-
(i) any Natural Gas properly notified for delivery on any Day which
Sellers have not delivered for any reason other than the failure of Buyers to
accept;
(ii) any Natural Gas properly notified for delivery on any Day which
Buyers have been prevented by Force Majeure from accepting;
(iii) any Natural Gas not delivered by reason of construction or tie-in
work pursuant to Sub-clause 4.12.1.
Each Buyer shall be deemed to have purchased and taken a
portion of total Natural Gas delivered in a Contract Year proportional to
its DCQ*.
4.9.2 If in a Contract Year a Buyer has not taken at least its Net ACQ*,
such Buyer shall pay Sellers the price or prices applicable in that Contract
Year for the quantity equal to the difference between the Net ACQ* and the
quantity of Natural Gas actually taken(the said Contract Year shall be called a
"Debit Year"), and such quantity shall be the Take-or-Pay Gas quantity for that
Contract Year.
Provided that:-
(i) If in any previous Contract Year Buyer has taken and paid for Natural
Gas (other than Natural Gas taken in accordance with Sub-clause 4.10.3) in
excess of its Net ACQ* for that Contract Year (such excess gas hereinafter
being called "Carry Forward Gas"), then such Carry Forward Gas shall be
offset against the Take-or-Pay obligation of such Buyer in subsequent
Contract Years.
(ii) the application of such offset by Carry Forward Gas shall in any
Contract Year be limited to fifteen (15) percent of the Net ACQ* for
that Contract Year and such Buyer shall pay the remainder, if any, of the
Take-or-Pay obligation for that Contract Year.
(iii) the balance (if any) of Carry Forward Gas not so used shall be carried
forward for offset in subsequent Contract Years, provided however that
Carry Forward Gas shall only be used to offset such Buyer's obligations
in the five (5) Contract Years following the Contract Year in which the
offset was earned.
4.9.3 When under Sub-clause 4.9.2 a Buyer has paid for a quantity of Natural
Gas not taken in a Debit Year, such Buyer may in any or all of the subsequent
Contract Years take free of charge, after such Buyer has taken the Net ACQ* for
that Contract Year, a quantity of Natural Gas up to the quantity of Natural Gas
so paid for in respect of the Debit Year or Years.
Provided that this Clause shall not oblige Sellers to deliver Natural Gas
in excess of the CDC on any Day.
4.10.1 Not later than ten (10) o'clock a.m. each Friday Buyers'
Representative, as stipulated in Article XXIV, shall notify Sellers'
Representative of the quantity of Natural Gas nominated by Buyers for each Day
of the following week. Such quantity shall be delivered at a rate which if
sustained throughout the Day will provide not more than the CDC, and so far as
reasonably practicable, Sellers shall deliver and each Buyer shall receive at a
rate as consistent as possible throughout the Day, with due consideration for
the normal fluctuations caused by demand variations and operational control of
facilities.
4.10.2 Buyers' Representative may at any time before or during any Day call
for the rate of delivery previously notified to be varied to any extent within
the limit of Clause 4.7 and Sub-clause 4.9.1 and Sellers shall use reasonable
endeavors to comply with such request except that:-
(i) Any request for a change of equal to or less than ten (10) percent
must be complied with within six (6) hours.
(ii) Any request for a change of greater than or equal to ten (10)
percent but less than twenty-five (25) percent must be complied with within
twelve (12) hours.
(iii) Any request for a change of twenty-five (25) percent or greater
must be complied with within twenty-four (24) hours.
4.10.3 At the request of Buyers, Sellers shall deliver Natural Gas at a rate
exceeding the limits in Sub-clauses 4.7.1 and 4.7.2 if in Sellers' sole judgment
they are from a technical point of view reasonably able to do so.
4.10.4 For the purpose of this Agreement, the Natural Gas quantity properly
notified for delivery on any Day shall be that quantity which would be tendered
for delivery if the delivery rate or rates required by Buyer or Buyers had been
sustained throughout the number of hours for which the rate was or the rates
were required to be effective.
Provided that if Buyers have in fact called for a rate exceeding the
applicable CDC, the properly nominated quantity shall be calculated as if the
rate called for had been that of the applicable CDC.
4.11 After any event causing a total cessation of Natural Gas deliveries,
Sellers, while using reasonable endeavors to meet Buyer's or Buyers'
nominations, shall, subject to the provisions of this Agreement, be relieved
from the consequences of any failure to deliver the properly nominated quantity
in full for a period of twenty-four (24) hours from the time of resumption of
deliveries.
4.12.1 (a) For each Year there shall be allocated sufficient time for
planned maintenance work of Sellers' production and delivery facilities. The
annual maintenance schedule is to be drawn up by Sellers and agreed to by Buyers
prior to the start of each Year and such agreement shall not to be unreasonably
withheld. Each annual maintenance schedule shall consist of the number of
maintenance Days for that Year and the dates planned for the performing of
maintenance work, as required by Sellers acting to the standard of a Reasonable
and Prudent Operator.
(b) It is agreed that Sellers' delivery obligation may, based on prudent
operatorship, be reduced to zero (0) percent DCQ provided that:-
(i) it shall only be applicable until duplicate production
facilities are installed; and
(ii) it shall only be for the purpose of Sellers' simultaneous
repair and maintenance of their equipment and facilities; and
(iii) it shall not exceed a period of forty-eight (48) hours. The
Parties recognize that the forty-eight (48) hours is dependent upon the
extent and flexibility of Buyers' line-pack and that such period will be
shortened if Buyers' line-pack or flexibility is reduced.
(c) Following installation of duplicate production facilities, the
minimum volume of DCQ to be maintained by Sellers shall not be less than fifty
(50) percent of the agreed DCQ.
(d) Such minimum volume shall, for that Day, be deemed to constitute
and be counted as the CDC for the purpose of determining any Shortfall on
Sellers' part and as the deemed DCQ for the purpose of determining a Buyers'
Take-or-Pay obligation.
(e) Each Day during the maintenance schedule shall be referred to as a
"Scheduled Maintenance Day".
(f) The maximum allowable maintenance Days for each Year shall be ten
(10) Days. Days on which construction or tie-in work required for installation
of booster compression, bringing future offshore fields online and other similar
operations required from time to time ("Construction Days") shall not be
considered as part of the Scheduled Maintenance Days.
(g) The Parties may mutually agree to change the maximum allowable
maintenance Days, such agreement shall not be unreasonably withheld, as
necessary by taking into account amongst others;
(i) the condition and age of Sellers' facilities;
(ii) any significant changes in production levels;
(iii) any significant changes affecting Sellers' production operations;
(iv) any maintenance work which may not be necessary on an annual
basis but at intervals of more than one Year at a time; and
(v) the condition and age of Buyer's or Buyers' facilities and its
or their scheduled Maintenance Days as may be required by Buyer or Buyers.
4.12.2 The Parties shall confer on a regular basis and to every reasonable
extent possible shall schedule their respective planned maintenance work to
coincide on the same Day or Days. For any planned maintenance work that is to be
carried out on any dates other than those as planned, the Party wishing to
conduct such work shall give the other Party at least five (5) Days written
notice in advance of the Day or Days to be utilized for such work. Such Day or
Days shall be part of the maximum allowable maintenance Days described in
Sub-clause 4.12.1 (f), and not additional thereto.
4.12.3 Based on Sellers' maximum allowable maintenance Days for any Contract
Year, Buyer or Buyers may utilize equal time for planned maintenance of its or
their gas transmission facilities, gas separation plants and other related
facilities. Buyers shall use reasonable endeavours to ensure that their
maintenance work coincides with Sellers scheduled maintenance days.
4.12.4 Sellers shall give written notice to Buyers at least one hundred
eighty (180) Days prior to Construction Days, and shall as a prudent operator,
designate a number of Days in which this work shall be fully performed. At
least forty-five (45) Days prior to commencing such work, Sellers shall notify
Buyers of the proposed timing and duration of the work. The proposed timing and
duration shall have to be agreed by Buyers, such agreement shall not be
unreasonably withheld. With such notice Sellers shall indicate a minimum volume,
which may be zero (0) percent of the applicable DCQ, for each Construction Day,
and such minimum volume shall, for that Day, be deemed to constitute and be
counted as the CDC for the purpose of determining any Shortfall on Sellers' part
and as the deemed DCQ for the purpose of determining a Buyers' Take-or-Pay
obligation.
ARTICLE V
SELLERS' RESERVATIONS
There are reserved to Sellers the following:
5.1 Without prejudice to the nature and extent of the obligations of Sellers
under this Agreement the right to decide the manner in which they shall conduct
their physical operations.
5.2 The right to use Natural Gas produced by Sellers from the Reservoir for
any of the following purposes to the extent that they may be necessary or
convenient for the fulfillment of their obligations under this Agreement,
including but not limited to:
(i) the operation of Sellers' field facilities, process facilities and
other miscellaneous uses, including flaring, relating to production from the
Reservoir; and
(ii) gas lift operations, repressuring, pressure maintenance or cycling
operations within the Reservoir.
5.3 The right to process the Natural Gas recovered before delivery to Buyers
for the removal of any constituents other than methane, ethane, propane and
butane (except such minimum amounts of methane, ethane, propane and butane as
would necessarily be removed in the recovery of such constituents). Such removed
constituents shall not be a part of this Agreement.
5.4 Any right as may be exercisable by Sellers under this Article V shall
not adversely affect Sellers' obligation to deliver and sell Natural Gas to
Buyer or Buyers and Buyer's or Buyers' right to take and purchase Natural Gas
from Sellers under this Agreement.
<PAGE>
ARTICLE VI
BUYERS' FACILITIES
6.1 Buyers shall provide at their expense such facilities as may be
necessary to connect Sellers' nominated platform(s) or other related facilities
to Buyers' gas transmission pipelines, gas separation plant and such other
downstream facilities as may be necessary to enable Buyers to transmit and
dispose of the Natural Gas on and after the DCD at the rate or rates calculated
as herein provided.
