UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(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, 1997
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
MARY 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 VOTING STOCK HELD BY NON-AFFILIATES OF
THE REGISTRANT AT MARCH 16, 1998 (FOR SUCH PURPOSES ONLY, ALL DIRECTORS AND
EXECUTIVE OFFICERS ARE PRESUMED TO BE AFFILIATES) WAS APPROXIMATELY $1.2
BILLION, BASED ON THE CLOSING SALES PRICE OF $32 13/16 ON THE NEW YORK STOCK
EXCHANGE.
AS OF MARCH 16, 1998, 36,576,047 ORDINARY SHARES OF THE REGISTRANT
----------------
WERE OUTSTANDING.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE PROXY STATEMENT PERTAINING TO THE 1998 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 19
ITEM 4. Submission of Matters to a Vote of Security Holders 20
PART II
ITEM 5. Market for Registrant's Common Equity and Related
Stockholder Matters 21
ITEM 6. Selected Financial Data 23
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations 24
ITEM 7.A. Quantitative and Qualitative Disclosures about Market Risk 35
ITEM 8. Financial Statements and Supplementary Data 35
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 35
PART III
ITEM 10. Directors and Executive Officers of the Registrant 36
ITEM 11. Executive Compensation 36
ITEM 12. Security Ownership of Certain Beneficial Owners and Management 36
ITEM 13. Certain Relationships and Related Transactions 36
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 37
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 and Malaysia-Thailand. The
Company is actively exploring for oil and gas in these areas, as well as in
southern Europe, Africa, Asia and the Middle East.
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 Company's principal executive offices are located at Caledonian House,
Mary Street, George Town, Grand Cayman, Cayman Islands, and its telephone
number is (345) 949-0050. 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.
RECENT DEVELOPMENT
On March 30, 1998, the Company announced that its Board of
Directors approved the retention of CIBC World Markets Lovegrove & Associates
and Lehman Brothers, Inc. as independent advisers to assist in studying
strategic alternatives for maximizing shareholder value. The strategic
alternatives under consideration may include the sale or farmout of a portion
or all of the Company's interest in Block A-18 of the Malaysia-Thailand Joint
Development Area in the Gulf of Thailand, the sale of a portion or all of the
Company's interest in the Cusiana and Cupiagua oil fields in Colombia, or
both. The Company can give no assurance that it will be successful in pursuing
any of these strategic alternatives or as to the terms upon which any such
transaction may ultimately be consummated.
OIL AND GAS PROPERTIES
Colombia
--------
Through the Company's wholly owned subsidiaries, Triton Colombia,
Inc. and Triton Resources Colombia, Inc. (collectively, "Triton Colombia"),
the Company has varying participation interests in seven licenses in Colombia.
Cusiana and Cupiagua Fields
Contract Terms. In the foothills of the Llanos Basin area in
---------------
eastern Colombia, Triton Colombia holds a 12% interest in the SDLA, Tauramena
and Rio Chitamena contract areas, covering approximately 66,000, 36,300 and
6,700 acres, respectively, where an active appraisal and development program
is being carried out in the Cusiana and Cupiagua fields. Triton's partners in
these areas are Empresa Colombiana De Petroleos ("Ecopetrol"), the Colombian
national oil company, with a 50% interest, BP Exploration Company (Colombia)
Limited ("BP"), the operator, with a 19% interest, and TOTAL Exploratie en
Produktie Maatschippij B.V. ("TOTAL"), also with a 19% interest. In 1993,
Ecopetrol declared the Cusiana and Cupiagua fields to be commercial and
exercised its right to acquire a 50% interest. Triton's 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 expenditures
relating thereto.
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 Colombia, 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. Under the plan, the parties have
agreed to develop the Cusiana oil structure in a technically efficient and
cooperative manner during three consecutive periods of time. During the
initial period (ending with the expiration of the SDLA association contract in
2010), petroleum produced from the unified area will be owned by the parties
according to their respective undivided interests in each contract area.
Within the first quarter of 2005, an independent determination of
the original barrels of oil equivalent ("BOE") of petroleum in place under the
unified area and under each association contract will be made. Then a "tract
factor" will be calculated for each association contract. Each tract factor
will be the amount of original BOEs of petroleum in place under the particular
association contract 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 association contract in 2010) and
during the final period (commencing from the termination of the second
association contract to termination) will be the aggregate of that party's
interest in each remaining association contract multiplied by the tract factor
for each such contract.
Recent Drilling Results. In the Cusiana Field, Triton Colombia and
------------------------
its working interest partners have completed and have in service 36 producing
wells, 10 gas injection wells and one water injection well. The gas injection
wells recycle to the reservoir 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 well is injecting the field's produced water into the Barco
and Guadalupe formations for disposal and pressure maintenance. There are
currently five drilling rigs operating in the Cusiana Field, and it is
expected that 13 oil-production and gas-injection wells will be completed
during 1998. Development drilling is proceeding on a schedule that is intended
to have sufficient well capacity at all times to meet production capacities of
field facilities and export pipelines from the area.
During 1997, Triton Colombia and its working interest partners
completed an additional seven wells in the Cupiagua Field, bringing the
yearend total completions to date to 17 wells, which are awaiting startup of
production facilities in 1998. There are currently five drilling rigs
operating in the Cupiagua Field, and it is expected that 13 additional wells
will be completed during 1998. Development wells drilled during 1997 more
fully defined the areal extent of the field and the oil/water contacts in the
fields.
In January 1998, the sidetrack of the suspended Cusiana 5 well,
referred to as the Cupiagua-EXP well, was completed as a discovery of the
Cupiagua South extension of the Cupiagua Field. The well penetrated the
Mirador and Barco formations and confirmed the upthrown block of the Cupiagua
lower plate. The logs and other data taken from the well confirmed that the
accumulation has a different oil/water contact than either the core of the
Cupiagua Field or the lower plate discovered in the Cupiagua K-5 well, drilled
in late 1995.
Production Facilities and Pipelines. The four early production units of
------------------------------------
the Cusiana Field central processing facility are designed to handle
approximately 180,000 barrels of daily production throughput. In July and
August 1997, two 80,000 barrels of oil per day ("BOPD") Cusiana production
trains were commissioned, which brought the production capacity of the Cusiana
central processing facility to 320,000 BOPD. Startup of the two 100,000 BOPD
production trains at the Cupiagua central processing facility is expected in
1998. Upon completion of the Cupiagua facilities, the total production
capacity from the Cusiana/Cupiagua complex is expected to reach 500,000 BOPD.
In the third quarter of 1997, expansion of pipeline and port facilities
to transport and handle crude oil from the Cusiana and Cupiagua fields to the
Caribbean port of Covenas was completed. These pipeline and port facilities
are operated by Oleoducto Central S.A. ("OCENSA"), a 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.
The new pipeline segments complete a 793-kilometer (495-mile)
pipeline system from the Cusiana and Cupiagua fields to the port of Covenas.
It generally follows the route of the two existing pipelines: the Central
Llanos pipeline from El Porvenir to Vasconia and the Oleoducto de Colombia
pipeline from Vasconia to Covenas. A portion of the Central Llanos pipeline
and pump station upgrades at El Porvenir and Miraflores were acquired by
OCENSA in 1995.
Other Areas in Colombia
Triton owns rights to four additional licenses in Colombia. In the
Middle Magdalena Valley basin and adjacent foothills, Triton owns a 50%
interest (before certain royalties and government participation) in the El
Pinal al contract area, which covers approximately 71,000 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). In 1995, Ecopetrol approved
Triton's application to declare the Liebre Field commercial. Production
from the field, which began in January 1997, is currently 370 BOPD from
the two wells.
