UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(AMENDMENT NO. 2)
(Mark One)
( X ) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED: December 31, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___________ TO ______________
Commission File Number: 1-11675
TRITON ENERGY LIMITED
(Exact name of registrant as specified in its charter)
CAYMAN ISLANDS NONE
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
CALEDONIAN HOUSE
JENNETT STREET, P.O. BOX 1043
GEORGE TOWN
GRAND CAYMAN, CAYMAN ISLANDS NONE
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 345-949-0050
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
---------------------- -------------------
Ordinary Shares, $.01 par value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None.
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES [ X ] NO [
--------
]
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM
405 OF REGULATION S-K (SECTION 229.405 OF THIS CHAPTER) IS NOT CONTAINED HEREIN,
AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE
PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS
FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. [ ]
---------
THE AGGREGATE MARKET VALUE OF THE OUTSTANDING ORDINARY SHARES HELD BY
NON-AFFILIATES OF THE REGISTRANT AT MARCH 7, 2000 (FOR SUCH PURPOSES ONLY, ALL
DIRECTORS AND EXECUTIVE OFFICERS ARE PRESUMED TO BE AFFILIATES) WAS
APPROXIMATELY $1.0 BILLION, BASED ON THE CLOSING SALES PRICE OF $30.25 ON THE
NEW YORK STOCK EXCHANGE.
AS OF MARCH 7, 2000, 35,944,174 ORDINARY SHARES OF THE REGISTRANT WERE
OUTSTANDING.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE PROXY STATEMENT PERTAINING TO THE 2000 ANNUAL MEETING OF
SHAREHOLDERS OF TRITON ENERGY LIMITED ARE INCORPORATED BY REFERENCE INTO PART
III HEREOF.
TRITON ENERGY LIMITED
TABLE OF CONTENTS
Form 10-K Item Page
- -------------- ----
PART I
ITEMS 1. and 2. Business and Properties 2
ITEM 3. Legal Proceedings 20
ITEM 4. Submission of Matters to a Vote of Security Holders 22
PART II
ITEM 5. Market for Registrant's Common Equity and Related
Stockholder Matters 23
ITEM 6. Selected Financial Data 29
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations 30
ITEM 7.A. Quantitative and Qualitative Disclosures about Market Risk 43
ITEM 8. Financial Statements and Supplementary Data 46
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 46
PART III
ITEM 10. Directors and Executive Officers of the Registrant 47
ITEM 11. Executive Compensation 47
ITEM 12. Security Ownership of Certain Beneficial Owners and Management 47
ITEM 13. Certain Relationships and Related Transactions 47
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 48
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
Triton Energy Limited is an international oil and gas exploration and
production company. 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.
The Company conducts substantially all of its exploration and production
operations outside the United States. All of the Company's sales are currently
derived from oil and gas production in Colombia. For a discussion of certain
political, economic and other uncertainties associated with operations in
foreign countries, particularly in the oil and gas business, see note 19 of
Notes to Consolidated Financial Statements.
Triton Energy Limited was incorporated in the Cayman Islands in 1995 to
become the parent holding company of Triton Energy Corporation, a corporation
formed in Texas in 1962 and reincorporated in Delaware in 1995. The terms
"Company" and "Triton" when used in this report mean Triton Energy Limited and
its subsidiaries and other affiliates through which Triton conducts its
business, unless the context otherwise implies. The Company's principal
executive offices are located at Caledonian House, Jennett Street, George Town,
Grand Cayman, Cayman Islands, and its telephone number is (345) 949-0050.
Information regarding the Company can be obtained by contacting the Company's
Investor Relations department at Triton Energy, 6688 North Central Expressway,
Suite 1400, Dallas, Texas 75206, telephone number (214) 691-5200, or at the
Company's web site, www.tritonenergy.com.
OIL AND GAS PROPERTIES
Through various subsidiaries and affiliates, the Company has participating
interests in exploration licenses in Latin America, Southeast Asia, Africa,
Europe and the Middle East. The following is intended to describe the Company's
interests in these licenses and recent operations over these licenses.
Colombia
- --------
Santiago de Las Atalayas, Tauramena and Rio Chitamena Contract Areas
The Company holds a 12% interest in the Santiago de Las Atalayas ("SDLA"),
Tauramena and Rio Chitamena contract areas, covering approximately 66,000,
36,300 and 6,700 acres, respectively, where an active development program is
being carried out in the Cusiana and Cupiagua fields. The area is located
approximately 160 kilometers (100 miles) northeast of Bogota in the Andean
foothills of the Llanos Basin area in eastern Colombia. Triton's partners in
these areas are Empresa Colombiana De Petroleos ("Ecopetrol"), the Colombian
national oil company, with a 50% interest, and subsidiaries of BP/Amoco ("BP")
and TotalFina SA ("TOTAL"), each with a 19% interest. BP is the operator.
Triton's interest is 12%, and its net revenue interest is approximately 9.6%
after governmental royalties. Triton's net revenue is reduced by up to 0.36%
pursuant to an agreement with an original co-investor, subject to Triton being
reimbursed for a proportionate share of related expenditures.
Contract Terms. The Company and its private partners have secured the right
---------------
to produce oil and gas from the SDLA and Tauramena contract areas through the
years 2010 and 2016, respectively, and from the Rio Chitamena contract area
through 2015 or 2019, depending on contract interpretation. In July 1994,
Triton, BP, TOTAL and Ecopetrol entered into an Integral Plan for the Unified
Exploitation of the Cusiana Oil Structure in the SDLA, Tauramena and Rio
Chitamena Association Contract Areas to develop the Cusiana oil structure in a
technically efficient and cooperative manner. The plan contemplates that the
parties' interests will be determined over three consecutive periods of time.
Until the expiration of the SDLA contract in 2010, petroleum produced from the
unified area will be owned by the parties according to their interests in each
contract area.
In the first quarter of 2005, the parties will engage an independent party
to determine the original barrels of oil equivalent ("BOE") of petroleum in
place under the unified area and under each contract area. Then a "tract factor"
will be calculated for each contract area. Each tract factor will be the amount
of original BOEs of petroleum in place under the particular contract area as a
percentage of the total original BOEs under the unified area. Each party's
unified area interest during the second period (commencing from the expiration
of the SDLA contract in 2010) and during the final period (commencing from the
termination of the second contract to termination) will be the aggregate of that
party's interest in each remaining contract area multiplied by the tract factor
for each such contract area.
Recent Operating Activity. In the Cusiana field, during 1999, Triton and
---------------------------
its working interest partners completed an additional six wells, bringing the
total completions to 43 producing wells, 13 gas injection wells and four water
injection wells. The gas injection wells recycle to the Mirador formation most
of the gas that is associated with the oil production to increase the oil
recoverable during the life of the field. The water injection wells inject the
field's produced water into the Barco and Guadalupe formations for disposal and
pressure maintenance. There are currently four drilling rigs operating in the
Cusiana field to drill production, water and gas injection wells. The Company
expects that five wells will be completed during 2000.
During 1999, in the Cupiagua field, including the Cupiagua South extension
of the field discovered in January 1998, Triton and its working interest
partners completed an additional eight wells, bringing the total completions to
24 producing wells and seven gas injection wells. There are currently three
drilling rigs operating in the Cupiagua field on the SDLA contract area to drill
production, water and gas injection wells. The Company expects that nine wells
will be completed during 2000.
Recetor Contract Area
In 1999, the Company acquired a 20% interest in the Recetor contract area,
covering approximately 70,215 acres. The area is located adjacent to and north
of the SDLA contract area and includes an extension of the Cupiagua field.
Triton's partners in these areas are BP, with a 63.3% interest, and,
Inaquimicas, with a 16.7% interest. BP is the operator. The Company's interest
is subject to certain government royalties and the right of Ecopetrol to acquire
up to a 50% interest in the contract upon declaration of commerciality. The
contract provides the Company and its private partners the right to produce oil
and gas from the Recetor contract area through the year 2017.
In January 2000, Triton and its working interest partners completed the
Liria YD-2 well on the extension of the Cupiagua field in the Recetor contract
area. The well reached total depth of 16,953 feet and will be tested into the
Cupiagua Central Processing Facility (CPF). The Company expects that Ecopetrol
will grant commerciality and the well will be put on production into the
Cupiagua CPF provided the working interest partners reach agreement with the
SDLA working interest partners. There is currently one drilling rig operating in
the Recetor contract area. The Company expects that at least one additional well
will be drilled in the Recetor contract area in 2000.
Production Facilities and Pipelines
The production facilities in the Cusiana and Cupiagua fields have been
completed. The components of the Cusiana CPF consist of a long term test
facility, four early production units, and two 80,000 barrels of oil per day
("BOPD") production trains, which brought the production capacity of the Cusiana
CPF to approximately 320,000 BOPD. Currently, the production of the Cusiana
field is limited by the gas handling capacity of the Cusiana CPF of about 1,400
million cubic feet of gas per day.
The components of the Cupiagua CPF consist of two 100,000 BOPD production
trains, which process the condensate and gas production from the Cupiagua
producing wells. The gas handling capacity of the Cupiagua CPF is approximately
1,300 million cubic feet of gas per day.
Crude oil and condensate produced from the Cusiana and Cupiagua fields, as
well as crude oil from other third parties, are transported to the Caribbean
port of Covenas through the 832-kilometer (520-mile) pipeline system operated by
Oleoducto Central S. A. ("OCENSA"). OCENSA is a Colombian company formed by
Triton Pipeline Colombia, Inc., a wholly owned subsidiary of the Company until
its sale in February 1998, Ecopetrol, BP Colombia Pipelines Ltd., Total Pipeline
Colombie, S.A., IPL Enterprises (Colombia) Inc. and TCPL International
Investments Inc.
Gross production from the Cusiana and Cupiagua fields has reached over 500
million barrels of oil since production commenced, and averaged approximately
430,000 BOPD during 1999. Based on estimates of the operator of the Cusiana and
Cupiagua fields, the Company believes that combined Cusiana and Cupiagua oil
production will be approximately 8% to 11% lower in 2000 than in 1999, although
there can be no assurance that actual production will equal that amount.
Other Contract Areas in Colombia
Triton owns a 100% interest (before certain royalties and government
participation) in the El Pinal license, which covers approximately 36,000 acres
approximately 330 kilometers (205 miles) north of Bogota. In the southern part
of El Pinal, Triton discovered and confirmed the Liebre field with two wells
(the Liebre-1 and -2). Liebre-1 ceased production in June 1998 while Liebre-2
continues to produce approximately 160 BOPD.
During 1999, in the Guayabo A and B licenses, the Company drilled an
unsuccessful exploratory well and conducted a surface geology program in
satisfaction of its commitments. The Company has relinquished its interest in
these areas.
Malaysia-Thailand
-----------------
In Block A-18 of the Malaysia-Thailand Joint Development Area in the Gulf
of Thailand, the Company and its partners have discovered eight natural gas
fields - known as the Bulan, Bumi, Bumi East, Cakerawala, Samudra, Senja,
Suriya, and Wira fields. The Company owns its interest through a company owned
one half by Triton and one half by a subsidiary of Atlantic Richfield Company
("ARCO"). The operator is Carigali-Triton Operating Company Sdn. Bhd. ("CTOC"),
a company owned by Triton and ARCO, through their jointly owned company, and
Petronas Carigali (JDA) Sdn. Bhd. ("Carigali"), a subsidiary of the Malaysian
national oil company.
Block A-18 is located in the Gulf of Thailand in an area known as the
Malaysia-Thailand Joint Development Area. The contract area in the Gulf of
Thailand, which encompasses approximately 731,000 acres, had been the subject of
overlapping claims between Malaysia and Thailand. The two countries established
the Malaysia-Thailand Joint Authority (the "MTJA") to administer the development
of the Joint Development Area. In April 1994, Triton entered into a
production-sharing contract with the MTJA and Carigali. Triton previously held a
license from Thailand that covered part of the Joint Development Area.
Contract Terms
The term of the production-sharing contract is 35 years, subject to
possible relinquishment of certain areas and subject to the treaty between
Malaysia and Thailand creating the MTJA remaining in effect. Triton and its
partners have the right to explore for oil and gas for the first eight years of
the contract. The contract provides that if there is a discovery of natural gas
(not associated with crude oil), the contractors will submit to the MTJA a
development plan for the field. If the MTJA accepts the plan, the contractors
would have the right to hold that gas field without production for an additional
five-year period, but not beyond the tenth anniversary of the contract. The
contractors would then have a five-year period to develop the field, and have
the right to produce gas from the field for 20 years plus a number of years
equal to the number of years, if any, prior to the end of the holding period
that gas production commenced (or until the termination of the contract, if
earlier). The contract requires the contractors to drill two exploratory wells
before April 2002.
For a discovery of an oil field, the contract grants to the operators the
right to produce oil from the field for 25 years (or until the termination of
the contract, if earlier). Any areas not developed and producing within the
periods provided will be relinquished.
As oil and gas are produced, the MTJA is entitled to a 10% royalty. A
portion of each unit of production is considered "cost oil" or "cost gas" and
will be allocated to the contractors to the extent of their recoverable costs,
with the balance considered "profit oil" or "profit gas" to be divided 50% to
the MTJA and 50% to the contractors (i.e., 25% to Carigali and 25% to the
company jointly owned with ARCO). The portion that will be considered "cost gas"
for production from the Cakerawala and Bulan fields is a maximum of 60%. The
Cakerawala and Bulan fields are the fields planned for first-phase development.
The portion that will be considered "cost gas" for production from the other
fields is a maximum of 50%. There is an additional royalty attributable to
Triton's and ARCO's joint interest equal to 0.75% of Block A-18 production. Tax
rates imposed by the MTJA on behalf of the governments of Malaysia and Thailand
are 0% for the first eight years of production, 10% for the next seven years of
production and 20% for any remaining production.
The Company's agreements with ARCO 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. The agreements provide that the Company will recover its investment in
recoverable costs in the project, approximately $100 million, and that ARCO will
recover its investment in recoverable costs, on a first-in, first-out basis from
the cost recovery portion of future production. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
note 2 of Notes to Consolidated Financial Statements.
Gas Sales Agreement
In October 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. The sales agreement provides
for gas deliveries over a term concurrent with the production-sharing contract
and contemplates initial deliveries of 195 million cubic feet of gas (MMCF) per
day for the first six months of the agreement, and 390 MMCF per day for a period
of twenty years. The sales agreement includes a take-or-pay provision that
specifies that the buyers must take a minimum of 90% of the annual daily
contract quantity and the sellers must be able to deliver a maximum of 110% of
the daily contract quantity. Delivery is made at the offshore production
platform.
The price for gas will be adjusted annually for changes in the US Consumer
Price Index, the Producer Price Index for Oil Field and Gas Field Machinery and
Tools, and medium fuel oil (180 CST) in Singapore. The price is calculated
annually and will apply to sales over the succeeding twelve months. All
calculations and payments are in U.S. dollars. The base price is $2.30 per
mmbtu. To give the buyers incentive to accelerate the timing of the delivery of
the gas, the sales agreement gives the buyers a discount of 5% after 500 billion
cubic feet has been delivered and a discount of 10% after an aggregate of 1.3
trillion cubic feet has been delivered.
The sales agreement provides that the initial delivery date will be a date
to be agreed upon by the sellers and the buyers between April 1, 2002 and June
30, 2002. If the parties do not agree on a date for initial delivery, the
agreement provides that the date will be deemed to be June 30, 2002.
By the first delivery date, the sellers will be required to have completed
the facilities necessary to meet its delivery obligations. The MTJA had
previously approved the field development plan for the Cakerawala field in
December 1997. CTOC has begun field development work and has awarded several
contracts for long lead-time equipment, including CO2 removal, structural steel,
refrigeration, power generation and gas compression. In March 2000, CTOC
awarded the contract for engineering, procurement and construction (EPC) of
three wellhead platforms, a production platform with living quarters platform, a
riser platform and a floating storage and off-loading vessel for oil and
condensate. The initial development plan calls for 35 development wells.
The buyers currently do not have in place facilities necessary to transport
and process the gas. While it is not a requirement of the sales agreement, the
buyers anticipate constructing pipeline and processing facilities onshore
Thailand to accept deliveries of the gas. The sales agreement does recognize
that the buyers' downstream facilities will require that certain environmental
approvals be obtained before the buyers' facilities can be constructed. The
agreement provides that, if a delay in obtaining the necessary environmental
approvals results in a delay of the completion of the buyers' downstream
facilities, this will be treated as a force majeure event and will excuse the
buyers from their take or pay obligations for the length of the delay. The
Company can give no assurance as to when the environmental approvals will be
obtained, and a lengthy approval process, or significant opposition to the
project, could delay construction and the commencement of gas sales.
Notwithstanding a possible future delay in the buyers' environmental
approvals process, in order to meet the June 30, 2002 deadline, the sellers are
committed to, or will be required to commit to, significant expenditures,
including the EPC contract. Although ARCO is committed to pay all development
costs associated with Block A-18 up to $377 million, the Company has agreed to
provide some compensation to ARCO in the event that gas sales are 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 commitment to the
EPC contract. The Company's obligation is capped at 24 months of these payments.
Equatorial Guinea
------------------
The Company signed production-sharing contracts in March 1997 covering two
contiguous blocks (Blocks F and G) with the Republic of Equatorial Guinea. The
contracts became effective in April 1997. During 1999, the Company announced an
oil discovery, the Ceiba field, in Block G, and confirmed the significance of
the discovery with the Ceiba-2 appraisal well.
The contracts give the Company the right to explore and develop an area
covering approximately 1.3 million acres located offshore and southwest of the
town of Bata in water depths of up to 5,200 feet. The Company is the operator
and Energy Africa Equatorial Guinea Limited is the Company's partner. Currently,
the Company's contract interest is 85% and Energy Africa's contract interest is
15%, but these interests are subject to the renegotiation of the contracts as
discussed below.
Contract Terms
Currently, the Company's commitments under the production-sharing contracts
for the contract year ending April 2001 are to drill at least one exploration
well, and a second exploration well contingent upon the Company identifying an
additional structure it believes is a drillable prospect. The Company can extend
the exploration period of each contract for three additional one-year periods if
it agrees to certain operational commitments for those periods, including the
drilling of at least one exploration well, and a second exploration well
contingent upon the Company identifying an additional structure it believes is a
drillable prospect. The Company is required to relinquish 30% of each contract's
original area by April 2000, and an additional 20% of the remaining contract
area by the end of April 2002, 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 area or areas to be
surrendered is to be designated by the Company, provided that, where
possible, each area is of sufficient size and convenient shape to permit
petroleum operations.
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
Ministry approved the Ceiba field as commercial in December 1999.
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%.
At the request of the Republic of Equatorial Guinea, the Company and its
partner are negotiating amendments to certain terms of the contracts with the
government. The parties have signed a memorandum of understanding reflecting the
revised terms, and negotiations of definitive amendments are continuing. The
memorandum of understanding provides that the government would receive a 5%
carried participating interest, and its royalty would vary based on average
daily production, ranging from 11% to 16%. After making the royalty payments,
the contractors would be entitled to receive up to 70% of the production until
they recover their costs. Production not allocated to the contractors for cost
recovery would be allocated between the contractors and the government based on
cumulative production, with the government's share ranging from 20% to 60%, to
the extent production exceeds certain levels. This share of production is in
addition to the share the government would receive through its 5% carried
participating interest. The implementation of the revised terms of the contract
is subject to the negotiation and execution of definitive amendments, but there
can be no assurance as to whether, or when, such definitive amendments will be
executed.
Recent Operating Activity
During 1999, the Company announced an oil discovery, the Ceiba field, in
Block G, and confirmed the significance of the discovery with the Ceiba-2
appraisal well. On test, the Ceiba-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.
The Ceiba-2 well was drilled approximately one mile to the southwest and
342 feet down-dip of the Ceiba-1 discovery well. The well encountered net
oil-bearing pay of 300 feet in a single, continuous column. In addition, the
well confirmed the oil-water contact found in Ceiba-1, and demonstrated lateral
reservoir continuity and connectivity. The well is located 22 miles off the
continental coast and was drilled to a total depth of 8,744 feet in 2,347 feet
of water. The Company elected not to flow test the well based on wireline logs,
extensive coring and pressure data, as well as Ceiba-1 flow-test results.
The Company intends to maintain both the Ceiba-1 and Ceiba-2 wells as
potential future producers.
The Company has acquired a 1,025,000-acre (4,200 square kilometer) 3D
seismic survey, out of the total 1.3 million acres, to assist in delineating the
extent of the Ceiba field, identify drilling locations for the
appraisal/production wells, and better define other exploration prospects on the
blocks. The Company is in the process of evaluating the data.
The Company intends to accelerate its exploration, appraisal and
development drilling activities through implementation of a two-rig drilling
program. The drilling program provides for up to ten wells: four firm well
commitments and six optional wells. The rigs will be used to:
- - Complete the Ceiba-1 and -2 wells as oil producers.
- - Drill and complete two Ceiba field appraisal/production wells, Ceiba-3 and
Ceiba-4.
- - Drill two exploration wells, one each on Blocks F and G.
- - At the option of the Company, drill a combination of up to six additional
development, appraisal and/or exploration wells.
Plan of Development
In January 2000, the Company received notice from the Ministry of Mines and
Energy of the Republic of Equatorial Guinea that the Ministry had approved
Triton's plan of development for the Ceiba field. The plan of development
provides for initial or phase one production of 52,000 BOPD utilizing a floating
production storage and offloading (FPSO) system, although there can be no
assurance that actual production will be at this level. Selection of a
FPSO-based development concept was designed to allow for accelerated development
of the Ceiba field. Specifications call for the FPSO vessel to provide storage
for two million barrels of oil and initial processing capacity of up to 60,000
barrels of oil per day. The FPSO vessel can also be expanded cost effectively
through the addition of incremental processing capacity, to accommodate up to
240,000 barrels of oil per day.
As part of this initial phase of development, four sub-sea production wells
are scheduled to be completed and connected through flow lines to the FPSO,
including the Ceiba-1 and Ceiba-2 wells.
Based on discussions held to date with development contractors, the Company
is targeting first oil production to occur by year end, although the Company can
give no assurance that it will meet this target. The Company believes that due
to transportation and preliminary assays of the quality of the crude oil, the
oil from the Ceiba field will sell at a discount to Brent crude.
Greece
------
The Company has signed two leases with Hellenic Petroleum, the national oil
company of Greece, with the Company having an 88% interest in each lease and
Hellenic Petroleum the remaining 12% interest. The Gulf of Patraikos contract
area covers approximately 402,000 acres (after a contractually-required
relinquishment in 1999) located offshore between the western coast of Greece and
the offshore Ionian islands of Lefkas, Kefalonia and Zakynthos in water depths
of up to 1,700 feet. The lease provides a primary exploration term expiring in
September 2001 with a commitment of 1,000 kilometers (625 miles) of new 2D
seismic and the drilling of one exploratory well for a total expenditure of not
less than $13.5 million. The Company has reprocessed approximately 3,000
kilometers (1,900 miles) of existing 2D seismic and acquired approximately 1,000
kilometers (625 miles) of 2D seismic and gravity in January 2000.
The Aitoloakarnania contract area covers approximately 658,000 acres (after
a contractually-required relinquishment in 1999) located onshore in western
Greece. The lease provides a primary exploration term expiring in June 2000 with
a commitment of 200 kilometers of 2D seismic and the drilling of two exploratory
wells for a total expenditure of not less than $13.25 million. The Company has
reprocessed approximately 660 kilometers (410 miles) of existing 2D seismic and
acquired approximately 200 kilometers (125 miles) of new 2D seismic. The Company
plans to drill the commitment wells this year although the Company may attempt
to negotiate amendments to these commitments.
Italy
-----
The Company holds interests in six licenses in Italy comprising three
offshore blocks in the Adriatic Sea and three onshore blocks in the Southern
Apennines.
The Company has a 47% interest in each of the contiguous DR71 and DR72
licenses covering approximately 369,400 acres (after a contractually required
relinquishment in 1999) in the Adriatic Sea located 45 kilometers (28 miles)
offshore the city of Brindisi. Triton's partner in these licenses is Enterprise
Oil Italiana, S.p.A. ("Enterprise"), the operator, with a 53% interest. During
1998, the Company and its working interest partners drilled the Giove-1 well.
The well was drilled to a total depth of 3,458 feet but was prematurely
abandoned due to a gas blowout and mechanical failure. A replacement well,
Giove-2, was drilled to a total depth of 4,285 feet and encountered oil and gas.
Additional work is required to evaluate the commercial potential of the
licenses. During 1999, a subsidiary of ExxonMobil withdrew from its interest in
the licenses and the Company and Enterprise each received its proportionate
share of ExxonMobil's interest.
In 1998, Triton acquired a 20% interest in the FR33AG offshore license. The
license covers approximately 71,600 acres and is adjacent to the DR71 and DR72
licenses. Eni S.p.A. is operator, with a 50% interest, and Enterprise holds the
remaining 30% interest. The license provides a primary exploration term expiring
in September 2004 with a commitment of 250 kilometers (156 miles) of new 2D
seismic and the drilling of one exploratory well.
In the southern Apennine Mountains, the Company has an interest in three
contiguous licenses, Fosso del Lupo, Valsinni and Masseria de Sole, covering
approximately 58,000 acres in the Matera province. The Company is the operator,
with a 50% interest, and a subsidiary of ARCO holds the remaining 50% interest.
The licenses provide a primary exploration term expiring in August 2002 and
were amended in 1999 to provide a combined work commitment of approximately 50
kilometers (31 miles) of new 2D seismic and the drilling of one exploratory
well. In connection with the amendment, the Company relinquished approximately
40% of the acreage. The Company acquired the 50 kilometers of seismic data over
the license area in 1999.
Oman
----
In 1998, the Company signed a production-sharing contract for Block 40,
covering approximately 1.3 million acres located offshore in the Straits of
Hormuz. The contract provides an exploration term expiring in June 2001 with a
commitment of the drilling of one exploratory well. The Company is the operator
with a 50% contract interest and Atlantis Holding Norway AS is the Company's
partner with a 50% interest.
Triton has completed the reprocessing and interpretation of 4,083
kilometers (2,546 miles) of existing 2D seismic, and completed the acquisition
of a 620 square kilometer 3D seismic survey in January 2000. The Company expects
that it will process and interpret this data during 2000 and drill an
exploratory well in early 2001.
Madagascar
----------
The Company has signed a production-sharing contract with the Office of
National Mines and Strategic Industries in Madagascar for the Ambilobe Block,
covering approximately 4.3 million acres. The block is located directly offshore
from Ambilobe in water depths of up to 11,500 feet. The Company has acquired
approximately 3,000 kilometers (1,875 miles) of 2D seismic.
Ecuador
-------
In 1999, the Company assigned its 55% interest in Block 19 in the Oriente
Basin to Vintage Petroleum Ecuador, Inc. The assignment is subject to approval
of the Ministry of Energy and Mines.
RESERVES
The following table sets forth a summary of the Company's estimated proved
oil and gas reserves at December 31, 1999, and is based on separate estimates of
the Company's net proved reserves prepared by:
- - the independent petroleum engineers, DeGolyer and MacNaughton, with respect
to the proved reserves in the Cusiana and Cupiagua fields in
Colombia,
- - the independent petroleum engineers, Netherland, Sewell & Associates, Inc.,
with respect to the proved reserves in the Ceiba field in Equatorial
Guinea,
- - the internal petroleum engineers of the operating company, Carigali-Triton
Operating Company (CTOC) with respect to the proved reserves in
Malaysia-Thailand on Block A-18 in the Gulf of Thailand, and
- - the Company's internal petroleum engineers with respect to the proved
reserves in the Liebre field in Colombia.
For additional information regarding the Company's reserves, including the
standardized measure of future net cash flows, see note 23 of Notes to
Consolidated Financial Statements. Oil reserves data include natural gas liquids
and condensate.
Net proved reserves at December 31, 1999, were:
PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
------------------- ---------------------- ------------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
---------- ------- ------------ -------- -------- --------
Colombia (1) 91,859 11,566 33,712 --- 125,571 11,566
Malaysia-Thailand (2) --- --- 13,223 553,862 13,223 553,862
Equatorial Guinea --- --- 32,033 --- 32,033 ---
---------- ------- ------------ -------- -------- --------
Total 91,859 11,566 78,968 553,862 170,827 565,428
========== ======= ============ ======== ======== ========
____________________
(1) Includes liquids to be recovered from Ecopetrol as reimbursement for
precommerciality expenditures.
(2) As of December 31, 1999, gas sales had not yet commenced. The proved gas
reserves are calculated using the base price in the gas sales agreement of
$2.30. The base price is subject to annual adjustments based on various indices.
There can be no assurance as to what the actual price will be when gas sales
commence. See "Item 1. Business and Properties - Malaysia-Thailand."
Reserve quantities are estimates and there are a number of uncertainties.