6.2 Sellers will arrange to make space available on the portion of their
Production Platform(s) or other related facilities that faces the Buyers'
sealine for the installation and operation of Buyers' gas transmission pipelines
and such other facilities, and Buyers agree to compensate Sellers for any proper
cost as may reasonably be incurred by Sellers thereby. Any specific arrangements
for Buyers' facilities tie-ins shall be the subject of a separate utilization
agreement between the Parties.
Buyers shall give written notice to Sellers at least one hundred eighty (180)
Days prior to commencing construction, installation, testing and commissioning
Buyers' sealine and riser and other related facilities to be installed on or
within three (3) kilometers of Sellers' facilities, and shall designate the
thirty (30) Day period in which this work shall be fully performed. At least
forty five (45) Days prior to commencing such work, Buyers shall notify Sellers
of the fourteen (14) Day period in which the work shall be fully performed,
providing that the fourteen (14) Day period must be completely contained within
the thirty (30) Day period originally designated by Buyers.
All such construction, installation, testing, and commissioning shall be
conducted so as to minimize any interruption of or interference with platform
operations, as reasonably judged by Sellers. Buyers shall indemnify and hold
Sellers harmless in respect of any damages suffered by Sellers, or claimed by
third parties, in anyway related to such operations by Buyers.
<PAGE>
ARTICLE VII
EXCHANGE OF INFORMATION
7.1 The Parties will at all times give to each other all such information
necessary to enable each Party to carry out its obligations under this Agreement
and in particular (but without prejudice to the generality of the foregoing)
will meet together approximately three (3) Months before each new Contract Year
to exchange and discuss written forecasts which shall indicate future programs
of operations and expectations for succeeding years.
7.2 Within the first Contract Year Buyers shall give Sellers a list of basic
data that they require necessary to permit Buyers to determine Field Reserves.
Sellers shall give to Buyers all such basic data whether or not notice of a
redetermination of Field Reserves has been given under Clause 8.2. This basic
data shall be given to Buyers within thirty (30) Days after the end of each
Contract Year.
7.3 All information given under this Article shall be given at the expense
of the Party providing the same and shall not be disclosed to any person not in
the service or employment or professionally retained by the Party receiving the
same or in the service or employment of the Government of Thailand and the
Government of Malaysia who is/are entitled to receive the same. Any information
disclosed hereunder shall be so disclosed only on condition that the recipient
shall make no further disclosure thereof.
<PAGE>
ARTICLE VIII
DETERMINATION OF RESERVES
8.1 Without prejudice to Sub-clauses 4.6.1, 4.6.2, 4.6.3, and 4.6.4:-
(i) Either Buyer or Buyers, or, Sellers may, at any time or from time
to time, by notice in writing to the other, require a redetermination of the
Field Reserves.
(ii) Field Reserves shall be redetermined in accordance with the
requirements of this Article VIII and good oil and gas industry practice. The
Field Reserves so redetermined shall become effective according to Clause 8.2
and shall be used to calculate the DCQ to be agreed between the Parties.
(iii) Unless the Parties shall expressly agree to the contrary, no
notice requiring a redetermination shall be given before the expiration of one
(1) Year from the completion date of the previous redetermination.
8.2 If the Parties agree upon the result of such redetermination, the Party
requesting such redetermination shall issue a notice of completion of
redetermination specifying the new quantity of Field Reserves. If the Parties do
not so agree, then within sixty (60) Days of the notice requiring the
redetermination, either Buyer or Buyers or Sellers may require that a
redetermination to be carried out by an expert appointed pursuant to Article XX,
who shall be given access to all material data including raw data available to
Sellers and Buyer or Buyers. The expert shall then issue a written report
specifying the new quantity of the Field Reserves. The Field Reserves as so
redetermined shall become effective for all purposes of this Agreement on the
Day of the issuance of a notice of completion by the Party or the written report
by the expert as the case may be.
8.3 For any redetermination conducted pursuant to Clauses 8.1 and 8.2, the
Field Reserves shall contain all Proved Natural Gas Reserves and no more than
twenty (20) percent of the total Field Reserves shall be Probable Natural Gas
Reserves.
<PAGE>
ARTICLE IX
PRICE AND PRICE ADJUSTMENT
9.1 Natural Gas delivered under this Agreement in each Contract Year (or to
be paid for whether delivered or not) shall be paid for in the manner and at the
prices following.
9.2 The Initial Base Price (IBP) shall be US. Dollars two decimal three zero
(2.30) for each one million (1,000,000) BTUs.
9.3.1 In the Month immediately preceding the RIP established under
Sub-clause 4.2.3 and in the Month of September every Year thereafter for the
duration of this Agreement, the IBP shall be used to calculate the Current Price
in the following manner and the Current Price so obtained shall become effective
on the first (1st) Day of October immediately following and remain effective
until the thirtieth (30th) Day of September the following Year unless previously
changed under Sub-clause 9.3.3.
9.3.2 Four prices (Ay, By, Cy, Dy) shall be calculated according to the four
formulae in Sub-clauses 9.3.2(i), 9.3.2(ii), 9.3.2(iii) and 9.3.2(iv) below:
(i) Ceiling Price
Ay = 1.1(IBP)(Fy/F)
(ii) Normal Price
By=IBP[0.25(CPIy/CPI)+0.25(OMy/OM)+0.35(Fy/F)+0.15]
(iii) Floor Price
Cy=(IBP-$0.125)[0.25(CPIy/CPI)+0.25(OMy/OM)+0.2(Fy/F)+0.3]
(iv) Special Floor Price
Dy = Ay+Cy
-----
2
Where:
F is agreed to be US $14.500000 per barrel.
Fy = the arithmetic average of the figures last published for each
Month of the calendar Year immediately preceding the Year in which the prices
have to be adjusted in United States Dollars per barrel of medium fuel oil (180
CST) ex Singapore from BP Oil International, Caltex Petroleum Corporation, Shell
Eastern Petroleum PTE Ltd., Mobil Sales and Supply Corporation, Singapore
Petroleum Corporation PTE Ltd. and Esso Singapore PTE Ltd. as published in
Platt's Oilgram Price Service.
CPI = the arithmetic average of the figures published for each
Month of the twelve (12) Month period, inclusive, for the Consumer Price Index
number in the United States of America, all items, all urban consumers (CPI-U)
based on 100 for the calendar Year 1982-84 as published by the United States
Department of Labor, Bureau of Labor Statistics. "CPI" is agreed to be one
hundred forty seven decimal three six six six six seven (147.366667) for the
time period 1st October, 1993 to 30th September, 1994.
CPIy = the arithmetic average of the figures published as for CPI
above in respect of the twelve (12) Month period ending twelve (12) Months prior
to the date on which the prices will be adjusted pursuant to Sub-clause 9.3.1.
OM = the arithmetic average of the figures published for each Month
of the twelve (12) Month period, inclusive, for the Producer Price Index for Oil
Field and Gas Field Machinery and Tools, Commodity Code No. 1191, based on 100
for the calendar Year 1982 as published by the United States Department of
Labor, Bureau of Labor Statistics. OM is agreed to be one hundred ten decimal
zero eight three three three three (110.083333) for the time period 1st October,
1993 through 30th September, 1994.
OMy = the arithmetic average of the figures published as for OM
above for each Month of the twelve (12) Month period ending twelve (12) Months
prior to the date on which the prices will be adjusted pursuant to Sub-clause
9.3.1.
9.3.3 The Current Price shall be:
(i) "By" if "Ay" is greater than "By" and "By" is greater than "Cy";
(ii) "Ay" if "By" is greater than "Ay" and "Ay" is greater than "Cy";
(iii) "Cy" if "Ay" is greater than "Cy" and "Cy" is greater than "By";
(iv) "Dy" if "Cy" is greater than "Ay".
The Contract Price paid to Sellers by Buyers shall be the Current Price until a
cumulative zero decimal five zero (0.50) Trillion Cubic Feet of Natural Gas has
been delivered from the Contract Area by Sellers and paid for by Buyers. For
deliveries in excess of zero decimal five zero (0.50) Trillion Cubic Feet of
Natural Gas until a cumulative one decimal three zero (1.30) Trillion Cubic Feet
of Natural Gas has been delivered from the Contract Area and paid for by Buyers,
the Current Price shall be multiplied by zero decimal nine five (0.95) to obtain
the Contract Price to be paid to Sellers by Buyers. For deliveries from the
Contract Area in excess of a cumulative one decimal three zero (1.30) Trillion
Cubic Feet of Natural Gas the Current Price shall be multiplied by zero decimal
nine zero (0.90) to obtain the Contract Price to be paid to Sellers by Buyers.
9.4.1 If any of the factors used in this Clause 9.3 are not made available
on a timely basis, pricing and payment shall be made on a provisional basis
using the best estimates available and shall be adjusted retroactively when the
final figures become available.
9.4.2 If at any time or from time to time any of the indices or sets of
statistics used in this Article IX shall be discontinued, or if either Party
considers any of the indices or sets of statistics to be so changed or become so
out-of-date that it ceases to fulfil the objective for which it was intended by
the Parties as evidenced by the context in which it was used in this Agreement
then that Party may so notify the other Party. The Parties shall in good faith,
endeavour to mutually agree to new indices or sets of statistics.
9.4.3 If, within sixty (60) Days of the notification under Sub-clause 9.4.2
the Parties have failed to so agreed then at the request of either Party the
matter shall be referred to an expert appointed under Article XX and such expert
shall, as the case may require, either amend such index or set of statistics or
replace the same with some new or other appropriate index or set of statistics.