In June 1995, the Company was awarded the Guayabo A and B and Las
Amelias association contracts covering a contiguous area of approximately 1.8
million acres. The area is located approximately 150 kilometers (93 miles)
north of Bogota and 140 kilometers (87 miles) northwest of the Cusiana and
Cupiagua fields, and is contiguous with the El Pinal contract area to the
north. The terms of these association contracts are less favorable than the
terms of the Cusiana and Cupiagua association contracts. Triton has acquired
seismic data in a program totaling 178 kilometers (111 miles) over the Guayabo
A and B blocks, and 195 kilometers (122 miles) over the Las Amelias block, as
well as approximately 15,000 kilometers (9,375 miles) of aeromagnetic data.
Triton's partner in these areas is Deminex Colombia Petroleum GmbH with a 50%
interest.
Malaysia-Thailand
-----------------
Through the Company's wholly owned subsidiaries, Triton Oil Company
of Thailand (JDA) Limited and Triton Oil Company of Thailand (collectively,
"Triton Thailand"), the Company has a participating interest in Block A-18 of
the Malaysia-Thailand Joint Development Area in the Gulf of Thailand. To date,
eight fields have been discovered on the block.
Contract Terms
In April 1994, Triton Thailand signed a production-sharing contract
covering the offshore area designated as Block A-18 of 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 other parties to the
production-sharing contract are the Malaysia-Thailand Joint Authority (the
"MTJA"), which has been established by treaty to administer the Joint
Development Area, and Petronas Carigali (JDA) Sdn. Bhd. ("Carigali"), a
subsidiary of the Malaysian national oil company. The treaty provides for the
development of the Joint Development Area that includes Block A-18. Triton
Thailand previously held a license from Thailand that covered part of the
Joint Development Area.
The term of the 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 Carigali have the
right to explore for oil and gas for the first five years of the contract. The
contract provides that if there is a discovery of natural gas (not associated
with crude oil), and if the MTJA agrees, the contractors will be able to hold
that gas field without production for an additional five-year period, provided
the contractors submit to the MTJA an acceptable development plan for the
field. In 1997, the MTJA agreed, subject to government approval, to extend the
five-year exploration period by three years, but the holding period for any
discovery in the additional three-year period would not extend beyond the
tenth anniversary of the contract. The 35-year term also was unaffected. The
contractors then have a five-year period from the MTJA's acceptance of the
development plan 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 grants to the
operators the right to produce oil from an oil field for 25 years plus a
number of years equal to the number of years, if any, prior to the fifth
anniversary of the contract that oil production commenced (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.
Up to 50% 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
Triton). Triton's share of production is subject to an additional royalty
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.
Simultaneously with the execution of the production sharing
contract, the parties executed a joint operating agreement governing Block
A-18 operations. The operating agreement designated as operator
Carigali-Triton Operating Company Sdn. Bhd. ("CTOC"), a company owned equally
by Triton Thailand and Carigali.
Negotiations for a Gas-Sales Agreement
In May 1996, the MTJA, Triton and Carigali signed a Memorandum of
Understanding on the sale and purchase of natural gas with Petronas and PTT,
the national oil companies of Malaysia and Thailand, respectively. The
Memorandum of Understanding provides a basis for negotiation of a gas-sales
agreement for natural gas to be produced from Block A-18. The parties
currently are negotiating a heads of agreement intended to include agreement
in principle on the key gas-sales agreement terms. The Company expects that
negotiation and execution of a definitive gas-sales agreement reflecting the
heads of agreement will follow execution of the heads of agreement.
Recent Drilling Results
During 1997, one appraisal well and four exploratory wells were
drilled on Block A-18.
In July 1997, the Bumi North-1 appraisal well was drilled to
delineate the Bumi Field. The well was tested at a combined rate of 42 MMcf of
gas and 362 barrels of condensate per day from selected intervals. The well
was drilled in approximately 183 feet of water to a total depth of 9,250 feet,
approximately 15 kilometers (9 miles) north-northeast of Bumi-1.
During 1997, exploratory drilling discovered four additional fields
in Block A-18. The Senja-1 well discovered both oil- and gas-bearing zones in
the Senja Field. On test, the well flowed at a combined rate of 2,725 barrels
of oil, 39 MMcf of gas and 368 barrels of condensate per day from selected
intervals. The well was drilled in approximately 179 feet of water to a total
depth of 7,600 feet. The Senja Field is located in the northwest portion of
the block. The Bumi East-1 well tested at a combined rate of 34 MMcf of gas
and 1,681 barrels of condensate per day from selected intervals in the Bumi
East Field. The well was drilled in approximately 188 feet of water to a total
depth of 9,100 feet, approximately 16 kilometers (10 miles) northeast of
Bumi-1. The Samudra-1 well tested at a combined rate of 49 MMcf of gas and 858
barrels of condensate per day from selected intervals. The well was drilled in
approximately 176 feet of water to a total depth of 12,000 feet. The Samudra
Field is located in the southwest portion of the block. The Wira-1 well
discovered the Wira Field, located in the central portion of the block. The
well was drilled in approximately 174 feet of water to a total depth of 10,000
feet. One production test was conducted to confirm results of electric logs
and hydrocarbon samples taken from the reservoir. The Wira-1 well flowed at a
maximum daily rate of 9.1 MMcf of gas and 137 barrels of condensate per day.
Development Plan
In December 1997, the MTJA approved the field development plan for
the Cakerawala Field. Initial development plans call for three wellhead
platforms, a production platform, a living quarters platform, a floating
storage and offloading vessel for oil and condensate and 35 development wells.
Development of the field is expected to commence following execution of the
heads of agreement and to take approximately 30 to 36 months to complete.
Ecuador
-------
Through the Company's subsidiary, Triton Ecuador, Inc. LLC, the
Company holds an interest in Block 19, which covers approximately 494,000
acres located in the Ecuadorian foothills of the eastern side of the Andes
Mountains in the Oriente Basin. Triton's partners in the block are Vintage
Petroleum Ecuador, Inc., with a 30% interest, and Ranger Oil Limited, with a
15% interest. The partners' work program commitments for Block 19 consist of
the acquisition of 400 kilometers (250 miles) of new seismic data and the
drilling of two exploratory wells during a four-year exploration period. The
Huataracu-1 exploratory well, completed in May 1997, was plugged and abandoned
after tests failed to confirm the presence of commercial quantities of oil or
gas. An environmental impact study for a second exploratory well, Arapino-1,
was approved in December of 1997.
Guatemala
---------
Through the Company's subsidiary, Triton Guatemala S.A., the Company
has acquired an interest in two contiguous blocks. The blocks cover a total of
approximately 608,000 acres located on the border with Mexico in an extension
of the Chiapas Fold Belt province. In May 1997, Triton executed an agreement
with Pioneer Natural Resources providing Pioneer the right to earn a 40%
interest in both blocks, subject to government approval. The Piedras Blancas-1
exploratory well was drilled in 1997, reaching a total depth of 10,188 feet,
and was plugged and abandoned after tests failed to confirm the presence of
commercial quantities of oil or gas. In 1998, Triton's request for extensions
of the seismic option periods for both blocks was approved. Triton is
reviewing the Blocks for future drilling opportunities.
China
-----
The Company's subsidiary, Triton China, Inc. LLC, has signed
production sharing contracts with the China National Offshore Oil Company
("CNOOC"), which give the Company the right to explore and develop two
contiguous offshore contract areas, Blocks 16/03 and 16/22. The blocks cover a
total of 2.4 million acres located in the Huizhou Sub-Basin of the Pearl River
Mouth Basin approximately 175 kilometers (110 miles) offshore Hong Kong in
water depths ranging from 300 to 650 feet. Pursuant to extensions granted in
1998, the blocks have a primary exploration term expiring on March 31, 1999.