Reserve estimates are approximate and may be expected to change as
additional information becomes available. In addition there are inherent
uncertainties in making reserve estimates, such as the following:
- - the Company, and if applicable the independent engineers, must make certain
assumptions and projections based on engineering data;
- - there are uncertainties inherent in interpreting engineering data;
- - the Company, and if applicable the independent engineers, must project
future rates of production and the timing of development expenditures;
- - reservoir engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact way; and
- - the accuracy of reserve estimates is a function of the quality of available
data and of engineering and geological interpretation and judgment.
Accordingly, the Company cannot give any assurance that the Company will
ultimately produce the quantity of reserves set forth in the table, and the
Company cannot give any assurance that the proved undeveloped reserves will be
developed within the periods anticipated.
The Company has not filed any estimates of total proved net oil or gas
reserves with, or included estimates of total proved net oil or gas reserves in
any report to, any United States authority or agency since the beginning of the
Company's last fiscal year.
OIL AND GAS OPERATIONS
Production and Sales
----------------------
During 1999, 1998 and 1997, the Company produced and sold oil and gas only
from its property in Colombia. More details regarding the Company's revenues,
assets and certain other data by geographical area is contained in note 21 of
Notes to Consolidated Financial Statements.
The following table sets forth the net quantities of oil and gas the Company
produced during 1999, 1998 and 1997.
OIL PRODUCTION (1) GAS PRODUCTION
--------------------------- --------------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
, --------------------------- --------------------------
1999 1998 1997 1999 1998 1997
------ ------ ------ ------ ------ ------
(Mbbls) (MMcf)
Colombia (2) 12,469 9,979 5,776 459 503 802
____________________
(1) Includes natural gas liquids and condensate.
(2) Includes Ecopetrol reimbursement barrels and excludes 3.1 million, 3.1
million and 2.5 million barrels of oil produced and delivered for the years
ended December 31, 1999, 1998 and 1997, respectively, in connection with the
Company's forward oil sale in May 1995. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - Results of
Operations" and note 8 of Notes to Consolidated Financial Statements.
The following tables summarize for 1999, 1998 and 1997: (i) the average
sales price per barrel of oil and per Mcf of natural gas; (ii) the average sales
price per equivalent barrel of production; (iii) the depletion cost per
equivalent barrel of production; and (iv) the production cost per equivalent
barrel of production:
AVERAGE SALES PRICE AVERAGE SALES PRICE
PER BARREL OF OIL (1) PER MCF OF GAS
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------- ------------------------
1999 1998 1997 1999 1998 1997
------- ------ ------ ----- ----- -----
Colombia (4) $ 15.95 $12.31 $17.54 $0.88 $0.99 $1.15
PER EQUIVALENT BARREL (2)
----------------------------------------------------------------------------
AVERAGE SALES PRICE DEPLETION (3) PRODUCTION COST
------------------------- ------------------------ -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------- ------------------------ -----------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
------ ------ ------ ------ ------ ------ ------ ------ ------
Colombia (4) $15.89 $12.27 $17.37 $ 3.80 $ 4.07 $ 3.67 $ 4.77 $ 5.97 $ 6.47
____________________
(1) Includes natural gas liquids and condensate.
(2) Natural gas has been converted into equivalent barrels of oil based on
six Mcf of natural gas per barrel of oil.
(3) Includes depreciation calculated on the unit of production method for
support equipment and facilities.
(4) Includes barrels delivered under the forward oil sale which are recorded
at $11.56 per barrel upon delivery. Excludes the full cost ceiling
limitation writedown in 1998 totaling $241 million.
Competition
-----------
The Company encounters strong competition from major oil companies
(including government-owned companies), independent operators and other
companies for favorable oil and gas concessions, licenses, production-sharing
contracts and leases, drilling rights and markets. Additionally, the governments
of certain countries in which the Company operates may, from time to time, give
preferential treatment to their nationals. The oil and gas industry as a whole
also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual consumers. The Company
believes that the principal means of competition in the sale of oil and gas are
product availability, price and quality.
Markets
-------
Crude oil, natural gas, condensate and other oil and gas products generally
are sold to other oil and gas companies, government agencies and other
industries. The Company does not believe that the loss of any single customer or
contract pursuant to which oil and gas are sold would have a long-term material,
adverse effect on the revenues from the Company's oil and gas operations.
In Colombia, crude oil is exported through the Caribbean port of Covenas
where it is sold at prices based on United States prices, adjusted for quality
and transportation. The oil produced from the Cusiana and Cupiagua fields is
transported to the export terminal by pipeline.
For a discussion of certain factors regarding the Company's markets and
potential markets that could affect future operations, see note 19 of Notes to
Consolidated Financial Statements.
ACREAGE
The following table shows the total gross and net developed and undeveloped
oil and gas acreage held by Triton at December 31, 1999. "Gross" refers to the
total number of acres in an area in which the Company holds an interest without
adjustment to reflect the actual percentage interest held therein by the
Company. "Net" refers to the gross acreage as adjusted for working interests
owned by parties other than the Company.
"Developed" acreage is acreage spaced or assignable to productive wells.
"Undeveloped" acreage is acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas, regardless of whether such acreage contains proved reserves.
DEVELOPED UNDEVELOPED
ACREAGE ACREAGE (1)
----------- --------------
GROSS NET GROSS NET
----- ----- ------- -----
(In thousands)
Colombia 109 13 106 50
Malaysia-Thailand --- --- 731 183
Greece --- --- 1,060 933
Italy --- --- 499 217
Oman --- --- 1,322 661
Equatorial Guinea (2) --- --- 1,306 1,110
Madagascar --- --- 4,300 4,300
----- ----- ------- -----
Total 109 13 9,324 7,454
===== ===== ======= =====
____________________
(1) Triton's interests in certain of this acreage may expire if not
developed at various times in the future pursuant to the terms and provisions of
the leases, licenses, concessions, contracts, permits or other agreements under
which it was acquired.
(2) The acreage listed does not take into account the 5% carried
participating interest the Company expects to assign to the government of
Equatorial Guinea in connection with the renegotiation of the production-sharing
contract.
PRODUCTIVE WELLS AND DRILLING ACTIVITY
In this section, "gross" wells refers to the total number of wells drilled
in an area in which the Company holds any interest without adjustment to reflect
the actual ownership interest held. "Net" refers to the gross number of wells
drilled adjusted for working interests owned by parties other than the Company.
At December 31, 1999, in Colombia, Triton held gross and net working
interests in 93 and 12.92 productive wells, respectively, which include 20 gross
(2.4 net) gas-injection wells and four gross (.48 net) water-injection wells.
The following tables set forth the results of the oil and gas well drilling
activity on a gross basis for wells in which the Company held an interest during
1999, 1998 and 1997.
GROSS EXPLORATORY WELLS
PRODUCTIVE (1) DRY TOTAL
------------------------ ----------------------- -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ ----------------------- -----------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
------ ------ ------ ------ ------ ------ ------ ------ ------
Colombia --- 1 1 1 --- 1 1 1 2
Malaysia-Thailand --- 2 5 --- --- --- --- 2 5
Equatorial Guinea 2 --- --- --- --- --- 2 --- ---
Italy --- --- --- --- 2 --- --- 2 ---
Guatemala --- --- --- --- --- 1 --- --- 1
China --- --- --- --- 1 --- --- 1 ---
Ecuador --- --- --- --- --- 1 --- --- 1
Tunisia --- --- --- --- 1 --- --- 1 ---
------ ------ ------ ------ ------ ------ ------ ------ ------
Total 2 3 6 1 4 3 3 7 9
====== ====== ====== ====== ====== ====== ====== ====== ======
GROSS DEVELOPMENT WELLS
PRODUCTIVE (1) DRY TOTAL
------------------------ ----------------------- -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ ----------------------- -----------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
------ ------ ------ ------ ------ ------ ------ ------ ------
Colombia 14 13 18 --- --- --- 14 13 18
Malaysia-Thailand --- --- --- --- --- --- --- --- ---
Equatorial Guinea --- --- --- --- --- --- --- --- ---
------ ------ ------ ------ ------ ------ ------ ------ ------
Total 14 13 18 --- --- --- 14 13 18
====== ====== ====== ====== ====== ====== ====== ====== ======
___________________
(1) A productive well is producing or capable of producing oil and/or gas in
commercial quantities. Multiple completions have been counted as one well. Any
well in which one of the multiple completions is an oil completion is classified
as an oil well.
The following tables set forth the results of drilling activity on a net
basis for wells in which the Company held an interest during 1999, 1998 and 1997
(those wells acquired or disposed of since January 1, 1997, are reflected in the
following tables only since or up to the effective dates of their respective
acquisitions or sales, as the case may be):
NET EXPLORATORY WELLS
PRODUCTIVE (1) DRY TOTAL
------------------------ ----------------------- -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ ----------------------- -----------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
----- ----- ----- ----- ----- ----- ----- ----- -----
Colombia (2) --- 0.12 0.12 0.50 --- 0.50 0.50 0.12 0.62
Malaysia-Thailand (3) --- 1.00 2.50 --- --- --- --- 1.00 2.50
Equatorial Guinea 1.70 --- --- --- --- --- 1.70 --- ---
Italy --- --- --- --- 0.80 --- --- 0.80 ---
Guatemala --- --- --- --- --- 0.60 --- --- 0.60
China --- --- --- --- 0.50 --- --- 0.50 ---
Ecuador --- --- --- --- --- 0.55 --- --- 0.55
Tunisia --- --- --- --- 0.50 --- --- 0.50 ---
----- ----- ----- ----- ----- ----- ----- ----- -----
Total 1.70 1.12 2.62 0.50 1.80 1.65 2.20 2.92 4.27
===== ===== ===== ===== ===== ===== ===== ===== =====
NET DEVELOPMENT WELLS
PRODUCTIVE (1) DRY TOTAL
------------------------ ----------------------- -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ ----------------------- -----------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
----- ----- ----- ----- ----- ----- ----- ----- -----
Colombia (2) 1.68 1.56 2.16 --- --- --- 1.68 1.56 2.16
Malaysia-Thailand --- --- --- --- --- --- --- --- ---
Equatorial Guinea --- --- --- --- --- --- --- --- ---
----- ----- ----- ----- ----- ----- ----- ----- -----
Total 1.68 1.56 2.16 --- --- --- 1.68 1.56 2.16
===== ===== ===== ===== ===== ===== ===== ===== =====
__________________
(1) A productive well is producing or capable of producing oil and/or gas in
commercial quantities. Multiple completions have been counted as one well. Any
well in which one of the multiple completions is an oil completion is classified
as an oil well.
(2) Adjusted to reflect the national oil company participation at
commerciality for the Cusiana and Cupiagua fields.
(3) The interest in the wells drilled in 1998 was not reduced to take into
account the sale of the Company's interest in Block A-18 to ARCO because such
sale occurred after the drilling of the wells.
OTHER PROPERTIES
The Company leases or owns office space and other properties for its
operations in various parts of the world. For additional information on the
Company's leases, including its office leases, see note 20 of Notes to
Consolidated Financial Statements.
FORWARD-LOOKING INFORMATION
Certain information contained in this report, as well as written and oral
statements made or incorporated by reference from time to time by the Company
and its representatives in other reports, filings with the Securities and
Exchange Commission, press releases, conferences, teleconferences or otherwise,
may be deemed to be "forward-looking statements" within the meaning of Section
21E of the Securities Exchange Act of 1934 and are subject to the "Safe Harbor"
provisions of that section. Forward-looking statements include statements
concerning the Company's and management's plans, objectives, goals, strategies
and future operations and performance and the assumptions underlying such
forward-looking statements. When used in this document, the words "anticipates,"
"estimates," "expects," "believes," "intends," "plans" and similar expressions
are intended to identify such forward-looking statements. These statements
include information regarding:
- - drilling schedules;
- - expected or planned production capacity;
- - future production of the Cusiana and Cupiagua fields in Colombia, including
from the Recetor license;
- - the completion of development and commencement of production in
Malaysia-Thailand;
- - future production of the Ceiba field in Equatorial Guinea, including volumes
and timing of first production;
- - the acceleration of the Company's exploration, appraisal and development
activities in Equatorial Guinea;
- - the Company's capital budget and future capital requirements;
- - the Company's meeting its future capital needs;
- - the Company's utilization of net operating loss carryforwards and realization
of its deferred tax asset;
- - the level of future expenditures for environmental costs;
- - the outcome of regulatory and litigation matters;
- - the estimated fair value of derivative instruments, including the equity
swap; and
- - proven oil and gas reserves and discounted future net cash flows therefrom.
These statements are based on current expectations and involve a number of
risks and uncertainties, including those described in the context of such
forward-looking statements and in notes 19 and 20 of Notes to 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.
EMPLOYEES
At March 6, 2000, the Company employed approximately 126 full-time
employees.
EXECUTIVE OFFICERS OF THE COMPANY
The following table sets forth certain information regarding the executive
officers of the Company at March 6, 2000:
SERVED WITH
-----------
THE COMPANY
-----------
NAME AGE POSITION WITH THE COMPANY SINCE
- ------------------ --- ---------------------------------- -----------
James C. Musselman 52 President and Chief Executive
Officer 1998
A.E. Turner, III 51 Senior Vice President and
Chief Operating Officer 1994
W. Greg Dunlevy 44 Vice President, Investor Relations
and Treasurer 1993
Marvin Garrett 44 Vice President, Production 1994
Brian Maxted 42 Vice President, Exploration 1994
Mr. Musselman was elected director of the Company in May 1998, and was
elected Chief Executive Officer in October 1998. Mr. Musselman has served as
Chairman, President and Chief Executive Officer of Avia Energy Development, LLC,
a private company engaged in gas processing and drilling, since September
1994. From June 1991 to September 1994, Mr. Musselman was the President and
Chief Executive Officer of Lone Star Jockey Club, LLC, a company formed to
organize a horse racetrack facility in Texas.
Mr. Turner was elected Senior Vice President and Chief Operating Officer in
March 1999, and prior to that served as Senior Vice President, Operations, of
the Company since March 1994. From 1988 to February 1994, Mr. Turner served in
various positions with British Gas Exploration & Production, Inc., including
Vice President and General Manager of operations in Africa and the Western
Hemisphere from October 1993.
Mr. Dunlevy has served as Vice President, Investor Relations, of the
Company since April 1993 and was elected Treasurer in July 1998.
Mr. Garrett has served as Vice President, Production, of the Company since
December 1999, and prior to that served in various capacities within the
Company's Operations Department since August 1994, including most recently as
Director, Operations. Prior to joining the Company in August 1994, Mr. Garrett
served in various positions with British Gas Exploration and Production, Inc.,
including General Manager and Managing Director of Zaafarana Joint Operating
Company in Cairo, Egypt.
Mr. Maxted has served as Vice President, Exploration, of the Company since
January 1998, and prior to that served as Exploration Manager of CTOC since June
1994. From 1979 to 1994, Mr. Maxted was employed by British Petroleum in various
capacities, including Exploration Manager, Colombia from 1990 to 1992 and
License Manager, Norway from 1992 to 1994.
All executive officers of the Company are elected annually by the Board of
Directors of the Company to serve in such capacities until removed or their
successors are duly elected and qualified. There are no family relationships
among the executive officers of the Company.
ITEM 3. LEGAL PROCEEDINGS
LITIGATION
In July through October 1998, eight lawsuits were filed against the Company
and Thomas G. Finck and Peter Rugg, in their capacities as Chairman and Chief
Executive Officer and Chief Financial Officer, respectively. The lawsuits were
filed in the United States District Court for the Eastern District of Texas,
Texarkana Division, and have been consolidated and are styled In re: Triton
Energy Limited Securities Litigation. In November 1999, the plaintiffs filed a
consolidated complaint. It alleges violations of Sections 10(b) and 20(a) of the
Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated
thereunder, in connection with disclosures concerning the Company's properties,
operations, and value relating to a prospective sale of the Company or of all or
a part of its assets. The lawsuits seek recovery of an unspecified amount of
compensatory damages, fees and costs. In the consolidated complaint, the
plaintiffs abandoned a claim for negligent misrepresentation and punitive
damages that had previously been asserted in one of the eight individual suits.
In September 1999, the court granted the plaintiffs' motion for appointment
as lead plaintiffs and for approval of selection of lead counsel. In October
1999, the defendants filed a motion to dismiss the claims alleged in the eight
individual suits, and in December 1999, the defendants filed a supplement to
their motion to dismiss to address the plaintiffs' consolidated complaint. The
Company's motion, as supplemented, is currently pending.
The Company believes its disclosures have been accurate and intends to
vigorously defend these actions. There can be no assurance that the litigation
will be resolved in the Company's favor. An adverse result could have a material
adverse effect on the Company's financial position or results of operations.
In November 1999, a lawsuit was filed against the Company, one of its
subsidiaries and Thomas G. Finck, Peter Rugg and Robert B. Holland, III, in
their capacities as officers of the Company, in the District Court of the State
of Texas for Dallas County. The lawsuit is styled Aaron Sherman, et al. vs.
Triton Energy Corporation et al. and seeks an unspecified amount of compensatory
and punitive damages and interest. The lawsuit alleges as causes of action fraud
and negligent misrepresentation in connection with disclosures concerning the
prospective sale by the Company of all or a substantial part of its assets
announced in March 1998. The Company's date to answer has not yet run. Its
subsidiary has filed various motions to dispose of the lawsuit on the grounds
that the plaintiffs do not have standing. The Court has ordered the plaintiffs
to replead and has stayed discovery pending its further orders.
In August 1997, the Company was sued in the Superior Court of the State of
California for the County of Los Angeles, by David A. Hite, Nordell
International Resources Ltd., and International Veronex Resources, Ltd. The
action has since been removed to the United States District Court for the
Central District of California. The Company and the plaintiffs were adversaries
in a 1990 arbitration proceeding in which the interest of Nordell International
Resources Ltd. in the Enim oil field in Indonesia was awarded to the Company
(subject to a 5% net profits interest for Nordell) and Nordell was ordered to
pay the Company nearly $1 million. The arbitration award was followed by a
series of legal actions by the parties in which the validity of the award and
its enforcement were at issue. As a result of these proceedings, the award was
ultimately upheld and enforced. The current suit alleges that the plaintiffs
were damaged in amounts aggregating $13 million primarily because of the
Company's prosecution of various claims against the plaintiffs as well as its
alleged misrepresentations, infliction of emotional distress, and improper
accounting practices. The suit seeks specific performance of the arbitration
award, damages for alleged fraud and misrepresentation in accounting for Enim
field operating results, an accounting for Nordell's 5% net profit interest, and
damages for emotional distress and various other alleged torts. The suit seeks
interest, punitive damages and attorneys fees in addition to the alleged actual
damages. In August 1998, the district court dismissed all claims asserted by the
plaintiffs other than claims for malicious prosecution and abuse of the legal
process, which the court held could not be subject to a motion to dismiss. The
abuse of process claim was later withdrawn, and the damages sought were reduced
to approximately $700,000 (not including punitive damages). The lawsuit was
tried and the jury found in favor of the plaintiffs and assessed compensatory
damages against the Company in the amount of approximately $700,000 and punitive
damages in the amount of approximately $11 million. The Company believes it has
acted appropriately and intends to appeal the verdict.
During the quarter ended September 30, 1995, the United States
Environmental Protection Agency (the "EPA") and Justice Department advised the
Company that one of its domestic oil and gas subsidiaries, as a potentially
responsible party for the clean-up of the Monterey Park, California, Superfund
site operated by Operating Industries, Inc., could agree to contribute
approximately $2.8 million to settle its alleged liability for certain remedial
tasks at the site. The offer did not address responsibility for any groundwater
remediation. The subsidiary was advised that if it did not accept the settlement
offer, it, together with other potentially responsible parties, may be ordered
to perform or pay for various remedial tasks. After considering the cost of
possible remedial tasks, its legal position relative to potentially responsible
parties and insurers, possible legal defenses and other factors, the subsidiary
declined to accept the offer. In October 1997, the EPA advised the Company that
the estimated cost of the clean-up of the site would be approximately $217
million to be allocated among the 280 known operators. The subsidiary's share
would be approximately $1 million based upon a volumetric allocation, but there
can be no assurance that any allocation of liability to the subsidiary would be
made on a volumetric basis. No proceeding has been brought in any court against
the Company or the subsidiary in this matter.
The Company is also subject to litigation that is incidental to its
business.
CERTAIN FACTORS
None of the legal matters described above is expected to have a material
adverse effect on the Company's consolidated financial position. However, this
statement of the Company's expectation is a forward-looking statement that is
dependent on certain events and uncertainties that may be outside of the
Company's control. Actual results and developments could differ materially from
the Company's expectation, for example, due to such uncertainties as jury
verdicts, the application of laws to various factual situations, the actions
that may or may not be taken by other parties and the availability of insurance.
In addition, in certain situations, such as environmental claims, one defendant
may be responsible for the liabilities of other parties. Moreover, circumstances
could arise under which the Company may elect to settle claims at amounts that
exceed the Company's expected liability for such claims in an attempt to avoid
costly litigation. Judgments or settlements could, therefore, exceed any
reserves.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted by the Company during the fourth quarter of the
year ended December 31, 1999, to security holders, through the solicitation of
proxies or otherwise.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Ordinary Shares
- ----------------
Triton's ordinary shares are listed on the New York Stock Exchange and are
traded under the symbol OIL. Set forth below are the high and low sales prices
of Triton's ordinary shares as reported on the New York Stock Exchange Composite
Tape for the periods indicated:
CALENDAR PERIODS HIGH LOW
- -------------------- ----- -----
2000:
First Quarter* 29.56 19.19
1999:
Fourth Quarter 27.50 13.50
Third Quarter 14.69 10.00
Second Quarter 16.00 6.94
First Quarter 8.88 5.19
1998:
Fourth Quarter 12.63 7.13
Third Quarter 37.75 9.75
Second Quarter 43.38 32.44
First Quarter 38.13 25.56
_____________
*Through March 6, 2000.
Triton has not declared any cash dividends on its ordinary shares since
fiscal 1990. The holders of ordinary shares are entitled to receive such
dividends as are declared by the Board of Directors. Under applicable corporate
law, the Company may pay dividends or make other distributions to its
shareholders in such amounts as appear to the directors to be justified by the
profits of the Company or out of the Company's share premium account if the
Company has the ability to pay its debts as they come due.
The Company's current intent is to retain earnings for use in the Company's
business and the financing of its capital requirements. The payment of any
future cash dividends on the ordinary shares is necessarily dependent upon the
earnings and financial needs of the Company, along with applicable legal and
contractual restrictions. Triton is prohibited from paying cash dividends on the
ordinary shares under its revolving credit facility. In addition, the
Shareholders Agreement between the Company and HM4 Triton, L.P. provides that
for so long as HM4 Triton, L.P. and its affiliates own a certain number of
shares, Triton cannot pay a dividend on the ordinary shares without HM4 Triton,
L.P.'s consent. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and note 12 of Notes to Consolidated
Financial Statements. Finally, the terms of the 8% Convertible Preference
Shares and the 5% Convertible Preference Shares prohibit the payment of
dividends on the ordinary shares unless full cumulative dividends on all such
outstanding preference shares have been paid in full or set aside for payment.
There is no tax treaty between the United States and the Cayman Islands.
At March 6, 2000, there were 4,061 record holders of the Company's ordinary
shares.
Preference Shares
- -----------------
The Company has two series of preference shares outstanding, the 8%
Convertible Preference Shares and the 5% Convertible Preference Shares. The
following summary of certain provisions of the resolutions establishing the
terms of the outstanding preference shares is not complete. Copies of the
resolutions are filed as exhibits to this report.
8% Convertible Preference Shares
As of March 6, 2000, the Company had outstanding 5,189,758 8% Convertible
Preference Shares.
Dividends. The Company is required to pay dividends on the 8% Convertible
---------
Preference Shares semi-annually at the rate of 8% per year of the stated value
per share (initially $70) for each semi-annual dividend period ending on June 30
and December 31 of each year. Dividends on the 8% Convertible Preference Shares
are cumulative. The Company can choose to pay dividends in cash or in additional
8% Convertible Preference Shares. If the Company pays a dividend in additional
shares, the number of additional shares to be issued 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 Company may not pay a dividend or other distribution on any ordinary
shares or other shares ranking equal or junior to the 8% Convertible Preference
Shares unless all dividends on the 8% Convertible Preference Shares have been
paid. The Company may pay a partial dividend on shares ranking equal to the 8%
Convertible Preference Shares as to dividends if the Company pays a partial to
the holders of both the 8% Convertible Preference Shares and the equally-ranked
shares in proportion to the accrued and unpaid dividends on each share.
So long as the 8% Convertible Preference Shares are outstanding, the
Company may not redeem or purchase any ordinary shares or any Triton shares
ranking junior as to dividends to the 8% Convertible Preference Shares or any
other Triton shares ranking junior to the 8% Convertible Preference Shares as to
liquidation rights unless (1) full dividends on all outstanding 8% Convertible
Preference Shares and any other shares ranking equal as to dividends to the 8%
Convertible Preference Shares have been, or contemporaneously are, paid and (2)
the Company pays or sets aside cash (or additional shares of 8% Convertible
Preference Shares) in amounts sufficient to pay the dividend for the current
dividend period. In any event, the Company may purchase or acquire such junior
shares either (1) pursuant to any employee or director incentive or benefit plan
or arrangement or (2) in exchange solely for junior shares.
Conversion. Holders of 8% Convertible Preference Shares generally have the
----------
right to convert their 8% Convertible Preference Shares into ordinary shares at
any time before redemption at the conversion price in effect at the time of
conversion. The current conversion price is $17.50 per ordinary share so that
each 8% Convertible Preference Share is convertible into four ordinary shares.
The conversion price is subject to adjustment under certain circumstances. Upon
the conversion of 8% Convertible Preference Shares, the holder is also entitled
to receive an amount in cash equal to all accumulated and unpaid dividends on
the 8% Convertible Preference Shares converted through the effective date of
conversion.
Redemption. The Company cannot redeem the 8% Convertible Preference Shares
----------
before September 30, 2001. Beginning September 30, 2001, the Company can redeem
all, but not less than all, of the outstanding 8% Convertible Preference Shares
at any time if the average market value of the ordinary shares is above certain
prices. The redemption price is $70 per share, plus an amount equal to all
accumulated but unpaid dividends, and is payable in cash.
The average market value is determined by averaging the closing price of
the ordinary shares for the 20 trading days preceding the notice of redemption.
The Company may only redeem the 8% Convertible Preference Shares if this
average price in a particular six-month period exceeds the price set forth
below:
REDEMPTION NOTICE GIVEN ON THE SIX MONTHS ENDING: AVERAGE PRICE
- ------------------------------------------------- --------------
March 31, 2002 $ 28.54
September 30, 2002 31.14
March 31, 2003 34.20
September 30, 2003 37.58
March 31, 2004 32.57
September 30, 2004 34.97
March 31, 2005 37.60
Beginning April 1, 2005, the minimum average price will be increased every
six months to reflect an internal rate of return of 20% for a holder purchasing
8% Convertible Preference Shares as of the date the first 8% Convertible
Preference Share was issued. The minimum average prices set forth above will be
adjusted in the event of any combination, subdivision or reclassification of
ordinary shares, or any similar event.
Liquidation Rights. The liquidation preference of the 8% Convertible
-------------------
Preference Shares is $70 per share, plus accumulated and unpaid dividends.
Voting Rights. The holders of the 8% Convertible Preference Shares
--------------
generally vote with the holders of the ordinary shares on all matters brought
before the Company's shareholders. In addition, a class vote of the 8%
Convertible Preference Shares is required in certain limited circumstances. The
holders of the 8% Convertible Preference Shares will also be entitled to elect
two directors if the Company does not pay dividends on the 8% Convertible
Preference Shares under certain circumstances. When voting with the holders of
the ordinary shares, the holders of the 8% Convertible Preference Shares have
the number of votes for each share that they would have if they had converted
their shares into ordinary shares on the related record date. When voting as a
class, the holders of the 8% Convertible Preference Shares have one vote per
share.
The Shareholders Agreement between the Company and HM4 Triton, L.P.
provides that, in general, for so long as the entire Board of Directors consists
of ten members, HM4 Triton, L.P. (and its designated transferees, collectively)
may designate four nominees for election to the Board of Directors. The right of
HM4 Triton, L.P. (and its designated transferees) to designate nominees for
election to the Board of Directors will be reduced if the number of ordinary
shares held by HM4 Triton, L.P. and its affiliates (assuming conversion of 8%
Convertible Preference Shares into ordinary shares) represents less than certain
specified percentages of the number of ordinary shares (assuming conversion of
8% Convertible Preference Shares into ordinary shares) purchased by HM4 Triton,
L.P. under the Stock Purchase Agreement between Triton and HM4 Triton, L.P.
In the Shareholders Agreement, the Company also agreed that it would not
take certain fundamental corporate actions without the consent of HM4 Triton,
L.P. Some of the actions that would require HM4 Triton, L.P.'s consent are
listed below:
- - entering into a merger or similar business combination transaction, or
effecting a reorganization, recapitalization or other transaction pursuant to
which a majority of the outstanding ordinary shares or any 8% Convertible
Preference Shares are exchanged for securities, cash or other property;
- - authorizing, creating or modifying the terms of any securities that would
rank equal to or senior to the 8% Convertible Preference Shares;
- - selling assets comprising more than 50% of the market value of the Company;
- - paying dividends on the Company's ordinary shares;
- - incurring certain levels of debt; and
- - commencing a tender offer or exchange offer for any of the Company's ordinary
shares.