9.5 If, for any reason, any of the components of the final data, namely, Fy,
CPIy, and OMy are not published or made available for use in Clause 9.3 when it
becomes necessary to recalculate a new Current Price, then such adjustment shall
be provisionally made using the arithmetic average of the latest available
twelve (12) Months in the calculation of CPIy, OMy, or Fy as the case may be and
the final adjustment shall be made within thirty (30) Days of all of the
components of the final data becoming available. Such final adjustments shall
have retroactive effect.
9.6.1 All figures in calculations performed under this Article IX shall at
each stage in the calculation be rounded to six (6) decimal places by rounding
off the (7th) seventh decimal place, a five (5) in the (7th) seventh decimal
place being rounded upwards.
9.6.2 The final figures used for the prices payable under this Article IX
shall be rounded to four (4) decimal places by rounding off the (5th) fifth
decimal place, a five (5) in the (5th) fifth decimal place being rounded
upwards.
9.7 Payment for any Natural Gas delivered by Sellers to Buyer or Buyers from
the DCD until the successful conclusion of the Test Period shall be at
seventy-five (75) percent of the Contract Price. Such volumes of Natural Gas
paid for at this discounted price shall be excluded from the calculation of the
cumulative sales by Sellers to Buyers referred to in Sub-clause 9.3.3.
The actual price to be paid for any Natural Gas delivered at the earlier of
the successful completion of the Test Period or the CDD shall be at the Contract
Price pursuant to Sub-clause 9.3.3 or at the reduced price applicable under
Articles XI, XII, and XIV.
9.8 Effective from the CDD, Buyers shall pay Sellers (in the manner provided
in Article X) for an amount of Natural Gas equal to the Net ACQ for each
Contract Year at the Contract Price or at the reduced prices applicable under
Articles XI, XII and XV in the following priority:
(i) Firstly for such volumes of Natural Gas to which the reduced prices
under Articles XI, XII and XV shall apply at such reduced prices.
(ii) Secondly for the remaining balance, if any, of the Net ACQ, at the
Contract Price.
9.9 Any Natural Gas taken in each Contract Year in addition to the Net ACQ
shall be paid for in the following priority:
(i) Firstly, such volumes of Take-or-Pay Gas as each Buyer has paid for but
not taken in Debit Years in accordance with Sub-clauses 4.9.2 and 4.9.3 shall be
free of charge.
(ii) Secondly, the remaining balance, if any, of the volumes of Natural
Gas to which the reduced prices under Article XI, XII, and XV apply.
(iii) Thirdly, the remaining balance, if any, at the Contract Price.
<PAGE>
ARTICLE X
BILLING AND PAYMENT
10.1 On or before the tenth (10th) Day of each Month, beginning the Month
following the Month in which the DCD occurs, Sellers shall render or cause to be
rendered to Buyers' Representative a statement and invoice showing for the
preceding Month:-
(i) the quantity of Natural Gas properly nominated by Buyers'
Representative for delivery on each Day and the amount of Natural Gas delivered
by Sellers to Buyers hereunder on each Day expressed in Cubic Feet and million
BTUs;
(ii) the DCQ and DCQs* applicable on each Day;
(iii) the quantity of Natural Gas actually taken by Buyers each Day;
(iv) the Shortfall for each Day and the cumulative Shortfall for that
Month for each Buyer;
(v) the adjustment (if any) in the ACQ and ACQs* to be made in respect
of that Month;
(vi) the Gross Calorific Value of the Natural Gas delivered in each Day
expressed in BTU per Cubic Foot;
(vii) the sum due from each Buyer and owing to each of the Sellers
under Article IX for Natural Gas delivered during the Month and any prior Month
showing the quantities at the different prices if applicable;
(viii) any sums due and owing to each Buyer under Article XI;
(ix) the net sum payable to each Seller; and
(x) any other relevant information or data as may be agreed between
Parties.
10.2 On or before the January 31st of each calendar Year, Sellers shall
render or cause to be rendered to each Buyer an annual statement and invoice for
the preceding Contract Year, or portion thereof, showing:
(i) the total quantity of Natural Gas delivered hereunder in total and to
each Buyer in the preceding Contract Year expressed in Cubic Feet and million
BTUs;
(ii) the Net ACQ and the Net ACQs* for that Contract Year;
(iii) the quantity (if any) of undelivered Natural Gas (expressed in
Cubic Feet and million BTUs calculated from the weighted average Gross Calorific
Value of the Natural Gas delivered during that Contract Year) for which each
Buyer must pay under Clause 9.8;
(iv) the quantities (if any) of Carry Forward Gas each Buyer earned
during that Contract Year, the quantity (if any) of Carry Forward Gas used
during that Contract Year and the balance (if any) of Carry Forward Gas
remaining at the end of that Contract Year;
(v) the quantity (if any) of Natural Gas delivered which is free of
charge to each Buyer under Sub-clause 9.9 (i);
(vi) the net sum or sums (if any) payable by one Party to another in
respect of such quantity or quantities; and
(vii) any other relevant information or data as may be agreed between
Parties.
Provided that if by the thirty first (31st) Day of January of a given
calendar Year Sellers shall not have rendered an annual statement and invoice,
then Buyer or Buyers may itself or themselves prepare the same and render it to
Sellers.
10.3 On or before the thirtieth (30th) Day of each Month, or the twentieth
(20th) Day following receipt of the statement for that Month, whichever is later
each Buyer shall pay Sellers the net sums set out in the statement under
Sub-clause 10.1 (ix).
10.4 On or before the twenty eighth (28th) Day of February each Year, or the
twentieth (20th) Day following receipt of the relevant statement, whichever is
later each Buyer or Sellers (as the case may be), shall pay the net sum or sums
(if any) referred to in Sub-clause 10.2 (vi).
10.5 Where any sum is in dispute the undisputed portion shall promptly be
paid and after settlement of the dispute any amount agreed or otherwise
determined to be due shall be paid within fourteen (14) Days after such
agreement or determination with interest thereon in accordance with Clause 10.7.
10.6 Payment under this Article X shall be made by wire transfer, or other
method as the Parties may agree, in US Dollar to the credit of each of Sellers
or Buyers (as the case may be) at such place as each Party may request or at
such other place as the Parties may agree.
10.7 Should any Party fail to make payment to another of any sum due
hereunder interest thereon shall accrue equal to London Inter-Bank Offered Rate
(LIBOR) rate for US Dollar for one (1) Month as published in the Financial Times
of London plus two (2) percent, except to the extent that the failure to make
payment arose from an error on the part of the Party to whom payment was due to
be made.
10.8 Buyers and Sellers shall have the right at reasonable hours to examine
the books, records and charts of the other Party relative to this Agreement to
the extent necessary to verify the accuracy of any statement, charges or
computation made pursuant to any of the provisions of this Agreement. Provided
that:
(i) such books, records and charts need not be preserved longer than a
period of four (4) Years from the date of recording; and
(ii) if any such examination reveals any inaccuracy in any billing
theretofore made the necessary adjustment shall be made promptly but in any
event, no adjustment shall be made after four (4) Years from the date of
recording and such adjustment shall include interest on the adjustment amount
over the period from the date on which such adjustment first accrued to the date
such adjustment is paid, at a rate equal to LIBOR plus two (2) percent.
<PAGE>
ARTICLE XI
QUALITY
11.1 From the CDD and thereafter Natural Gas delivered by Sellers to Buyers
under this Agreement shall, at the Delivery Point(s), be in accordance with the
quality specifications set out in the Second Schedule to this Agreement.
11.2 From the CDD and thereafter, if at any time or from time to time the
Natural Gas offered for delivery hereunder shall fail to conform to the
specifications set out in the Second Schedule and each Buyer or Buyers become
aware by notification from Sellers or otherwise, each Buyer or Buyers after
using reasonable endeavors to accept as much of the deficient Natural Gas
offered as is possible, may either:
(i) refuse to accept delivery of the Natural Gas in whole or in part
until the deficiency has been remedied and in the event of such refusal, Buyers'
only rights and remedies shall be as set forth in Article XV; or
(ii) accept delivery of the Natural Gas in whole or in part
(notwithstanding the deficiency in quality). Each Buyer may recoup from Sellers
all reasonable expenses of a temporary nature incurred by each Buyer incidental
to the acceptance of such quality-deficient Natural Gas and all actual and
reasonable costs incurred by each Buyer in the course of any temporary measures
which each Buyer or Buyers may take to render the Natural Gas in compliance with
the quality specifications upon presentation of supporting cost documents by
reducing the price to be paid to Sellers of Natural Gas to be delivered
thereafter by twenty (20) percent until such cost is fully repaid. Sellers'
liability hereunder to Buyers in any Month shall never exceed the value of an
amount of Natural Gas that would be delivered in two days at the DCQ and
Contract Price in force adjusted by the weighted average Gross Calorific Value
for the Natural Gas delivered during the preceding twelve (12) Months.
11.3 Sellers shall as soon as possible after any failure in Natural Gas
quality inform Buyers' Representative of the cause of such failure and give an
estimate of the probable duration of such failure.
11.4 Within thirty (30) Days after any failure in Natural Gas quality
Sellers may give notice to Buyers' Representative that Sellers propose within a
period of not more than one hundred and eighty (180) Days to carry out the works
necessary to remedy the deficiency in quality and in such event during the
period mentioned in such notice or for so long as during such period Sellers are
actively and diligently carrying out the said works each Buyer or Buyers shall
not be entitled to carry out any remedial works of a permanent nature but may
either refuse or accept delivery of Natural Gas in the manner set out in Clause
11.2.