The obligation well for Block 16/03 was plugged and abandoned with no tests.
Mobil Exploration & Producing China Inc. has notified Triton of its intent to
withdraw from the blocks effective March 31, 1998.
Triton is also party to an offshore Joint Study Agreement with
CNOOC for Block JSA 24/05, which covers approximately 1.5 million acres in
water depths ranging from 50 to 200 feet in the Liedong area of the South
China Sea. In 1998, the Company determined that it would not convert the Joint
Study Agreement for Block JSA 24/10 into a production sharing contract.
Greece
------
The Company's subsidiary, Triton Hellas S.A., has signed two leases
with the national oil company of Greece, which give the Company the right to
explore and develop an area of approximately 1.5 million acres. The Gulf of
Patraikos contract area is located offshore between the coastline of the
western Greece's mainland and the offshore Ionian islands of Lefkas, Kefalonia
and Zakynthos in water depths of up to 1,700 feet. The lease provides a
primary four-year exploration term with a commitment of 2,000 kilometers of
seismic and the drilling of one exploratory well for a total expenditure of
not less than $13.5 million. The Aitoloakarnania contract area is located
onshore in the prefecture of Aitoloakarnania in western Greece. The lease
provides a primary two-year exploration term with a commitment of 200
kilometers of seismic and the drilling of two exploratory wells for a total
expenditure of not less than $13.25 million. Reprocessing of existing seismic
was completed in both areas during 1997.
Italy
-----
The Company has a 40% interest in each of the contiguous DR71 and
DR72 licenses operated by Enterprise Oil Italiana, S.p.A., in the Adriatic
Sea, and a 50% interest in three onshore licenses, operated by Triton Italy,
Inc., in the southern Apennine Mountains. Triton has applications pending for
additional licenses onshore and offshore.
The DR71 and DR72 licenses lie 45 kilometers (28 miles) offshore the
city of Brindisi and cover approximately 493,000 acres. One well, Medusa-1,
was drilled on DR72 in 1996 to a total depth of 4,725 feet. The well proved
the presence of oil and gas in a new play but in noncommercial quantities and
was not tested. Additional drilling is expected in 1998.
The contiguous southern Apennines licenses - Fosso del Lupo,
Valsinni and Masseria di Sole - cover approximately 101,000 acres in the
Matera province. The licenses were awarded in August 1996. In 1997, Triton
purchased and reprocessed 300 kilometers of seismic data over the licenses.
Oman
----
The Company's subsidiary, Triton Oman, Inc., was awarded a 100%
interest in a production-sharing contract covering Block 22, Masirah Bay, by
the Sultanate of Oman in June 1996. The offshore block covers approximately
two million acres in water depths ranging from 50 to 200 feet. The minimum
contractual obligation during the initial three-year exploration period
requires the reprocessing and reinterpretation of existing seismic data, 1,000
kilometers (625 miles) of seismic acquisition and one exploratory well
contingent on the results of the seismic program.
During 1997, the Company reprocessed and interpreted approximately
1,100 kilometers (688 miles) of existing seismic data, and acquired
approximately 1,750 kilometers (1,094 miles) of 2D seismic and 24,000
kilometers (15,000 miles) of high resolution aeromagnetic and remote sensing
studies. The seismic acquisition fulfills Triton's seismic obligation on the
block.
Indonesia
---------
In February 1997, the Company's subsidiary, TriBlora Indonesia B.V.,
acquired from Eurafrep B.V. a 30% interest in the Blora production-sharing
contract covering a block of approximately 1.4 million acres located within
central Java. Triton's partners are Eurafrep B.V., the operator, with a 40%
interest, YPF International Ltd. with a 16.7% interest and Warrior Jawa Inc.
with a 13.3% interest.
The work program calls for an unspecified amount of seismic
reprocessing, as well as the acquisition of 150 kilometers (95 miles) of 2D
seismic and the drilling of a well within the three-year initial exploration
period for a total expenditure of not less than $4.5 million. In 1997,
reprocessing of approximately 1,600 kilometers (1,000 miles) of existing 2D
seismic was completed. Acquisition of 760 kilometers (475 miles) of new 2D
seismic data was completed in January 1998 and drilling is planned for late
1998.
Equatorial Guinea
------------------
The Company's subsidiary, Triton Equatorial Guinea, Inc., has signed
production-sharing contracts covering two contiguous blocks (Blocks F and G)
with the Republic of Equatorial Guinea. 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. They provide a primary two-year exploration term with a commitment
of 2,000 kilometers (1,250 miles) of seismic and the drilling of one
exploratory well for a total expenditure of not less than $5 million.
Madagascar
----------
The Company's subsidiary, Triton Madagascar, Inc., has signed
production-sharing contracts covering two blocks with the Office of National
Mines and Strategic Industries in Madagascar. The Ambilobe Block
(approximately 7.1 million acres) is located directly offshore from Ambilobe
in water depths of up to 11,500 feet and the Cap St. Marie Block
(approximately 6.8 million acres) is located directly offshore from Cap St.
Marie in water depths of up to 5,900 feet. The blocks have a primary one-year
exploration term involving geological and geophysical studies.
Tunisia
-------
In May 1997, the Company's subsidiary, Triton Tunisia, Inc., signed
an agreement with Carthago Oil Company Tunisia, the operator, to acquire a 50%
interest in the Medjerda production sharing contract covering a block of
approximately 1.1 million acres located in northern Tunisia. The first phase
of the contract has been extended to December 1998 with a commitment to
acquire 250 kilometers (156 miles) of 2D seismic and drill one exploratory
well. The Medjerda-1 well was spudded in January 1998 and is being drilled.
Argentina
---------
In 1997, the Company sold its Argentine subsidiary.
RESERVES
The following table sets forth a summary of the estimated oil and
gas reserves of the Company at December 31, 1997, 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 all proved
reserves in the Cusiana and Cupiagua fields in Colombia, and by the Company's
internal petroleum engineers with respect to all proved reserves in
Malaysia-Thailand on Block A-18 in the Gulf of Thailand and the Liebre Field
in Colombia. This table sets forth the estimated net quantities of proved
developed and undeveloped oil and gas reserves and total proved oil and gas
reserves owned by the Company and its consolidated subsidiaries. At December
31, 1997, the Company had no proved developed or proved undeveloped reserves
in Ecuador, Guatemala, China, Greece, Italy, Oman, Indonesia, Equatorial
Guinea, Madagascar or Tunisia. For additional information regarding the
Company's reserves, including the standardized measure of future net cash
flows, see note 24 of Notes to Consolidated Financial Statements. Oil
reserves data include natural gas liquids and condensate.
Net proved reserves at December 31, 1997, were:
PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
------------------------ ------------------- -------------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
---------- ------------ ------- ---------- -------- ----------
Colombia (1) 81,931 14,619 64,068 --- 145,999 14,619
Malaysia-Thailand (2) --- --- 29,800 1,223,800 29,800 1,223,800
---------- ------------ ------- ---------- -------- ----------
Total 81,931 14,619 93,868 1,223,800 175,799 1,238,419
---------- ------------ ------- ---------- -------- ----------
____________________
(1) Includes liquids to be recovered from Ecopetrol as reimbursement for
precommerciality expenditures.
(2) As of December 31, 1997, the Company did not have a contract for the
sale of gas to be produced from its 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
natural-gas prices derived from what the Company believed to be the most
comparable market price at December 31, 1997. There can be no assurance that
the price to be provided in any gas contract will be equal to the price used
in the Company's calculations.