5% Convertible Preference Shares
As of March 6, 2000, the Company had outstanding 209,558 5% Convertible
Preference Shares.
Dividends. The Company is required to pay dividends on the 5% Convertible
---------
Preference Shares semi-annually at the rate of 5% per year of the redemption
price per share (initially $34.41) for each semi-annual dividend period on
September 30 and March 30 of each year. Dividends on the 5% Convertible
Preference Shares are cumulative.
The Company may not pay a dividend (other than dividends payable solely in
shares ranking junior to the 5% Convertible Preference Shares) or other
distribution on any ordinary shares or other shares ranking junior to the 5%
Convertible Preference Shares unless all dividends on the 5% Convertible
Preference Shares have been paid. The Company may not pay dividends on any class
or series of shares ranking equal to the 5% Convertible Preference Shares unless
the Company has paid, or concurrently pays, all accrued and unpaid dividends for
all prior periods on the 5% Convertible Preference Shares. If any accrued
dividends are not paid in full on the 5% Convertible Preference Shares and any
shares ranking equal to the 5% Convertible Preference Shares as to dividends,
the Company must pay any dividends on the 5% Convertible Preference Shares and
such equally-ranked shares so that the amount of dividends declared per share on
the 5% Convertible Preference Shares and such equally-ranked shares will bear
the same ratio that accrued and unpaid dividends per share on the 5% Convertible
Preference Shares and such equally-ranked shares bear to each other.
Conversion. Holders of 5% Convertible Preference Shares generally have the
----------
right to convert their 5% Convertible Preference Shares into ordinary shares at
any time before redemption. Currently, each 5% Convertible Preference Share is
convertible into one ordinary share. The conversion price is subject to
adjustment under certain circumstances. No payment or adjustment will be made in
respect of accrued or unpaid dividends on the 5% Convertible Preference Shares
upon conversion of 5% Convertible Preference Shares except as set forth below.
Redemption. The Company can redeem the 5% Convertible Preference Shares at
----------
any time in whole or in part. The redemption price is $34.41 per share, plus an
amount equal to all accumulated but unpaid dividends, and is payable in cash.
If any 5% Convertible Preference Shares are outstanding on March 30, 2004,
the Company is required to redeem the 5% Convertible Preference Shares. In this
event, the Company may redeem the 5% Convertible Preference Shares by
(1) paying cash at the $34.41 redemption price plus any accrued and unpaid
dividends to the redemption date;
(2) issuing to the holder a number of ordinary shares with a market value
equal to the $34.41 redemption price plus any accrued and unpaid dividends to
the redemption date; or
(3) a combination of cash or ordinary shares equal to the $34.41 redemption
price plus any accrued and unpaid dividends to the redemption date.
Liquidation Rights. The liquidation preference of the 5% Convertible
-------------------
Preference Shares is $34.41 per share, plus accumulated and unpaid dividends.
Voting Rights. The holders of the 5% Convertible Preference Shares
--------------
generally have no voting rights except as required under Cayman Islands law. So
long as any 5% Convertible Preference Shares are outstanding, the consent of the
holders of at least two-thirds of the outstanding 5% Convertible Preference
Shares is required if the Company issues, other than wholly for cash
consideration, any shares of any class of shares that would rank senior to the
5% Convertible Preference Shares in dividend or liquidation rights, or if the
Company proposes to amend its articles of association in a manner adversely
affecting the rights of the holders of the 5% Convertible Preference Shares. The
Company's articles of association may be amended to increase the number of
authorized preference shares without the vote of the holders of the outstanding
5% Convertible Preference Shares. When voting as a class, the holders of the 5%
Convertible Preference Shares have one vote per share.
Shareholder Rights Plan
- -------------------------
The Company has adopted a Shareholder Rights Plan pursuant to which
preference share rights attach to all ordinary shares at the rate of one right
for each ordinary share. Each right entitles the registered holder to purchase
from the Company one one-thousandth of a Series A Junior Participating
Preference Share, par value $.01 per share ("Junior Preference Shares"), of the
Company at a price of $120 per one one-thousandth of a share of such Junior
Preference Shares, subject to adjustment. Generally, the rights only become
distributable 10 days following public announcement that a person has acquired
beneficial ownership of 15% or more of Triton's ordinary shares or 10 business
days following commencement of a tender offer or exchange offer for 15% or more
of the outstanding ordinary shares; provided that, pursuant to the terms of the
plan, any acquisition of Triton shares by HM4 Triton, L.P. or its affiliates,
including Hicks, Muse, Tate & Furst, Incorporated, will not result in the
distribution of rights unless and until HM4 Triton, L.P.'s ownership of Triton
shares is reduced below certain levels.
If, among other events, any person becomes the beneficial owner of 15% or
more of Triton's ordinary shares (except as provided with respect to HM4 Triton,
L.P.), each right not owned by such person generally becomes the right to
purchase a number of ordinary shares of the Company equal to the number obtained
by dividing the right's exercise price (currently $120) by 50% of the market
price of the ordinary shares on the date of the first occurrence. In addition,
if the Company is subsequently merged or certain other extraordinary business
transactions are consummated, each right generally becomes a right to purchase a
number of shares of common stock of the acquiring person equal to the number
obtained by dividing the right's exercise price by 50% of the market price of
the common stock on the date of the first occurrence.
Under certain circumstances, the Company's directors may determine that a
tender offer or merger is fair to all shareholders and prevent the rights from
being exercised. At any time after a person or group acquires 15% or more of the
ordinary shares outstanding (other than with respect to HM4 Triton, L.P.) and
prior to the acquisition by such person or group of 50% or more of the
outstanding ordinary shares or the occurrence of an event described in the prior
paragraph, the Board of Directors of the Company may exchange the rights (other
than rights owned by such person or group which will become void), in whole or
in part, at an exchange ratio of one ordinary share, or one one-thousandth of a
Junior Preference Share, per right (subject to adjustment). The Company has the
ability to amend the rights (except the redemption price) in any manner prior to
the public announcement that a 15% position has been acquired or a tender offer
has been commenced. The Company will be entitled to redeem the rights at $0.01 a
right at any time prior to the time that a 15% position has been acquired. The
rights will expire on May 22, 2005, unless earlier redeemed by the Company.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth certain financial and oil and gas data on a
historical basis.
AS OF OR FOR YEAR ENDED
DECEMBER 31,
-----------------------------------------------------
1999 1998 1997 1996 1995
-------- ---------- ----------- -------- --------
OPERATING DATA (IN THOUSANDS, EXCEPT PER
SHARE DATA):
Oil and gas sales $247,878 $ 160,881 $ 145,419 $129,795 $106,844
Sales and other operating revenues 247,878 228,618 149,496 133,977 107,472
Earnings (loss) from continuing operations 47,557 (187,504) 5,595 23,805 6,541
Earnings (loss) before extraordinary items 47,557 (187,504) 5,595 23,805 2,720
Net earnings (loss) 47,557 (187,504) (8,896) 22,609 2,720
Average ordinary shares outstanding 36,135 36,609 36,471 35,929 35,147
Basic earnings (loss) per ordinary share:
Continuing operations $ 0.52 $ (5.21) $ 0.14 $ 0.64 $ 0.16
Before extraordinary item 0.52 (5.21) 0.14 0.64 0.05
Net earnings (loss) 0.52 (5.21) (0.26) 0.61 0.05
Diluted earnings (loss) per ordinary share:
Continuing operations $ 0.52 $ (5.21) $ 0.14 $ 0.62 $ 0.16
Before extraordinary item 0.52 (5.21) 0.14 0.62 0.05
Net earnings (loss) 0.52 (5.21) (0.25) 0.59 0.05
BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment $524,152 $ 470,907 $ 835,506 $676,833 $524,381
Total assets 974,475 754,280 1,098,039 914,524 824,167
Long-term debt, including current maturities (1) 413,487 427,492 573,687 416,630 402,503
Shareholders' equity 463,052 223,807 296,620 300,644 246,025
CERTAIN OIL AND GAS DATA (2) :
Production
Sales volumes (Mbbls) (3) 12,469 9,979 5,776 5,987 6,303
Forward oil sale deliveries (Mbbls) 3,050 3,050 2,462 701 409
-------- ---------- ----------- -------- --------
Total revenue barrels (Mbbls) 15,519 13,029 8,238 6,688 6,712
======== ========== =========== ======== ========
Gas (MMcf) 459 503 802 2,517 5,312
Average sales price
Oil (per bbl) (4) $ 15.95 $ 12.31 $ 17.54 $ 19.61 $ 16.60
Gas (per Mcf) $ 0.88 $ 0.99 $ 1.15 $ 1.69 $ 1.64
__________________________
(1) Includes current maturities totaling $9.0 million, $14.0 million, $130.4
million, $199.6 million, and $1.3 million at December 31, 1999, 1998, 1997,
1996, and 1995, respectively.
(2) Information presented includes the 49.9% equity investment in Crusader
Limited until its sale in 1996.
(3) Includes natural gas liquids and condensate.
(4) Includes barrels delivered under the forward oil sale, which are recognized
in oil and gas sales at $11.56 per barrel upon delivery.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL REQUIREMENTS
----------------------------------
Cash and equivalents totaled $186.3 million and $18.8 million at December
31, 1999 and 1998, respectively, and working capital (deficit) was $161.3
million and ($21.6 million) at December 31, 1999 and 1998, respectively.
The following summary table reflects cash flows of the Company for the
years ended December 31, 1999, 1998 and 1997 (in thousands):
1999 1998 1997
---------- --------- ----------
Net cash provided (used) by operating activities $ 116,522 $ 1,466 $ (97,416)
Net cash provided (used) by investing activities $(118,530) $ 84,191 $(212,700)
Net cash provided (used) by financing activities $ 170,143 $(80,071) $ 313,368
Operating Activities
- --------------------
Cash flows provided by operating activities for the year ended
December 31, 1999, benefited from increased production from the Cusiana and
Cupiagua fields in Colombia, and higher oil prices. Gross production from the
Cusiana and Cupiagua fields averaged approximately 430,000 BOPD during 1999
compared with 350,000 BOPD during 1998 and 220,000 BOPD during 1997. During
1999, 1998 and 1997, the Company's average realized oil price was $15.95, $12.31
and $17.54, respectively. See "Results of Operations - Oil and Gas Sales"
below. Based on estimates of the operator of the Cusiana and Cupiagua fields,
the Company believes that combined Cusiana and Cupiagua oil production will be
approximately 8% to 11% lower in 2000 than in 1999, although there can be no
assurance that actual production will equal that amount.
During 1999, the Company received substantially all of the
remaining proceeds (approximately $31.9 million) from a forward oil sale in May
1995. Starting with the second quarter of 2000, 254,136 barrels per month, the
amount currently delivered under the forward oil sale, will become available for
sale.
The Company's reported cash flows from operating activities for
the year ended December 31, 1997, were reduced by $124.8 million, which was
attributable to interest accreted with respect to the Company's Senior
Subordinated Discount Notes due November 1, 1997 (the "1997 Notes"), and the
9 3/4% Senior Subordinated Discount Notes due December 31, 2000
(the "9 3/4% Notes"), through the dates of retirement in the second
quarter of 1997.
Investing Activities
- ---------------------
The Company's capital expenditures and other capital investments were
$121.5 million, $180.2 million and $219.2 million during the years ended
December 31, 1999, 1998 and 1997, respectively, primarily for exploration and
development of the Cusiana and Cupiagua fields in Colombia, and for exploration
within the Company's licenses in Equatorial Guinea, the Malaysia-Thailand Joint
Development Area in the Gulf of Thailand and in other areas. Restructuring
activities undertaken in 1998 contributed to lower capital spending in 1999.
Proceeds from asset sales were $2.4 million, $267 million and $5.9 million
during 1999, 1998 and 1997, respectively. See "Results of Operations" below and
note 2 of Notes to Consolidated Financial Statements.
Financing Activities
- ---------------------
In August 1998, the Company and HM4 Triton, L.P., an affiliate of
Hicks, Muse, Tate & Furst Incorporated ("Hicks Muse"), entered into a stock
purchase agreement (the "Stock Purchase Agreement") that provided for a $350
million equity investment in the Company. The investment was effected in two
stages. At the closing of the first stage in September 1998 (the "First
Closing"), the Company issued to HM4 Triton, L.P. 1,822,500 shares of 8%
Convertible Preference Shares for $70 per share (for proceeds of $116.8 million,
net of transaction costs). Pursuant to the Stock Purchase Agreement, the second
stage was effected through a rights offering for 3,177,500 shares of 8%
Convertible Preference Shares at $70 per share, with HM4 Triton L.P. being
obligated to purchase any shares not subscribed. At the closing of the second
stage, which occurred on January 4, 1999 (the "Second Closing"), the Company
issued an additional 3,177,500 8% Convertible Preference Shares for proceeds
totaling $217.8 million, net of closing costs (of which, HM4 Triton L.P.
purchased 3,114,863 shares).
In April 1999, the Company's Board of Directors authorized a share
repurchase program enabling the Company to repurchase up to ten percent of the
Company's then outstanding 36.7 million ordinary shares. Purchases of ordinary
shares by the Company began in April and may be made from time to time in the
open market or through privately negotiated transactions at prevailing market
prices depending on market conditions. The Company has no obligation to
repurchase any of its outstanding shares and may discontinue the share
repurchase program at management's discretion. As of December 31, 1999, the
Company had purchased 948,300 ordinary shares for $11.3 million. Because of
anticipated capital needs in Equatorial Guinea, the Company did not include in
its capital budget for 2000 any amounts for share repurchases under the program.
In addition, the Company's revolving credit facility, entered into in February
2000, generally does not permit the Company to repurchase its ordinary shares
without the banks' consent.
During 1999, the Company repaid borrowings totaling $19 million,
including $10 million under unsecured credit facilities that were outstanding at
December 31, 1998. By December 31, 1999, all of the Company's unsecured
revolving credit facilities that were outstanding at December 31, 1998 had
expired. In addition, the Company paid cash preference dividends totaling $17.6
million in 1999.
During 1998, the Company borrowed $162.5 million and repaid $360.1
million under revolving lines of credit, notes payable and long-term debt. The
Company terminated a $125 million revolving credit facility during 1998 upon the
repayment of the amounts then outstanding.
In April 1997, the Company issued $400 million aggregate face value of
senior indebtedness to refinance other indebtedness. The senior indebtedness
consisted of $200 million face amount of 8 3/4% Senior Notes due April 15,
2002 (the "2002 Notes"), at 99.942% of the principal amount
(resulting in $199.9 million aggregate net proceeds) and $200 million face
amount of 9 1/4% Senior Notes due April 15, 2005 (the "2005 Notes" and,
together with the 2002 Notes, the "Senior Notes"), at 100% of the principal
amount for total aggregate net proceeds of $399.9 million before deducting
transaction costs of approximately $1 million.
In May and June 1997, the Company offered to purchase all of its
outstanding 1997 Notes and 9 3/4% Notes, which resulted in the retirement of
the 1997 Notes and substantially all of the 9 3/4% Notes. The remainder of
the 9 3/4% Notes were retired in 1998. During the year ended December
31, 1997, the Company borrowed $630 million and repaid $321.5 million under
revolving lines of credit, notes payable and long-term debt (including
the Senior Notes).
FUTURE CAPITAL NEEDS
The Company intends to implement an accelerated appraisal and
development program to enable early production from the Ceiba field, with a
target of first production by the end of 2000, and has contracted for a floating
production storage and offloading (FPSO) system that is expected to provide
storage for two million barrels of oil and initial processing capacity of up to
60,000 barrels of oil per day from a single production unit. Capacity can be
cost-effectively increased through the addition of up to three similar units.
In addition, the Company intends to accelerate its exploration, appraisal and
development drilling activities through implementation of a two-rig drilling
program that is intended to enable the Company to complete the Ceiba-1 and -2
wells as production wells, to drill and complete two additional
appraisal/production wells in the Ceiba field, to drill two exploration wells
and to provide the Company the option to drill up to six additional wells.
The Company expects that its accelerated appraisal and development
program for Equatorial Guinea will require significant capital outlays
commencing in the year 2000. For internal planning purposes, the Company's
capital spending program for the year ending December 31, 2000, is approximately
$191 million, excluding capitalized interest and acquisitions, of which
approximately $122 million relates to exploration and development activities in
Equatorial Guinea, $58 million relates to the Cusiana and Cupiagua fields in
Colombia, and $11 million relates to the Company's exploration activities in
other parts of the world. The 2000 capital spending program does not include
the six optional wells in Equatorial Guinea.
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, L.P. of the 8% Convertible
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. For example, if the Purchaser
sold the TPC shares for an amount equal to the value the Company has estimated
for purposes of preparing its balance sheet as of December 31, 1999, the Company
would have to make a payment to the Counterparty under the equity swap of
approximately $8.4 million. There can be no assurance that the value the
Purchaser may realize in any sale of the TPC shares will equal the value of the
shares estimated by the Company for purposes of valuing the equity swap. The
Company has no right or obligation to repurchase the TPC shares at any time, but
the Company is not prohibited from offering to purchase the shares if the
Purchaser offers to sell them. The Company expects to make a bid for the
acquisition of the TPC shares because the Company's pipeline tariffs can be
lowered by electing to cancel the dividend to the holder of the OCENSA shares.
See "Results of Operations - Other Income and Expenses" below, note 2 of Notes
to Consolidated Financial Statements, and "Quantitative and Qualitative
Disclosures about Market Risk" below.
In February 2000, the Company entered into an unsecured two-year
revolving credit facility with a group of banks, which matures in February 2002.
The credit facility gives the Company the right to borrow from time to time up
to the amount of the borrowing base determined by the banks, not to exceed $150
million. As of February 2000, the borrowing base was $150 million. The credit
facility contains various restrictive covenants, including covenants that
require the Company to maintain a ratio of earnings before interest,
depreciation, depletion, amortization and income taxes to net interest expense
of at least 2.5 to 1, and that prohibit the Company from permitting net debt to
exceed the product of 3.75 times the Company's earnings before interest,
depreciation, depletion, amortization and income taxes, in each case, on a
trailing four quarters basis. As of March 6, 2000, the Company had not made a
borrowing under the facility.
The Company expects to fund 2000 capital spending with a combination of
some or all of the following: cash flow from operations, cash, the Company's
committed bank credit facility, and the issuance of debt or equity securities.
To facilitate a possible future securities issuance or issuances, the Company
has on file 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.
At December 31, 1999, the Company had guaranteed the performance of a total
of $16.4 million in future exploration expenditures to be incurred through
September 2001 in various countries. A total of approximately $6 million of the
exploration expenditures are included in the 2000 capital spending program
related to a commitment for two onshore exploratory wells in Greece. These
commitments are backed primarily by unsecured letters of credit. The Company
also had guaranteed loans of approximately $1.4 million, which expire September
2000, for a Colombian pipeline company, Oleoducto de Colombia S.A., in which the
Company has an ownership interest.
On October 30, 1999, the Company and the other parties to the
production-sharing contract for Block A-18 executed a gas sales agreement
providing for the sale of the first phase of gas. Under the terms of the gas
sales agreement, delivery of gas is scheduled to begin by the end of the second
quarter of 2002, following timely completion and approval of an environmental
impact assessment associated with the buyers' pipeline and processing
facilities. No assurance can be given as to when such approval will be obtained.
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. See "Certain Factors Relating to Malaysia-Thailand" in note 19 of Notes
to Consolidated Financial Statements.
RESULTS OF OPERATIONS
---------------------
YEAR ENDED DECEMBER 31, 1999,
COMPARED WITH YEAR ENDED DECEMBER 31, 1998
Oil and Gas Sales
--------------------
Oil and gas sales in 1999 totaled $247.9 million, a 54% increase from
1998, due to higher average realized oil prices and higher production. The
average realized oil price was $15.95 and $12.31 in 1999 and 1998, respectively,
an increase of 30% for 1999, resulting in higher revenues of $56.4 million
compared to 1998. Total revenue barrels, including production related to barrels
delivered under the forward oil sale, totaled 15.5 million barrels in 1999, an
increase of 19%, compared to the prior year, resulting in an increase in
revenues of $30.7 million. The increased production was primarily due to the
start-up during the second half of 1998 of two new 100,000 BOPD oil-production
units at the Cupiagua central processing facility.
As a result of financial and commodity market transactions settled
during the year ended December 31, 1999, the Company's risk management program
resulted in lower oil sales of approximately $19.8 million than if the Company
had not entered into such transactions. Additionally, the Company has hedged
its WTI price on a portion of its projected 2000 oil production. See
"Quantitative and Qualitative Disclosures about Market Risk" below.
The delivery requirement under the forward oil sale will be completed
in March 2000. Starting with the second quarter of 2000, 254,136 barrels per
month, the amount currently delivered under the forward oil sale and recognized
in revenues at $11.56 per barrel, will become available for sale.
Gain on Sale of Oil and Gas Assets
-----------------------------------------
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 a gain of $63.2 million. In December 1998, the
Company sold its Bangladesh subsidiary for $4.5 million and recorded a gain of
the same amount.
Operating Expenses
-------------------
Operating expenses, which include field operating expenses, pipeline
tariffs and production taxes, decreased $5.4 million in 1999. On an oil
equivalent-barrel basis, operating expenses were $4.50 and $5.97 in 1999 and
1998, respectively. 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. Operating expenses on a per
equivalent-barrel basis were lower primarily due to higher production volumes.
OCENSA pipeline tariffs totaled $42.1 million and $49.9 million in 1999 and
1998, respectively. Pipeline tariffs for 1999 were lower primarily due to a
non-recurring credit issued by OCENSA in February 2000 totaling $4.2 million.
The credit resulted from OCENSA's compliance with a Colombian government decree
in December 1999 that reduced its 1999 noncash expenses. OCENSA imposes a
tariff on shippers from the Cusiana and Cupiagua 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.
Depreciation, Depletion and Amortization
-------------------------------------------
Depreciation, depletion and amortization increased $2.5 million,
primarily due to higher production volumes, including barrels delivered under
the forward oil sale. Off-setting the effect of higher production, full cost
ceiling test writedowns taken during 1998 reduced the per barrel depletion in
1999.
General and Administrative Expenses
--------------------------------------
General and administrative expense before capitalization decreased
$16.6 million from $47.2 million in 1998 to $30.6 million in 1999, while
capitalized general and administrative costs were $6.9 million and $20.6 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 in March 1999.
Writedown of Assets
---------------------
In June and December 1998, the carrying amount of the Company's evaluated
oil and gas properties in Colombia was written down by $105.4 million ($68.5
million, net of tax) and $135.6 million ($115.9 million, net of tax),
respectively, through application of the full cost ceiling limitation as
prescribed by the SEC, principally as a result of a decline in oil prices. No
adjustments were made to the Company's reserves in Colombia as a result of the
decline in prices. The SEC ceiling test was calculated using the June 30, and
December 31, 1998, WTI oil prices of $14.18 per barrel and $12.05 per barrel,
respectively, that, after a differential for Cusiana crude delivered at the port
of Covenas in Colombia, resulted in a net price of approximately $13 per barrel
and $11 per barrel, respectively.
During 1998, the Company evaluated the recoverability of its approximate
6.6% investment in a Colombian pipeline company, Oleoducto de Colombia S.A.
("ODC"), which is accounted for under the cost method. Based on an analysis of
the future cash flows expected to be received from ODC, the Company expensed the
carrying value of its investment totaling $10.3 million.
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.
In conjunction with the plan to restructure operations and scale back
exploration-related expenditures in 1998, 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. 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.
Special Charges
----------------
As a result of the restructuring, the Company recognized special
charges of $15 million during the third quarter of 1998 and $3.3 million during
the fourth quarter of 1998 for a total of $18.3 million. Of the $18.3 million
in special charges, $14.5 million related to the reduction in workforce, and
represented the estimated costs for severance, benefit continuation and
outplacement costs, which will be paid over a period of up to two years
according to the severance formula. Since July 1998, the Company has paid $13.1
million in severance, benefit continuation and outplacement costs. A total of
$2.1 million of special charges related to the closing of foreign offices, and
represented the estimated costs of terminating office leases and the write-off
of related assets. The remaining special charges of $1.7 million primarily
related to the write-off of other surplus fixed assets resulting from the
reduction in workforce. At December 31, 1999, all of the positions had been
eliminated, all designated foreign offices had closed and all licenses had been
relinquished, sold, or their commitments renegotiated. During the fourth quarter
of 1999, the Company reversed $.7 million of the accrual associated with the
completion of restructuring activities. The remaining liability related to the
restructuring activities undertaken in 1998 was $1 million at December 31, 1999.
In March 1999, the Company accrued special charges of $1.2 million
related to an additional 15% reduction in the number of employees resulting from
the Company's continuing efforts to reduce costs. The special charges consisted
of $1 million for severance, benefit continuation and outplacement costs and $.2
million related to the write-off of surplus fixed assets. Since March 1999, the
Company has paid $.9 million in severance, benefit continuation and outplacement
costs. At December 31, 1999, the remaining liability related to the
restructuring activities undertaken in 1999 was $.1 million.
In September 1999, the Company recognized special charges totaling $2.4
million related to the transfer of its working interest in Ecuador to a third
party.
Gain on Sale of Triton Pipeline Colombia
----------------------------------------------
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.
Interest Expense
-----------------
Gross interest expense for 1999 and 1998 totaled $37.2 million and
$46.4 million, respectively, while capitalized interest for 1999 decreased $8.7
million to $14.5 million. The decrease in capitalized interest is primarily due
to the writedown of unevaluated oil and gas properties in June 1998 and a sale
of 50% of the Company's Block A-18 project in August 1998.
Other Income (Expense), Net
------------------------------
Other income (expense), net, included a foreign exchange gain (loss)
of ($2.7 million) and $2.1 million in 1999 and 1998, respectively. During 1999
and 1998, the Company recorded gains of $6.2 million and $.4 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 an expense of $6.9 million and $3.3 million,
respectively, in other income (expense), net, related to the net payments made
under and the change in the fair value of the equity swap entered into in
conjunction with the sale of TPC. 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 (expense), net in such
periods. See "Quantitative and Qualitative Disclosures About Market Risk"
below. In 1999 and 1998, the Company recorded loss provisions of $2.3 million
and $.8 million, respectively, for certain legal matters. In 1998, the Company
recognized gains of $7.6 million on the sale of corporate assets in addition to
the ARCO and TPC transactions.
Income Taxes
-------------
Statement of Financial Accounting Standards No. 109 ("SFAS 109"),
"Accounting for Income Taxes," requires that the Company make projections about
the timing and scope of certain future business transactions in order to
estimate recoverability of deferred tax assets primarily resulting from the
expected utilization of net operating loss carryforwards ("NOLs"). Changes in
the timing or nature of actual or anticipated business transactions, projections
and income tax laws can give rise to significant adjustments to the Company's
deferred tax expense or benefit that may be reported from time to time. For
these and other reasons, compliance with SFAS 109 may result in significant
differences between tax expense for income statement purposes and taxes actually
paid.
Current taxes related to the Company's Colombian operations were $20.8
million and $4.4 million in 1999 and 1998, respectively. The income tax
provision for 1999 included a foreign deferred tax expense totaling $9.2 million
compared with a foreign deferred tax benefit of $57 million in 1998. The
benefit recognized in 1998 primarily resulted from the writedown of oil and gas
properties. Additionally, the income tax provision included a deferred tax
benefit in the United States totaling $1.4 million, compared with an expense of
$1.5 million in 1998.
At December 31, 1999, the Company had U.S. NOLs of approximately
$450.2 million compared with NOLs of approximately $415.6 million at December
31, 1998. The NOLs expire from 2000 to 2020. See note 10 of Notes to
Consolidated Financial Statements. At December 31, 1999, the Company's
Colombian operations and other foreign operations had NOLs and other credit
carryforwards totaling $57.4 million and $40.7 million, respectively, that will
expire between 2001 and 2004.
During 1999, the Company acquired the Colombian entity of its former
partner in the El Pinal field. In addition to the working interest in the El
Pinal field, the acquired entity has tax basis and NOLs totaling approximately
$40 million, included in total foreign NOLs above, which the Company
expects to utilize in 2000. At December 31, 1999, the tax affected amount of
the tax basis and NOLs ($14.2 million) has been included in current assets as
a deferred tax asset. In addition, the Company recorded deferred income of
$10.6 million, representing the difference between the value of the deferred
tax asset and the purchase price. During 2000, the deferred tax asset and
the deferred income will be reduced as the tax basis and NOLs are
utilized.
The Company recorded a U.S. deferred tax asset of $88.2 million, net
of a valuation allowance of $72.9 million, at December 31, 1999. The valuation
allowance was primarily attributable to management's assessment of the
utilization of NOLs in the U.S., the expectation that other tax credits will
expire without being utilized, and certain temporary differences will reverse
without a benefit to the Company. The minimum amount of future taxable income
necessary to realize the U.S. deferred tax asset is approximately $252 million.