11.5 If Sellers shall not have served a notice within the period mentioned
in Clause 11.4 or (having served a notice) shall have ceased to carry out the
works actively and diligently, then (in either such event) Buyer or Buyers may
carry out such works as may reasonably be required to remedy the deficiency in
quality after completion of the same, and upon submittal of cost documentation,
may recover the cost (and interest thereon in accordance with Clause 10.7), not
to exceed the value of a volume of Natural Gas that would be delivered in
fourteen (14) Days at the DCQ and Contract Price in force adjusted by the
weighted average Gross Calorific Value for the Natural Gas delivered during the
preceding twelve (12) Months, from Sellers by reducing the price of Natural Gas
to be delivered thereafter by twenty (20) percent until such cost (and interest)
is repaid.
11.6 During any period in which Buyer or Buyers are carrying out any
remedial works under Clause 11.5, they may either refuse or accept delivery of
Natural Gas in the manner set out in Clause 11.2.
11.7 Any difference between the Parties which may arise in respect of the
quality of the Natural Gas or the cost incurred in remedying any deficiency
therein or in connection with the carrying out of any remedial works under this
Article XI shall (at the request of either Party) be referred to an expert to be
appointed pursuant to Article XX.
ARTICLE XII
DELIVERY PRESSURE
12.1 From the CDD and thereafter, Natural Gas to be delivered under this
Agreement shall be delivered at the Delivery Point(s) at such pressure as
Buyers' Representative shall specify, which shall thereafter be the "Contract
Delivery Pressure", taking into account Buyer's or Buyers' back pressure at the
Delivery Point at the time of delivery, but not to exceed two thousand (2000)
PSIG.
12.2 If, at any time or from time to time from the CDD and thereafter, the
Natural Gas offered for delivery hereunder is not at the Contract Delivery
Pressure, Buyer or Buyers may either:-
(i) refuse to accept delivery of the Natural Gas in whole or in part
and in the event of such refusal Buyer or Buyers only rights and remedies shall
be as set forth in Article XV; or
(ii) accept delivery of the Natural Gas in whole or in part and in such
event the Natural Gas accepted shall be paid for at a price equal to eighty (80)
percent of the Contract Price.
<PAGE>
ARTICLE XIII
MEASUREMENT
13.1.1 Natural Gas delivered under this Agreement shall be measured in Cubic
Feet and BTUs according to the procedure set out in the Third Schedule attached
hereto.
13.1.2 Sellers' Equipment shall include, but not be limited to, all
measuring and testing equipment and related housings, devices, materials,
equipment and appliances, and shall be furnished, installed, maintained and
operated by Sellers at their own expense.
Provided that Buyer or Buyers may, at their own expense, install and
operate check measuring and testing equipment which shall not interfere with the
use of Sellers' Equipment.
13.1.3 Sellers shall provide in respect of Sellers' Equipment such
reasonable alternative facilities as shall ensure that withdrawal of any
individual component or part for maintenance or adjustment does not affect the
supply of Natural Gas.
13.1.4 Buyer or Buyers shall have the right from time to time and at all
times upon giving reasonable notice to Sellers' Representative to inspect or
cause to be inspected Sellers' Equipment and the charts and other measurements
or test data of Sellers but the reading, calibration and adjustment of Sellers'
Equipment and the changing of any charts shall be carried out only by Sellers
who shall preserve all original test data, charts and other similar records for
a period of four (4) Years and shall make a copy thereof available to Buyers'
Representative at any time upon reasonable advance request.
The Parties agree that each Buyer or Buyers or its/their employees, agents
or representatives may enter upon any facilities owned or installed by Sellers
pursuant to this Article XIII at the sole risk and expense of such Buyer or
Buyers.
Provided further that each Buyer or the Buyers shall afford to Sellers the
same rights of inspection and verification at the sole risk of Sellers in
respect of all check measuring and testing equipment installed at its check
measurement station by Buyer or Buyers in respect of the Natural Gas delivered
hereunder.
13.2.1 Each component of the measuring and testing equipment shall be
adjusted to operate accurately within a limit prescribed by the manufacturer but
which shall not in any case exceed a limit of one (1) percent.
13.2.2 The accuracy of Sellers' Equipment shall be verified by Sellers once
in every Month during the Contract Period or at such other frequency as may be
agreed (and at other times if so required by either Party) and Sellers shall
give to Buyers' Representative sufficient prior notice of the date, time and
nature of every verification to enable a representative of each Buyer or Buyers
to be present. The results of any verification shall be binding on the Parties
unless either Buyer or Buyers shall within seven (7) Days after such
verification give notice to Sellers that it or they dispute(s) the accuracy of
such verification.
13.2.3 Verifications shall be made at the expense of Sellers but each Buyer
or Buyers shall bear the cost of the attendance of its representatives at any
verification and shall bear the whole expense of any verification made at its
request if the accuracy of the equipment concerned is found to be within the
limits mentioned in Sub-clause 13.2.1.
13.3 If, at any time or from time to time during the continuance of this
Agreement, any component of Sellers' Equipment is found to be out of service or
registering outside the limits of accuracy agreed under Sub-clause 13.2.1,
Sellers shall forthwith adjust it to read accurately within the limits mentioned
in Sub-clause 13.2.1 or (if that is not possible) replace it with a serviceable
component and (unless Sellers and Buyer or Buyers shall otherwise agree) the
following provisions shall apply with regard to earlier readings affected by the
defective component.
(i) No correction shall be made in respect of readings made during the
period before the period immediately preceding verification of the defective
component;
(ii) If the time at which the component became defective can be
established, then readings affected thereby shall be corrected with effect from
that time in the manner provided by paragraphs (a), (b), and (c) of Sub-clause
13.3 (iii);
(iii) If the time at which the component became defective cannot be
established, then the time which has elapsed since the immediately preceding
verification shall be divided into two (2) equal parts and estimated readings
shall be established in respect of the first such part by assuming that the
defective component has operated accurately throughout such part and in respect
of the second such part:
(a) by using the readings recorded by any check measuring or
testing equipment if such equipment shall be registering accurately within the
limits mentioned in Sub-clause 13.2.1; or
(b) if such equipment shall not be registering accurately or if no
such equipment shall have been installed; by correcting the error if the
percentage of error is ascertainable to the satisfaction of both Parties by
calibration test or mathematical calculation; or
(c) if the percentage of error is not so ascertainable; by
estimating the quantity and/or quality of Natural Gas delivered by reference to
deliveries under similar conditions when the defective component was registering
accurately.
13.4 The Parties shall meet to discuss and to endeavor to settle any dispute
which may arise with regard to the application of the provisions of this Article
XIII or the measurement of the quantity of Natural Gas delivered and if within
thirty (30) Days after the commencement of such meeting they shall have been
unable to agree, the matter shall then be referred to an expert to be appointed
under the provisions of Article XX.
<PAGE>
ARTICLE XIV
POINT OF DELIVERY, TITLE AND RISK
14.1 Natural Gas to be delivered under the terms of this Agreement shall be
delivered by Sellers to each Buyer at the Delivery Point(s) specified in the
Fourth Schedule attached hereto.
Should future development require additional Delivery Point(s) both Parties
shall meet in good faith with the view to agreeing on such additional Delivery
Point(s).
14.2 The title and risk in the Natural Gas delivered by Sellers shall pass
to Buyers at the Delivery Point(s).
Provided that, if any Natural Gas so delivered is deficient in quality at
the moment of its passage through a Delivery Point, regardless of Buyer's
knowledge of such quality deficiency, such Natural Gas, for the purposes of this
Agreement, shall be deemed to have been delivered and Buyers may recoup from
Sellers for any damages incurred by Buyers in consequence of such deficiency up
to a monetary amount equal to the value of a volume of Natural Gas that would be
delivered in six (6) Days at the DCQ and Contract Price in force adjusted by the
weighted average Gross Calorific Value for the Natural Gas delivered during the
preceding twelve (12) Months by reducing the price of Natural Gas to be
delivered thereafter by twenty (20) percent until such cost is repaid which
recoupment shall be in place of any other rights and remedies of each Buyer.
14.3 As soon as reasonably practicable upon notification by Buyers'
Representative of the occurrence of a breakage of a sealine causing an escape of
Natural Gas, Sellers shall stop delivering Natural Gas and Buyer or Buyers shall
not be required to pay for any Natural Gas passing the respective Delivery
Point(s) after such breakage has been notified, provided that Buyer or Buyers
shall, in good faith, promptly and diligently repair such breakage.
<PAGE>
ARTICLE XV
DEFAULT
15.1 Except as otherwise provided in this Article XV and Clauses 11.2 and
12.2, each Party shall be liable to the other in the event of such Party's
default or breach of an obligation hereunder only for actual costs, expenses and
damages incurred by such other Party as the direct result of such default or
breach.
15.2 Except as otherwise provided under Clause 15.3, if, after the CDD,
Sellers fail to deliver on any Day the quantity, or any portion thereof, of the
Natural Gas properly notified by Buyers' Representative for delivery on that Day
(the deficient quantity being termed "Shortfall"), Buyer's remedy shall be the
right to take as soon as possible as part of the Net ACQ in the following Month
(or Months if required) a quantity of Natural Gas equal to the quantity of
Shortfall at a reduced price equal to seventy-five (75) percent of the Contract
Price applicable at the time the Shortfall occurred.
Whenever this Clause 15.2 is applicable, the rights provided herein shall
be in place of any and all other rights and remedies, including any right to
damages, that Buyer or Buyers might otherwise have been entitled to.
15.3 Regardless of whether or not Clause 15.2 is applicable, Sellers shall
not be liable to either Buyer for failure to deliver the quantity of Natural Gas
properly notified for any Day:
(i) If Sellers have been prevented by Force Majeure from delivering
such Natural Gas; or
(ii) If Buyer or Buyers have failed to accept delivery of such Natural
Gas (unless the Buyer or Buyers have properly refused to accept delivery under
Article XI or Article XII).