Reserve estimates are approximate and may be expected to change as
additional information becomes available. Furthermore, estimates of oil and
gas reserves, of necessity, are projections based on engineering data, and
there are uncertainties inherent in the interpretation of such data, as well
as the projection of 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 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.
No estimates of total proved net oil or gas reserves have been filed
by the Company with, or included in any report to, any United States authority
or agency pertaining to the Company's individual reserves since the beginning
of the Company's last fiscal year.
OIL AND GAS OPERATIONS
Production and Sales
- ----------------------
The following table sets forth the net quantities of oil and gas
produced by the Company for the years ended December 31, 1997, 1996 and 1995.
The table includes production attributable to the Company's 49.9% ownership
interest in Crusader Limited ("Crusader") through the date of its sale in
1996, as well as the minority interests in Crusader's consolidated
subsidiaries. The production and sales information relating to properties or
subsidiary or affiliate ownership interests acquired or disposed of is
reflected in the table only since or up to the effective dates of their
respective acquisitions or sales, as the case may be.
OIL PRODUCTION (1) GAS PRODUCTION
------------------------ -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ -----------------------
1997 1996 1995 1997 1996 1995
---- ---- ---- ---- ---- ----
(MBBLS) (MMCF)
Colombia (2) 5,776 5,738 5,089 802 298 158
France (3) --- --- 498 --- --- ---
Indonesia (4) --- 95 255 --- --- ---
United States (5) --- 20 121 --- 475 1,207
Crusader (6):
Australia --- 134 287 --- 1,744 3,884
Canada --- --- 53 --- --- 63
------- ------- ----- ---- ----- -----
Total 5,776 5,987 6,303 802 2,517 5,312
------- ------- ----- ---- ----- -----
____________________
(1) Includes natural gas liquids and condensate.
(2) Includes Ecopetrol reimbursement barrels and excludes 2.5 million, .7
million and .4 million barrels of oil produced and delivered for the years
ended December 31, 1997, 1996 and 1995, respectively, in connection with the
Company's forward sale of oil in May 1995. See Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Results of Operations" and note 3 of Notes to Consolidated Financial
Statements.
(3) In August 1995, Triton Europe sold its interest in its subsidiary,
Triton France S.A.
(4) In May 1996, the Company sold substantially all of the assets of
Triton Indonesia, Inc.
(5) In March 1996, Triton sold substantially all of its domestic royalty
and mineral interests.
(6) In 1996, the Company sold all of its interest in Crusader. In June
1995, Crusader sold all of its interest in Ausquacan Energy Limited.
The following tables summarize for the years ended December 31,
1997, 1996 and 1995: (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,
------------------------- ------------------------
1997 1996 1995 1997 1996 1995
------ ------ ------ ----- ----- -----
Colombia $17.54 $19.62 $16.29 $1.15 $2.56 $1.96
France --- --- 18.11 --- --- ---
Indonesia --- 19.54 17.77 --- --- ---
United States --- 16.00 13.62 --- 1.15 1.49
Crusader:
Australia --- 19.95 20.38 --- 1.69 1.69
Canada --- --- 15.42 --- --- 0.99
PER EQUIVALENT BARREL (2)
-------------------------------------------------------------------------------
AVERAGE SALES PRICE DEPLETION (3) PRODUCTION COST
-------------------------- ------------------------- ------------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
-------------------------- ------------------------- ------------------------
1997 1996 1995 1997 1996 1995 1997 1996 1995
------- ------- ------- ------- ------ ------ ----- ----- ------
Colombia $ 17.37 $ 19.58 $ 16.26 $ 3.67 $ 2.83 $ 2.67 $6.47 $ 5.66 $ 5.52
France --- --- 18.11 --- --- 3.14 --- --- 10.96
Indonesia --- 19.54 17.77 --- 0.52 0.95 --- 15.89 17.34
United States --- 8.75 10.68 --- 5.59 6.05 --- 3.25 1.03
Crusader:
Australia --- 13.23 13.29 --- 3.47 3.35 --- 4.10 4.77
Canada --- --- 13.87 --- --- 2.35 --- --- 7.52
____________________
(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.
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 principal means of competition in the sale of oil and gas are
product availability, price and quality. While it is not possible for the
Company to state precisely its competitive position in the oil and gas
industry, the Company believes that it represents a minor competitive factor.
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 is 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, 1997. "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 36 5 1,934 938
Malaysia-Thailand --- --- 731 366
Ecuador --- --- 494 272
Guatemala --- --- 608 365
China --- --- 3,978 2,761
Greece --- --- 1,475 1,298
Italy --- --- 594 248
Oman --- --- 2,044 2,044
Indonesia --- --- 1,413 424
Equatorial Guinea --- --- 1,306 1,306
Madagascar --- --- 13,914 13,914
Tunisia --- --- 1,102 551
------- ------ ------ ------
Total 36 5 29,593 24,487
------- ------ ------ ------
____________________
(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.
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, 1997, in Colombia, Triton held gross and net working
interests in 64 and 7.7 productive wells, respectively, which include 10 gross
(1.2 net) gas-injection wells and one gross (.12 net) water-injection well.
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 for the years ended December 31, 1997, 1996 and 1995.
GROSS EXPLORATORY WELLS
PRODUCTIVE (1) DRY TOTAL
----------------------- ----------------------- -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
---------------------- ----------------------- ----------------------
1997 1996 1995 1997 1996 1995 1997 1996 1995
----- ----- ------ ----- ---- ----- ---- ----- -----
Colombia 1 3 2 1 --- 2 2 3 4
Malaysia-Thailand 5 7 2 --- --- --- 5 7 2
Argentina --- --- --- --- 2 2 --- 2 2
Italy --- --- --- --- 1 --- --- 1 ---
Guatemala --- --- --- 1 --- --- 1 --- ---
China --- --- --- --- 1 --- --- 1 ---
Ecuador --- --- --- 1 --- --- 1 --- ---
Crusader (2):
Argentina --- --- 1 --- --- 2 --- --- 3
Australia --- 14 23 --- 4 11 --- 18 34
---- ----- ------ ----- --- ---- ---- ----
Total 6 24 28 3 8 17 9 32 45
---- ----- ------ ----- --- ---- ---- ---- ----
GROSS DEVELOPMENT WELLS
PRODUCTIVE (1) DRY TOTAL
------------------------ ----------------------- -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ ----------------------- -----------------------
1997 1996 1995 1997 1996 1995 1997 1996 1995
----- ------ ------ ----- ---- ---- ---- ---- ----
Colombia 18 15 8 --- --- --- 18 15 8
Malaysia-Thailand --- --- --- --- --- --- --- --- ---
Crusader (2):
Australia --- 2 5 --- --- 1 --- 2 6
--- ------ ----- ---- ---- ---- ---- ---- ---
Total 18 17 13 --- --- 1 18 17 14
--- ------ ----- ---- ---- ---- ---- ---- ---
___________________
(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) In 1996, the Company sold all of its interest in Crusader. In 1995,
Crusader sold its interests in Argentina and Canada.