Although there can be no assurance the Company will achieve such levels of
income, management believes the deferred tax asset will be realized through
income from its operations.
YEAR ENDED DECEMBER 31, 1998,
COMPARED WITH YEAR ENDED DECEMBER 31, 1997
Oil and Gas Sales
--------------------
Oil and gas sales in 1998 totaled $160.9 million, an 11% increase from
1997, due to higher production, which was partially offset by significantly
lower average realized oil prices. Total revenue barrels, including production
related to barrels delivered under the forward oil sale, totaled 13 million
barrels in 1998, an increase of 58%, compared to the prior year, resulting in an
increase in revenues of $84.2 million. The increased production was primarily
due to the start-up in late 1997 of two new 80,000 BOPD oil-production units at
the Cusiana central processing facility. In addition, two 100,000 BOPD
oil-production units at the Cupiagua central processing facility began
production during the second half of 1998. The average realized oil price was
$12.31 and $17.54 in 1998 and 1997, respectively, a decrease of 30% for 1998,
resulting in lower revenues of $68.3 million compared to 1997. The lower
average realized oil price resulted from a significant decrease in the 1998
average WTI oil price.
Gain on Sale of Oil and Gas Assets
-----------------------------------------
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 a gain of $63.2 million. In December 1998, the
Company sold its Bangladesh subsidiary for $4.5 million and recorded a gain of
the same amount.
In June 1997, the Company sold its Argentine subsidiary for cash
proceeds of $4.1 million and recognized a gain of $4.1 million.
Operating Expenses and Depreciation, Depletion and Amortization
---------------------------------------------------------------------
Operating expenses increased $22.2 million in 1998, and depreciation,
depletion and amortization increased $22 million, primarily due to higher
production volumes, including barrels delivered under the forward oil sale. The
Company's operating costs per oil equivalent-barrel were $5.97 and $6.47 in 1998
and 1997, respectively. Operating expenses on a per equivalent-barrel basis were
lower primarily due to higher production volumes and a decrease in production
taxes of $7.8 million. Beginning in 1998, no production taxes were assessed on
production from the Cusiana field. These improvements to operating costs were
partially offset by an increase in OCENSA pipeline tariffs which totaled $49.9
million or $4.08 per barrel, and $28.7 million or $3.69 per barrel, in 1998 and
1997, respectively. The OCENSA pipeline expansion was completed at the end of
1997. At such time, the full cost of the pipeline was included in the tariff
computation, which was the primary contributor to the higher 1998 tariffs.
General and Administrative Expenses
--------------------------------------
General and administrative expense before capitalization decreased
$13.8 million to $47.2 million in 1998, while capitalized general and
administrative costs were $20.6 million and $32.4 million in 1998 and 1997,
respectively. General and administrative expenses, and the portion capitalized,
decreased as a result of restructuring activities undertaken in the third
quarter of 1998 to reduce overhead costs and exploration expenses.
Interest Expense
-----------------
Gross interest expense for 1998 and 1997 totaled $46.4 million and
$49.7 million, respectively, while capitalized interest for 1998 decreased $2.6
million to $23.2 million. The decrease in capitalized interest is 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 (Expense), Net
------------------------------
Other income (expense), net, included foreign exchange gains of $2.1
million and $9.5 million in 1998 and 1997, respectively, primarily related to
noncash adjustments to deferred tax liabilities in Colombia associated with
devaluation of the Colombian peso versus the U.S. dollar. In 1998 and 1997, the
Company recognized gains of $7.6 million and $1.4 million, respectively, on the
sale of corporate assets. During 1998 and 1997, the Company recorded a gain
(loss) of $.4 million and ($9.7 million), respectively, representing the change
in the fair value of the call options purchased in anticipation of a forward oil
sale. In addition, during 1998, the Company recorded an expense of $3.3 million
in other income (expense), net, related to the net payments made under and the
change in the fair value of the equity swap entered into in conjunction with the
sale of TPC.
Income Taxes
-------------
The income tax provision for 1998 included a foreign deferred tax
benefit totaling $57 million compared with a foreign deferred tax expense of $16
million in 1997. The benefit recognized in 1998 primarily resulted from the
writedown of oil and gas properties. Additionally, the income tax provision
included deferred tax expense in the United States totaling $1.5 million,
compared with a benefit of $7.9 million in 1997. Current taxes related to the
Company's Colombian operations were $4.4 million and $3.4 million in 1998 and
1997, respectively.
Extraordinary Item
-------------------
In May and June 1997, the Company completed a tender offer and consent
solicitation with respect to its 1997 Notes and 9 3/4% Notes that resulted in
the retirement of the 1997 Notes and substantially all of the 9 3/4%
Notes. The Company's results of operations for 1997 included an
extraordinary expense of $14.5 million, net of a $7.8 million tax
benefit, associated with the extinguishment of the 1997 Notes and
9 3/4% Notes. The remainder of the 9 3/4% Notes were retired in 1998.
EXPLORATION OPERATIONS
-----------------------
Costs related to acquisition, holding and initial exploration of
licenses in countries with no proved reserves are initially capitalized,
including internal costs directly identified with acquisition, exploration and
development activities. The Company's exploration licenses are periodically
assessed for impairment on a country-by-country basis. If the Company's
investment in exploration licenses within a country where no proved reserves are
assigned is deemed to be impaired, the licenses are written down to estimated
recoverable value. If the Company abandons all exploration efforts in a country
where no proved reserves are assigned, all acquisition and exploration costs
associated with the country are expensed. The Company's assessments of whether
its investment within a country is impaired and whether exploration activities
within a country will be abandoned are made from time to time based on its
review and assessment of drilling results, seismic data and other information it
deems relevant. Due to the unpredictable nature of exploration drilling
activities, the amount and timing of impairment expense are difficult to predict
with any certainty. For example, in the second quarter of 1998, the Company
recorded a $77.3 million ($72.6 million, net of tax) writedown of unevaluated
oil and gas properties relating to the Company's operations in China, Ecuador,
Guatemala and other countries. There can be no assurance that, in the future,
the Company will not incur writedowns or expense with respect to its exploration
licenses. Financial information concerning the Company's assets at December 31,
1999, including capitalized costs by geographic area, is in note 21 of Notes to
Consolidated Financial Statements.
ENVIRONMENTAL MATTERS
---------------------
The Company is subject to extensive environmental laws and
regulations. These laws regulate the discharge of oil, gas or other materials
into the environment and may require the Company to remove or mitigate the
environmental effects of the disposal or release of such materials at various
sites. The Company believes that the level of future expenditures for
environmental matters, including clean-up obligations, is impractical to
determine with a precise and reliable degree of accuracy. Management believes
that such costs, when finally determined, will not have a material adverse
effect on the Company's operations or consolidated financial condition.
RECENT ACCOUNTING PRONOUNCEMENTS
--------------------------------
In June 1998, the Financial Accounting Standards Board issued
Statement No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and
Hedging Activities." SFAS 133 establishes accounting and reporting standards
for derivative instruments and for hedging activities. It requires enterprises
to recognize all derivatives as either assets or liabilities in the balance
sheet and measure those instruments at fair value. The requisite accounting for
changes in the fair value of a derivative will depend on the intended use of the
derivative and the resulting designation. The Company must adopt SFAS 133
effective January 1, 2001. Based on the Company's outstanding derivatives
contracts, the Company believes that the impact of adopting this standard would
not have a material adverse effect on the Company's operations or consolidated
financial condition. However, no assurances can be given with regard to the
level of the Company's derivatives activities at the time SFAS 133 is adopted or
the resulting effect on the Company's operations or consolidated financial
condition.
YEAR 2000 UPDATE
----------------
In 1998, the Company began a formal process to prepare the Company's
internal computerized systems for the Year 2000. From inception through
December 31, 1999, the Company spent approximately $250,000 related to the Year
2000 readiness issue. These costs included external consultants, professional
advisors, and software and hardware. No further material expenses are
anticipated. To date, the Company has not experienced any significant problems
related to Year 2000 compliance. Although the Company has not suffered any
significant Year 2000 issues or related disruptions as a result of the roll over
from 1999 to 2000, including through third parties with whom the Company has a
business relationship, it is possible that certain Year 2000 issues may exist
but have not yet materialized. While the Company believes that any future Year
2000 issues are of a much lower risk, there can be no assurance that these
issues will not have a material effect on the Company's operations.
CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS
---------------------------------------------------
Certain information contained in this report, as well as written and
oral statements made or incorporated by reference from time to time by the
Company and its representatives in other reports, filings with the Securities
and Exchange Commission, press releases, conferences, teleconferences or
otherwise, may be deemed to be "forward-looking statements" within the meaning
of Section 21E of the Securities Exchange Act of 1934 and are subject to the
"Safe Harbor" provisions of that section. Forward-looking statements include
statements concerning the Company's and management's plans, objectives, goals,
strategies and future operations and performance and the assumptions underlying
such forward-looking statements. When used in this document, the words
"anticipates," "estimates," "expects," "believes," "intends," "plans" and
similar expressions are intended to identify such forward-looking statements.
These statements include information regarding:
- - drilling schedules;
- - expected or planned production capacity;
- - future production from the Cusiana and Cupiagua fields in Colombia, including
from the Recetor license;
- - the completion of development and commencement of production in
Malaysia-Thailand;
- - future production of the Ceiba field in Equatorial Guinea, including volumes
and timing of first production;
- - the acceleration of the Company's exploration, appraisal and development
activities in Equatorial Guinea;
- - the Company's capital budget and future capital requirements;
- - the Company's meeting its future capital needs;
- - the Company's utilization of net operating loss carryforwards and realization
of its deferred tax asset;
- - the level of future expenditures for environmental costs;
- - the outcome of regulatory and litigation matters;
- - the estimated fair value of derivative instruments, including the equity
swap; and
- - proven oil and gas reserves and discounted future net cash flows therefrom.
These statements are based on current expectations and involve a
number of risks and uncertainties, including those described in the context of
such forward-looking statements, and in notes 19 and 20 of Notes to 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 7. A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
Commodity Risk
- --------------
The Company's primary commodity market risk exposure is to changes in the
pricing applicable to its oil production, which is normally priced with
reference to a defined benchmark, such as light, sweet crude oil traded on the
New York Mercantile Exchange (WTI). Actual prices received vary from the
benchmark depending on quality and location differentials. The markets for
crude oil historically have been volatile and are likely to continue to be
volatile in the future. During the three year period ended December 31, 1999,
WTI oil prices fluctuated between a low price of $11.37 per barrel and a high
price of $27.07 per barrel.
From time to time, it is the Company's policy to use financial market
transactions, including swaps, collars and options, with creditworthy
counterparties, primarily to reduce the risk associated with the pricing of a
portion of the oil and natural gas that it sells. The policy is structured to
underpin the Company's planned revenues and results of operations. The Company
does not enter into financial market transactions for trading purposes.
During the years ended December 31, 1999 and 1997, markets provided the
Company the opportunity to realize WTI benchmark oil prices on average $6.37 per
barrel and $2.35 per barrel, respectively, above the WTI benchmark oil price the
Company set as part of its annual plan for the period. During the year ended
December 31, 1998, the Company did not have any outstanding financial market
transactions to hedge against oil price fluctuations. As a result of financial
and commodity market transactions settled during the years ended December 31,
1999 and 1997, the Company's risk management program resulted in an average net
realization of approximately $1.65 per barrel and $.11 per barrel, respectively,
lower than if the Company had not entered into such transactions. Realized gains
or losses from the Company's price risk management activities are recognized in
oil and gas sales at the time of settlement of the underlying hedged
transaction.
With respect to the sale of oil to be produced by the Company, the Company has
entered into oil price collars with creditworthy counterparties to establish a
weighted average minimum WTI benchmark price of $18.92 per barrel and a maximum
of $24.45 per barrel on an aggregate of 3.6 million barrels of production during
the period from January through June 2000. As a result, to the extent the
average monthly WTI price exceeds $24.45, the Company will pay the
counterparties the difference between the average monthly WTI price and $24.45,
and to the extent that the average monthly WTI price is below $18.92, the
counterparties will pay the Company the difference between the average monthly
WTI price and $18.92. In addition, the Company has entered into option
contracts for an aggregate of 300,000 barrels of production during the period
from July through September 2000. As a result, to the extent the monthly
average WTI exceeds $28.43 per barrel, the Company will pay the counterparty the
difference between the average WTI and $28.43, and to the extent WTI is at or
below $22.00, the counterparty will pay the Company $2.00 per barrel. The
Company used a sensitivity analysis technique to evaluate the hypothetical
effect that changes in WTI oil prices may have on the fair value of these
contracts. At December 31, 1999, the potential decrease in future earnings,
assuming a ten percent movement in WTI oil prices, would not have a material
adverse effect on the Company's consolidated financial position or results of
operations.
In anticipation of entering into the forward oil sale, in 1995 the Company
purchased WTI benchmark call options to retain the ability to benefit from WTI
price increases above a weighted average price of $20.42 per barrel. The
volumes and expiration dates on the call options coincide with the volumes and
delivery dates of the forward oil sale, which will be completed in March 2000.
During the years ended December 31, 1999, 1998 and 1997, the Company recorded a
gain (loss) of $6.1 million, $.4 million, and ($9.7 million), respectively, in
other income (expense), net, related to the change in the fair market value of
the call options. In November 1999, the Company sold WTI benchmark call options
with the same notional quantities, strike price and contract period as the
remaining call option contracts outstanding for a premium of $4.4 million for
the purpose of realizing the fair value of the purchased call options. As a
result, the Company has eliminated its exposure to future changes in value of
the call options caused by fluctuating oil prices.
Interest Rate Risk
- --------------------
Equity Swap
------------
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 Company's LIBOR-based payments commenced in March 1998,
and OCENSA commenced paying dividends in September 1998. OCENSA's first
dividend was attributable to the four month period ending June 1998. During the
years ended December 31, 1999 and 1998, the Company made payments to the
Counterparty totaling $6.2 million and $5.9 million, respectively, and received
payments from the Counterparty totaling $7.8 million and $2.6 million,
respectively.
The equity swap is carried in the Company's financial statements at fair
value during its term, which, as amended, will expire April 14, 2000. The value
of the equity swap in the Company's financial statements is equal to 97% of the
estimated fair value of the shares of OCENSA owned by TPC. Because there is no
public market for the shares of OCENSA, the Company estimates their value using
a discounted cash flow model applied to the distributions expected to be paid in
respect of the OCENSA shares. The discount rate applied to the estimated cash
flows from the OCENSA shares is based on a combination of current market rates
of interest, a credit spread for OCENSA's debt, and a spread to reflect the
preferred stock nature of the OCENSA shares. During the years ended December 31,
1999 and 1998, the Company recorded an expense of $6.9 million and $3.3 million
in other income (expense), net, related to the net payments made under and the
change in the fair market value of the equity swap. The Company also evaluated
the potential effect that near-term changes in interest rates could have on the
fair value of the equity swap. Based upon an analysis utilizing the actual
discount rate in effect as of December 31, 1999, and assuming a ten percent
adverse movement in the discount rate, the potential decrease in the fair value
of the equity swap at December 31, 1999, would be approximately $6.3 million.
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
(expense), net in such periods. There can be no assurance that changes in
interest rates, or in other factors that affect the value of the OCENSA shares
and/or the equity swap, will not have a material adverse effect on the carrying
value of the equity swap.
Upon the expiration of the equity swap in April 2000, the Company
expects that the Purchaser will sell the TPC shares. Under the terms of the
equity swap with the Counterparty, upon any sale by the Purchaser of the TPC
shares, the Company will receive from the Counterparty, or pay to the
Counterparty, an amount equal to the excess or deficiency, as applicable, of the
difference between 97% of the net proceeds from the Purchaser's sale of the TPC
shares and the notional amount of $97 million. For example if the Purchaser
sold the TPC shares for an amount equal to the value the Company has estimated
for purposes of preparing its balance sheet as of December 31, 1999, the Company
would have to make a payment to the Counterparty under the equity swap of
approximately $8.4 million. There can be no assurance that the value the
Purchaser may realize in any sale of the TPC shares will equal the value of the
shares estimated by the Company for purposes of valuing the equity swap. The
Company has no right or obligation to repurchase the TPC shares at any time, but
the Company is not prohibited from offering to purchase the shares if the
Purchaser offers to sell them. The Company expects to make a bid for the
acquisition of the TPC shares because the Company's pipeline tariffs can be
lowered by electing to cancel the dividend to the holder of the OCENSA shares.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Results of Operations - Other Income and Expenses" and note 2 of
Notes to Consolidated Financial Statements.
Indebtedness of the Company
------------------------------
The Company believes its interest rate exposure on debt is not
significant since only $13.5 million out of total debt of $413.5 million at
December 31, 1999, has floating interest rate obligations.
Foreign Currency Risk
- -----------------------
The Company derives substantially all of its consolidated revenues
from international operations. A risk inherent in international operations is
the possibility of realizing economic currency-exchange losses when transactions
are completed in currencies other than U.S. dollars. The Company's risk of
realizing currency-exchange losses currently is largely mitigated because the
Company receives U.S. dollars for sales of its petroleum products in Colombia.
With respect to expenditures denominated in currencies other than the U.S.
dollar, the Company generally converts U.S. dollars to the local currency near
the applicable payment dates to minimize exposure to losses caused by holding
foreign currency deposits. During the three-year period ended December 31,
1999, the Company did not realize any material foreign exchange losses from its
international operations.
The Company evaluated the potential effect that reasonably possible
near-term changes in foreign exchange rates may have on the fair value of
foreign currency denominated assets. Based on analysis utilizing the actual
foreign currency exchange rates at December 31, 1999, and assuming a ten percent
adverse movement in exchange rates, the potential decrease in fair value of
foreign currency denominated assets does not have a material adverse effect on
the Company's consolidated financial position or results of operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements required by this item begin at page F-1 hereof.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information relating to the Company's directors and nominees for
election as directors of the Company is incorporated herein by reference from
the Proxy Statement for the 2000 Annual Meeting of Shareholders of the Company
(the "Proxy Statement"), specifically the discussion under the heading "Election
of Directors." The Company expects that the Proxy Statement will be publicly
available and mailed in April 2000. Certain information as to executive officers
is included herein under Items 1 and 2, "Business and Properties - Executive
Officers." The discussion under "Section 16(a) Beneficial Ownership Reporting
Compliance" in the Proxy Statement is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The discussion under "Management Compensation" in the Proxy Statement
is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The discussion under "Security Ownership of Management and Certain
Shareholders" in the Proxy Statement is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The discussion under "Management Compensation - Compensation Committee
Interlocks and Insider Participation and Certain Transactions" in the Proxy
Statement is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this Annual Report on
Form 10-K:
1. Financial Statements: The financial statements filed as part of
this report are listed in the "Index to Financial Statements and Schedules" on
page F-1 hereof.
2. Financial Statement Schedules: The financial statement schedules
filed as part of this report are listed in the "Index to Financial Statements
and Schedules" on page F-1 hereof.
3. Exhibits required to be filed by Item 601 of Regulation S-K. (Where
the amount of securities authorized to be issued under any of Triton Energy
Limited's and any of its subsidiaries' long-term debt agreements does not exceed
10% of the Company's assets, pursuant to paragraph (b)(4) of Item 601 of
Regulation S-K, in lieu of filing such as exhibits, the Company hereby agrees to
furnish to the Commission upon request a copy of any agreement with respect to
such long-term debt.)
3.1 Memorandum of Association (previously filed as an exhibit to the Company's
Registration Statement on Form S-3 (No 333-08005) and incorporated herein by
reference)
3.2 Articles of Association (previously filed as an exhibit to the Company's
Registration Statement on Form S-3 (No 333-08005) and incorporated herein by
reference)
4.1 Specimen Share Certificate of Ordinary Shares, $.01 par value, of the Company
(previously filed as an exhibit to the Company's Registration Statement on Form 8-A
dated March 25, 1996, and incorporated herein by reference)
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 (previously filed as an exhibit to the
Company's Registration Statement on Form S-3 (No 333-08005) and incorporated herein
by reference)
4.3 Resolutions Authorizing the Company's 5% Convertible Preference Shares (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)
4.4 Amendment No. 1 to Rights Agreement dated as of August 2, 1996, between Triton
Energy Limited and The Chase Manhattan Bank, as Rights Agent (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)
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 (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)
4.6 Unanimous Written Consent of the Board of Directors authorizing a Series of
Preference Shares (previously filed as an exhibit to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and
incorporated herein by reference.)
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 (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)
10.1 Amended and Restated Retirement Income Plan (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) (1)
10.2 Amendment to the Retirement Income Plan dated August 1, 1998. (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.) (1)
10.3 Amendment to Amended and Restated Retirement Income Plan dated
December 31, 1996 (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) (1)
10.4 Amended and Restated Supplemental Executive Retirement Income Plan. (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.) (1)
10.5 1981 Employee Non-Qualified Stock Option Plan. (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.) (1)
10.6 Amendment No. 1 to the 1981 Employee Non-Qualified Stock Option Plan. (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 herein by reference.) (1)
10.7 Amendment No. 2 to the 1981 Employee Non-Qualified Stock Option Plan. (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.) (1)
10.8 Amendment No. 3 to the 1981 Employee Non-Qualified Stock Option Plan. (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.) (1)
10.9 1985 Stock Option Plan. (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.) (1)
10.10 Amendment No. 1 to the 1985 Stock Option Plan. (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)
10.11 Amendment No. 2 to the 1985 Stock Option Plan. (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.) (1)
10.12 Amended and Restated 1986 Convertible Debenture Plan. (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 herein by reference.) (1)
10.13 1988 Stock Appreciation Rights Plan. (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.) (1)
10.14 1989 Stock Option Plan. (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.) (1)
10.15 Amendment No. 1 to 1989 Stock Option Plan. (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.) (1)
10.16 Amendment No. 2 to 1989 Stock Option Plan. (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 herein by reference.) (1)
10.17 Second Amended and Restated 1992 Stock Option Plan.(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.) (1)
10.18 Form of Amended and Restated Employment Agreement with Triton Energy Limited
and certain officers, including Messrs. Dunlevy, Garrett and Maxted (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.) (1)
10.19 Amended and Restated Employment Agreement among Triton Energy Limited, Triton
Exploration Services, Inc. and Robert B. Holland, III. (previously filed as an exhibit
to the Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1998, and incorporated herein by reference.) (1)
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. (previously
filed as an exhibit to the Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 1998, and incorporated herein by reference.) (1)
10.21 Letter Agreement among Triton Energy Limited, Triton Exploration Services, Inc.
and Robert B. Holland, III dated December 17, 1998. (previously filed as an exhibit to
the Company's Annual Report on Form 10-K for the year ended December 31, 1998 and
incorporated herein by reference.) (1)
10.22 Letter Agreement among Triton Energy Limited, Triton Exploration Services, Inc.
and Peter Rugg dated December 10, 1998. (previously filed as an exhibit to the
Company's Annual Report on Form 10-K for the year ended December 31, 1998 and
incorporated herein by reference.) (1)
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. (previously
filed as an exhibit to the Annual Report on Form 10-K for the year ended December 31,
1998 and incorporated herein by reference.) (1)
10.24 Amended and Restated 1985 Restricted Stock Plan. (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 herein by reference.) (1)
10.25 First Amendment to Amended and Restated 1985 Restricted Stock Plan. (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.) (1)
10.26 Second Amendment to Amended and Restated 1985 Restricted Stock Plan. (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.) (1)
10.27 Executive Life Insurance Plan. (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.) (1)
10.28 Long Term Disability Income Plan. (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.) (1)
10.29 Amended and Restated Retirement Plan for Directors. (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.) (1)
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. (previously filed as an exhibit to Triton Energy Corporation's Annual
Report on Form 10-K for the fiscal year ended May 31, 1990, and incorporated
herein by reference.)
10.31 Contract for Exploration and Exploitation for Tauramena with an effective date of July
4, 1988, between Triton Colombia, Inc., and Empresa Colombiana De Petroleos.
(previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended May 31, 1990, and incorporated herein by reference.)
10.32 Summary of Assignment legalized by Public Instrument No. 1255 dated September 15,
1987 (Assignment is in Spanish language). (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 herein by reference.)
10.33 Summary of Assignment legalized by Public Instrument No. 1602 dated June 11, 1990
(Assignment is in Spanish language). (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 herein by reference.)
10.34 Summary of Assignment legalized by Public Instrument No. 2586 dated September 9,
1992 (Assignment is in Spanish language). (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 herein by reference.)
10.35 401(K) Savings Plan. (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 herein by reference.) (1)
10.36 Amendment to the 401(k) Savings Plan dated August 1, 1998. (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.) (1)
10.37 Amendment to 401(k) Savings Plan dated December 31, 1996. (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.) (1)
10.38 Contract between Malaysia-Thailand 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. (previously
filed as an exhibit to Triton Energy Corporation's Current Report on Form 8-K dated
April 21, 1994, and incorporated herein by reference.)
10.39 Triton Crude Purchase Agreement between Triton Colombia, Inc. and Oil Co., LTD.
dated May 25, 1995. (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.)
10.40 Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation,
NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States
(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.)
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. (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.)
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. (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)
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. (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)
10.44 Form of Indemnity Agreement entered into with each director and officer of the
Company. (previously filed as an exhibit to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1998, and incorporated herein by reference)
10.45 Description of Performance Goals for Executive Bonus Compensation. (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) (1)
10.46 Stock Purchase Agreement dated September 2, 1997, between The Strategic
Transaction Company and Triton International Petroleum, Inc. (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)
10.47 Fourth Amendment to Stock Purchase Agreement dated February 2, 1998, between
The Strategic Transaction Company and Triton International Petroleum, Inc. (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)
10.48 Amended and Restated 1997 Share Compensation Plan. (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) (1)
10.49 First Amendment to Amended and Restated Retirement Plan for Directors. (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) (1)
10.50 First Amendment to Second Amended and Restated 1992 Stock Option Plan. (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) (1)
10.51 Second Amendment to Second Amended and Restated 1992 Stock Option Plan.
(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) (1)
10.52 Amended and Restated Indenture dated July 25, 1997, between Triton Energy
Limited and The Chase Manhattan Bank. (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)
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. (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)
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. (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)
10.55 Share Purchase Agreement dated July 17, 1998, among Triton Energy Limited, Triton
Asia Holdings, Inc., Atlantic Richfield Company and ARCO JDA Limited.
(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)
10.56 Shareholders Agreement dated August 3, 1998, among Triton Energy Limited, Triton
Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA Limited.
(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)
10.57 Stock Purchase Agreement dated as of August 31, 1998, between Triton Energy
Limited and HM4 Triton, L.P. (previously filed as an exhibit to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and
incorporated herein by reference)
10.58 Shareholders Agreement dated as of September 30, 1998, between Triton Energy
Limited and HM4 Triton, L.P. (previously filed as an exhibit to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and
incorporated herein by reference)
10.59 Financial Advisory Agreement dated as of September 30, 1998, between Triton Energy
Limited and Hicks, Muse & Co. Partners, L.P. (previously filed as an exhibit to the
Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998,
and incorporated herein by reference)
10.60 Monitoring and Oversight Agreement dated as of September 30, 1998, between Triton
Energy Limited and Hicks, Muse & Co. Partners, L.P. (previously filed as an exhibit to
the Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
1998, and incorporated herein by reference)
10.61 Severance Agreement dated as of July 15, 1998, between Thomas G. Finck and Triton
Energy Limited. (previously filed as an exhibit to the Company's Quarterly Report
on Form 10-Q for the quarter ended September 30, 1998, and incorporated herein by
reference) (1)
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. (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) (1)
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. (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) (1)
10.64 Third Amendment to Amended and Restated 1985 Restricted Stock Plan (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) (1)
10.65 Amendment to Triton Exploration Services, Inc. Retirement Income Plan. (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) (1)
10.66 Amendment to the Triton Exploration Services, Inc. Supplemental Executive
Retirement Plan. (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) (1)
10.67 Third Amendment to the Second Amended and Restated 1992 Stock Option Plan
(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) (1)
10.68 First Amendment to the Amended and Restated 1997 Share Compensation Plan
(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) (1)
10.69 Amendment dated May 11, 1999, to Amended and Restated Employment Agreement
dated July 15, 1998 among Triton Exploration Services, Inc., Triton Energy Limited
and A.E. Turner, III.(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) (1)
10.70 Form of Amendment dated May 11, 1999, to Employment Agreement
among Triton Exploration Services, Inc., Triton Energy Limited and certain officers,
including Messrs. Dunlevy, Garrett and Maxted (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) (1)
10.71 Second Amendment to Retirement Plan for Directors. (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) (1)
10.72 Amendment to Triton Exploration Services, Inc. 401 (k) Savings Plan. (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) (1)
10.73 Amendment No. 1 to Shareholders Agreement between Triton Energy Limited
and HM4 Triton, L.P. (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) (1)
10.74 Amendment No. 4 to the 1981 Employee Nonqualified Stock Option Plan. (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) (1)
10.75 Amendment No. 3 to the 1985 Stock Option Plan. (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) (1)
10.76 Amendment No. 3 to the 1989 Stock Option Plan. (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) (1)
10.77 Supplemental Letter Agreement dated October 28, 1999, among Triton Energy
Limited, Triton Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA
Limited (previously filed as an exhibit to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1999, and incorporated herein by reference)
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. (previously filed
as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1999, and incorporated herein by reference)
10.79* Form of Stock Option Agreement between Triton Energy Limited and its
non-employee directors. (1)
10.80* Form of Stock Option Agreement between Triton Energy Limited and its employees,
including its executive officers. (1)
10.81* Amendment to Stock Options dated as of January 3, 2000, between Triton Energy Limited and A.E. Turner. (1)
10.82* Form of Amendment to Stock Options dated as of January 3, 2000, between Triton
Energy Limited and its non-employee directors. (1)
10.83* Production Sharing Contract between the Republic of Equatorial Guinea
and Triton Equatorial Guinea, Inc. for Block F.