15.4 The maximum liability of any Buyer in respect of non-fulfilment of its
obligations to take Natural Gas hereunder shall be limited to its liability to
pay for gas not taken pursuant to Sub-clause 4.9.2 subject always to Buyer's
rights under Sub-clauses 4.9.3 and 18.3.1.
15.5 In no event shall either Party be liable to the other for indirect or
special damages of any kind nor shall either Party be liable to the other for
damages asserted or claimed to have been suffered by any third party who is not
a Party to this Agreement.
<PAGE>
ARTICLE XVI
FORCE MAJEURE
16.1 In this Agreement, the term "Force Majeure" means any happening, event
or its pernicious results which are beyond the control of a Party acting as a
Reasonable and Prudent Operator, which causes or results in a failure by such
Party to fulfil any obligation (other than obligations to give a notice or to
pay money to another or others of the Parties) under this Agreement.
16.2 Events which may be subject to Clause 16.1 and considered as Force
Majeure events shall include, but not be limited to, acts of government,
strikes, lock-outs, acts of the public enemy, wars whether declared or
undeclared, blockades, insurrection, riots, epidemics, landslides, lightning,
earthquakes, fires, storms, floods, washouts, civil disturbances, protests of
the public which obstruct or cause any delay in the construction of the Pipeline
System as defined in Article 4.2.1 (b), explosions, partial or entire failure,
breakage or accident to the facilities used or required to deliver and receive
Natural Gas including machinery, pipelines, Natural Gas Separation plants, and
related facilities, inability to obtain environmental approvals and permits and
EIA Approval necessary for the installation of the Pipeline System from the
Office of Environmental Policy and Planning of Thailand and/or other relevant
government authorities thereof by September 30, 2000, freezing of wells or
pipelines, partial or entire failure of wells, inability to obtain necessary
materials or supplies due to changes in laws and regulations, material changes
in the obligations of Sellers under the PSC, as may be imposed by the
Government of Thailand or the Government of Malaysia, or the inability of any
customer or customers of Buyer or Buyers to take Natural Gas which it or they
would have taken if such inability is caused by a happening which would have
constituted Force Majeure under Clause 16.1 as if the customer or customers
concerned had been a Party to this Agreement, provided that the customer or
customers claiming Force Majeure is or are capable of accepting gas deliveries
from the pipeline system connected to the Contract Area.
Provided that a Buyer shall have no right to Force Majeure relief hereunder by
reason of the inability of any of its customers to take Natural Gas unless Buyer
shall pro-rate the amount of relief which it requires among all of its relevant
suppliers. Buyer shall quantify the pro-rated reduction in production it
requires from its relevant suppliers by making the following calculation: the
deemed amount of Natural Gas which would have been delivered to the customer
concerned calculated by reference to the average delivery to that customer over
the immediately preceding ninety (90) Days or such lesser period if data from
ninety (90) Days deliveries are not available divided by Buyer's receipts from
all of its relevant Natural Gas suppliers based on the average take of Natural
Gas from each relevant supplier over the same ninety (90) Days or lesser period.
16.3 A Party claiming relief on account of Force Majeure shall:
(i) as soon as practicable give notice to the other Party or Parties of
the happening said to constitute Force Majeure. Such notice shall include full
information about the circumstances and a statement of the steps and time
believed necessary to remedy the failure but neither Party shall be obliged to
settle or prevent any strike or other industrial action except on terms
acceptable to it.
(ii) subject to Article XVIII and Sub-clause 4.8.1 proceed as a
Reasonable and Prudent Operator at its own expense to remedy the failure with
all reasonable dispatch.
16.4 A Party failing to fulfil its obligations (other than the obligations
to give notice or to pay money excepted under Clause 16.1) by reason of Force
Majeure and fulfilling the requirements of Clause 16.3 shall be relieved of its
obligations under this Agreement, so far as they are affected by such Force
Majeure during the continuance of any inability so caused, including without
limitation, liability as follows:
(a) in the case of Sellers to the extent that Force Majeure has
prevented them from delivering Natural Gas that they should have delivered.
(b) in the case of Buyer or Buyers to the extent that Force Majeure has
prevented them or their customers (subject to the proviso of Clause 16.2) from
accepting Natural Gas which they should have accepted or from disposing of the
same.
<PAGE>
ARTICLE XVII
TERM OF AGREEMENT
The term of this Agreement shall begin on the Effective Date, and shall so
continue in force subject to the provisions of Article XVIII, for the duration
remaining in the PSC, or any extension to the PSC unless otherwise mutually
agreed by the Parties. Rights and obligations accrued to and incurred by each
Party prior to termination of this Agreement shall survive such termination.
<PAGE>
ARTICLE XVIII
TERMINATION
18.1 Notwithstanding the provision of Article XVII, this Agreement shall
terminate upon the first occurrence of either of the following:
(i) There is no longer a positive balance of Field Reserves remaining
in the Reservoir. If this Agreement terminates because there is no longer a
positive balance of Field Reserves remaining in the Reservoir, then Sellers
shall reimburse to each Buyer the net amount which each Buyer has paid for gas
pursuant to Sub-clause 4.9.2 but not taken pursuant to Sub-clause 4.9.3.
Reimbursement shall be made within thirty (30) Days of termination, after which
interest shall be paid in accordance with Clause 10.7 until payment is effected;
or
(ii) Upon the termination of the PSC or any extension to the PSC.
18.2 Sellers shall in good faith endeavor to give to Buyers not less than
two (2) Years notice in advance of the date upon which the termination event is
expected to occur but this Agreement shall terminate when such event occurs
whether before or after the date notified by Sellers.
18.3.1 If at any time after Sellers have served a notice of a decrease in
DCQ* under Sub-clause 4.8.1, the sealine connecting the Production Platform with
the shore or any other part of the facilities necessary for the transmission,
compression, treatment or distribution of the Natural Gas which is the subject
of this Agreement is damaged by a happening beyond the control of Buyer or
Buyers acting in accordance with the standards of a Reasonable and Prudent
Operator and
(i) it would be necessary for Buyer or Buyers to incur an expenditure
in order to repair the damage; and
(ii) a Reasonable and Prudent Operator would not make such additional
expenditure,
then Buyer or Buyers, subject to the determination of an expert as
appointed in Sub-clause 18.3.2 below, may reduce their DCQ* or terminate this
Agreement, as appropriate to the extent of the damage, with immediate effect and
if this Agreement is so terminated then Buyer or Buyers and Sellers shall be
excused from all obligations thereafter.
18.3.2 If within sixty (60) Days following the receipt of such notice under
Sub-clause 18.3.1, Sellers have informed Buyer or Buyers that Sellers consider
that a Reasonable and Prudent Operator would make such additional expenditure
and the Parties are unable to agree then either Party may require the matter to
be submitted to an expert to be appointed under the provisions of Article XX and
the expert shall be given access to all material data including raw data
available to Buyer or Buyers.
18.4 Termination under this Article XVIII shall not relieve any Party of an
obligation to pay amounts due and payable to another at the time of termination.
18.5 If any provision or part of this Agreement is void, this Agreement as a
whole shall not be effected thereby, and, if practicable, the remainder of the
provisions hereof shall remain valid and enforceable. Provided, however, that if
such affected provision is considered as essential by any Party, the Parties
shall meet and endeavour in good faith to set out a legal replacement provision.
<PAGE>
ARTICLE XIX
ASSIGNMENT
19.1 No Party shall be entitled to assign any of its rights or obligations
under this Agreement to a third party without the written consent of the other
Parties. Such consent shall not be unreasonably withheld.
<PAGE>
ARTICLE XX
EXPERTS
20.1 The provisions of this Article XX shall apply whenever in this
Agreement it is provided that any person is to be appointed an expert, or that
any matter is to be referred to an expert, or whenever during the term of this
Agreement the Parties agree that a point of difference between them shall be
resolved by an expert.
20.2 The procedure for the appointment of an expert shall be the following:
20.2.1 The Party wishing the appointment of an expert to be made shall give
notice in writing to that effect to the other Parties and in such notice shall
give details of the matter which is proposed to be resolved by the expert.
20.2.2 The Parties shall meet in an endeavor to agree upon a single expert
to whom the matter in dispute shall be referred to for determination.
20.2.3 If within twenty-one (21) Days from the service of the said notice,
the Parties have either failed to meet or failed to agree upon an expert, then
the matter shall forthwith be referred by the Party wishing the appointment to
be made, to the President of the International Gas Union who shall be requested
to make the appointment of the said expert within thirty (30) Days and may in so
doing take such independent advice as he thinks fit. If the President of the
International Gas Union fails to appoint an expert within such thirty (30) Days,
then the Party wishing the appointment to be made shall apply to the Centre for
Technical Expertise of the International Chamber of Commerce ("I.C.C."), Paris,
France, for an appointment of an expert in accordance with the Rules for
Expertise of the I.C.C.
20.2.4 At such time as the Parties agree upon an expert or one is selected
under the foregoing provisions of this Article XX, the Parties shall forthwith
notify such expert of his selection and shall request him to state within
fourteen (14) Days whether or not he is willing and able to accept the
appointment. Acceptance of appointment shall be notified within twenty-four (24)
hours to the other Parties.
20.2.5 If such expert shall be either unwilling or unable to accept such
appointment or shall not have accepted within the said fourteen (14) Days then
unless the Parties are able to agree on the appointment of another expert who is
willing and able to act, the matter shall again be referred to the President of
the International Gas Union who shall be requested to make a further appointment
and if not, then to the I.C.C. for a further appointment, and the process shall
be repeated until an expert who accepts the appointment is found.
20.3.1 No person shall be appointed to act as the expert under this Article
XX unless he shall be qualified by education, experience and training to
determine the matter in dispute, and shall have an international reputation or
expertise in the area of dispute.