The following tables set forth the results of drilling activity on a
net basis for wells in which the Company held an interest for the years ended
December 31, 1997, 1996 and 1995 (those wells acquired or disposed of since
January 1, 1995 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,
------------------------ ----------------------- -----------------------
1997 1996 1995 1997 1996 1995 1997 1996 1995
----- ------ -------- ---- ---- ---- ---- ---- ----
Colombia (2) 0.12 0.12 0.12 0.50 0.50 2.00 0.62 0.62 2.12
Malaysia-Thailand 2.50 3.50 1.00 --- --- --- 2.50 3.50 1.00
Argentina --- --- --- --- 2.00 2.00 --- 2.00 2.00
Italy --- --- --- --- 0.40 --- --- 0.40 ---
Guatemala --- --- --- 0.60 --- --- 0.60 --- ---
China --- --- --- --- 0.50 --- --- 0.50 ---
Ecuador --- --- --- 0.55 --- --- 0.55 --- ---
Crusader (3):
Argentina --- --- 0.06 --- --- 0.12 --- --- 0.18
Australia --- 0.34 0.35 --- 0.10 0.29 --- 0.44 0.64
----- ------ -------- ---- ---- ---- ---- ---- ----
Total 2.62 3.96 1.53 1.65 3.50 4.41 4.27 7.46 5.94
----- ------ -------- ---- ---- ---- ---- ---- ----
NET DEVELOPMENT WELLS
PRODUCTIVE (1) DRY TOTAL
------------------------ ----------------------- -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ ----------------------- -----------------------
1997 1996 1995 1997 1996 1995 1997 1996 1995
----- ------- ----- ----- ------ ---- ---- ---- ----
Colombia (2) 2.16 1.80 0.96 --- --- --- 2.16 1.80 0.96
Malaysia-Thailand --- --- --- --- --- --- --- --- ---
Crusader (3):
Australia --- 0.05 0.10 --- --- 0.02 --- 0.05 0.12
---- ------- ----- ---- ---- ---- ---- ---- ----
Total 2.16 1.85 1.06 --- --- 0.02 2.16 1.85 1.08
---- ------- ----- ---- ---- ---- ---- ---- ----
__________________
(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) Adjusted to reflect the Company's 49.9% interest in Crusader, which
was sold in 1996.
OTHER PROPERTIES
The Company leases or owns office space and other properties for its
various 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 statements in this Annual Report on Form 10-K, including
expectations, intentions, plans and beliefs of the Company and management,
including those contained in or implied by Items 1 and 2, "Business and
Properties", and Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations," are forward-looking statements, as
defined in Section 21D of the Securities Exchange Act of 1934, that are
dependent on certain events, risks and uncertainties that may be outside the
Company's control. These forward-looking statements include statements of
management's plans and objectives for future operations and statements of
future economic performance; information regarding drilling schedules and
schedules for the start-up of production facilities; expected or planned
production or transportation capacity; when the Fields might become
self-financing; future production of the Fields; the negotiation of a heads of
agreement to a gas-sales contract and a gas-sales contract and commencement of
production in Malaysia-Thailand; the Company's capital budget and future
capital requirements; the Company's meeting its future capital needs; the
amount by which production from the Fields may increase or when such increased
production may commence; the Company's realization of its deferred tax asset;
the level of future expenditures for environmental costs; the outcome of
regulatory and litigation matters, the impact of Year 2000 issues; and proven
oil and gas reserves and discounted future net cash flows therefrom; and the
assumptions described in this report underlying such forward-looking
statements. Actual results and developments could differ materially from
those expressed in or implied by such statements due to a number of factors,
including those described in the context of such forward-looking statements
and in notes 19 and 20 of Notes to Consolidated Financial Statements.
EMPLOYEES
At March 16, 1998, the Company employed approximately 295 full-time
employees.
EXECUTIVE OFFICERS OF THE COMPANY
The following table sets forth certain information regarding the
executive officers of the Company at March 16, 1998:
SERVED WITH
-----------
THE COMPANY
-----------
NAME AGE POSITION WITH THE COMPANY SINCE
- ----------------------------- ---- ---------------------------------------------------- -----
Thomas G. Finck 51 Chairman of the Board and Chief Executive Officer 1992
Nick De'Ath 49 Senior Vice President, Exploration 1993
Robert B. Holland, III 45 Senior Vice President, General Counsel and Secretary 1993
Peter Rugg 50 Senior Vice President and Chief Financial Officer 1993
A.E. Turner, III 49 Senior Vice President, Operations 1994
In August 1992, Mr. Finck was elected Director, President and Chief
Operating Officer of the Company. Effective January 1993, Mr. Finck was
elected Chief Executive Officer, and effective May 1995, he assumed the
additional position of Chairman of the Board. From July 1991 to August 1992,
Mr. Finck served as President and Chief Executive Officer of American Energy
Group, an independent oil and natural gas exploration and production company.
From May 1984 until June 1991, Mr. Finck served as President and Chief
Executive Officer of Ensign Oil & Gas, Inc., a private domestic oil and gas
exploration company.
Mr. De'Ath was elected Senior Vice President, Exploration in 1993.
From 1992 to 1993, Mr. De'Ath served as President and owner of Pinnacle Ltd.,
a management consulting firm providing services to multinational companies in
Colombia, and from 1971 to 1992 served in various positions with subsidiaries
of British Petroleum Company, p.l.c., including general manager of exploration
for BP International Limited in Mexico from 1991 to 1992 and general manager
of BP's Colombian operation from 1986 to 1991.
Mr. Holland was elected Senior Vice President, General Counsel and
Secretary of the Company in January 1993. For more than five years prior to
joining the Company, Mr. Holland was a partner of the law firm of Jackson &
Walker, L.L.P., Dallas, Texas.
Mr. Rugg was elected Senior Vice President and Chief Financial
Officer in April 1993. From September 1992 to April 1993, Mr. Rugg served as
Vice President of J.P. Morgan & Co., Incorporated ("J.P. Morgan"), a financial
services firm, and for more than the five years prior to September 1992, Mr.
Rugg served as Vice President of Morgan Guaranty Trust Company of New York, an
international bank owned by J.P. Morgan.
Mr. Turner was elected Senior Vice President, Operations in 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.
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
The Company and subsidiaries or former subsidiaries of the Company
were among numerous defendants in a lawsuit brought in the Superior Court of
the State of California, County of Los Angeles, by Travelers Indemnity Company
arising out of a 1988 tidal wave at King Harbor in Redondo Beach, California.
The lawsuit alleged, among other things, that the defendants' negligence
contributed to the collapse of a hotel and the flooding of a restaurant in the
tidal wave. This lawsuit was settled in 1998.
During the quarter ending 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 subsidiary
has a formal period of negotiation regarding performing the final remediation
design for the clean-up of the site, and demanded reimbursement for certain
unpaid costs that have been incurred. The government estimates the aggregate
amount being negotiated as $217 million to be allocated among the 280 known
operators. The subsidiary's share would be approximately $1 million based
upon a volumetric allocation. The Company has been advised that the
government expects that defendants such as the subsidiary will be given an
opportunity to settle some time in the second half of 1998. At that time, it
is expected that an allocation will be made as to such defendants, which may
be greater or less than the estimated volumetric allocation.
On August 22, 1997, the Company was sued in the Superior Court of
the State of California for the County of Los Angeles, by David A. Hite,
Nordell International Resources Ltd., and International Veronex Resources,
Ltd. The Company and the plaintiffs were adversaries in a 1990 arbitration
proceeding in which the interest of Nordell International Resources Ltd. in
the Enim oil field in Indonesia was awarded to the Company (subject to a 5%
net profits interest for Nordell) and Nordell was ordered to pay the Company
nearly $1 million. The arbitration award was followed by a series of legal
actions by the parties in which the validity of the award and its enforcement
were at issue. As a result of these proceedings, the award was ultimately
upheld and enforced.