10.84* Production Sharing Contract between the Republic of Equatorial Guinea and Triton
Equatorial Guinea, Inc. for Block G.
10.85* Supplementary Contract (No. 1) to the Production Sharing Contract for Block A-18
dated 21 April 1994 between Malaysia-Thailand Joint Authority and Petronas
Carigali (JDA) SDN.BHD., Triton Oil Company of Thailand and Triton Oil Company
of Thailand (JDA) Limited.
10.86* Supplementary Contract (No. 2) to the Production Sharing Contract for Block A-18
dated 21 April 1994 between Malaysia-Thailand Joint Authority and Petronas Carigali
(JDA) SDN.BHD., Triton Oil Company of Thailand and Triton Oil Company of
Thailand (JDA) Limited.
10.87* Credit Agreement dated as of February 29, 2000, among Triton Energy Limited,
the Lenders party thereto and The Chase Manhattan bank, as Administrative Agent
12.1* Computation of Ratio of Earnings to Fixed Charges.
12.2* Computation of Ratio of Earnings to Combined Fixed Charges and Preference
Dividends.
21.1* Subsidiaries of the Company.
23.1* Consent of PricewaterhouseCoopers LLP.
23.2* Consent of DeGolyer and MacNaughton.
23.3* Consent of Netherland, Sewell & Associates, Inc.
24.1* The power of attorney of officers and directors of the Company
27.1* Financial Data Schedule.
99.1 Rio Chitamena Association Contract. (previously filed as an exhibit to Triton Energy
Corporation's Current Report on Form 8-K/A dated July 15, 1994, and incorporated
herein by reference)
99.2 Rio Chitamena Purchase and Sale Agreement. (previously filed as an exhibit to Triton
Energy Corporation's Current Report on Form 8-K/A dated July 15, 1994, and
incorporated herein by reference)
99.3 Integral Plan - Cusiana Oil Structure. (previously filed as an exhibit to Triton Energy
Corporation's Current Report on Form 8-K/A dated July 15, 1994, and incorporated
herein by reference)
99.4 Letter Agreements with co-investor in Colombia. (previously filed as an exhibit to
Triton Energy Corporation's Current Report on Form 8-K/A dated July 15, 1994, and
incorporated herein by reference)
99.5 Amended and Restated Oleoducto Central S.A. Agreement dated as of March 31,
1995. (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)
- -------------------------
* Previously filed herewith.
(1) Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K.
None
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Amendment No. 2 to
Annual Report on Form 10-K to be signed by the undersigned thereunto duly
authorized on the 15th day of March, 2000.
TRITON ENERGY LIMITED
By:/s/W. Greg Dunlevy
-------------------------------------
W. Greg Dunlevy
Vice President, Finance
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Amendment No. 2 to Annual Report on Form 10-K has been signed below by the
following persons on behalf of the Registrant and in the capacities
indicated on the 15th day of March, 2000.
Signatures Title
---------- -----
/s/W. Greg Dunlevy Vice President
- -----------------------
W. Greg Dunlevy (Principal Financial Officer)
/s/Kevin B. Wilcox Controller
- ----------------------
Kevin B. Wilcox
* Chairman of the Board
- ----------------------
Thomas O. Hicks
* President and Chief Executive Officer
- ---------------------- (Principal Executive Officer)
James C. Musselman
* Director
- ----------------------
Sheldon R. Erikson
* Director
- ----------------------
Jack D. Furst
* Director
- ----------------------
Fitzgerald Hudson
* Director
- ----------------------
John R. Huff
* Director
- ----------------------
Michael E. McMahon
* Director
- ----------------------
C. Lamar Norsworthy
* Director
- ----------------------
C. Richard Vermillion
* Director
- ----------------------
J. Otis Winters
*By /s/ W. Greg Dunlevy
--------------------------
W. Greg Dunlevy, Attorney-in-Fact
TRITON ENERGY LIMITED AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
PAGE
-----
TRITON ENERGY LIMITED AND SUBSIDIARIES:
Report of Independent Accountants. . . . . . . . . . . . . . . . . . . . . . . . F-2
Consolidated Statements of Operations - Years ended December 31, 1999, 1998
and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-3
Consolidated Balance Sheets - December 31, 1999 and 1998 . . . . . . . . . . . . F-4
Consolidated Statements of Cash Flows - Years ended December 31, 1999, 1998
and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5
Consolidated Statements of Shareholders' Equity - Years ended December 31, 1999,
1998 and 1997. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-6
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . F-7
SCHEDULE:
II - Valuation and Qualifying Accounts - Years ended December 31, 1999,
1998 and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-52
All other schedules are omitted as the required information is inapplicable or
presented in the consolidated financial statements or related notes.
REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------
To the Board of Directors and Shareholders of
Triton Energy Limited
In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Triton
Energy Limited and its subsidiaries at December 31, 1999 and 1998, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally
accepted in the United States which require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Dallas, Texas
February 23, 2000
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
--------------------------------
1999 1998 1997
--------- ---------- ---------
SALES AND OTHER OPERATING REVENUES:
Oil and gas sales $247,878 $ 160,881 $145,419
Gain on sale of oil and gas assets --- 67,737 4,077
--------- ---------- ---------
247,878 228,618 149,496
--------- ---------- ---------
COSTS AND EXPENSES:
Operating 68,130 73,546 51,357
General and administrative 23,636 26,653 28,607
Depreciation, depletion and amortization 61,343 58,811 36,828
Writedown of assets --- 328,630 ---
Special charges 2,909 18,324 ---
--------- ---------- ---------
156,018 505,964 116,792
--------- ---------- ---------
OPERATING INCOME (LOSS) 91,860 (277,346) 32,704
Gain on sale of Triton Pipeline Colombia --- 50,227 ---
Interest income 10,579 3,258 5,178
Interest expense, net (22,648) (23,228) (23,858)
Other income (expense), net (3,614) 8,480 2,872
--------- ---------- ---------
(15,683) 38,737 (15,808)
--------- ---------- ---------
EARNINGS (LOSS) BEFORE INCOME TAXES
AND EXTRAORDINARY ITEM 76,177 (238,609) 16,896
Income tax expense (benefit) 28,620 (51,105) 11,301
--------- ---------- ---------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM 47,557 (187,504) 5,595
Extraordinary item - extinguishment of debt --- --- (14,491)
--------- ---------- ---------
NET EARNINGS (LOSS) 47,557 (187,504) (8,896)
DIVIDENDS ON PREFERENCE SHARES 28,671 3,061 400
--------- ---------- ---------
EARNINGS (LOSS) APPLICABLE TO ORDINARY SHARES $ 18,886 $(190,565) $ (9,296)
========= ========== =========
Average ordinary shares outstanding 36,135 36,609 36,471
========= ========== =========
BASIC EARNINGS (LOSS) PER ORDINARY SHARE:
Earnings (loss) before extraordinary item $ 0.52 $ (5.21) $ 0.14
Extraordinary item - extinguishment of debt --- --- (0.40)
--------- ---------- ---------
BASIC EARNINGS (LOSS) $ 0.52 $ (5.21) $ (0.26)
========= ========== =========
DILUTED EARNINGS (LOSS) PER ORDINARY SHARE:
Earnings (loss) before extraordinary item $ 0.52 $ (5.21) $ 0.14
Extraordinary item - extinguishment of debt --- --- (0.39)
--------- ---------- ---------
DILUTED EARNINGS (LOSS) $ 0.52 $ (5.21) $ (0.25)
========= ========== =========
See accompanying Notes to Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
ASSETS DECEMBER 31,
---------------------
1999 1998
---------- ---------
CURRENT ASSETS:
Cash and equivalents $ 186,323 $ 18,757
Trade receivables, net 17,246 9,514
Other receivables 23,814 47,756
Deferred income taxes 20,090 ---
Inventories, prepaid expenses and other 7,806 1,639
---------- ---------
TOTAL CURRENT ASSETS 255,279 77,666
Property and equipment, at cost, net 524,152 470,907
Investment in affiliate 93,188 84,735
Deferred income taxes 88,228 100,916
Other assets 13,628 20,056
---------- ---------
$ 974,475 $754,280
========== =========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt $ 9,027 $ 14,027
Short-term borrowings --- 5,000
Accounts payable and accrued liabilities 62,576 44,973
Deferred income and other 22,347 35,254
---------- ---------
TOTAL CURRENT LIABILITIES 93,950 99,254
Long-term debt, excluding current maturities 404,460 413,465
Deferred income taxes 6,677 3,235
Other liabilities 6,336 14,519
SHAREHOLDERS' EQUITY:
5% preference shares, par value $.01; authorized 420,000
shares; issued 209,639 shares at December 31, 1999 and
1998, respectively, stated value $34.41 7,214 7,214
8% preference shares, par value $.01; authorized 11,000,000
shares; issued 5,193,643 and 1,822,500 shares at
December 31, 1999 and 1998, respectively, stated value $70 363,555 127,575
Ordinary shares, par value $.01; authorized 200,000,000
shares; issued 35,763,728 and 36,643,478 shares at
December 31, 1999 and 1998, respectively 358 366
Additional paid-in capital 531,904 575,863
Accumulated deficit (437,528) (485,085)
Accumulated other non-owner changes in shareholders' equity (2,451) (2,126)
---------- ---------
TOTAL SHAREHOLDERS' EQUITY 463,052 223,807
Commitments and contingencies (note 20) --- ---
---------- ---------
$ 974,475 $754,280
========== =========
The Company uses the full cost method to account for its oil- and gas-producing
activities.
See accompanying Notes to Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
----------------------------------
1999 1998 1997
---------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ 47,557 $(187,504) $ (8,896)
Adjustments to reconcile net earnings to net cash provided (used)
by operating activities:
Depreciation, depletion and amortization 61,343 58,811 36,828
Proceeds from forward oil sale 31,932 1,770 830
Amortization of deferred income (35,254) (35,254) (28,467)
Gain on sale of oil and gas assets --- (67,737) (4,077)
Gain on sale of Triton Pipeline Colombia --- (50,227) ---
Writedown of assets --- 328,630 ---
Payment of accreted interest on extinguishment of debt --- --- (124,794)
Extraordinary loss on extinguishment of debt, net of tax --- --- 14,491
Amortization of debt discount --- --- 7,949
Deferred income taxes 7,827 (55,592) 8,078
Gain on sale of other assets (677) (7,590) (1,409)
Other, net 8,921 3,962 6,100
Changes in working capital:
Trade and other receivables (16,131) 6,300 (3,238)
Inventories, prepaid expenses and other (3,577) 918 1,794
Accounts payable and accrued liabilities 14,581 4,979 (2,605)
---------- ---------- ----------
Net cash provided (used) by operating activities 116,522 1,466 (97,416)
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures and investments (121,483) (180,215) (219,216)
Proceeds from sale of oil and gas assets --- 147,027 4,077
Proceeds from sale of Triton Pipeline Colombia --- 97,656 ---
Proceeds from sales of other assets 2,353 22,353 1,822
Other 600 (2,630) 617
---------- ---------- ----------
Net cash provided (used) by investing activities (118,530) 84,191 (212,700)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving lines of credit and long-term debt --- 162,530 620,413
Payments on revolving lines of credit and long-term debt (19,028) (350,511) (321,515)
Short-term notes payable, net --- (9,600) 9,600
Issuance of 8% preference shares, net 217,805 115,329 ---
Issuances of ordinary shares 419 2,544 5,260
Repurchase of ordinary shares (11,285) --- ---
Dividends paid on preference shares (17,617) (368) (400)
Other (151) 5 10
---------- ---------- ----------
Net cash provided (used) by financing activities 170,143 (80,071) 313,368
---------- ---------- ----------
Effect of exchange rate changes on cash and equivalents (569) (280) (849)
---------- ---------- ----------
Net increase in cash and equivalents 167,566 5,306 2,403
CASH AND EQUIVALENTS AT BEGINNING OF YEAR 18,757 13,451 11,048
---------- ---------- ----------
CASH AND EQUIVALENTS AT END OF YEAR $ 186,323 $ 18,757 $ 13,451
========== ========== ==========
See accompanying Notes to Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1999 1998 1997
-------------------- ---------------------- --------------------
OWNER SOURCES OF SHAREHOLDERS' EQUITY:
5% PREFERENCE SHARES:
Balance at beginning of period $ 7,214 $ 7,511 $ 8,515
Conversion of 5% preference shares --- (297) (1,004)
---------- ---------- ----------
Balance at end of period 7,214 7,214 7,511
---------- ---------- ----------
8% PREFERENCE SHARES:
Balance at beginning of period 127,575 --- ---
Issuances of 8% preference shares at $70 per share 222,425 127,575 ---
Conversion of 8% preference shares (192) --- ---
Stock dividends, 8% preference shares 13,747 --- ---
---------- ---------- ----------
Balance at end of period 363,555 127,575 ---
---------- ---------- ----------
ORDINARY SHARES:
Balance at beginning of period 366 365 363
Stock repurchase (9) --- ---
Exercise of employee stock options and debentures 1 1 2
---------- ---------- ----------
Balance at end of period 358 366 365
---------- ---------- ----------
ADDITIONAL PAID-IN CAPITAL:
Balance at beginning of period 575,863 588,454 582,581
Dividends, 5% preference shares (361) (368) (400)
Dividends, 8% preference shares (28,310) (2,693) ---
Exercise of employee stock options and debentures 418 2,548 3,831
Conversion of 5% preference shares --- 297 1,004
Conversion of 8% preference shares 192 --- ---
Transaction costs for issuance of
8% preference shares (4,620) (12,370) ---
Stock repurchase (11,276) --- ---
Other, net (2) (5) 1,438
---------- ---------- ----------
Balance at end of period 531,904 575,863 588,454
---------- ---------- ----------
TREASURY SHARES:
Balance at beginning of period --- (3) (2)
Retirement and other, net --- 3 (1)
---------- ---------- ----------
Balance at end of period --- --- (3)
---------- ---------- ----------
TOTAL OWNER SOURCES OF SHAREHOLDERS' EQUITY 903,031 711,018 596,327
---------- ---------- ----------
NON-OWNER SOURCES OF SHAREHOLDERS' EQUITY:
ACCUMULATED DEFICIT:
Balance at beginning of period (485,085) (297,581) (288,685)
Net earnings (loss) 47,557 $47,557 (187,504) $(187,504) (8,896) $(8,896)
---------- ---------- ----------
Balance at end of period (437,528) (485,085) (297,581)
---------- ---------- ----------
ACCUMULATED OTHER NON-OWNER CHANGES IN
SHAREHOLDERS' EQUITY:
Balance at beginning of period (2,126) (2,126) (2,128)
Valuation reserve on marketable securities --- --- 2
Adjustment for minimum pension liability (325) --- ---
-------- ---------- --------
Other non-owner changes in shareholders' equity (325) (325) --- --- 2 2
---------- -------- ---------- ---------- ---------- --------
Non-owner changes in shareholders' equity $47,232 $(187,504) $(8,894)
======== ========== ========
Balance at end of period (2,451) (2,126) (2,126)
---------- ---------- ----------
TOTAL NON-OWNER SOURCES OF
SHAREHOLDERS' EQUITY (439,979) (487,211) (299,707)
---------- ---------- ----------
TOTAL SHAREHOLDERS' EQUITY $ 463,052 $ 223,807 $ 296,620
========== ========== ==========
See accompanying Notes to Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS IN TABLES IN THOUSANDS, EXCEPT FOR SHARE, PER SHARE AND PER BARREL
DATA)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
Triton Energy Limited ("Triton") is an international oil and gas exploration and
production company. The term "Company" when used herein means Triton and its
subsidiaries and other affiliates through which the Company conducts its
business. The Company's principal properties, operations, and oil and gas
reserves are located in Colombia, Malaysia-Thailand and Equatorial Guinea. The
Company is exploring for oil and gas in these areas, as well as in southern
Europe, Africa, and the Middle East. All sales are currently derived from oil
and gas production in Colombia.
Triton, a Cayman Islands company, was incorporated in 1995 to become the parent
holding company of Triton Energy Corporation, a Delaware corporation ("TEC").
On March 25, 1996, the stockholders of TEC approved the merger of a wholly owned
subsidiary of Triton with and into TEC (the "Reorganization"). Pursuant to the
Reorganization, Triton became the parent holding company of TEC and each share
of common stock, par value $1.00, and 5% preferred stock of TEC outstanding on
March 25, 1996, was converted into one Triton ordinary share, par value $.01,
and one 5% Triton preference share, respectively. The Reorganization has been
accounted for as a combination of entities under common control.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Triton and its
majority-owned subsidiaries. All intercompany balances and transactions have
been eliminated in consolidation. Investments in 20%- to 50%-owned affiliates
which the Company exercises significant influence over operating and financial
policies are accounted for using the equity method. Investments in less than
20%-owned affiliates are accounted for using the cost method.
CASH EQUIVALENTS
Cash equivalents are highly liquid investments purchased with an original
maturity of three months or less.
INVENTORIES
Inventories consist principally of oil produced but not sold, stated at market
value, and materials and supplies, stated at the lower of cost or market.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for exploration and
development of oil and gas reserves, whereby all acquisition, exploration and
development costs are capitalized. Individual countries are designated as
separate cost centers. All capitalized costs plus the undiscounted estimated
future development costs of proved reserves are depleted using the
unit-of-production method based on total proved reserves applicable to each
country. A gain or loss is recognized on sales of oil and gas properties only
when the sale involves significant reserves.
Costs related to acquisition, holding and initial exploration of licenses in
countries with no proved reserves are initially capitalized, including internal
costs directly identified with acquisition, exploration and development
activities. Costs related to production, general overhead or similar activities
are expensed. The Company's exploration licenses are periodically assessed for
impairment on a country-by-country basis. If the Company's investment in
exploration licenses within a country where no proved reserves are assigned is
deemed to be impaired, the licenses are written down to estimated recoverable
value. If the Company abandons all exploration efforts in a country where no
proved reserves are assigned, all acquisition and exploration costs associated
with the country are expensed. Due to the unpredictable nature of exploration
drilling activities, the amount and timing of impairment expense are difficult
to predict with any certainty.
The net capitalized costs of oil and gas properties for each cost center, less
related deferred income taxes, cannot exceed the sum of (i) the estimated future
net revenues from the properties, discounted at 10%; (ii) unevaluated costs not
being amortized; and (iii) the lower of cost or estimated fair value of unproved
properties being amortized; less (iv) income tax effects related to differences
between the financial statement basis and tax basis of oil and gas properties.
The estimated costs, net of salvage value, of dismantling facilities or projects
with limited lives or facilities that are required to be dismantled by contract,
regulation or law, and the estimated costs of restoration and reclamation
associated with oil and gas operations are included in estimated future
development costs as part of the amortizable base.
Support equipment and facilities are depreciated using the unit-of-production
method based on total reserves of the field related to the support equipment and
facilities. Other property and equipment, which includes furniture and
fixtures, vehicles and leasehold improvements, are depreciated principally on a
straight-line basis over estimated useful lives ranging from 3 to 20 years.
Repairs and maintenance are expensed as incurred, and renewals and improvements
are capitalized.
ENVIRONMENTAL MATTERS
Environmental costs are expensed or capitalized depending on their future
economic benefit. Costs that relate to an existing condition caused by past
operations and have no future economic benefit are expensed. Liabilities for
future expenditures of a noncapital nature are recorded when future
environmental expenditures and/or remediation is deemed probable, and the costs
can be reasonably estimated. Costs of future expenditures for environmental
remediation obligations are not discounted to their present value.
INCOME TAXES
Deferred tax liabilities or assets are recognized for the anticipated future tax
effects of temporary differences between the financial statement basis and the
tax basis of the Company's assets and liabilities using the enacted tax rates in
effect at year end. A valuation allowance for deferred tax assets is recorded
when it is more likely than not that the benefit from the deferred tax asset
will not be realized.
REVENUE RECOGNITION
Cost reimbursements arising from carried interests granted by the Company are
revenues to the extent the reimbursements are contingent upon and derived from
production. Obligations arising from net profit interest conveyances are
recorded as operating expenses when the obligation is incurred.
FOREIGN CURRENCY TRANSLATION
The U.S. dollar is the designated functional currency for all of the Company's
foreign operations. The cumulative translation adjustment represents the
cumulative effect of translating the balance sheet accounts of Triton Colombia,
Inc. from the functional currency into U.S. dollars during the period when the
Colombian peso was the functional currency.
RISK MANAGEMENT
Oil and natural gas sold by the Company are normally priced with reference to a
defined benchmark, such as light, sweet crude oil traded on the New York
Merchantile Exchange (West Texas Intermediate or "WTI"). Actual prices received
vary from the benchmark depending on quality and location differentials. From
time to time, it is the Company's policy to use financial market transactions,
including swaps, collars and options, with creditworthy counterparties,
primarily to reduce risk associated with the pricing of a portion of the oil and
natural gas that it sells. The Company does not enter into financial market
transactions for trading purposes.
Gains or losses on financial market transactions that qualify for hedge
accounting are recognized in oil and gas sales at the time of settlement of the
underlying hedged transactions. Premiums paid for financial market contracts
are capitalized and amortized as operating expenses over the contract period.
Changes in the fair market value of financial market transactions that do not
qualify for hedge accounting are reflected as noncash adjustments to other
income (expense), net in the period the change occurs. Realized gains or losses
on financial market transactions that do not qualify for hedge accounting are
recorded in oil and gas sales.
STOCK-BASED COMPENSATION
Statement of Financial Accounting Standards No. 123 ("SFAS 123"), "Accounting
for Stock-Based Compensation," encourages, but does not require, the adoption of
a fair value-based method of accounting for employee stock-based compensation
transactions. The Company has elected to apply the provisions of Accounting
Principles Board Opinion No. 25 ("Opinion 25"), "Accounting for Stock Issued to
Employees," and related interpretations, in accounting for its stock-based
compensation plans. Under Opinion 25, compensation cost is measured as the
excess, if any, of the quoted market price of the Company's stock at the date of
the grant above the amount an employee must pay to acquire the stock.
EARNINGS PER ORDINARY SHARE
Basic earnings (loss) per ordinary share amounts were computed by dividing net
earnings (loss) after deduction of dividends on preference shares by the
weighted average number of ordinary shares outstanding during the period.
Diluted earnings (loss) per ordinary share assumes the conversion of all
securities that are exercisable or convertible into ordinary shares that would
dilute the basic earnings per ordinary share during the period.
COMPREHENSIVE INCOME
Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive
Income," established standards for the reporting and display of comprehensive
income and its components, specifically net income and all other changes in
shareholders' equity except those resulting from investments by and
distributions to shareholders. The Company, which adopted the standard
beginning January 1, 1998, has elected to display comprehensive income (or
non-owner changes in shareholders' equity) in the Consolidated Statement of
Shareholders' Equity.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement No. 133
("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities."
SFAS 133 establishes accounting and reporting standards for derivative
instruments and for hedging activities. It requires enterprises to recognize
all derivatives as either assets or liabilities in the balance sheet and measure
those instruments at fair value. The requisite accounting for changes in the
fair value of a derivative will depend on the intended use of the derivative and
the resulting designation. The Company must adopt SFAS 133 effective January 1,
2001. Based on the Company's outstanding derivatives contracts, the Company
believes that the impact of adopting this standard would not have a material
adverse effect on the Company's operations or consolidated financial condition.
However, no assurances can be given with regard to the level of the Company's
derivatives activities at the time SFAS 133 is adopted or the resulting effect
on the Company's operations or consolidated financial condition.
THE USE OF ESTIMATES IN PREPARING FINANCIAL STATEMENTS
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, disclosure of contingent
assets and liabilities at the date of the financial statements, and reported
amounts of revenues and expenses during the reporting period. Actual results
could differ from these estimates.
RECLASSIFICATIONS
Certain previously reported financial information has been reclassified to
conform to the current period's presentation.
2. ASSET DISPOSITIONS
In December 1998, the Company sold its Bangladesh subsidiary for cash proceeds
of $4.5 million and recognized a gain of $4.5 million in gain on sale of oil and
gas assets.
In July 1998, the Company and Atlantic Richfield Company ("ARCO") signed an
agreement providing financing for the development of the Company's gas reserves
on Block A-18 of the Malaysia-Thailand Joint Development Area. Under terms of
the agreement, consummated in August 1998, the Company sold to a subsidiary of
ARCO for $150 million one-half of the shares of the subsidiary through which the
Company owned its 50% share of Block A-18. The Company received net proceeds of
$142 million and recorded a gain of $63.2 million in gain on the sale of oil and
gas assets. After the sale, which resulted in a 50% ownership in the previously
wholly owned subsidiary, the Company's remaining ownership is accounted for
using the equity method. This investment in Block A-18 is presented in
investment in affiliate at December 31, 1999 and 1998.
The agreements also require ARCO to pay the future exploration and development
costs attributable to the Company's and ARCO's collective interest in Block
A-18, up to $377 million or until first production from a gas field, after which
the Company and ARCO would each pay 50% of such costs. There can be no
assurance that the Company's and ARCO's collective share of the cost of
developing the project will not exceed $377 million. Additionally, the
agreements require ARCO to pay the Company an additional $65 million each at
July 1, 2002, and July 1, 2005, if certain specific development objectives are
met by such dates, or $40 million each if the objectives are met within one year
thereafter. There can be no assurance that the Company will receive any
incentive payments. The agreements provide that the Company will recover its
investment in recoverable costs in the project, approximately $100 million, and
that ARCO will recover its investment in recoverable costs, on a first-in,
first-out basis from the cost-recovery portion of future production.
In February 1998, the Company sold Triton Pipeline Colombia, Inc. ("TPC"), a
wholly owned subsidiary that held the Company's 9.6% equity interest in the
Colombian pipeline company, Oleoducto Central S.A. ("OCENSA"), to an unrelated
third party (the "Purchaser") for $100 million. Net proceeds were approximately
$97.7 million. The sale resulted in a gain of $50.2 million.
In conjunction with the sale of TPC, the Company entered into an equity swap
with a creditworthy financial institution (the "Counterparty"). The equity swap
has a notional amount of $97 million and requires the Company to make quarterly
floating LIBOR-based payments on the notional amount to the Counterparty. In
exchange, the Counterparty is required to make payments to the Company
equivalent to 97% of the dividends TPC receives in respect of its equity
interest in OCENSA. The equity swap is carried in the Company's financial
statements at fair value during its term, which, as amended, will expire April
14, 2000. The value of the equity swap in the Company's financial statements is
equal to 97% of the estimated fair value of the shares of OCENSA owned by TPC.
Because there is no public market for the shares of OCENSA, the Company
estimates their value using a discounted cash flow model applied to the
distributions expected to be paid in respect of the OCENSA shares. The discount
rate applied to the estimated cash flows from the OCENSA shares is based on a
combination of current market rates of interest, a credit spread for OCENSA's
debt, and a spread to reflect the preferred stock nature of the OCENSA shares.
During the years ended December 31, 1999 and 1998, the Company recorded an
expense of $6.9 million and $3.3 million, respectively, in other income
(expense), net, related to the net payments made under the equity swap and its
change in fair value. Net payments made (or received) under the equity swap, and
any fluctuations in the fair value of the equity swap, in future periods, will
affect other income in such periods. There can be no assurance that changes in
interest rates, or in other factors that affect the value of the OCENSA shares
and/or the equity swap, will not have a material adverse effect on the carrying
value of the equity swap.
Upon the expiration of the equity swap in April 2000, the Company expects that
the Purchaser will sell the TPC shares. Under the terms of the equity swap with
the Counterparty, upon any sale by the Purchaser of the TPC shares, the Company
will receive from the Counterparty, or pay to the Counterparty, an amount equal
to the excess or deficiency, as applicable, of the difference between 97% of the
net proceeds from the Purchaser's sale of the TPC shares and the notional amount
of $97 million. For example, if the Purchaser sold the TPC shares for an amount
equal to the value the Company has estimated for purposes of preparing its
balance sheet as of December 31, 1999, the Company would have to make a payment
to the Counterparty under the equity swap of approximately $8.4 million. There
can be no assurance that the value the Purchaser may realize in any sale of the
TPC shares will equal the value of the shares estimated by the Company for
purposes of valuing the equity swap. The Company has no right or obligation to
repurchase the TPC shares at any time, but the Company is not prohibited from
offering to purchase the shares if the Purchaser offers to sell them.