20.3.2 No person shall be appointed an expert who at the time of appointment
is an employee, former employee, or any person engaged as a consultant by either
Party, or if such expert has any interest or duty which conflicts with the
duties and functions of the expert for the purpose of the appointment pursuant
to this Agreement. Further, the expert may be removed if he has or acquires at
any time before rendering his decision an interest or duty which conflicts with
the duties and functions of the expert for the purposes of any decision under
this Agreement.
20.4.1 The expert appointed shall make his decision on data, information and
submissions supplied to him by the Parties not later than thirty (30) Days after
his acceptance of the appointment and shall ignore data, information and
submissions supplied and made after such thirty (30) Days unless the same are
furnished in response to a specific request from him. The Parties shall
cooperate with the expert to the fullest extent. The expert shall be provided
access to data and information, which the Parties are able to make available and
which in the judgement of the expert might aid him in making a valid
determination. Representatives of the Parties shall have the right to consult
with the expert and to furnish him written materials, but the expert may impose
reasonable limitations on this right and shall be free to evaluate the extent to
which any data or information is substantiated or pertinent.
20.4.2 If within a reasonable period which shall not in the case of a
redetermination under Article VIII exceed one hundred and eighty (180) Days or
in any other case ninety (90) Days after the acceptance by an expert of the
appointment such expert shall not have rendered a decision, declines to act,
dies or otherwise becomes unable to act as expert hereunder, then at the request
of either Party a new expert shall be appointed under the provisions of this
Article XX and upon the acceptance of appointment by such new expert the
appointment of the previous expert shall cease.
Provided that if the previous expert shall have rendered a decision prior to the
date upon which the new expert accepts his appointment then such decision shall
be binding upon the Parties and the instructions to the new expert shall be
withdrawn.
20.5 The said expert shall be deemed not to be an arbitrator but shall
render his decision as an expert. The report of the expert shall be in writing
and shall set forth his decision and reasons therefore.
20.6 The decision of the expert shall be final and binding upon the Parties
save in the event of fraud, mistake or failure by the expert to disclose any
relevant conflict of interest. A Party acting in compliance with a decision of
the expert shall not be liable for loss or damage suffered by the other Party
resulting from acts or omissions committed by the first mentioned Party which
are necessary for compliance with the expert's decision.
20.7 Each Party shall bear the costs and expenses of all counsel, witnesses,
and employees retained by it but the costs and expenses of the expert shall be
apportioned equally between Sellers and Buyer or Buyers.
<PAGE>
ARTICLE XXI
ARBITRATION
21.1 Any and all disputes between the Parties arising out of or in
connection with this Agreement, including its negotiation, execution,
interpretation, performance or non-performance which they are not by this
Agreement required or entitled to refer for determination to an expert appointed
under the provisions of Article XX shall be solely and finally settled by
arbitration in accordance with the procedures and rules of UNCITRAL and as set
out below. Each Party agrees not to institute any lawsuit in respect of any
dispute falling within the foregoing agreement to arbitrate except to enforce
this Agreement to arbitrate or to enforce the award of the arbitrators .
21.2 If either Party refers a dispute to arbitration, each Party shall
appoint one arbitrator and such arbitrators in turn shall jointly appoint a
third arbitrator.
21.3 Each Party shall inform the other Party of the name of its own
arbitrator within sixty (60) Days from the date on which either Party referred
the dispute to arbitration; and if any Party fails to do so within the
prescribed time, the other Party may request the President of the International
Bank for Reconstruction and Development (hereinafter called "World Bank") to
appoint an arbitrator for the first Party.
21.4 The arbitrators shall appoint the third arbitrator within sixty (60)
Days from the date on which both arbitrators have been appointed; and if the
arbitrators fail to do so or fail to agree on the appointment of the third
arbitrator within the prescribed time, either Party or both Parties may request
the President of the World Bank to appoint the third arbitrator for them.
21.5 If the President of the World Bank fails to appoint an arbitrator in
accordance with Clause 21.3 or 21.4 within sixty (60) Days from the date of
request thereunder, then either Party or both Parties may request the
International Chamber of Commerce to make the appointment.
21.6 If for any reason whatsoever the appointment of an arbitrator is not
made or a vacancy is not filled in accordance with Clause 21.5, either Party
may request the President of the Federal Tribunal of Switzerland to make the
relevant appointment.
21.7 The expenses of the arbitrator of either Party, whether or not
appointed by that Party, shall be advanced by that Party. The expenses of the
third arbitrator shall be advanced equally by both Parties.
21.8 The place of arbitration shall be as agreed upon by the Parties or, in
the absence of an agreement, shall be Singapore. The language for the
arbitration shall be English.
21.9 The procedure shall be that of the UNCITRAL Arbitration Rules.
21.10 In rendering an award, the arbitrators shall take into account the
general principles of international laws as may be applicable, and any generally
accepted customs and usages of the international petroleum business and shall
determine in the award the expenses and fees of the arbitrators to be borne
solely by either Party or to be shared by both Parties in such proportion as may
be deemed proper.
21.11 The award of the arbitrators shall be final and binding on both
Parties. Should any Party fail to comply with such award or if no settlement
shall be obtained through arbitration then and only then the Parties shall
submit the dispute to a court of competent jurisdiction.
<PAGE>
ARTICLE XXII
WAIVER
No waiver by either Party of any default or defaults by the other in the
performance of any of the provisions of this Agreement shall operate or be
construed as a waiver of any other or further default or defaults whether of a
like or different character.
<PAGE>
ARTICLE XXIII
SUCCESSORS AND ASSIGNS
Subject to Article XIX, this Agreement shall bind and enure to the benefit of
the Parties hereto and their respective successors and assigns.
<PAGE>
ARTICLE XXIV
REPRESENTATIVES
Sellers designate Carigali-Triton Operating Company, as their representative for
the giving and receiving of all notices to and from each Buyer, provided that
all notices related to the provisions of Articles IV, VIII and IX shall also be
delivered to each Seller. Should Sellers subsequently designate a new
representative, Sellers shall notify each Buyer in writing. Anything done,
performed or agreed to by Carigali-Triton Operating Company, or any succeeding
Sellers' Representative shall be deemed as if it were done, performed, or agreed
by Sellers.
Buyers shall designate their representative ("Buyers' Representative") for the
giving and receiving of all notices to and from Sellers or Sellers'
Representative and for all other purposes of this Agreement. Should Buyers'
subsequently designate a new representative, Buyers shall notify each Seller in
writing. Anything done, performed, or agreed by such Buyers' Representative or
any succeeding Buyers' Representative shall be deemed as if it were done,
performed, or agreed by Buyers.
<PAGE>
ARTICLE XXV
APPLICABLE LAW
This Agreement shall be governed by and construed in accordance with the laws of
England, exclusive of the conflict of law rules.
ARTICLE XXVI
NOTICES
26.1 Any notice, under this Agreement shall be in writing and shall be
deemed received if delivered it to the Party in question by registered mail to
the following address:
Sellers:
Malaysia-Thailand Joint Authority
27th Floor, City Square Centre,
182 Jalan Tun Razak
50400 Kuala Lumpur, Malaysia
Attn: Chief Executive Officer
And:
Petronas Carigali (JDA) Sdn. Bhd.
Tower 1, Petronas Twin Towers,
Kuala Lumpur City Center
50088 Kuala Lumpur, Malaysia
Attn: Chief Operating Officer
And:
Triton Oil Company of Thailand
Triton Oil Company of Thailand (JDA) Limited
Suite 13.01, 13th Floor, Menara Tan & Tan
207 Jalan Tun Razak
50400 Kuala Lumpur, Malaysia
Attn: General Manager
Sellers' Representative:
Carigali-Triton Operating Company
Suite 5.01-5.03, 5th Floor, Wisma Inai
Jalan Tun Razak
50400 Kuala Lumpur, Malaysia
Attn: General Manager
Buyers:
Petroleum Authority of Thailand
555 Vibhavadi Rangsit Road
Ladyao Sub-district, Chatuchak District
Bangkok 10900
Attn: Governor
And:
Petroliam Nasional Berhad
Tower 1, PETRONAS Twin Towers,
Kuala Lumpur City Center,
50088 Kuala Lumpur
Malaysia
Attn: Senior General Manager
Legal & Corporate Affairs Division
or at any other address that a Party may from time to time notify the other
in writing. Buyers shall provide to Sellers the address of Buyers'
Representative for the purpose of this Article XXVI accordingly.
26.2 Any notice, communication or statement given by ordinary mail, hand,
telex, telegram or facsimile shall be deemed received by the addressee when
actually received. However, when in doubt it shall be deemed received by the
addressee when such receipt is acknowledged in writing without prejudice to the
validity of the original.
<PAGE>
ARTICLE XXVII
MARGINAL HEADINGS
The marginal headings in this Agreement are inserted for convenience only and
shall not affect the construction of this Agreement.
ARTICLE XXVIII
ENTIRE AGREEMENT AND ATTACHMENTS
This Agreement and the terms hereof shall constitute the entire Agreement
between the Parties hereto with respect to all matters herein and its execution
has not been induced by, nor do either of the Parties rely upon or regard as
material, any representations or writings whatsoever not incorporated herein.
This Agreement may be modified or supplemented only by amendment in writing
executed by the Parties hereto.
There are attached to this Agreement four (4) Schedules numbered from the First
to the Fourth and such Schedules are hereby made a part of this Agreement and
incorporated herein by reference.
ARTICLE XXIX
EFFECTIVE DATE
This Agreement shall become effective when Buyers and Sellers have each executed
this Agreement.