The current suit alleges that the plaintiffs were damaged in amounts
aggregating $13 million primarily because of the Company's prosecution of
various claims against the plaintiffs as well as its alleged
misrepresentations, infliction of emotional distress, and improper accounting
practices. The suit seeks specific performance of the arbitration award,
damages for alleged fraud and misrepresentation in accounting for Enim field
operating results, an accounting for Nordell's 5% net profit interest, and
damages for emotional distress and various other alleged torts. The suit
seeks interest, punitive damages and attorneys fees in addition to the alleged
actual damages.
On September 26, 1997, the Company removed the action to the United
States District Court for the Central District of California. The Company
believes the suit is without merit and intends vigorously to defend it.
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, 1997 to security holders, through the solicitation
of proxies or otherwise.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
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
closing 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
- ---------------- -------- --------
1998:
First Quarter* 33 15/16 25 13/16
1997:
First Quarter 52 1/2 38 1/4
Second Quarter 45 13/16 32 3/8
Third Quarter 48 38 3/16
Fourth Quarter 44 7/8 27 5/8
1996:
First Quarter 59 3/4 46 3/4
Second Quarter 57 1/8 45 3/4
Third Quarter 49 3/8 40 1/2
Fourth Quarter 50 5/8 42 1/2
______________________
*Through March 16, 1998.
Triton has not declared any cash dividends on its ordinary shares
since fiscal 1990. 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 is necessarily dependent upon the
earnings and financial needs of the Company, along with applicable legal and
contractual restrictions.
The payment of dividends on the Company's capital stock is
restricted pursuant to the Company's revolving credit facilities.
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.
As of March 16, 1998, the Company had outstanding 217,732 shares of
its 5% Convertible Preference Shares ("5% Preference Shares"). Each 5%
Preference Share may be converted 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% 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 (or such
earlier date as there are fewer than 133,005 5% Preference Shares outstanding)
for cash equal to the redemption price. Any shares of 5% Preference 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.
See note 12 of Notes to Consolidated Financial Statements.
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, Oppenheimer Group, Inc. ("Oppenheimer") may increase its
level of beneficial ownership to 19.9% without triggering a distribution of
the rights. 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
Oppenheimer), each right not owned by such person generally becomes the right
to purchase such 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 such 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
Oppenheimer) 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 rights will expire on May 22, 2005, unless such expiration date
is extended or unless the rights are earlier redeemed or exchanged by the
Company. At any time prior to a person acquiring beneficial ownership of 15%
or more of Triton's ordinary shares, the Company may redeem the rights in
whole, but not in part, at a price of $.01 per right. For so long as the
rights are redeemable, the Company may, except with respect to the redemption
price, amend the rights in any manner.
At March 16, 1998, there were 4,244 record holders of the Company's
ordinary shares.
ITEM 6. SELECTED FINANCIAL DATA
AS OF OR FOR YEAR ENDED
DECEMBER 31,
----------------------------------------------
1997 1996 1995 1994
---------- -------- --------- ---------
(unaudited)
OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA):
Sales and other operating revenues (1) $ 149,496 $133,977 $ 107,472 $ 32,952
Earnings (loss) from continuing operations (1) (2) 5,595 23,805 6,541 (49,610)
Earnings (loss) before extraordinary
items and cumulative effect of
accounting change 5,595 23,805 2,720 (52,701)
Net earnings (loss) (2) (8,896) 22,609 2,720 (52,701)
Average ordinary shares outstanding 36,471 35,929 35,147 34,916
Basic earnings (loss) per ordinary share:
Continuing operations (1) (2) $ 0.14 $ 0.64 $ 0.16 $ (1.43)
Before extraordinary item and
cumulative effect of accounting change 0.14 0.64 0.05 (1.52)
Net earnings (loss) (0.26) 0.61 0.05 (1.52)
Diluted earnings (loss) per ordinary share:
Continuing operations (1) (2) $ 0.14 $ 0.62 $ 0.16 $ (1.43)
Before extraordinary item and
cumulative effect of accounting change 0.14 0.62 0.05 (1.52)
Net earnings (loss) (0.25) 0.59 0.05 (1.52)
BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment $ 835,506 $676,833 $ 524,381 $399,658
Total assets 1,098,039 914,524 824,167 619,201
Long-term debt (3) 443,312 217,078 401,190 315,258
Redeemable preference shares of
subsidiaries --- --- --- ---
Shareholders' equity 296,620 300,644 246,025 237,195
CERTAIN OIL AND GAS DATA (4) :
Production
Oil (Mbbls) (5) 5,776 5,987 6,303 2,534
Gas (MMcf) 802 2,517 5,312 5,516
Average sales price
Oil (per bbl) $ 17.54 $ 19.61 $ 16.60 $ 15.26
Gas (per Mcf) $ 1.15 $ 1.69 $ 1.64 $ 1.51
AS OF OR
FOR SEVEN
MONTHS ENDED AS OF OR FOR YEAR ENDED
DECEMBER 31, MAY 31,
-----------------------
1994 1994 1993
--------- --------- ---------
OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA):
Sales and other operating revenues (1) $ 20,736 $ 43,208 $ 84,414
Earnings (loss) from continuing operations (1) (2) (26,630) (4,597) (76,509)
Earnings (loss) before extraordinary
items and cumulative effect of
accounting change (27,708) (9,341) (93,552)
Net earnings (loss) (2) (27,708) (9,341) (89,535)
Average ordinary shares outstanding 34,944 34,775 34,241
Basic earnings (loss) per ordinary share:
Continuing operations (1) (2) $ (0.78) $ (0.13) $ (2.23)
Before extraordinary item and
cumulative effect of accounting change (0.81) (0.27) (2.73)
Net earnings (loss) (0.81) (0.27) (2.61)
Diluted earnings (loss) per ordinary share:
Continuing operations (1) (2) $ (0.78) $ (0.13) $ (2.23)
Before extraordinary item and
cumulative effect of accounting change (0.81) (0.27) (2.73)
Net earnings (loss) (0.81) (0.27) (2.61)
BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment $ 399,658 $ 308,498 $ 330,151
Total assets 619,201 616,101 561,931
Long-term debt (3) 315,258 294,441 159,147
Redeemable preference shares of
subsidiaries --- --- 11,399
Shareholders' equity 237,195 263,422 255,432
CERTAIN OIL AND GAS DATA (4) :
Production
Oil (Mbbls) (5) 1,488 2,886 3,691
Gas (MMcf) 3,427 9,078 21,958
Average sales price
Oil (per bbl) $ 16.41 $ 15.15 $ 18.67
Gas (per Mcf) $ 1.44 $ 1.44 $ 1.27
(1) Operating data for the year ended December 31, 1994 (unaudited), the
seven months ended December 31, 1994, and the years ended May 31, 1994 and
1993, are restated to reflect the aviation sales and services segment and the
wholesale fuel products segment as discontinued operations in 1995 and 1993,
respectively.
(2) Gives effect to the writedown of assets and loss provisions of $46.2
million, $1.1 million, $14.7 million, $1.0 million, $45.8 million and $99.9
million for the years ended December 31, 1996, 1995 and 1994 (unaudited), the
seven months ended December 31, 1994, and the years ended May 31, 1994 and
1993, respectively.
(3) Long-term debt does not include current maturities totaling $130.4
million, $199.6 million, $1.3 million, $.3 million, $.3 million and $3.4
million at December 31, 1997, 1996, 1995 and 1994, and May 31, 1994 and 1993,
respectively.
(4) Information presented includes the 49.9% equity investment in Crusader
Limited, which was sold in 1996.