In June 1997, the Company sold its Argentine subsidiary for cash proceeds of
$4.1 million and recognized a gain of $4.1 million in gain on sale of oil and
gas assets.
3. WRITEDOWN OF ASSETS
Writedown of assets in 1998 is summarized as follows:
YEAR ENDED
DECEMBER 31,
1998
-----------
Evaluated oil and gas properties (SEC ceiling test) $ 241,005
Unevaluated oil and gas properties 73,890
Other assets 13,735
-----------
$ 328,630
===========
In June and December 1998, the carrying amount of the Company's evaluated oil
and gas properties in Colombia was written down by $105.4 million ($68.5
million, net of tax) and $135.6 million ($115.9 million, net of tax),
respectively, through application of the full cost ceiling limitation as
prescribed by the Securities and Exchange Commission ("SEC"), principally as a
result of a decline in oil prices. No adjustments were made to the Company's
reserves in Colombia as a result of the decline in prices. The SEC ceiling test
was calculated using the June 30, and December 31, 1998, WTI oil prices of
$14.18 per barrel and $12.05 per barrel, respectively, that, after a
differential for Cusiana crude delivered at the port of Covenas in Colombia,
resulted in a net price of approximately $13 per barrel and $11 per barrel,
respectively.
In conjunction with the plan to restructure operations and scale back
exploration-related expenditures, the Company assessed its investments in
exploration licenses and determined that certain investments were impaired. As
a result, unevaluated oil and gas properties and other assets totaling $77.3
million ($72.6 million, net of tax) were expensed in June 1998. The writedown
included $27.2 million and $22.5 million related to exploration activity in
Guatemala and China, respectively. The remaining writedowns related to the
Company's exploration projects in certain other areas of the world.
During 1998, the Company evaluated the recoverability of its approximate 6.6%
investment in a Colombian pipeline company, Oleoducto de Colombia S.A. ("ODC"),
which is accounted for under the cost method. Based on an analysis of the
future cash flows expected to be received from ODC, the Company expensed the
carrying value of its investment totaling $10.3 million.
4. SPECIAL CHARGES
In September 1999, the Company recognized special charges totaling $2.4 million
related to the transfer of its working interest in Ecuador to a third party.
In July 1998, the Company commenced a plan to restructure the Company's
operations, reduce overhead costs and substantially scale back
exploration-related expenditures. The plan contemplated the closing of foreign
offices in four countries, the elimination of approximately 105 positions, or
41% of the worldwide workforce, and the relinquishment or other disposal of
several exploration licenses. As a result of the restructuring, the Company
recognized special charges of $15 million during the third quarter of 1998 and
$3.3 million during the fourth quarter of 1998 for a total of $18.3 million. Of
the $18.3 million in special charges, $14.5 million related to the reduction in
workforce, and represented the estimated costs for severance, benefit
continuation and outplacement costs, which will be paid over a period of up to
two years according to the severance formula. Since July 1998, the Company has
paid $13.1 million in severance, benefit continuation and outplacement costs. A
total of $2.1 million of special charges related to the closing of foreign
offices, and represented the estimated costs of terminating office leases and
the write-off of related assets. The remaining special charges of $1.7 million
primarily related to the write-off of other surplus fixed assets resulting from
the reduction in workforce. At December 31, 1999, all of the positions had been
eliminated, all designated foreign offices had closed and all licenses had been
relinquished, sold or their commitments renegotiated. During the fourth quarter
of 1999, the Company reversed $.7 million of the accrual associated with the
completion of restructuring activities. The remaining liability related to the
restructuring activities undertaken in 1998 was $1 million at December 31, 1999.
In March 1999, the Company accrued special charges of $1.2 million related to an
additional 15% reduction in the number of employees resulting from the
Company's continuing efforts to reduce costs. The special charges consisted of
$1 million for severance, benefit continuation and outplacement costs and $.2
million related to the write-off of surplus fixed assets. Since March 1999, the
Company has paid $.9 million in severance, benefit continuation and outplacement
costs. At December 31, 1999, the remaining liability related to the
restructuring activities undertaken in 1999 was $.1 million.
5. OTHER RECEIVABLES
Other receivables consisted of the following:
DECEMBER 31,
----------------
1999 1998
------- -------
Receivables from and advances to partners and others $10,684 $ 2,007
Receivable from financial market transactions 4,861 180
Receivable from insurance 2,300 7,800
Receivable from the forward oil sale 1,081 31,932
Other 4,888 5,837
------- -------
$23,814 $47,756
======= =======
6. PROPERTY AND EQUIPMENT
Property and equipment, at cost, are summarized as follows:
DECEMBER 31,
------------------
1999 1998
-------- --------
Oil and gas properties, full cost method:
Evaluated $560,240 $543,514
Unevaluated 78,527 70,836
Support equipment and facilities 303,953 289,659
Other 17,535 18,790
-------- --------
960,255 922,799
Less accumulated depreciation and depletion 436,103 451,892
-------- --------
$524,152 $470,907
======== ========
The Company capitalized general and administrative expenses related to
exploration and development activities of $6.9 million, $20.6 million and $32.4
million in the years ended December 31, 1999, 1998 and 1997, respectively.
7. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Accounts payable and accrued liabilities are summarized as follows:
DECEMBER 31,
----------------
1999 1998
------- -------
Colombian income taxes $14,471 $ ---
Accrued exploration and development 9,762 3,774
Equity swap 8,435 ---
Accrued interest payable 7,864 8,160
Taxes other than income 7,713 2,970
Litigation and environmental matters 3,872 2,064
Accrued special charges 1,246 7,869
Accounts payable, principally trade 1,242 9,136
Dividends payable --- 2,693
Other 7,971 8,307
------- -------
$62,576 $44,973
======= =======
8. DEFERRED INCOME AND OTHER
In May 1995, the Company sold 10.4 million barrels of oil from the Cusiana and
Cupiagua fields in Colombia in a forward oil sale. Under the terms of the sale,
the Company received approximately $87 million of the approximately $124 million
net proceeds. In 1999, the Company received substantially all of the remaining
proceeds totaling approximately $31.9 million. The Company has recorded the net
proceeds as deferred income and recognizes such revenue when the barrels of oil
are delivered during the five-year period that began in June 1995. Under the
terms of the agreement, the Company must deliver to the buyer 58,425 barrels per
month through March 1997 and 254,136 barrels per month from April 1997 to March
2000. At December 31, 1999 and 1998, $8.8 million and $35.3 million,
respectively, were recorded as deferred income and included in current
liabilities.
During 1999, the Company acquired the Colombian entity of its former partner in
the El Pinal field. In addition to the working interest in the El Pinal field,
the acquired entity has tax basis and net operating loss carryforwards ("NOLs")
totaling approximately $40 million, which the Company expects to utilize in
2000. At December 31, 1999, the tax affected amount of the tax basis and NOLs
($14.2 million) was included in current assets as a deferred tax asset. In
addition, the Company recorded deferred income of $10.6 million, representing
the difference between the value of the deferred tax asset and the purchase
price. During 2000, the deferred tax asset and the deferred income will be
reduced as the tax basis and NOLs are utilized.
9. DEBT
A summary of long-term debt follows:
DECEMBER 31,
------------------
1999 1998
-------- --------
Senior Notes due 2005 $200,000 $200,000
Senior Notes due 2002 199,947 199,924
Term credit facility maturing 2001 13,540 22,568
Revolving credit facility maturing 1999 --- 5,000
-------- --------
413,487 427,492
Less current maturities 9,027 14,027
-------- --------
$404,460 $413,465
======== ========
In April 1997, the Company issued $400 million aggregate face value of senior
indebtedness to refinance other indebtedness. The senior indebtedness consisted
of $200 million face amount of 8 3/4% Senior Notes due April 15, 2002 (the
"2002 Notes"), at 99.942% of the principal amount (resulting in $199.9
million aggregate net proceeds) and $200 million face amount of 9 1/4% Senior
Notes dueApril 15, 2005 (the "2005 Notes" and, together with the 2002 Notes,
the "SeniorNotes"), at 100% of the principal amount, for total aggregate net
proceeds of$399.9 million before deducting transaction costs of approximately
$1 million.
Interest on the Senior Notes is payable semi-annually on April 15 and October
15. The Senior Notes are redeemable at any time at the option of the Company,
in whole or in part, and contain certain covenants limiting the incurrence of
certain liens, sale/leaseback transactions, and mergers and consolidations.
In November 1995, a subsidiary signed an unsecured term credit facility with a
bank supported by a guarantee issued by the Export-Import Bank of the United
States ("EXIM") for $45 million, which matures in January 2001. Principal and
interest payments are due semi-annually on January 15 and July 15 and borrowings
bear interest at LIBOR plus .25%, adjusted on a semi-annual basis. At December
31, 1999, the Company had outstanding borrowings of $13.5 million under the
facility.
In February 2000, the Company entered into an unsecured two-year revolving
credit facility with a group of banks, which matures in February 2002. The
credit facility gives the Company the right to borrow from time to time up to
the amount of the borrowing base determined by the banks, not to exceed $150
million. As of February 2000, the borrowing base was $150 million. The credit
facility contains various restrictive covenants, including covenants that
require the Company to maintain a ratio of earnings before interest,
depreciation, depletion, amortization and income taxes to net interest expense
of at least 2.5 to 1, and that prohibit the Company from permitting net debt to
exceed the product of 3.75 times the Company's earnings before interest,
depreciation, depletion, amortization and income taxes, in each case, on a
trailing four quarters basis.
The Company capitalizes interest on qualifying assets, principally unevaluated
oil and gas properties, major development projects in progress and investments
accounted for by the equity method while the investee has activities in progress
necessary to commence its principle operations. Capitalized interest amounted
to $14.5 million, $23.2 million and $25.8 million in the years ended December
31, 1999, 1998 and 1997, respectively.
The Company amortizes debt issue costs over the life of the borrowing using the
interest method. Amortization related to the Company's debt issue costs was $.5
million, $2.9 million and $2 million in the years ended December 31, 1999, 1998
and 1997, respectively. The aggregate maturities of long-term debt for the five
years during the period ending December 31, 2004, are as follows: 2000 -- $9
million; 2001 -- $4.5 million; 2002 -- $199.9 million; 2003 -- nil; and 2004 --
nil.
10. INCOME TAXES
The components of earnings (loss) from continuing operations before income taxes
and extraordinary item were as follows:
YEAR ENDED DECEMBER 31,
--------------------------------------------
1999 1998 1997
--------- ---------- ---------
Cayman Islands $(35,907) $ 82,995 $(12,969)
United States (7,810) (24,003) (31,694)
Foreign - other 119,894 (297,601) 61,559
--------- ---------- ---------
$ 76,177 $(238,609) $ 16,896
========= ========== =========
Pursuant to the Reorganization in March 1996, Triton, a Cayman Islands company,
became the parent holding company of TEC, a Delaware corporation. As a result,
the Company's corporate domicile became the Cayman Islands.
The components of the provision for income taxes on continuing operations were
as follows:
YEAR ENDED DECEMBER 31,
-----------------------------
1999 1998 1997
-------- --------- --------
Current:
Cayman Islands $ --- $ --- $ ---
United States --- --- (7)
Foreign - other 20,793 4,487 3,230
-------- --------- --------
Total current 20,793 4,487 3,223
-------- --------- --------
Deferred:
Cayman Islands --- --- ---
United States (1,410) 1,457 (7,929)
Foreign - other 9,237 (57,049) 16,007
-------- --------- --------
Total deferred 7,827 (55,592) 8,078
-------- --------- --------
Total $28,620 $(51,105) $11,301
======== ========= ========
A reconciliation of the differences between the Company's applicable statutory
tax rate and the Company's effective income tax rate follows:
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- ---------
Tax provision at statutory tax rate 0.0 % 0.0 % 0.0 %
Increase (decrease) resulting from:
Net change in valuation allowance (15.7)% 3.9 % 263.0 %
Foreign items without tax benefit 18.9 % (34.9)% 77.8 %
Income subject to tax in excess of statutory rate 36.6 % 32.6 % 36.9 %
Current year change in NOL/credit carryforwards (7.6)% (4.8)% (356.7)%
Temporary differences:
Oil and gas basis adjustments 3.3 % 25.7 % 32.5 %
Reimbursement of pre-commerciality costs 2.3 % (1.1)% 13.2 %
Other (0.2)% --- % 0.2 %
------- ------- --------
37.6% 21.4 % 66.9 %
======= ======= =========
The components of the net deferred tax asset and liability were as follows:
DECEMBER 31, 1999 DECEMBER 31, 1998
------------------------------ -------------------------------
OTHER OTHER
U.S. COLOMBIA FOREIGN U.S. COLOMBIA FOREIGN
--------- -------- --------- --------- --------- ---------
Deferred tax asset:
Net operating loss carryforwards $157,558 $20,090 $ 9,832 $145,475 $ 7,992 $ 7,219
Depreciable/depletable property 1,748 8,778 --- 1,252 27,730 ---
Credit carryforwards 2,048 --- --- 1,731 6,813 ---
Reserves 819 --- --- 2,502 --- ---
Other 176 --- --- 1,505 --- ---
--------- -------- --------- --------- --------- ---------
Gross deferred tax asset 162,349 28,868 9,832 152,465 42,535 7,219
Valuation allowances (72,908) (8,778) --- (65,881) (27,730) ---
--------- -------- --------- --------- --------- ---------
Net deferred tax asset 89,441 20,090 9,832 86,584 14,805 7,219
--------- -------- --------- --------- --------- ---------
Deferred tax liability:
Depreciable/depletable property --- --- (16,509) --- --- (10,454)
Other (1,213) --- --- (473) --- ---
--------- -------- --------- --------- --------- ---------
Net deferred tax asset (liability) 88,228 20,090 (6,677) 86,111 14,805 (3,235)
Less current deferred tax asset (liability) --- 20,090 --- --- --- ---
--------- -------- --------- --------- --------- ---------
Noncurrent deferred tax asset (liability) $ 88,228 $ --- $ (6,677) $ 86,111 $ 14,805 $ (3,235)
========= ======== ========= ========= ========= =========
At December 31, 1999, the Company had NOLs and depletion carryforwards for U.S.
tax purposes of $450.2 million and $20.3 million, respectively. The U.S. NOLs
expire from 2000 through 2020 as follows:
NOLS
EXPIRING
BY YEAR
---------
May 2000 $ 19,571
May 2001 30,389
May 2002 22,702
May 2003 20,566
May 2004 8,263
May 2005 - May 2020 348,675
---------
$ 450,166
=========
At December 31, 1999, the Company's Colombian operations and other foreign
operations had NOLs and other credit carryforwards totaling $57.4 million and
$40.7 million, respectively. The NOLs expire from 2001 through 2004.
The deferred tax valuation allowance of $81.7 million at December 31, 1999, is
primarily attributable to management's assessment of the utilization of NOLs in
the U.S., the expectation that other tax credits will expire without being
utilized, and certain temporary differences will reverse without a benefit to
the Company. The minimum amount of future taxable income necessary to realize
the deferred tax asset is approximately $252 million and $57 million in the U.S.
and Colombia, respectively. Although there can be no assurance the Company will
achieve such levels of income, management believes the deferred tax asset will
be realized through income from its operations.
If certain changes in the Company's ownership should occur, there would be an
annual limitation on the amount of U.S. NOLs that can be utilized. To the
extent a change in ownership does occur, the limitation is not expected to
materially impact the utilization of such carryforwards.
11. EMPLOYEE BENEFITS
PENSION PLANS
The Company has a defined benefit pension plan covering substantially all
employees in the United States. The benefits are based on years of service and
the employee's final average monthly compensation. Contributions are intended
to provide for benefits attributed to past and future services. The Company
also has a Supplemental Executive Retirement Plan ("SERP") that is unfunded and
provides supplemental pension benefits to a select group of management and key
employees.
The funding status of the plans follows:
DECEMBER 31,
----------------------------------------
1999 1998
------------------- -------------------
DEFINED DEFINED
BENEFIT SERP BENEFIT SERP
PLAN PLAN PLAN PLAN
--------- -------- --------- --------
Change in benefit obligation:
Benefit obligation at beginning of year $ 6,435 $ 6,579 $ 6,008 $ 6,621
Service cost 392 537 560 799
Interest cost 421 435 438 607
Amendments --- --- --- 434
Actuarial loss/(gain) (750) 1,465 472 913
Benefits paid (531) (1,385) (377) (1,617)
Curtailment gain --- --- (666) (1,178)
--------- -------- --------- --------
Benefit obligation at end of year 5,967 7,631 6,435 6,579
--------- -------- --------- --------
Change in plan assets:
Fair value of plan assets at beginning of year 7,068 --- 5,531 ---
Actual return on plan assets 1,971 --- 1,446 ---
Company contribution 480 1,385 468 1,617
Benefits paid (531) (1,385) (377) (1,617)
--------- -------- --------- --------
Fair value of plan assets at end of year 8,988 --- 7,068 ---
--------- -------- --------- --------
Reconciliation:
Funded status 3,021 (7,631) 633 (6,579)
Unrecognized actuarial (gain)/loss (2,999) 1,945 (908) 480
Unrecognized transition (asset)/obligation (6) 527 (8) 695
Unrecognized prior service cost 317 226 373 253
--------- -------- --------- --------
Prepaid/(accrued) pension cost 333 (4,933) 90 (5,151)
--------- -------- --------- --------
Adjustment for minimum liability --- (1,255) --- ---
--------- -------- --------- --------
Adjusted prepaid/(accrued) pension cost $ 333 $(6,188) $ 90 $(5,151)
========= ======== ========= ========
The adjustment required to recognize the minimum liability for the SERP plan at
December 31, 1999, resulted in the recognition of $.8 million as an intangible
asset and $.5 million ($.3 million, net of tax) as a charge to accumulated
other non-owner changes in shareholder's equity.
A summary of the components of pension expense follows:
YEAR ENDED DECEMBER 31,
-------------------------
1999 1998 1997
------- ------- -------
Components of net periodic pension cost:
Service cost $ 929 $1,359 $ 832
Interest cost 856 1,045 783
Expected return on plan assets (618) (481) (416)
Recognized net actuarial loss/(gain) (12) --- ---
Amortization of transition obligation 166 591 166
Amortization of prior service cost 83 538 67
------- ------- -------
Net periodic pension cost $1,404 $3,052 $1,432
======= ======= =======
The projected benefit obligations at December 31, 1999 and 1998, assume a
discount rate of 7.75% and 6.75%, respectively, and a rate of increase in
compensation expense of 5%. The expected long-term rate of return on assets is
9% for the defined benefit plan. During 1998, work-force reductions resulted in
the recognition of additional prior service cost of $.2 million each for the
defined benefit plan and the SERP plan and additional transition obligation of
$.4 million for the SERP plan.
EMPLOYEE STOCK OWNERSHIP PLAN
Effective January 1, 1994, the Company amended and restated the employee stock
ownership plan to form a 401(k) plan (the "Plan"). The Company recognizes
expense based on actual amounts contributed to the Plan. The cost recognized
for the Plan was $.2 million, $.6 million and $.6 million for the years ended
December 31, 1999, 1998 and 1997, respectively.
12. SHAREHOLDERS' EQUITY
5% CONVERTIBLE PREFERENCE SHARES
In connection with the acquisition of the minority interest in Triton Europe in
1994, the Company designated a series of 550,000 preferred shares (522,460
shares issued) as 5% Preferred Stock, no par value, with a stated value of
$34.41 per share. Pursuant to the Reorganization, Triton converted each share
of 5% Preferred Stock into one 5% Convertible Preference Share, par value $.01.
Each share of the Company's 5% Convertible Preference Shares is convertible into
one Triton ordinary share and bears a cash dividend, which has priority over
dividends on Triton's ordinary shares, equal to 5% per annum on the redemption
price of $34.41 per share, payable semi-annually on March 30 and September 30 of
each year. The 5% Convertible Preference Shares have priority over Triton
ordinary shares upon liquidation, and may be redeemed at Triton's option at any
time on or after March 30, 1998, for cash equal to the redemption price. Any
shares that remain outstanding on March 30, 2004, must be redeemed at the
redemption price, either for cash or, at the Company's option, for Triton
ordinary shares. At December 31, 1999 and 1998, there were 209,639 5%
Convertible Preference Shares outstanding and at December 31, 1997, there were
218,285 shares outstanding.
8% CONVERTIBLE PREFERENCE SHARES
In August 1998, the Company and HM4 Triton, L.P., an affiliate of Hicks, Muse,
Tate & Furst Incorporated ("Hicks Muse"), entered into a stock purchase
agreement (the "Stock Purchase Agreement") that provided for a $350 million
equity investment in the Company. The investment was effected in two stages. At
the closing of the first stage in September 1998 (the "First Closing"), the
Company issued to HM4 Triton, L.P. 1,822,500 shares of 8% Convertible Preference
Shares for $70 per share (for proceeds of $116.8 million, net of transaction
costs). Pursuant to the Stock Purchase Agreement, the second stage was effected
through a rights offering for 3,177,500 shares of 8% Convertible Preference
Shares at $70 per share, with HM4 Triton, L.P. being obligated to purchase any
shares not subscribed. At the closing of the second stage, which occurred on
January 4, 1999 (the "Second Closing"), the Company issued an additional
3,177,500 8% Convertible Preference Shares for proceeds totaling $217.8 million,
net of closing costs (of which, HM4 Triton, L.P. purchased 3,114,863 shares).
Each 8% Convertible Preference Share is convertible at any time at the option of
the holder into four ordinary shares of the Company (subject to certain
antidilution protections). Holders of 8% Convertible Preference Shares are
entitled to receive, when and if declared by the Board of Directors, cumulative
dividends at a rate per annum equal to 8% of the liquidation preference of $70
per share, payable for each semi-annual period ending June 30 and December 30 of
each year. At the Company's option, dividends may be paid in cash or by the
issuance of additional whole shares of 8% Convertible Preference Shares. If a
dividend is to be paid in additional shares, the number of additional shares to
be issued in payment of the dividend will be determined by dividing the amount
of the dividend by $70, with amounts in respect of any fractional shares to be
paid in cash. The first dividend period was the period from January 4, 1999, to
June 30, 1999. The Company's Board of Directors elected to pay the dividend for
that period in additional shares resulting in the issuance of 196,388 8%
Convertible Preference Shares. The dividend for the period July 1, 1999 to
December 31, 1999 was paid in cash. The declaration of a dividend in cash or
additional shares for any period should not be considered an indication as to
whether the Board will declare dividends in cash or additional shares in future
periods. Holders of 8% Convertible Preference Shares are entitled to vote with
the holders of ordinary shares on all matters submitted to the shareholders of
the Company for a vote, with each 8% Convertible Preference Share entitling its
holder to a number of votes equal to the number of ordinary shares into which it
could be converted at that time. At December 31, 1999 and 1998, 5,193,643 and
1,822,500 8% Convertible Preference Shares were outstanding, respectively.
ORDINARY SHARES
Changes in issued ordinary shares were as follows:
YEAR ENDED DECEMBER 31,
------------------------------------
1999 1998 1997
----------- ----------- ----------
Balance at beginning of year 36,643,478 36,541,064 36,342,181
Share repurchase (948,300) --- ---
Issuances under stock plans 49,367 46,648 35,961
Conversion of 8% preference shares 10,980 --- ---
Exercise of employee stock options 8,213 47,238 83,736
Conversion of 5% preference shares --- 8,646 29,184
Other, net (10) (118) 50,002
----------- ----------- ----------
Balance at end of year 35,763,728 36,643,478 36,541,064
=========== =========== ==========
Changes in ordinary shares held in treasury were as follows:
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997
------ ------
Balance at beginning of year 73 40
Purchase of treasury shares 64 33
Retirement of treasury shares (137) ---
----- ---
Balance at end of year --- 73
====== ======
SHARE REPURCHASE
In April 1999, the Company's Board of Directors authorized a share repurchase
program enabling the Company to repurchase up to ten percent of the Company's
then outstanding 36.7 million ordinary shares. Purchases of ordinary shares by
the Company began in April and may be made from time to time in the open market
or through privately negotiated transactions at prevailing market prices
depending on market conditions. The Company has no obligation to repurchase any
of its outstanding shares and may discontinue the share repurchase program at
management's discretion. As of December 31, 1999, the Company had purchased
948,300 ordinary shares for $11.3 million. The Company canceled and returned
the repurchased ordinary shares to the status of authorized but unissued shares.
The Company's revolving credit facility entered into in February 2000, generally
does not permit the Company to repurchase its ordinary shares without the bank's
consent.
SHAREHOLDER RIGHTS PLAN
The Company has adopted a Shareholder Rights Plan pursuant to which preference
share rights attach to all ordinary shares at the rate of one right for each
ordinary share. Each right entitles the registered holder to purchase from the
Company one one-thousandth of a Series A Junior Participating Preference Share,
par value $.01 per share ("Junior Preference Shares"), of the Company at a price
of $120 per one one-thousandth of a share of such Junior Preference Shares,
subject to adjustment. Generally, the rights only become distributable 10 days
following public announcement that a person has acquired beneficial ownership of
15% or more of Triton's ordinary shares or 10 business days following
commencement of a tender offer or exchange offer for 15% or more of the
outstanding ordinary shares; provided that, pursuant to the terms of the plan,
any acquisition of Triton shares by HM4 Triton, L.P. or its affiliates,
including Hicks, Muse, Tate & Furst Incorporated, will not result in the
distribution of rights unless and until HM4 Triton, L.P.'s ownership of Triton
shares is reduced below certain levels.
If, among other events, any person becomes the beneficial owner of 15% or more
of Triton's ordinary shares (except as provided with respect to HM4 Triton,
L.P.), each right not owned by such person generally becomes the right to
purchase a number of ordinary shares of the Company equal to the number obtained
by dividing the right's exercise price (currently $120) by 50% of the market
price of the ordinary shares on the date of the first occurrence. In addition,
if the Company is subsequently merged or certain other extraordinary business
transactions are consummated, each right generally becomes a right to purchase a
number of shares of common stock of the acquiring person equal to the number
obtained by dividing the right's exercise price by 50% of the market price of
the common stock on the date of the first occurrence.
Under certain circumstances, the Company's directors may determine that a tender
offer or merger is fair to all shareholders and prevent the rights from being
exercised. At any time after a person or group acquires 15% or more of the
ordinary shares outstanding (other than with respect to HM4 Triton, L.P.) and
prior to the acquisition by such person or group of 50% or more of the
outstanding ordinary shares or the occurrence of an event described in the prior
paragraph, the Board of Directors of the Company may exchange the rights (other
than rights owned by such person or group which will become void), in whole or
in part, at an exchange ratio of one ordinary share, or one one-thousandth of a
Junior Preference Share, per right (subject to adjustment). The Company has the
ability to amend the rights (except the redemption price) in any manner prior to
the public announcement that a 15% position has been acquired or a tender offer
has been commenced. The Company will be entitled to redeem the rights at $0.01 a
right at any time prior to the time that a 15% position has been acquired. The
rights will expire on May 22, 2005, unless earlier redeemed by the Company.
13. STOCK COMPENSATION PLANS
STOCK OPTION PLANS
Options to purchase ordinary shares of the Company may be granted to officers
and employees under various stock option plans. The exercise price of each
option is equal to or greater than the market price of the Company's ordinary
shares on the date of grant. Grants generally become exercisable in 25% or 33%
cumulative annual increments beginning one year from the date of issuance and
generally expire during a period from 5 to 10 years after the date of grant,
depending on terms of the grant. In addition, each non-employee director
receives an option to purchase 15,000 shares each year. These grants become
exercisable at the date of the grant and expire at the end of 10 years. At
December 31, 1999 and 1998, shares available for grant were 1,019,021 and
2,521,133, respectively.
A summary of the status of the Company's stock option plans is presented below:
DECEMBER 31, 1999 DECEMBER 31, 1998 DECEMBER 31, 1997
-------------------- --------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
----------- ------- ------------ ------- ---------- -------
Outstanding at beginning of year 4,057,207 $26.51 4,449,435 $39.05 3,854,046 $38.81
Granted 2,150,000 14.03 2,894,603 20.56 744,250 39.99
Exercised (8,213) 10.57 (47,238) 29.30 (83,736) 30.76
Canceled (351,138) 29.24 (3,239,593) 38.39 (65,125) 46.09
----------- ------------ -----------
Outstanding at end of year 5,847,856 21.78 4,057,207 26.51 4,449,435 39.05
=========== ============ ===========
Options exercisable at year-end 3,121,601 2,804,584 2,728,254
Weighted average fair value of options:
Granted at market prices $ 2.71 $ 6.12 $ 16.37
Granted at greater than market prices 4.93 2.84 ---
On December 2, 1998, the Compensation Committee approved the grant of new stock
options totaling 440,103 shares with an exercise price of $14.50 to
substantially all of its employees. Each participating employee was granted
options in an amount equal to one-half of any options then held by the employees
with an exercise price greater than $30.00 per share and the options with an
exercise price greater than $30.00 per share expired.