ARTICLE XXX
FINANCIAL ARRANGEMENTS
Sellers acknowledge that Buyers may be seeking financing for the sealines and
related facilities and Buyers acknowledge that Sellers may be seeking financing
for their production facilities. The Parties hereby agree to cooperate with the
other Parties and the various lenders that may be involved in connection with
such financial arrangements.
<PAGE>
IN WITNESS WHEREOF each Party hereto has caused this Agreement to be executed by
its duly authorized representative as of the date first written above.
FOR:MALAYSIA-THAILAND JOINT AUTHORITY FOR: PETRONAS CARIGALI (JDA)SDN BHD
Authorised Signature : Authorised Signature :
_____________________________ _____________________________
ISMAIL SULAIMAN DATO' MOHAMAD IDRIS MANSOR
CHIEF EXECUTIVE OFFICER CHAIRMAN
Witness: Witness:
_____________________________ _____________________________
DR. SONGPOPE POLACHAN MOHD AZHAR OSMAN KHAIRUDDIN
DEPUTY CHIEF EXECUTIVE OFFICER DIRECTOR
FOR: TRITON OIL COMPANY OF THAILAND
FOR:TRITON OIL COMPANY OF THAILAND (JDA) LIMITED
Authorised Signature : Authorised Signature :
_____________________________ _____________________________
JAMES C MUSSELMAN JAMES C MUSSELMAN
PRESIDENT & CHIEF EXECUTIVE OFFICER PRESIDENT & CHIEF EXECUTIVE OFFICER
Witness: Witness:
_____________________________ _____________________________
DON M DRINKARD, JR DON M DRINKARD, JR
GENERAL MANAGER GENERAL MANAGER
FOR: PETROLEUM AUTHORITY OF THAILAND FOR: PETROLIAM NASIONAL BERHAD
Authorised Signature : Authorised Signature :
_____________________________ _____________________________
VISET CHOOPIBAN TAN SRI DATO' MOHD HASSAN MARICAN
GOVERNOR PRESIDENT/CHIEF EXECUTIVE
Witness: Witness:
_____________________________ _____________________________
PITI YIMPRASERT DATO' ABDUL RAHIM ABU BAKAR
PRESIDENT, PTT GAS VICE PRESIDENT
FIRST SCHEDULE
GAS CONTRACT AREA -
Map of Block A-18
<PAGE>
SECOND SCHEDULE
QUALITY SPECIFICATION
1. Natural Gas delivered under this Agreement shall at the Point of Delivery
(1) GENERAL - be commercially free from materials and dust or other
solid matter, liquid matter, waxes, gums and gumforming constituents which might
cause injury to or interference with proper operations of the lines, meters,
regulators or other appliances through which Natural Gas flows. Sellers shall
furnish, install, maintain and operate such drips, separators, heaters and other
devices as Sellers deem necessary or desirable to effect compliance with this
specification.
(2) WATER CONTENT - contain not more than seven (7) pounds of water
vapor per one million (1,000,000) Cubic Feet of Natural Gas.
(3) SULFUR - contain not more than five decimal one seven (5.17) grains
total sulfur per one hundred (100) Cubic Feet of Natural Gas.
(4) HYDROGEN SULFIDE - contain not more than three decimal four five
(3.45) grains of hydrogen sulfide per one hundred (100) Cubic Feet of Natural
Gas, as determined by the weighted average at all applicable delivery points.
(5) CARBON DIOXIDE - contain not more than twenty-three (23) mole
percent of Carbon Dioxide, at each delivery point.
(6) OXYGEN - contain not more than zero decimal one (0.1) mole percent
of oxygen.
(7) HEATING VALUE - have a Gross Calorific Value not less than eight
hundred fifty (850) BTU per Cubic Foot and not more than eleven hundred fifty
(1,150) BTU per Cubic Foot.
(8) TEMPERATURE - shall have a temperature which is not less than sixty
degrees (60o) Fahrenheit and not more than one hundred forty degrees (140o)
Fahrenheit.
(9) MERCURY - contain not more than fifty (50) micrograms per cubic
meter, as determined by the weighted average at all applicable delivery
points.
2. Suitable standard test methods and measuring instruments of standard
manufacture acceptable to both Parties together with procedures for checking
and/or verification of the instruments shall be agreed between the Parties or be
determined by an expert.
THIRD SCHEDULE
MEASUREMENT OF NATURAL GAS DELIVERED
1. METERING
The Natural Gas delivered under this Agreement shall be measured with
meters constructed and installed, and whose computations of volume are made, in
accordance with the provisions of Gas Measurement Committee Report No. 3 of the
American Gas Association (AGA) as reprinted and revised September, 1985, with
any subsequent amendments or revisions which may be mutually acceptable to both
Parties.
2. ADJUSTMENT FOR SUPERCOMPRESSIBILITY
Adjustment for the effect of supercompressibility shall be made according
to the provisions of AGA Report No. 3 herein, above identified, for the average
conditions of pressure, flowing temperature and specific gravity at which the
gas was measured during the period under consideration and with the
proportionate values of each, carbon dioxide and nitrogen, in the gas delivered
included in the computation of the applicable supercompressibility factors.
Sellers agree to exercise due diligence in obtaining initial carbon dioxide and
nitrogen fraction values and to obtain subsequent values of these components as
may be required from time to time. Sellers shall use the AGA analysis method to
calculate the applicable supercompressibility factors for gas with diluent
content (carbon dioxide or nitrogen) greater than fifteen (15) mol. percent.
3. TEMPERATURE
The temperature of the gas shall be determined by a recording thermometer
so installed that it will record the temperature of the gas flowing through the
meters. The recording thermometer shall be installed and maintained by Sellers
in accordance with the specifications set forth in said AGA Gas Measurement
Committee Report No. 3. The arithmetical average of readings each Day shall be
deemed the gas temperature and used in computing the volume of gas metered
during such day.
4. SPECIFIC GRAVITY
Tests to determine the specific gravity of the gas being metered shall be
made by Sellers in accordance with ASTM (American Society for Testing and
Materials) Standard D1070-85 "Standard Test Methods for Relative Density of
Gaseous Fuels", or any subsequent revision thereof acceptable to both Parties.
In lieu of the use of ASTM Standard D1070-85, the Parties may agree to determine
the specific gravity of the gas in accordance with the calculations set forth in
said AGA Gas Measurement Committee Report No. 3.
The gas samples to be tested shall be representative of the gas being
metered at the time such samples are taken and may be either spot samples or
samples taken over a period of time. Samples shall be taken at reasonable
intervals by Sellers, provided that Sellers shall take additional samples when
requested by Buyer or Buyers to do so. The specific gravity determined by any
test shall apply to the gas metered from the date the spot sample was taken or
from the commencement date of a sample taken over a period of time, as the case
may be, until the next test.
Either Party to this Agreement can elect to have the specific gravity of
the gas determined by the continuous use of a recording gravitometer of standard
make, acceptable to both Parties, in accordance with ASTM Standard D1070-85. The
recording gravitometer will be installed and maintained by Sellers. The
arithmetic average of the specific gravity recorded each twenty-four (24) hour
Day or part thereof during which gas shall have been delivered shall be used in
computing gas volumes for that date.
5. HEATING VALUE DETERMINATION
The Gross Calorific Value of the Natural Gas in BTU's per Cubic Foot shall
be determined by Sellers from gas samples taken with a continuous sampler.
Tests to determine the calorific value of gas delivered shall be made by
utilizing a recording calorimeter operated and maintained in accordance with
ASTM (American Society for Testing and Materials) Standard D1826-88 "Standard
Test Method for Calorific Heating Value of Gases in Natural Gas Range by
Continuous Recording Calorimeter", or any subsequent revision thereof acceptable
to both Parties.
The Parties to this Agreement may agree to determine the calorific value of
gas delivered in accordance with the calculation set forth in said AGA Gas
Measurement Committee Report No. 3.
The Gross Calorific Value determined by any test shall apply to the gas
metered from the commencement date of the sample until the next sample is taken
for test.
In lieu of continuous sampling, the Parties may agree to spot sampling
which shall be representative of the gas delivered at the time such samples are
taken.
6. Notwithstanding anything contained herein the measurement of Natural Gas
delivered may be carried out by alternative methods if the Parties hereto agree.
For example, the microprocessor based measurement and computation devices,
commonly known as electronic flow computers, may be used as an alternative to
the chart recorder.
7. A periodic calibration and check of the primary and secondary metering
components shall be conducted by Sellers and witnessed by Buyer or Buyers.
<PAGE>
FOURTH SCHEDULE
DELIVERY POINTS
The Delivery Point(s) shall be at the flange weld or other agreed mark
connecting Sellers' facilities to Buyer' or Buyers' facilities for the reception
and transmission of the Natural Gas which is the subject of this Agreement. The
details of the Delivery Point(s) shall be mutually agreed by the Parties.
Sellers shall advise Buyer or Buyers of the location of each Delivery Point to
be in effect on the CDD as soon as possible but not later than one hundred and
eighty (180) Days after the Effective Date of this Agreement.