(5) Includes natural gas liquids and condensate. Production excludes 2.5
million, .7 million and .4 million barrels of oil produced and delivered under
a forward oil sale entered into in May 1995 for the years ended December 31,
1997, 1996 and 1995, respectively.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL REQUIREMENTS
--------------------------------
Changes in Working Capital
-----------------------------
Cash, cash equivalents and marketable securities totaled $13.5
million and $14.9 million at December 31, 1997 and 1996, respectively.
Working capital deficit improved to $115.2 million at December 31, 1997,
compared with $182.2 million at December 31, 1996. At December 31, 1997,
borrowings of $164.9 million under the Company's bank credit facilities, which
mature during the period August through November 1998, were classified as a
current liability. Current liabilities included deferred income totaling
$35.3 million and $28.5 million at December 31, 1997 and 1996, respectively,
related to a forward oil sale consummated in 1995.
Refinancing of Debt
---------------------
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 Senior Subordinated Discount Notes due November 1, 1997 (the "1997
Notes"), and 9 3/4% Senior Subordinated Discount Notes due December 15, 2000
(the "9 3/4% Notes"), resulting in the retirement of the 1997 Notes and
substantially all of the 9 3/4% Notes and the removal of the financial
covenants in the remaining 9 3/4% Notes. At December 31, 1996, $189.9 million
principal amount of the 1997 Notes was classified as a current liability. 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
the interest accreted with respect to the 1997 Notes and the 9 3/4% Notes
through the dates of retirement.
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 for $100 million. Net proceeds were approximately
$97.7 million after $2.3 million of expenses. The sale resulted in an
aftertax gain of $50.2 million, which will be recorded in the first quarter of
1998. The Company used the proceeds from the sale of the TPC shares and
borrowings under other unsecured credit facilities to repay and terminate its
$125 million unsecured credit facility.
Funding of Capital Expenditures
----------------------------------
The Company's capital expenditures and other capital investments
were $219.2 million, $252.7 million and $178.2 million during the years ended
December 31, 1997, 1996 and 1995, respectively, primarily for exploration and
development of the Cusiana and Cupiagua fields (the "Fields") in Colombia, and
for exploration in Block A-18 of the Malaysia-Thailand Joint Development Area
in the Gulf of Thailand and in other areas. The 1997 capital spending program
and repayment of debt were primarily funded with cash flow from operations
($27.4 million, excluding payment of accreted interest on extinguished debt),
issuance of the Senior Notes, and net borrowings under the Company's credit
facilities ($181 million).
The 1996 capital spending program and repayment of debt were funded
with cash, cash flow from operations ($80.7 million), and proceeds from sales
of marketable securities ($38.5 million) and other assets ($108.1 million).
The 1995 capital spending program was funded with cash flow from operations
(including a forward sale of Cusiana crude oil - $86.6 million), cash,
proceeds from marketable securities ($42.1 million), sales of assets ($20.9
million) and net borrowings ($36.3 million). In May 1995, the Company sold
10.4 million barrels of oil from the Fields in a forward oil sale. Under the
terms of the sale, the Company received approximately $87 million of the
approximately $124 million net proceeds and is entitled to receive
substantially all of the remaining proceeds (now held in various
interest-bearing reserve accounts) when the Company's Cusiana and Cupiagua
fields project becomes self-financing, which is expected in 1998, and when
certain other conditions are met.
Future Capital Needs
----------------------
Development of the Fields, including drilling and construction of
additional production facilities, will require further capital outlays.
Further exploration and development activities on Block A-18 in the
Malaysia-Thailand Joint Development Area in the Gulf of Thailand, as well as
exploratory drilling in other countries, also will require substantial capital
outlays. The Company's capital budget for the year ending December 31, 1998,
is approximately $176 million, excluding capitalized interest, of which
approximately $103 million relates to the Fields, $23 million relates to Block
A-18, and $50 million relates to the Company's activities in other parts of
the world. The 1998 capital budget includes funding requirements for committed
activities only. Substantial capital requirements for Block A-18 are expected
prior to the first deliveries of gas, which are estimated to occur between
30-36 months after signing of a heads of agreement to a gas-sales contract.
The Company expects to fund capital expenditures and repay debt in
the future with a combination of some or all of the following: asset sales
(which may involve interests in material assets), cash flow from operations
(including additional proceeds of $30 million from the 1995 forward oil sale),
cash, credit facilities and additional facilities to be negotiated, and the
issuance of debt and equity securities. Under the most restrictive covenant
in the Company's existing credit facilities, the Company generally could not
permit total indebtedness (as defined in the various agreements) to exceed
$650 million. The limitation on total indebtedness will increase to $725
million once the Fields achieve a production level of 340,000 barrels per day.
At February 28, 1998, the Company had total indebtedness outstanding of
approximately $555 million and available borrowing capacity under unused
credit facilities totaling approximately $45 million. The Company is
currently in negotiations for additional committed bank credit facilities, a
portion of which may be needed to meet the Company's cash needs in 1998.
There can be no assurance that the Company will be able to successfully
negotiate additional credit facilities, and the Company may be required to
seek alternative sources of capital. To facilitate a possible future
securities issuance or issuances, the Company has on file with the Securities
and Exchange Commission a shelf registration statement under which the Company
could issue up to an aggregate of $200 million debt or equity securities.
RESULTS OF OPERATIONS
---------------------
YEAR ENDED DECEMBER 31, 1997,
COMPARED WITH YEAR ENDED DECEMBER 31, 1996
Sales and Other Operating Revenues
--------------------------------------
Sales and other operating revenues were $149.5 million and $134
million in 1997 and 1996, respectively. Revenues in Colombia increased $18.3
million in 1997 due to higher production ($35 million). Revenue barrels in
Colombia, including barrels delivered under the forward oil sale, increased
from 6.4 million barrels in 1996 to 8.2 million barrels in 1997. Volume
increases were partially offset by lower average realized oil prices ($16.8
million) reflecting the increased deliveries under the forward oil sale and a
decrease in the 1997 average West Texas Intermediate ("WTI") oil price,
compared with the prior year. Forward oil sale deliveries, scheduled in 1995
and recorded at $11.56 per barrel, were 29% of sales volumes in 1997, compared
with 10% of the Company's sales volumes in 1996. In April 1997, the Company's
delivery requirement under the forward oil sale increased from 58,425 barrels
per month to 254,136 barrels per month, which had an adverse effect on the
Company's earnings and cash flows on a per-barrel basis during 1997.
Based on the operator's current projections, the Company expects
gross production capacity from the Fields to reach 500,000 barrels per day in
1998. The Company expects that the adverse effect from the forward oil sale
deliveries on the Company's results of operations and cash flows will be
mitigated by increased production from the Fields. There can be no assurance,
however, about the timing of any increase in production.
Subsequent to yearend, the price of oil declined significantly,
which will have a negative effect on earnings and cash flows in the
first-quarter of 1998.
Other operating revenues in 1997 included a gain of $4.1 million
from the sale of the Company's Argentine subsidiary. Other operating revenues
in 1996 included a gain of $4.1 million from the sale of the Company's royalty
interests in U.S. properties.
Costs and Expenses
--------------------
Operating expenses increased $14.7 million in 1997, and
depreciation, depletion and amortization increased $11.2 million, primarily
due to higher production volumes, including barrels delivered under the
forward oil sale. The Company pays lifting costs, production taxes and
transportation costs to the Colombian port of Covenas for barrels to be
delivered under the forward oil sale.