The following table summarizes information about stock options outstanding at
December 31, 1999:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------- -------------------------
WEIGHTED
RANGE AVERAGE WEIGHTED WEIGHTED
OF NUMBER REMAINING AVERAGE NUMBER AVERAGE
EXERCISE OUTSTANDING AT CONTRACTUAL EXERCISE EXERCISABLE AT EXERCISE
PRICES DEC. 31, 1999 LIFE PRICE DEC. 31, 1999 PRICE
- -------------- -------------- ----------- --------- -------------- ---------
$ 6.94 - 14.50 2,904,852 4.9 years $ 14.10 657,773 $ 12.75
16.81 - 29.50 1,607,932 3.9 years 20.52 1,150,006 21.64
31.75 - 39.63 667,072 2.4 years 34.10 667,072 34.10
40.25 - 52.25 668,000 3.6 years 45.86 646,750 46.04
-------------- --------------
5,847,856 3,121,601
============== ==============
EMPLOYEE STOCK PURCHASE PLAN
The Company has an employee stock purchase plan that provides for the award of
ordinary shares to officers and employees. Under the terms of the plan,
employees can choose each semi-annual period to have up to 15% of their annual
gross or base compensation withheld to purchase the Company's ordinary shares.
The purchase price of the stock is 85% of the lower of its beginning of period
or end of period market price. Under the plan, the Company sold 49,367 shares
and 46,648 shares to employees for the years ended December 31, 1999 and 1998,
respectively.
FAIR VALUE OF STOCK COMPENSATION
The Company applies Opinion 25 in accounting for its plans. Accordingly, no
compensation cost has been recognized for its fixed stock option plans and stock
purchase plan. Had the Company elected to recognize compensation expense
consistent with the fair value-based methodology in SFAS 123, the Company's net
income (loss) and earnings (loss) per share would have been as follows:
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
------- ---------- ---------
Net earnings (loss) applicable to ordinary shares:
As reported $18,886 $(190,565) $ (9,296)
Pro forma 12,579 (200,147) (16,802)
Basic earnings (loss) per ordinary share:
As reported $ 0.52 $ (5.21) $ (0.26)
Pro forma 0.35 (5.47) (0.46)
Diluted earnings (loss) per ordinary share:
As reported $ 0.52 $ (5.21) $ (0.25)
Pro forma 0.35 (5.47) (0.46)
The fair value of each option granted was estimated on the date of grant using
the Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 1999, 1998 and 1997: dividend yield of 0%;
expected volatility of approximately 54%, 40% and 26%, respectively; risk-free
interest rates of approximately 6%, 5% and 6%, respectively; and an expected
life of approximately three to seven years.
STOCK APPRECIATION RIGHTS PLAN
The Company had a stock appreciation rights ("SARs") plan which granted SARs to
non-employee directors of the Company. Upon exercise, SARs allow the holder to
receive the difference between the SARs' exercise price and the fair market
value of the ordinary shares covered by SARs on the exercise date and expire at
the earlier of 10 years or a date based on the termination of the holder's
membership on the board of directors. At December 31, 1999, SARs covering
20,000 ordinary shares, with an exercise price of $8.00 per share, were
outstanding.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS, RISK MANAGEMENT
AND CREDIT RISK CONCENTRATIONS
FAIR VALUE OF FINANCIAL INSTRUMENTS
At December 31, 1999 and 1998, the Company's financial instruments included cash
and equivalents, short-term receivables, long-term receivables, short-term and
long-term debt, and financial market transactions. The fair value of cash, cash
equivalents, short-term receivables and short-term debt approximated carrying
values because of the short maturities of these instruments. The fair values of
the Company's long-term receivables and financial market transactions, based on
broker quotes and discounted cash flows, approximated the carrying values. The
estimated fair value of long-term debt, based on quoted market prices and market
data for similar instruments, was $416 million (carrying value - $413 million)
and $397 million (carrying value - $428 million) at December 31, 1999 and 1998,
respectively.
RISK MANAGEMENT
Oil and natural gas sold by the Company are normally priced with reference to a
defined benchmark, such as light, sweet crude oil traded on the New York
Mercantile Exchange (WTI). Actual prices received vary from the benchmark
depending on quality and location differentials. From time to time, it is the
Company's policy to use financial market transactions, including swaps, collars
and options, with creditworthy counterparties primarily to reduce risk
associated with the pricing of a portion of the oil and natural gas that it
sells. The policy is structured to underpin the Company's planned revenues and
results of operations. The Company does not enter into financial market
transactions for trading purposes. There can be no assurance that the use of
financial market transactions will not result in losses.
During the years ended December 31, 1999 and 1997, markets provided the Company
the opportunity to realize WTI benchmark oil prices on average $6.37 per barrel
and $2.35 per barrel, respectively, above the WTI benchmark oil price the
Company set as part of its annual plan for the period. During the year ended
December 31, 1998, the Company did not have any outstanding financial market
transactions to hedge against oil price fluctuations. As a result of financial
and commodity market transactions settled during the years ended December 31,
1999 and 1997, the Company's risk management program resulted in an average net
realization of approximately $1.65 per barrel and $.11 per barrel, respectively,
lower than if the Company had not entered into such transactions.
In anticipation of entering into the forward oil sale, in 1995 the Company
purchased WTI benchmark call options to retain the ability to benefit from WTI
price increases above a weighted average price of $20.42 per barrel. The
volumes and expiration dates on the call options coincide with the volumes and
delivery dates of the forward oil sale which will be completed in March 2000.
During the years ended December 31, 1999, 1998 and 1997, the Company recorded a
gain (loss) of $6.1 million, $.4 million, and ($9.7 million), respectively, in
other income (expense), net, related to the change in the fair market value of
the call options. In November 1999, the Company sold WTI benchmark call options
with the same notional quantities, strike price and contract period as the
remaining call option contracts outstanding for a premium of $4.4 million for
the purpose of realizing the fair value of the purchased call options. As a
result, the Company has eliminated its exposure to future changes in value of
the call options caused by fluctuations in oil prices.
CONCENTRATION OF CREDIT RISK
Financial instruments that are potentially subject to concentrations of credit
risk consist of cash equivalents, receivables and financial market transactions.
The Company places its cash equivalents and financial market transactions with
high credit-quality financial institutions. The Company believes the risk of
incurring losses related to credit risk is remote.
The Company sells its crude oil production from the Cusiana and Cupiagua fields
through an agreement with a third party to approximately 10 to 15 buyers located
primarily in the United States. The Company does not believe that the loss of
any single customer or a termination of the agreement with the third party would
have a long-term material, adverse effect on its operations.
15. OTHER INCOME (EXPENSE), NET
Other income (expense), net is summarized as follows:
YEAR ENDED DECEMBER 31,
----------------------------
1999 1998 1997
-------- -------- --------
Equity swap $(6,858) $(3,283) $---
Change in fair market value of WTI
benchmark call options 6,150 366 (9,689)
Foreign exchange gain (loss) (2,674) 2,113 9,549
Loss provisions (2,250) (750) ---
Gain on sale of corporate assets 443 7,593 1,414
Other 1,575 2,441 1,598
-------- -------- --------
$(3,614) $ 8,480 $ 2,872
======== ======== ========
In 1999, 1998 and 1997, the Company recognized a net foreign exchange gain
(loss) of ($2.7 million), $2.1 million and $9.5 million, respectively,
consisting primarily of noncash adjustments related to deferred taxes in
Colombia associated with devaluation of the Colombian peso versus the U.S.
dollar.
16. EARNINGS PER ORDINARY SHARE
The following table reconciles the numerators and denominators of the basic and
diluted earnings per ordinary share computation for earnings from continuing
operations for the years ended December 31, 1999 and 1997.
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------ ------------ ------------
YEAR ENDED DECEMBER 31, 1999:
Net earnings $ 47,557
Less: Preference share dividends (28,671)
------------
Earnings available to ordinary shareholders 18,886
Basic earnings per ordinary share 36,135 $ 0.52
============
Effect of dilutive securities
Stock options --- 62
------------ ------------
Earnings available to ordinary shareholders and
assumed conversions $ 18,886
============
Diluted earnings per ordinary share 36,197 $ 0.52
============ ============
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
YEAR ENDED DECEMBER 31, 1997:
Earnings before extraordinary item $ 5,595
Less: Preference share dividends (400)
-----------
Earnings available to ordinary shareholders 5,195
Basic earnings per ordinary share 36,471 $ 0.14
=============
Effect of dilutive securities
Stock options --- 457
Convertible debentures --- 80
----------- -------------
Earnings available to ordinary shareholders and
assumed conversions $ 5,195
===========
Diluted earnings per ordinary share 37,008 $ 0.14
============= =========
For the year ended December 31, 1998, the computation of diluted net loss per
ordinary share was antidilutive, and therefore, the amounts reported for basic
and diluted net loss per ordinary share were the same.
At December 31, 1999, 5,193,643 shares of 8% Convertible Preference Shares and
209,639 shares of 5% Convertible Preference Shares were outstanding. Each 8%
Convertible Preference Share is convertible any time into four ordinary shares,
subject to adjustment in certain events. Each 5% Convertible Preference Share is
convertible any time into one ordinary share, subject to adjustment in certain
events. The 8% Convertible Preference Shares and 5% Convertible Preference
Shares were not included in the computation of diluted earnings per ordinary
share because the effect of assuming conversion was antidilutive.
17. STATEMENTS OF CASH FLOWS
Supplemental disclosures of cash payments and noncash investing and financing
activities follow:
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998 1997
-------- ------- --------
Cash paid during the year for:
Interest (net of amount capitalized) $22,810 $24,517 $133,265
Income taxes 5,564 4,339 4,666
Noncash financing activities:
8% Convertible preference shares issued
in lieu of cash dividend $13,747 $ --- $ ---
Conversion of preference shares into
ordinary shares 192 297 1,004
Cash paid for interest in 1997 included $124.8 million of interest accreted with
respect to the Senior Subordinated Discount Notes due November 1, 1997 and the
9 3/4% Senior Subordinated Discount Notes due September 15, 2000 through the
dates of retirement.
18. RELATED PARTY TRANSACTIONS
Pursuant to a financial advisory agreement (the "Financial Advisory Agreement")
between Triton and Hicks, Muse & Co. Partners L.P. ("Hicks Muse Partners"), an
affiliate of Hicks Muse, the Company paid Hicks Muse Partners transaction fees
aggregating approximately $9.6 million and $4.4 million for services as
financial advisor to the Company in connection with the First Closing and Second
Closing, respectively, contemplated by the Stock Purchase Agreement. In
accordance with the terms of the Financial Advisory Agreement, the Company has
retained Hicks Muse Partners as its exclusive financial advisor in connection
with any Sale Transaction (defined below) unless Hicks Muse Partners and the
Company agree to retain an additional financial advisor in connection with any
particular Sale Transaction. The Financial Advisory Agreement requires the
Company to pay a fee to Hicks Muse Partners in connection with any Sale
Transaction (unless the Chief Executive Officer of the Company elects not to
retain a financial advisor) in an amount equal to the lesser of (i) the amount
of fees then charged by first-tier investment banking firms for similar advisory
services rendered in similar transactions or (ii) 1.5% of the Transaction Value
(as defined in the Financial Advisory Agreement); provided that such fee will be
divided equally between Hicks Muse Partners and any additional financial advisor
which the Company and Hicks Muse Partners agree will be retained by the Company
with respect to any such transaction. A "Sale Transaction" is defined as any
merger, sale of securities representing a majority of the combined voting power
of the Company, sale of assets of the Company representing more than 50% of the
total market value of the assets of the Company and its subsidiaries or other
similar transaction. The Company is also required to reimburse Hicks Muse
Partners for reasonable disbursements and out-of-pocket expenses of Hicks Muse
Partners incurred in connection with its advisory services.
Pursuant to a monitoring agreement (the "Monitoring Agreement") between Triton
and Hicks Muse Partners, Hicks Muse Partners will provide financial oversight
and monitoring services as requested by the Company and the Company will pay to
Hicks Muse Partners an annual fee of $.5 million. In addition, the Company will
reimburse Hicks Muse Partners for reasonable disbursements and out-of-pocket
expenses incurred by Hicks Muse Partners or its affiliates for the account of
the Company or in connection with the performance of its services. During the
years ended December 31, 1999 and 1998, the Company paid Hicks Muse Partners $.6
million and $.1 million, respectively, under the terms of the Monitoring
Agreement.
The Financial Advisory Agreement and the Monitoring Agreement will remain in
effect until the earlier of (i) September 30, 2008, or (ii) the date on which
HM4 Triton, L.P. and its affiliates cease to own beneficially, directly or
indirectly, at least 5% of the Company's outstanding Ordinary Shares (determined
after giving effect to the conversion of all 8% Convertible Preference Shares
held by HM4 Triton, L.P. and its affiliates). The Company has agreed to
indemnify Hicks Muse Partners with respect to liabilities incurred as a result
of Hicks Muse Partners' performance of services for the Company pursuant to the
Financial Advisory Agreement and the Monitoring Agreement.
In 1999, the Company sold its hunting lease and related facilities to HMTF
Operating, L.P., an affiliate of Hicks Muse, for proceeds of $.9 million and
recognized a gain of $.4 million in other income (expense), net.
19. CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS
Certain information contained in this report, as well as written and oral
statements made or incorporated by reference from time to time by the Company
and its representatives in other reports, filings with the Securities and
Exchange Commission, press releases, conferences, teleconferences, or otherwise,
may be deemed to be "forward-looking statements" within the meaning of Section
21E of the Securities Exchange Act of 1934 and are subject to the "Safe Harbor"
provisions of that section. Forward-looking statements include statements
concerning the Company's and management's plans, objectives, goals, strategies
and future operations and performance and the assumptions underlying such
forward-looking statements. When used in this document, the words
"anticipates," "estimates," "expects," "believes," "intends," "plans," and
similar expressions are intended to identify such forward-looking statements.
These statements include information regarding:
- - drilling schedules;
- - expected or planned production capacity;
- - future production from the Cusiana and Cupiagua fields in Colombia, including
from the Recetor license;
- - the completion of development and commencement of production in
Malaysia-Thailand;
- - future production of the Ceiba field in Equatorial Guinea, including volumes
and timing of first production;
- - the acceleration of the Company's exploration, appraisal and development
activities in Equatorial Guinea;
- - the Company's capital budget and future capital requirements;
- - the Company's meeting its future capital needs;
- - the Company's utilization of net operating loss carryforwards and realization
of its deferred tax asset;
- - the level of future expenditures for environmental costs;
- - the outcome of regulatory and litigation matters;
- - the estimated fair value of derivative instruments, including the equity
swap; and
- - proven oil and gas reserves and discounted future net cash flows therefrom.
These statements are based on current expectations and involve a number of risks
and uncertainties, including those described in the context of such
forward-looking statements, as well as those presented below. Actual results
and developments could differ materially from those expressed in or implied by
such statements due to these and other factors.
CERTAIN FACTORS RELATING TO THE OIL AND GAS INDUSTRY
The markets for oil and natural gas historically have been volatile and are
likely to continue to be volatile in the future. Oil and natural gas prices
have been subject to significant fluctuations during the past several decades in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond the control of the Company. These factors include the level of consumer
product demand, weather conditions, domestic and foreign government regulations,
political conditions in the Middle East and other production areas, the foreign
supply of oil and natural gas, the price and availability of alternative fuels,
and overall economic conditions. It is impossible to predict future oil and gas
price movements with any certainty.
The Company follows the full cost method of accounting for exploration and
development of oil and gas reserves, whereby all acquisition, exploration and
development costs are capitalized. Costs related to acquisition, holding and
initial exploration of licenses in countries with no proved reserves are
initially capitalized, including internal costs directly identified with
acquisition, exploration and development activities. The Company's exploration
licenses are periodically assessed for impairment on a country-by-country basis.
If the Company's investment in exploration licenses within a country where no
proved reserves are assigned is deemed to be impaired, the licenses are written
down to estimated recoverable value. If the Company abandons all exploration
efforts in a country where no proved reserves are assigned, all acquisition and
exploration costs associated with the country are expensed. The Company's
assessments of whether its investment within a country is impaired and whether
exploration activities within a country will be abandoned are made from time to
time based on its review and assessment of drilling results, seismic data and
other information it deems relevant. Due to the unpredictable nature of
exploration drilling activities, the amount and timing of impairment expense are
difficult to predict with any certainty. Financial information concerning the
Company's assets at December 31, 1999, including capitalized costs by geographic
area, is set forth in note 21.
The Company's oil and gas business is also subject to all of the operating risks
normally associated with the exploration for and production of oil and gas,
including, without limitation, blowouts, explosion, uncontrollable flows of oil,
gas or well fluids, pollution, earthquakes, formations with abnormal pressures,
labor disruptions and fires, each of which could result in substantial losses to
the Company due to injury or loss of life and damage to or destruction of oil
and gas wells, formations, production facilities or other properties. In
accordance with customary industry practices, the Company maintains insurance
coverage limiting financial loss resulting from certain of these operating
hazards. Losses and liabilities arising from uninsured or underinsured events
would reduce revenues and increase costs to the Company. There can be no
assurance that any insurance will be adequate to cover losses or liabilities.
The Company cannot predict the continued availability of insurance, or its
availability at premium levels that justify its purchase.
The Company's oil and gas business is also subject to laws, rules and
regulations in the countries where it operates, which generally pertain to
production control, taxation, environmental and pricing concerns, and other
matters relating to the petroleum industry. Many jurisdictions have at various
times imposed limitations on the production of natural gas and oil by
restricting the rate of flow for oil and natural gas wells below their actual
capacity. There can be no assurance that present or future regulation will not
adversely affect the operations of the Company.
The Company is subject to extensive environmental laws and regulations. These
laws regulate the discharge of oil, gas or other materials into the environment
and may require the Company to remove or mitigate the environmental effects of
the disposal or release of such materials at various sites. In addition, the
Company could be held liable for environmental damages caused by previous owners
of its properties or its predecessors. The Company does not believe that its
environmental risks are materially different from those of comparable companies
in the oil and gas industry. Nevertheless, no assurance can be given that
environmental laws and regulations will not, in the future, adversely affect the
Company's consolidated results of operations, cash flows or financial position.
Pollution and similar environmental risks generally are not fully insurable.
CERTAIN FACTORS RELATING TO INTERNATIONAL OPERATIONS
The Company derives substantially all of its consolidated revenues from
international operations. Risks inherent in international operations include
risk of expropriation, nationalization, war, revolution, border disputes,
renegotiation or modification of existing contracts, import, export and
transportation regulations and tariffs; taxation policies, including royalty and
tax increases and retroactive tax claims; exchange controls, currency
fluctuations and other uncertainties arising out of foreign government
sovereignty over the Company's international operations; laws and policies of
the United States affecting foreign trade, taxation and investment; and the
possibility of having to be subject to the exclusive jurisdiction of foreign
courts in connection with legal disputes and the possible inability to subject
foreign persons to the jurisdiction of courts in the United States. To date,
the Company's international operations have not been materially affected by
these risks.
CERTAIN FACTORS RELATING TO COLOMBIA
The Company is a participant in significant oil and gas discoveries in the
Cusiana and Cupiagua fields, located approximately 160 kilometers (100 miles)
northeast of Bogota, Colombia. Development of reserves in the Cusiana and
Cupiagua fields is ongoing and will require additional drilling. Pipelines
connect the major producing fields in Colombia to export facilities and to
refineries.
From time to time, guerrilla activity in Colombia has disrupted the operation of
oil and gas projects. Such activity increased over the last year and appears to
be increasing as political negotiations among government and various rebel
groups proceed. In one recent case, a bomb planted near the pipeline caused
OCENSA to halt shipments, which in turn caused the operator of the fields to
curtail production for approximately two days. Although the Colombian
government, the Company and its partners have taken steps to maintain security
and favorable relations with the local population, there can be no assurance
that attempts to reduce or prevent guerrilla activity will be successful or that
guerrilla activity will not disrupt operations in the future.
Colombia is among several nations whose progress in stemming the production and
transit of illegal drugs is subject to annual certification by the President of
the United States. Although the President granted Colombia certification in
1999, Colombia was denied certification the last two years and only received a
national interest waiver for one of those years. There can be no assurance
that, in the future, Colombia will receive certification or a national interest
waiver. The consequences of the failure to receive certification or a national
interest waiver generally include the following: all bilateral aid, except
anti-narcotics and humanitarian aid, would be suspended; the Export-Import Bank
of the United States and the Overseas Private Investment Corporation would not
approve financing for new projects in Colombia; U.S. representatives at
multilateral lending institutions would be required to vote against all loan
requests from Colombia, although such votes would not constitute vetoes; and the
President of the United States and Congress would retain the right to apply
future trade sanctions. Each of these consequences could result in adverse
economic consequences in Colombia and could further heighten the political and
economic risks associated with the Company's operations in Colombia. Any
changes in the holders of significant government offices could have adverse
consequences on the Company's relationship with the Colombian national oil
company and the Colombian government's ability to control guerrilla activities
and could exacerbate the factors relating to foreign operations discussed above.
CERTAIN FACTORS RELATING TO MALAYSIA-THAILAND
The Company is a partner in a significant gas exploration project located in the
Gulf of Thailand approximately 450 kilometers (280 miles) northeast of Kuala
Lumpur and 750 kilometers (470 miles) south of Bangkok as a contractor under a
production-sharing contract covering Block A-18 of the Malaysia-Thailand Joint
Development Area. On October 30, 1999, the Company and the other parties to the
production-sharing contract for Block A-18 executed a gas sales agreement
providing for the sale of the first phase of gas. Under terms of the gas sales
agreement, delivery of gas is scheduled to begin by the end of the second
quarter of 2002, following timely completion and approval of an environmental
impact assessment associated with the buyers' pipeline and processing
facilities. No assurance can be given as to when such approval will be obtained.
A lengthy approval process, or significant opposition to the project, could
delay construction and the commencement of gas sales.
In connection with the sale to ARCO of one-half of the shares through which the
Company owned its interest in Block A-18, ARCO agreed to pay the future
exploration and development costs attributable to the Company's and ARCO's
collective interest in Block A-18, up to $377 million or until first production
from a gas field, after which the Company and ARCO would each pay 50% of such
costs. There can be no assurance that the Company's and ARCO's collective share
of the cost of developing the project will not exceed $377 million. ARCO also
agreed to pay the Company certain incentive payments if certain criteria were
met. The first $65 million in incentive payments is conditioned upon having the
production facilities for the sale of gas from Block A-18 completed by June 30,
2002. If the facilities are completed after June 30, 2002 but before June 30,
2003, the incentive payment would be reduced to $40 million. A lengthy
environmental approval process, or unanticipated delays in construction of the
facilities, could result in the Company's receiving a reduced incentive payment
or possibly the complete loss of the first incentive payment. In addition, the
Company has agreed to share with ARCO some of the risk that the environmental
approval might be delayed by agreeing to pay to ARCO $1.25 million per month for
each month, if applicable, that first gas sales are delayed beyond 30 months
following the commitment to an engineering, procurement and construction
contract for the project. The Company's obligation is capped at 24 months of
these payments.
INFLUENCE OF HICKS MUSE
In connection with the issuance of 8% Convertible Preference Shares to HM4
Triton, L.P., the Company and HM4 Triton, L.P. entered into a shareholders
agreement (the "Shareholders Agreement") pursuant to which, among other things,
the size of the Company's Board of Directors was set at ten, and HM4 Triton,
L.P. exercised its right to designate four out of such ten directors. The
Shareholders Agreement provides that, in general, for so long as the entire
Board of Directors consists of ten members, HM4 Triton, L.P. (and its designated
transferees, collectively) may designate four nominees for election to the Board
of Directors. The right of HM4 Triton, L.P. (and its designated transferees) to
designate nominees for election to the Board will be reduced if the number of
ordinary shares held by HM4 Triton, L.P. and its affiliates (assuming conversion
of 8% Convertible Preference Shares into ordinary shares) represents less than
certain specified percentages of the number of ordinary shares (assuming
conversion of 8% Convertible Preference Shares into ordinary shares) purchased
by HM4 Triton, L.P. pursuant to the Stock Purchase Agreement.
The Shareholders Agreement provides that, for so long as HM4 Triton, L.P. and
its affiliates continue to hold a certain minimum number of ordinary shares
(assuming conversion of 8% Convertible Preference Shares into ordinary shares),
the Company may not take certain actions without the consent of HM4 Triton,
L.P., including (i) amending its Articles of Association or the terms of the 8%
Convertible Preference Shares with respect to the voting powers, rights or
preferences of the holders of 8% Convertible Preference Shares, (ii) entering
into a merger or similar business combination transaction, or effecting a
reorganization, recapitalization or other transaction pursuant to which a
majority of the outstanding ordinary shares or any 8% Convertible Preference
Shares are exchanged for securities, cash or other property, (iii) authorizing,
creating or modifying the terms of any series of securities that would rank
equal to or senior to the 8% Convertible Preference Shares, (iv) selling or
otherwise disposing of assets comprising in excess of 50% of the market value of
the Company, (v) paying dividends on ordinary shares or other shares ranking
junior to the 8% Convertible Preference Shares, other than regular dividends on
the Company's 5% Convertible Preference Shares, (vi) incurring or guaranteeing
indebtedness (other than certain permitted indebtedness), or issuing preference
shares, unless the Company's leverage ratio at the time, after giving pro forma
effect to such incurrence or issuance and to the use of the proceeds, is less
than 2.5 to 1, (vii) issuing additional shares of 8% Convertible Preference
Shares, other than in payment of accumulated dividends on the outstanding 8%
Convertible Preference Shares, (viii) issuing any shares of a class ranking
equal or senior to the 8% Convertible Preference Shares, (ix) commencing a
tender offer or exchange offer for all or any portion of the ordinary shares or
(x) decreasing the number of shares designated as 8% Convertible Preference
Shares.
As a result of HM4 Triton, L.P.'s ownership of 8% Convertible Preference Shares
and ordinary shares and the rights conferred upon HM4 Triton, L.P. and its
designees pursuant to the Shareholder Agreement, HM4 Triton, L.P. has
significant influence over the actions of the Company and will be able to
influence, and in some cases determine, the outcome of matters submitted for
approval of the shareholders. The existence of HM4 Triton, L.P. as a
shareholder of the Company may make it more difficult for a third party to
acquire, or discourage a third party from seeking to acquire, a majority of the
outstanding ordinary shares. A third party would be required to negotiate any
such transaction with HM4 Triton, L.P. and the interests of HM4 Triton, L.P. as
a shareholder may be different from the interests of the other shareholders of
the Company.
POSSIBLE FUTURE ACQUISITIONS
The Company's strategy includes the possible acquisition of additional reserves,
including through possible future business combination transactions. There can
be no assurance as to the terms upon which any such acquisitions would be
consummated or as to the affect any such transactions would have on the
Company's financial condition or results of operations. Such acquisitions, if
any, could involve the use of the Company's cash, or the issuance of the
Company's debt or equity securities, which could have a dilutive effect on the
current shareholders.
COMPETITION
The Company encounters strong competition from major oil companies (including
government-owned companies), independent operators and other companies for
favorable oil and gas concessions, licenses, production-sharing contracts and
leases, drilling rights and markets. Additionally, the governments of certain
countries in which the Company operates may, from time to time, give
preferential treatment to their nationals. The oil and gas industry as a whole
also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual consumers. The Company
believes that the principal means of competition in the sale of oil and gas are
product availability, price and quality.
MARKETS
Crude oil, natural gas, condensate, and other oil and gas products generally are
sold to other oil and gas companies, government agencies and other industries.
The availability of ready markets for oil and gas that might be discovered by
the Company and the prices obtained for such oil and gas depend on many factors
beyond the Company's control, including the extent of local production and
imports of oil and gas, the proximity and capacity of pipelines and other
transportation facilities, fluctuating demands for oil and gas, the marketing of
competitive fuels, and the effects of governmental regulation of oil and gas
production and sales. Pipeline facilities do not exist in certain areas of
exploration and, therefore, any actual sales of discovered oil or gas might be
delayed for extended periods until such facilities are constructed.
LITIGATION
The outcome of litigation and its impact on the Company are difficult to predict
due to many uncertainties, such as jury verdicts, the application of laws to
various factual situations, the actions that may or may not be taken by other
parties and the availability of insurance. In addition, in certain situations,
such as environmental claims, one defendant may be responsible for the
liabilities of other parties. Moreover, circumstances could arise under which
the Company may elect to settle claims at amounts that exceed the Company's
expected liability for such claims in an attempt to avoid costly litigation.
Judgments or settlements could, therefore, exceed any reserves.
20. COMMITMENTS AND CONTINGENCIES
For internal planning purposes, the Company's capital spending program for the
year ending December 31, 2000, is approximately $191 million, excluding
capitalized interest and acquisitions, of which approximately $122 million
relates to exploration and development activities in Equatorial Guinea, $58
million relates to the Cusiana and Cupiagua fields in Colombia and $11 million
relates to the Company's exploration activities in other parts of the world.