EXHIBIT 12.1
TRITON ENERGY LIMITED AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(IN THOUSANDS, EXCEPT RATIOS)
(UNAUDITED)
<TABLE>
<CAPTION>
<S> <C> <C> <C>
YEAR
NINE MONTHS ENDING ENDING
SEPTEMBER 30, DECEMBER 31,
-------------------- ------------
1999 1998 1998
--------- --------- ----------
Fixed charges, as defined
Interest charges $ 28,951 $ 40,401 $ 50,253
Preferred dividend requirements of
subsidiaries adjusted to pre-tax basis --- --- ---
--------- --------- ----------
Total fixed charges $ 28,951 $ 40,401 $ 50,253
========= ========= ==========
Earnings, as defined (2):
Earnings (loss) from continuing operations
before income taxes, minority interest and
extraordinary item $ 44,937 $(91,533) $(238,609)
Fixed charges, above 28,951 40,401 50,253
Less interest capitalized (10,466) (19,786) (23,215)
Plus undistributed (earnings) loss of affiliates --- --- ---
Less preferred dividend requirements of
subsidiaries adjusted to pre-tax basis --- --- ---
--------- --------- ----------
$ 63,422 $(70,918) $(211,571)
========= ========= ==========
RATIO OF EARNINGS TO FIXED CHARGES (1) (2) 2.2 --- ---
========= ========= ==========
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
SEVEN MONTHS YEAR
ENDING ENDING
YEAR ENDING DECEMBER 31, DEC. 31, MAY 31,
-------------------------------
1997 1996 1995 1994 1994
--------- --------- --------- ---------- ----------
Fixed charges, as defined
Interest charges $ 50,625 $ 43,884 $ 41,305 $ 20,285 $ 26,951
Preferred dividend requirements of
subsidiaries adjusted to pre-tax basis --- --- --- --- 364
--------- --------- --------- ---------- ----------
Total fixed charges $ 50,625 $ 43,884 $ 41,305 $ 20,285 $ 27,315
========= ========= ========= ========== ==========
Earnings, as defined (2):
Earnings (loss) from continuing operations
before income taxes, minority interest and
extraordinary item $ 16,896 $ 20,945 $ 16,600 $ (22,834) $ (23,104)
Fixed charges, above 50,625 43,884 41,305 20,285 27,315
Less interest capitalized (25,818) (27,102) (16,211) (11,833) (16,863)
Plus undistributed (earnings) loss of affiliates --- (118) 2,249 4,102 (645)
Less preferred dividend requirements of
subsidiaries adjusted to pre-tax basis --- --- --- --- (364)
--------- --------- --------- ---------- ----------
$ 41,703 $ 37,609 $ 43,943 $ (10,280) $ (13,661)
========= ========= ========= ========== ==========
0.8 0.9 1.1 --- ---
RATIO OF EARNINGS TO FIXED CHARGES (1) (2) ========= ========= ========= ========== ==========
</TABLE>
____________________
(1) Earnings were inadequate to cover fixed charges for the nine months
ended September 30, 1998 by $111,319,000, for the years ended December 31, 1998,
1997 and 1996 by $261,824,000, $8,922,000 and $6,275,000, respectively, for the
seven months ended December 31, 1994 by $30,565,000 and for the year ended May
31, 1994 by $40,976,000.
(2) Earnings reflect nonrecurring writedowns and loss provisions of
$3,597,000 and $198,782,000 for the nine months ended September 30, 1999 and
1998, respectively, $348,064,000, $46,153,000 and $1,058,000 for the years ended
December 31, 1998, 1996 and 1995, respectively, $984,000 for the seven months
ended December 31, 1994 and $45,754,000 for the year ended May 31, 1994,
respectively. Nonrecurring gains from the sale of assets and other gains
aggregated $442,000 and $121,117,000 for the nine months ended September 30,
1999 and 1998, respectively, $125,617,000, $6,253,000, $22,189,000, $13,617,000
and $56,193,000 for the years ended December 31, 1998, 1997, 1996 and 1995 and
May 31, 1994, respectively. The ratio of earnings to fixed charges if adjusted
to remove nonrecurring items, would have been 2.3 and 0.2 for the nine months
ended September 30, 1999 and 1998, respectively, 0.2, 0.7, 1.4 and 0.8 for the
years ended December 31, 1998, 1997, 1996 and 1995, respectively. Without
nonrecurring items, earnings would have been inadequate to cover fixed charges
for the nine months ended September 30, 1998 by $33,654,000, for the years ended
December 31, 1998, 1997 and 1995 by $39,377,000, $15,175,000 and $9,921,000,
respectively, for the seven months ended December 31, 1994 by $29,581,000 and
for the year ended May 31, 1994 by $51,415,000.
EXHIBIT 12.2
TRITON ENERGY LIMITED AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERENCE
DIVIDENDS
(IN THOUSANDS, EXCEPT RATIOS)
(UNAUDITED)
<TABLE>
<CAPTION>
YEAR
NINE MONTHS ENDING ENDING
SEPTEMBER 30, DECEMBER 31,
-------------------- ----------
<S> <C> <C> <C>
1999 1998 1998
--------- --------- ----------
Fixed charges, as defined:
Interest charges $ 28,951 $ 40,401 $ 50,253
Preference dividend requirements of the Company 14,126 368 3,061
Preferred dividend requirements of subsidiaries
adjusted to pre-tax basis --- --- ---
--------- --------- ----------
Total fixed charges $ 43,077 $ 40,769 $ 53,314
========= ========= ==========
Earnings, as defined (2):
Earnings (loss) from continuing operations
before income taxes, minority interest and
extraordinary item $ 44,937 $(91,533) $(238,609)
Fixed charges, above 43,077 40,769 53,314
Less interest capitalized (10,466) (19,786) (23,215)
Plus undistributed (earnings) loss of affiliates --- --- ---
Less preference dividend requirements of the
Company and its subsidiaries adjusted to
pre-tax basis (14,126) (368) (3,061)
--------- --------- ----------
$ 63,422 $(70,918) $(211,571)
========= ========= ==========
RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERENCE DIVIDENDS (1) (2) 1.5 --- ---
========= ========= ==========
</TABLE>
<TABLE>
<CAPTION>
<C> <C> <C> <C>
SEVEN MONTHS YEAR
ENDING ENDING
YEAR ENDING DECEMBER 31, DEC. 31, MAY 31,
------------------------------- ---------- ----------
<S> 1997 1996 1995 1994 1994
--------- --------- --------- ---------- ----------
Fixed charges, as defined:
Interest charges $ 50,625 $ 43,884 $ 41,305 $ 20,285 $ 26,951
Preference dividend requirements of the Company 400 985 802 449 ---
Preferred dividend requirements of subsidiaries
adjusted to pre-tax basis --- --- --- --- 364
--------- --------- --------- ---------- ----------
Total fixed charges $ 51,025 $ 44,869 $ 42,107 $ 20,734 $ 27,315
========= ========= ========= ========== ==========
Earnings, as defined (2):
Earnings (loss) from continuing operations
before income taxes, minority interest and
extraordinary item $ 16,896 $ 20,945 $ 16,600 $ (22,834) $ (23,104)
Fixed charges, above 51,025 44,869 42,107 20,734 27,315
Less interest capitalized (25,818) (27,102) (16,211) (11,833) (16,863)
Plus undistributed (earnings) loss of affiliates --- (118) 2,249 4,102 (645)
Less preference dividend requirements of the
Company and its subsidiaries adjusted to
pre-tax basis (400) (985) (802) (449) (364)
--------- --------- --------- ---------- ----------
$ 41,703 $ 37,609 $ 43,943 $ (10,280) $ (13,661)
========= ========= ========= ========== ==========
RATIO OF EARNINGS TO COMBINED FIXED CHARGES 0.8 0.8 1.0 --- ---
AND PREFERENCE DIVIDENDS (1) (2) ========= ========= ========= ========== ==========
</TABLE>
______________________________
(1) Earnings were inadequate to cover combined fixed charges and preference
dividends for the nine months ended September 30, 1998 by $111,687,000, for the
years ended December 31, 1998, 1997 and 1996 by $264,885,000, $9,322,000 and
$7,260,000, respectively, for the seven months ended December 31, 1994 by
$31,014,000 and for the year ended May 31, 1994 by $40,976,000.
(2) Earnings reflect nonrecurring writedowns and loss provisions of
$3,597,000 and $198,782,000 for the nine months ended September 30, 1999 and
1998, respectively, $348,064,000, $46,153,000 and $1,058,000 for the years ended
December 31, 1998, 1996 and 1995, respectively, $984,000 for the seven months
ended December 31, 1994 and $45,754,000 for the year ended May 31, 1994.
Nonrecurring gains from the sale of assets and other gains aggregated $442,000
and $121,117,000 for the nine months ended September 30, 1999 and 1998,
respectively, $125,617,000, $6,253,000, $22,189,000, $13,617,000 and $56,193,000
for the years ended December 31, 1998, 1997, 1996 and 1995 and May 31, 1994,
respectively. The ratio of earnings to combined fixed charges and preference
dividends if adjusted to remove nonrecurring items, would have been 1.5 and 0.2
for the nine months ended September 30, 1999 and 1998, respectively, 0.2, 0.7,
1.4 and 0.7 for the years ended December 31, 1998, 1997, 1996 and 1995,
respectively. Without nonrecurring items, earnings would have been inadequate
to cover combined fixed charges and preference dividends for the nine months
ended September 30, 1998 by $34,022,000, for the years ended December 31, 1998,
1997 and 1995 by $42,438,000, $15,575,000 and $10,723,000, respectively, for the
seven months ended December 31, 1994 by $30,030,000 and for the year ended May
31, 1994 by $51,415,000.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM SEPTEMBER
30, 1999 FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 202,518
<SECURITIES> 0
<RECEIVABLES> 25,360
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 260,671
<PP&E> 1,085,127
<DEPRECIATION> 493,979
<TOTAL-ASSETS> 952,744
<CURRENT-LIABILITIES> 81,065
<BONDS> 404,455
0
370,932
<COMMON> 358
<OTHER-SE> 83,564
<TOTAL-LIABILITY-AND-EQUITY> 952,744
<SALES> 176,087
<TOTAL-REVENUES> 176,087
<CGS> 58,360
<TOTAL-COSTS> 58,360
<OTHER-EXPENSES> 45,404
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 17,536
<INCOME-PRETAX> 44,937
<INCOME-TAX> 20,405
<INCOME-CONTINUING> 24,532
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 24,532
<EPS-BASIC> .29
<EPS-DILUTED> .29
</TABLE>