During the normal course of business, the Company is subject to the terms of
various operating agreements and capital commitments associated with the
exploration and development of its oil and gas properties. It is management's
belief that such commitments, including the capital requirements in Colombia,
Equatorial Guinea and other parts of the world discussed above, will be met
without any material adverse effect on the Company's operations or consolidated
financial condition.
The Company leases office space, other facilities and equipment under various
operating leases expiring through 2005. Total rental expense was $1.3 million,
$2.1 million and $2 million for the years ended December 31, 1999, 1998 and
1997, respectively. At December 31, 1999, the minimum payments required under
terms of the leases are as follows 2000 -- $1.5 million; 2001 -- $1.6 million;
2002 -- $1.6 million; 2003 -- $1.6 million; 2004 -- $1.6 million; and thereafter
$1 million.
GUARANTEES
At December 31, 1999, the Company had guaranteed the performance of a total of
$16.4 million in future exploration expenditures to be incurred through
September 2001 in various countries. A total of approximately $6 million of the
exploration expentitures are included in the 2000 capital spending program
related to a commitment for two onshore exploratory wells in Greece. These
commitments are backed primarily by unsecured letters of credit. The Company
also had guaranteed loans of approximately $1.4 million, which expire September
2000, for a Colombian pipeline company, ODC, in which the Company has an
ownership interest.
ENVIRONMENTAL MATTERS
The Company is subject to extensive environmental laws and regulations. These
laws regulate the discharge of oil, gas or other materials into the environment
and may require the Company to remove or mitigate the environmental effects of
the disposal or release of such materials at various sites. The Company believes
that the level of future expenditures for environmental matters, including
clean-up obligations, is impracticable to determine with a precise and reliable
degree of accuracy. Management believes that such costs, when finally
determined, will not have a material adverse effect on the Company's operations
or consolidated financial condition.
LITIGATION
In July through October 1998, eight lawsuits were filed against the Company and
Thomas G. Finck and Peter Rugg, in their capacities as Chairman and Chief
Executive Officer and Chief Financial Officer, respectively. The lawsuits were
filed in the United States District Court for the Eastern District of Texas,
Texarkana Division, and have been consolidated and are styled In re: Triton
Energy Limited Securities Litigation. In November 1999, the plaintiffs filed a
consolidated complaint. It alleges violations of Sections 10(b) and 20(a) of the
Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated
thereunder, in connection with disclosures concerning the Company's properties,
operations, and value relating to a prospective sale of the Company or of all or
a part of its assets. The lawsuits seek recovery of an unspecified amount of
compensatory damages, fees and costs. In the consolidated complaint, the
plaintiffs abandoned a claim for negligent misrepresentation and punitive
damages that had previously been asserted in one of the eight individual suits.
In September 1999, the court granted the plaintiffs' motion for appointment
as lead plaintiffs and for approval of selection of lead counsel. In October
1999, the defendants filed a motion to dismiss the claims alleged in the eight
individual suits, and in December 1999, the defendants filed a supplement to
their motion to dismiss to address the plaintiffs' consolidated complaint. The
Company's motion, as supplemented, is currently pending.
The Company believes its disclosures have been accurate and intends to
vigorously defend these actions. There can be no assurance that the litigation
will be resolved in the Company's favor. An adverse result could have a material
adverse effect on the Company's financial position or results of operations.
In November 1999, a lawsuit was filed against the Company, and one of its
subsidiaries and Thomas G. Finck, Peter Rugg and Robert B. Holland, III, in
their capacities as officers of the Company, in the District Court of the State
of Texas for Dallas County. The lawsuit is styled Aaron Sherman, et al. vs.
Triton Energy Corporation et al. and seeks an unspecified amount of compensatory
and punitive damages and interest. The lawsuit alleges as causes of action fraud
and negligent misrepresentation in connection with disclosures concerning the
prospective sale by the Company of all or a substantial part of its assets
announced in March 1998. The Company's date to answer has not yet run. Its
subsidiary has filed various motions to dispose of the lawsuit on the grounds
that the plantiffs do not have standing. The Court has ordered the plantiffs to
replead and has stayed discovery pending its further orders.
In August 1997, the Company was sued in the Superior Court of the State of
California for the County of Los Angeles, by David A. Hite, Nordell
International Resources Ltd., and International Veronex Resources, Ltd. The
action has since been removed to the United States District Court for the
Central District of California. The Company and the plaintiffs were adversaries
in a 1990 arbitration proceeding in which the interest of Nordell International
Resources Ltd. in the Enim oil field in Indonesia was awarded to the Company
(subject to a 5% net profits interest for Nordell) and Nordell was ordered to
pay the Company nearly $1 million. The arbitration award was followed by a
series of legal actions by the parties in which the validity of the award and
its enforcement were at issue. As a result of these proceedings, the award was
ultimately upheld and enforced. The current suit alleges that the plaintiffs
were damaged in amounts aggregating $13 million primarily because of the
Company's prosecution of various claims against the plaintiffs as well as its
alleged misrepresentations, infliction of emotional distress, and improper
accounting practices. The suit seeks specific performance of the arbitration
award, damages for alleged fraud and misrepresentation in accounting for Enim
field operating results, an accounting for Nordell's 5% net profit interest, and
damages for emotional distress and various other alleged torts. The suit seeks
interest, punitive damages and attorneys fees in addition to the alleged actual
damages. In August 1998, the district court dismissed all claims asserted by the
plaintiffs other than claims for malicious prosecution and abuse of the legal
process, which the court held could not be subject to a motion to dismiss. The
abuse of process claim was later withdrawn, and the damages sought were reduced
to approximately $700,000 (not including punitive damages). The lawsuit was
tried and the jury found in favor of the plaintiffs and assessed compensatory
damages against the Company in the amount of approximately $700,000 and punitive
damages in the amount of approximately $11 million. The Company believes it has
acted appropriately and intends to appeal the verdict.
The Company is subject to certain other litigation matters, none of which is
expected to have a material, adverse effect on the Company's operations or
consolidated financial condition.
21. GEOGRAPHIC INFORMATION
Triton's operations are primarily related to crude oil and natural gas
exploration and production. The Company's principal properties, operations and
oil and gas reserves are located in Colombia, Malaysia-Thailand and Equatorial
Guinea. The Company is exploring for oil and gas in these areas, as well as in
southern Europe, Africa and the Middle East. All sales are currently derived
from oil and gas production in Colombia. Financial information about the
Company's operations by geographic area is presented below:
CORPORATE
MALAYSIA- EQUATORIAL AND
COLOMBIA THAILAND GUINEA EXPLORATION OTHER TOTAL
--------- --------- ---------- ----------- --------- ----------
YEAR ENDED DECEMBER 31, 1999:
Sales and other operating revenues $ 247,878 $ --- $ --- $ --- $ --- $ 247,878
Operating income (loss) 115,877 --- (469) (7,214) (16,334) 91,860
Depreciation, depletion and amortization 59,728 --- 16 144 1,455 61,343
Capital expenditures and investments 79,889 8,453 19,968 12,419 754 121,483
Assets 476,543 93,188 37,229 85,250 282,265 974,475
YEAR ENDED DECEMBER 31, 1998:
Sales and other operating revenues $ 160,881 $ 63,237 $ --- $ 4,500 $ --- $ 228,618
Operating income (loss) (220,697) 62,538 (124) (79,703) (39,360) (277,346)
Depreciation, depletion and amortization 53,641 49 1 175 4,945 58,811
Writedown of assets 251,312 --- --- 76,664 654 328,630
Capital expenditures and investments 106,624 25,319 5,913 41,603 756 180,215
Assets 468,533 84,735 10,766 78,086 112,160 754,280
YEAR ENDED DECEMBER 31, 1997:
Sales and other operating revenues $ 145,419 $ --- $ --- $ 4,077 $ --- $ 149,496
Operating income (loss) 59,719 (536) (42) (6,270) (20,167) 32,704
Depreciation, depletion and amortization 31,186 60 --- 505 5,077 36,828
Capital expenditures and investments 129,589 37,328 4,471 43,371 4,457 219,216
Assets 712,512 148,780 4,841 105,720 126,186 1,098,039
During 1998, the Company sold one-half of the shares of the subsidiary through
which the Company owned its 50% share of Block A-18 resulting in a gain of $63.2
million which is included in Malaysia-Thailand sales and other operating
revenues and operating income (loss). See note 2 - Asset Dispositions. After
the sale, which resulted in a 50% ownership in the previously wholly owned
subsidiary, the Company's remaining ownership is accounted for using the equity
method. This investment in Block A-18 is presented in Malaysia-Thailand assets
at December 31, 1999 and 1998.
Colombia operating income (loss) for the year ended December 31, 1998, included
a SEC full cost ceiling limitation writedown of $241 million. Additionally,
Exploration operating income (loss) included writedowns of oil and gas
properties and other assets totaling $76.7 million for the year ended December
31, 1998.
At December 31, 1999, corporate assets were principally cash and equivalents and
the U.S. deferred tax asset. Exploration assets included $41.6 million, $17.6
million, $16.5 million and $8.4 million in Italy, Greece, Oman and Madagascar,
respectively.
22. QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTER
-------------------------------------------
FIRST SECOND THIRD FOURTH
--------- ---------- -------- ----------
YEAR ENDED DECEMBER 31, 1999:
Sales and other operating revenues $ 49,170 $ 59,622 $ 67,295 $ 71,791
Gross profit 14,823 25,151 32,349 46,082
Net earnings 1,887 10,883 11,762 23,025
Basic earnings (loss) per ordinary share 0.05 (0.08) 0.32 0.24
Diluted earnings (loss) per ordinary share 0.03 (0.08) 0.20 0.23
Investment in affiliate 86,704 88,179 91,008 93,188
YEAR ENDED DECEMBER 31, 1998:
Sales and other operating revenues $ 36,175 $ 36,378 $105,862 $ 50,203
Gross profit (loss) 8,409 (180,179) 73,751 (134,350)
Net earnings (loss) 42,912 (150,062) 47,208 (127,562)
Basic earnings (loss) per ordinary share 1.17 (4.10) 1.28 (3.55)
Diluted earnings (loss) per ordinary share 1.16 (4.10) 1.28 (3.55)
Investment in affiliate --- --- 82,511 84,735
Gross profit (loss) is comprised of sales and other operating revenues less
operating expenses, depreciation, depletion and amortization, and writedowns
pertaining to operating assets. Gross profit for the fourth quarter of 1999
included a non-recurring credit issued by OCENSA in February 2000 totaling $4.2
million. The credit to pipeline tariffs resulted from OCENSA's compliance
with a Colombian government decree in December 1999 that reduced its 1999
noncash expenses.
23. OIL AND GAS DATA (UNAUDITED)
The following tables provide additional information about the Company's oil and
gas exploration and production activities. The oil and gas data reflect the
Company's proportionate interest in Block A-18 on an equity investment basis
since the sale of one-half of the subsidiary through which the Company owned its
50% share of Block A-18 in August 1998.
RESULTS OF OPERATIONS
The results of operations for oil- and gas-producing activities, considering
direct costs only, follow:
COLOMBIA
--------
YEAR ENDED DECEMBER 31, 1999:
Revenues $247,878
Costs:
Production costs 68,130
General operating expenses 3,954
Depletion 59,512
Income tax expense 42,083
--------
Results of operations $ 74,199
========
MALAYSIA- TOTAL
COLOMBIA THAILAND OTHER WORLDWIDE
--------- --------- --------- ---------
YEAR ENDED DECEMBER 31, 1998:
Revenues $ 160,881 $ 63,237 $ 4,500 $ 228,618
Costs:
Production costs 73,546 --- --- 73,546
General operating expenses 2,460 --- --- 2,460
Depletion 53,304 --- --- 53,304
Writedown of assets 251,312 --- 76,664 327,976
Income tax benefit (76,048) --- (22,527) (98,575)
---------- --------- ---------- ----------
Results of operations $(143,693) $ 63,237 $ (49,637) $(130,093)
========== ========= ========== ==========
TOTAL
COLOMBIA OTHER WORLDWIDE
-------- ------- ---------
YEAR ENDED DECEMBER 31, 1997:
Revenues $145,419 $ 4,077 $ 149,496
Costs:
Production costs 51,357 --- 51,357
General operating expenses 2,886 --- 2,886
Depletion 30,729 --- 30,729
Income tax expense 22,167 1,223 23,390
-------- ------- ---------
Results of operations $ 38,280 $ 2,854 $ 41,134
======== ======= =========
Malaysia-Thailand revenues for the year ended December 31, 1998, included a gain
of $63.2 million from the sale of one-half of the shares of the subsidiary
through which the Company owned its 50% share of Block A-18. Other revenues for
the years ended December 31, 1998 and 1997, included gains of $4.5 million, and
$4.1 million from the sale of the Company's Bangladesh subsidiary and Argentine
subsidiary, respectively.
Depletion includes depreciation on support equipment and facilities calculated
on the unit-of-production method.
COSTS INCURRED AND CAPITALIZED COSTS
The costs incurred in oil and gas acquisition, exploration and development
activities and related capitalized costs follow:
EQUATORIAL TOTAL
COLOMBIA GUINEA OTHER WORLDWIDE
-------- ------- ------ ---------
DECEMBER 31, 1999:
Costs incurred:
Property acquisition $ 6,400 $ --- $ 20 $ 6,420
Exploration 155 23,631 13,051 36,837
Development 80,782 --- --- 80,782
Depletion per equivalent
barrel of production 3.80 --- --- 3.80
Cost of properties at year-end:
Unevaluated $ --- $ 5,772 $72,755 $ 78,527
======== ======= ======= ========
Evaluated $530,947 $28,613 $ 680 $560,240
======== ======= ======= ========
Support equipment and
facilities $303,244 $ 709 $ --- $303,953
======== ======= ======= ========
Accumulated depletion and
depreciation at year-end $419,651 $ --- $ 680 $420,331
======== ======= ======= ========
MALAYSIA- EQUATORIAL TOTAL
COLOMBIA THAILAND GUINEA OTHER WORLDWIDE
-------- --------- ---------- ------- ---------
DECEMBER 31, 1998:
Costs incurred:
Property acquisition $ --- $ --- $ --- $ 500 $ 500
Exploration 2,886 17,739 5,913 43,153 69,691
Development 83,088 1,026 --- --- 84,114
Depletion per equivalent
barrel of production 4.07 --- --- --- 4.07
Cost of properties at year-end:
Unevaluated $ --- $ --- $ 10,754 $60,082 $ 70,836
======== ========= ========== ======= ========
Evaluated $467,147 $ --- $ --- $76,367 $543,514
======== ========= ========== ======= ========
Support equipment and
facilities $289,659 $ --- $ --- $ --- $289,659
======== ========= ========== ======= ========
Accumulated depletion and
depreciation at year-end $360,324 $ --- $ --- $76,367 $436,691
======== ========= ========== ======= ========
MALAYSIA- EQUATORIAL TOTAL
COLOMBIA THAILAND GUINEA OTHER WORLDWIDE
-------- --------- ---------- ------ ---------
DECEMBER 31, 1997:
Costs incurred:
Property acquisition $ --- $ --- $ 1,500 $ 1,628 $ 3,128
Exploration 7,583 36,373 2,971 44,893 91,820
Development 62,251 187 --- --- 62,438
Depletion per equivalent
barrel of production 3.67 --- --- --- 3.67
Cost of properties at year-end:
Unevaluated $ 2,172 $ 30,327 $ 4,841 $93,286 $130,626
======== ========= ========== ======= ========
Evaluated $396,774 $ 114,243 $ --- $ 7,563 $518,580
======== ========= ========== ======= ========
Support equipment and
facilities $250,193 $ --- $ --- $ --- $250,193
======== ========= ========== ======= ========
Accumulated depletion and
depreciation at year-end $ 66,250 $ --- $ --- $ 7,563 $ 73,813
======== ========= ========== ======= ========
A summary of costs excluded from depletion at December 31, 1999,
by year incurred follows:
DECEMBER 31,
----------------------------------------
TOTAL 1999 1998 1997 1996 AND PRIOR
-------- ------- ------- ------- --------------
Property acquisition $ 2,820 $ 20 $ 500 $ 1,700 $ 600
Exploration 93,258 29,697 34,394 16,008 13,159
Capitalized interest 11,062 6,587 2,971 1,383 121
-------- ------- ------- ------- ------------
Total worldwide $107,140 $36,304 $37,865 $19,091 $ 13,880
======== ======= ======= ======= ============
The Company excludes from its depletion computation property acquisition and
exploration costs of unevaluated properties and major development projects in
progress. The excluded costs include $34.4 million ($28.6 million and $5.8
million classified as evaluated and unevaluated, respectively) which relate
primarily to the Ceiba field in Equatorial Guinea that will become depletable
once production begins, currently estimated for year end 2000. Additionally,
excluded costs include exploration costs of $34.6 million, $16.8 million, $11.8
million and $8.4 million in Italy, Greece, Oman and Madagascar, respectively,
where there are no proved reserves at December 31, 1999. At this time, the
Company is unable to predict either the timing of the inclusion of these costs
and any related oil and gas reserves in its depletion computation or their
potential future impact on depletion rates. Drilling or other exploration
activities are being conducted in each of these cost centers.
The Company's share of costs incurred for Block A-18 were $8.2 million and $3.2
million for the years ended December 31, 1999 and 1998, respectively. Net
capitalized costs were $90.2 million and $85.2 million at December 31, 1999 and
1998, respectively.
OIL AND GAS RESERVE DATA (OIL RESERVES ARE STATED IN THOUSANDS OF BARRELS AND
GAS RESERVES ARE STATED IN MILLIONS OF CUBIC FEET.)
The following tables present the Company's estimates of its proved oil and gas
reserves. The estimates for the proved reserves in the Cusiana and Cupiagua
fields in Colombia and the Ceiba field in Equatorial Guinea were prepared by the
Company's independent petroleum engineers, DeGolyer and MacNaughton and
Netherland, Sewell & Associates, Inc., respectively. The estimates for proved
reserves in Malaysia-Thailand were prepared by the internal petroleum engineers
of the operating company, Carigali-Triton Operating Company (CTOC). The
estimates for the proved reserves in the Liebre field in Colombia were prepared
by the Company's internal petroleum reservoir engineers. The Company emphasizes
that reserve estimates are approximate and are expected to change as additional
information becomes available. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and gas that cannot be measured in
an exact way, and the accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. Accordingly, there can be no assurance that the reserves set forth
herein will ultimately be produced, and there can be no assurance that the
proved undeveloped reserves will be developed within the periods anticipated.
As of December 31, 1999, gas sales had not yet commenced from the Company's
interest in the Malaysia-Thailand Joint Development Area. In estimating its
reserves attributable to such interest, the Company assumed that production from
the interest would be sold at the base price in the gas sales agreement of
$2.30. The base price is subject to annual adjustments based on various
indices. There can be no assurance as to what the actual price will be when gas
sales commence.
EQUITY INVESTMENT
COLOMBIA EQUATORIAL GUINEA TOTAL WORLDWIDE MALAYSIA-THAILAND
----------------- ----------------- ---------------- -----------------
OIL GAS OIL GAS OIL GAS OIL GAS
-------- ------- ------ ------- ------- ------ ------ ---------
PROVED DEVELOPED AND
UNDEVELOPED RESERVES AS OF
DECEMBER 31, 1998 135,327 12,284 --- --- 135,327 12,284 8,017 570,312
Revisions (567) (259) --- --- (567) (259) 5,206 (16,450)
Purchases 3,280 --- --- --- 3,280 --- --- ---
Extensions and discoveries --- --- 32,033 --- 32,033 --- --- ---
Production (12,469) (459) --- --- (12,469) (459) --- ---
-------- ------- ------ -------- -------- ------- ------ ---------
AS OF DECEMBER 31, 1999 125,571 11,566 32,033 --- 157,604 11,566 13,223 553,862
======== ======= ====== ======== ======== ======= ====== =========
PROVED DEVELOPED RESERVES AT
DECEMBER 31, 1999 91,859 11,566 --- --- 91,859 11,566 --- ---
======== ======= ====== ======== ======== ======= ====== =========
EQUITY INVESTMENT
COLOMBIA MALAYSIA-THAILAND TOTAL WORLDWIDE MALAYSIA-THAILAND
----------------- -------------------- -------------------- -----------------
OIL GAS OIL GAS OIL GAS OIL GAS
-------- ------- -------- ---------- -------- ---------- ----- ----------
PROVED DEVELOPED AND
UNDEVELOPED RESERVES AS OF
DECEMBER 31, 1997 145,999 14,619 29,800 1,223,800 175,799 1,238,419 --- ---
Revisions (693) (1,832) (6,583) (41,588) (7,276) (43,420) --- ---
Sales --- --- (15,200) (625,400) (15,200) (625,400) --- ---
Equity investment --- --- (8,017) (570,312) (8,017) (570,312) 8,017 570,312
Extensions and discoveries --- --- --- 13,500 --- 13,500 --- ---
Production (9,979) (503) --- --- (9,979) (503) --- ---
-------- ------- -------- ---------- -------- ---------- ----- ---------
AS OF DECEMBER 31, 1998 135,327 12,284 --- --- 135,327 12,284 8,017 570,312
======== ======= ======== ========== ======== ========== ===== =========
PROVED DEVELOPED RESERVES AT
DECEMBER 31, 1998 86,039 12,284 --- --- 86,039 12,284 --- ---
======== ======= ======== ========== ======== ========== ===== =========
COLOMBIA MALAYSIA-THAILAND TOTAL WORLDWIDE
----------------- ------------------- --------------------
OIL GAS OIL GAS OIL GAS
-------- ------- ------- ---------- -------- ----------
PROVED DEVELOPED AND
UNDEVELOPED RESERVES AS OF
DECEMBER 31, 1996 135,310 14,651 24,700 871,100 160,010 885,751
Revisions 14,157 770 (2,000) (7,600) 12,157 (6,830)
Extensions and discoveries 2,308 --- 7,100 360,300 9,408 360,300
Production (5,776) (802) --- --- (5,776) (802)
-------- ------- ------- ---------- -------- ----------
AS OF DECEMBER 31, 1997 145,999 14,619 29,800 1,223,800 175,799 1,238,419
======== ======= ======= ========== ======== ==========
PROVED DEVELOPED RESERVES AT
DECEMBER 31, 1997 81,931 14,619 --- --- 81,931 14,619
======== ======= ======= ========== ======== ==========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH INFLOWS AND CHANGES THEREIN
The following table presents for the net quantities of proved oil and gas
reserves a standardized measure of discounted future net cash inflows discounted
at an annual rate of 10%. The future net cash inflows were calculated in
accordance with Securities and Exchange Commission guidelines. Future cash
inflows were computed by applying year-end prices of oil and gas relating to the
Company's proved reserves to the estimated year-end quantities of those
reserves. The future cash inflow estimates for 1999 attributable to oil
reserves were based on the year end WTI crude oil price of $25.60 per barrel for
the Company's reserves in Colombia and Malaysia-Thailand, and the year end Brent
crude oil price of $24.89 per barrel for the Company's reserves in Equatorial
Guinea, in each case before adjustments for oil quality and transportation
costs.
In 1999, the Company and the other parties to the production-sharing contract
for Block A-18 executed a gas sales agreement providing for the sale of the
first phase of gas. In estimating discounted future net cash inflows
attributable to such interest, the Company assumed that production from the
interest would be sold at the base price in the gas sales agreement of $2.30.
The base price is subject to annual adjustments based on various indices. There
can be no assurance as to what the actual price will be when gas sales commence.
Future production and development costs were computed by estimating those
expenditures expected to occur in developing and producing the proved oil and
gas reserves at the end of the year, based on year-end costs. The Company
emphasizes that the future net cash inflows should not be construed as
representative of the fair market value of the Company's proved reserves. The
meaningfulness of the estimates is highly dependent upon the accuracy of the
assumptions upon which they were based. Actual future cash inflows may vary
materially.
In connection with the sale to ARCO of one-half of the shares through which the
Company owned its interest in Block A-18, ARCO agreed to pay the Company an
additional $65 million each at July 1, 2002, and July 1, 2005, if certain
specific development objectives are met by such dates, or $40 million each if
the objectives are met within one year thereafter. For purposes of calculating
future cash inflows for Malaysia-Thailand at December 31, 1999, the Company
assumed that it would receive an incentive payment of $65 million in July 2002.
There can be no assurances that the Company will receive any incentive payments.
See note 19, "Certain Factors that Could Affect Future Operations - Certain
Factors Related to Malaysia-Thailand."
EQUITY
INVESTMENT
EQUATORIAL TOTAL MALAYSIA-
COLOMBIA GUINEA WORLDWIDE THAILAND
---------- ---------- ---------- ----------
DECEMBER 31, 1999:
Future cash inflows $3,152,352 $ 765,275 $3,917,627 $1,649,881
Future production and
development costs 817,065 399,365 1,216,430 703,419
---------- ---------- ---------- ----------
Future net cash inflows before
income taxes $2,335,287 $ 365,910 $2,701,197 $ 946,462
========== ========== ========== ==========
Future net cash inflows before
income taxes discounted at 10%
per annum $1,414,433 $ 263,849 $1,678,282 $ 266,631
Future income taxes discounted at
10% per annum 391,796 57,589 449,385 15,845
---------- ---------- ---------- ----------
Standardized measure of discounted
future net cash inflows $1,022,637 $ 206,260 $1,228,897 $ 250,786
========== ========== ========== ==========
EQUITY
INVESTMENT
MALAYSIA-
COLOMBIA THAILAND
---------- ----------
DECEMBER 31, 1998:
Future cash inflows $1,481,065 $1,555,929
Future production and
development costs 734,025 695,575
---------- ----------
Future net cash inflows before
income taxes $ 747,040 $ 860,354
========== ==========
Future net cash inflows before
income taxes discounted at 10%
per annum $ 415,127 $ 253,535
Future income taxes discounted at
10% per annum 3,909 8,917
---------- ----------
Standardized measure of discounted
future net cash inflows $ 411,218 $ 244,618
========== ==========
MALAYSIA- TOTAL
COLOMBIA THAILAND WORLDWIDE
---------- ---------- ----------
DECEMBER 31, 1997:
Future cash inflows $2,524,291 $4,078,609 $6,602,900
Future production and
development costs 1,142,382 1,883,881 3,026,263
---------- ---------- ----------
Future net cash inflows before
income taxes $1,381,909 $2,194,728 $3,576,637
========== ========== ==========
Future net cash inflows before
income taxes discounted at 10%
per annum $ 852,421 $ 427,463 $1,279,884
Future income taxes discounted at
10% per annum 173,785 36,756 210,541
---------- ---------- ----------
Standardized measure of discounted
future net cash inflows $ 678,636 $ 390,707 $1,069,343
========== ========== ==========
Changes in the standardized measure of discounted future net cash inflows
follow:
DECEMBER 31,
-------------------------------------
1999 1998 1997
----------- ----------- -----------
Total worldwide:
Beginning of year $ 411,218 $1,069,343 $1,292,195
Sales, net of production costs (179,748) (87,335) (94,062)
Sales of reserves --- (70,543) ---
Equity investment --- (244,618) ---
Revisions of quantity estimates (6,546) (29,321) 75,253
Net change in prices and production costs 1,105,963 (579,212) (552,863)
Extensions, discoveries and improved recovery 206,260 6,516 42,918
Change in future development costs (61,728) (46,633) (5,936)
Purchases of reserves 6,400 --- ---
Development and facilities costs incurred 70,828 105,808 53,199
Accretion of discount 74,704 120,270 160,406
Changes in production rates and other (10,567) (30,772) (3,089)
Net change in income taxes (387,887) 197,715 101,322
----------- ----------- -----------
End of year $1,228,897 $ 411,218 $1,069,343
=========== =========== ===========
SCHEDULE II
TRITON ENERGY LIMITED AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
ADDITIONS
---------
BALANCE AT CHARGED TO BALANCE
BEGINNING CHARGED TO OTHER AT CLOSE
CLASSIFICATIONS OF YEAR EARNINGS ACCOUNTS DEDUCTIONS OF YEAR
- ------------------------- ----------- ------------ ----------- ------------ ---------
Year ended Dec. 31, 1997:
Allowance for doubtful
receivables $ 76 $ --- $ --- $ (35) $ 41
=========== ============ =========== ============ =========
Allowance for deferred
tax asset $ 30,657 $ 44,435 $ --- $ --- $ 75,092
=========== ============ =========== ============ =========
Year ended Dec. 31, 1998:
Allowance for doubtful
receivables $ 41 $ --- $ --- $ (41) $ ---
=========== ============ =========== ============ =========
Allowance for deferred
tax asset $ 75,092 $ 18,519 $ --- $ --- $ 93,611
=========== ============ =========== ============ =========
Year ended Dec. 31, 1999:
Allowance for deferred
tax asset $ 93,611 $ (11,925) $ --- $ --- $ 81,686
=========== ============ =========== ============ =========