The Company's operating costs per oil equivalent-barrel were $6.47
and $5.77 in 1997 and 1996, respectively. Increased per-barrel costs resulted
from higher OCENSA pipeline tariffs. During 1997, construction of OCENSA's
pipeline system was completed, although its facilities were not utilized to
their capacity due to delays in escalating production in the Fields to 500,000
barrels per day. OCENSA imposes a tariff on shippers from the Fields (the
"Initial Shippers"), which is estimated to recoup: the total capital cost of
the project over a 15-year period; its operating expenses, which include all
Colombian taxes; interest expense; and the dividend to be paid by OCENSA to
its shareholders. Any shippers of crude oil who are not Initial Shippers
("Third Party Shippers") are assessed a tariff on a per-barrel basis, and
OCENSA will use revenues from such tariffs to reduce the Initial Shippers'
tariff.
During 1997 and 1996, the Company paid production taxes on
production from the Cusiana Field totaling $8.5 million, or $1.28 per barrel,
and $8.4 million, or $1.40 per barrel, respectively. Beginning January 1,
1998, no production taxes will be assessed on production from the Cusiana
Field.
General and administrative expenses before capitalization increased
$10.5 million to $61 million in 1997, primarily due to growth of the Company's
operations. Capitalized general and administrative costs were $32.4 million
and $24.6 million in 1997 and 1996, respectively. The increased capitalized
costs reflect the Company's increased exploration activities. At the end of
1997, the Company had licenses to explore for oil and gas on 28 blocks in 12
countries. During 1997, the Company acquired eight new exploration blocks in
five countries, and during 1996, the Company acquired six new exploration
blocks in four countries.
In 1996, the Company's oil and gas properties and other assets in
Argentina were written down $43 million following a review of technical
information that indicated the acreage portfolio did not meet the Company's
exploration objectives.
Other Income and Expenses
----------------------------
Interest expense increased $8 million primarily due to higher
average debt outstanding during 1997. Capitalized interest totaled $25.8
million and $27.1 million in 1997 and 1996, respectively.
Other income in 1997 included a foreign exchange gain of $9.5
million primarily on deferred tax liabilities in Colombia, compared with a
foreign exchange loss of $.6 million in 1996. During 1997 and 1996, the
Company recorded an unrealized gain (loss) of ($9.7 million) and $11 million,
respectively, representing the change in the fair market value of call options
purchased in anticipation of a forward oil sale. Other income in 1996
included a $10.4 million gain on the sale of the Company's shareholdings in
Crusader Limited ("Crusader"), a $7.6 million benefit for settlement of a
lawsuit in which the Company was plaintiff, and a loss provision of $3.2
million for certain legal matters.
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.
The income tax provision for 1997 and 1996 represented current and
deferred taxes in Colombia, deferred taxes on exploration projects throughout
the world, and a deferred tax benefit in the United States related to
anticipated future utilization of NOLs. Subject to the factors described
above, the Company currently expects that its foreign deferred tax provision
will substantially exceed its current tax provision (i.e., actual taxes paid),
resulting in an effective tax for income statement purposes that will exceed
statutory tax rates, at least until the Fields reach peak production. The
primary reason for the expected difference is the nondeductibility for
Colombian tax purposes of certain capital expenses and the treatment of
reimbursements for pre-commerciality costs as a return of capital under
Colombian tax laws. Conversely, Colombian tax law permits the Company to
adjust the tax basis of certain assets based on the Colombian inflation rate
and to include any resulting increases in tax depreciation of the underlying
asset based on rates of production and other factors. The Company's deferred
tax liability has not been reduced to reflect the impact of this inflation
adjustment.
At December 31, 1997, the Company had U.S. NOLs of approximately
$406.8 million, and certain U.S. subsidiaries had separate return limitation
years ("SRLY") operating loss carryforwards of approximately $40.6 million,
compared with NOLs of approximately $230.7 million and SRLY operating loss
carryforwards of $50.9 million at December 31, 1996. During 1997, the Company
amended certain prior-year tax returns that increased the Company's unused
NOLs. The NOLs expire from 1998 to 2013, and the SRLY operating loss
carryforwards expire from 1998 to 2002. See note 10 of Notes to Consolidated
Financial Statements.
The Company recorded a deferred tax asset of $87.1 million, net of a
valuation allowance of $75.1 million at December 31, 1997. The valuation
allowance was primarily attributable to management's assessment of the
utilization of NOLs, SRLY operating losses that are currently not realizable
due to the lack of potential future income in the applicable subsidiaries, and
the expectation that other tax credits will expire without being utilized.
The minimum amount of future taxable income necessary to realize the deferred
tax asset is approximately $249 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 increasing income from its
operations.
The income tax provision for 1997 included foreign deferred taxes
totaling $16 million in 1997, primarily related to the Company's Colombian
operations, compared with foreign deferred taxes of $15.4 million in 1996.
Additionally, the income tax provision included a deferred tax benefit in the
United States totaling $7.9 million, compared with a benefit of $23.5 million
in 1996. Current taxes related to the Company's Colombian operations were
$3.4 million and $5.5 million in 1997 and 1996, respectively.
Extraordinary Item
-------------------
The Company's results of operations for the year ended December 31,
1997, included an extraordinary expense of $14.5 million, net of a $7.8
million tax benefit, associated with extinguishment of the 1997 Notes and the
9 3/4% Notes. During the year ended December 31, 1996, the Company recognized
an extraordinary expense of $1.2 million, net of a $.6 million tax benefit,
resulting from the purchase of $30 million face value of its 1997 Notes.
Subsequent Events
------------------
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 after $2.3 million of
expenses. The sale resulted in an aftertax gain of $50.2 million, which will
be recorded in the first quarter of 1998.
In conjunction with the sale of TPC, the Company entered into a
five-year equity swap with a creditworthy financial institution (the
"Counterparty"). The equity swap has a notional amount of $97 million and
requires the Company to make floating LIBOR-based payments on the notional
amount to the Counterparty. In exchange, the Counterparty is required to make
payments to the Company equivalent to 97% of the dividends TPC receives with
respect to its equity interest in OCENSA. Upon a sale by the Purchaser of the
TPC shares, the Company will receive from the Counterparty, or make a cash
payment to the Counterparty, an amount equal to the excess or deficiency, as
applicable, of the difference between 97% of the net proceeds from the
Purchaser's sale of the TPC shares and the notional amount. The equity swap
will be carried in the Company's financial statements at fair value during the
five-year term. Fluctuations in the fair value of the equity swap will affect
other income as noncash adjustments.
YEAR ENDED DECEMBER 31, 1996,
COMPARED WITH YEAR ENDED DECEMBER 31, 1995
Revenues
--------
Sales and other operating revenues were $134 million and $107.5
million in 1996 and 1995, respectively. Revenues in Colombia increased by
$37.2 million in 1996 due to higher production ($15.7 million) and higher oil
prices ($21.5 million) resulting from more favorable market conditions and
batching of Cusiana crude that began in mid-1995. Revenue barrels in
Colombia, including barrels delivered under the forward oil sale, increased
from 5.5 million barrels in 1995 to 6.4 million barrels in 1996, even though
the Company received .7 million fewer barrels in 1996 as reimbursement of
pre-commerciality costs related to the Cusiana Field. Oil and gas sales from
properties sold in late 1995 and early 1996 aggregated $17 million in 1995,
compared with $2.7 million in 1996.
Other operating revenues in 1996 included a gain of $4.1 million
resulting from the sale of the Company's royalty interests in U.S. properties
for $23.8 million based on an effective date of January 1, 1996.
Costs and Expenses
--------------------
Operating expenses increased $1.4 million in 1996, and depreciation,
depletion and amortization increased $2.4 million. The Company's operating
costs per oil equivalent-barrel were $5.77 and $6.28 in 1996 and 1995,
respectively. Higher production in Colombia increased operating expenses by
$9.9 million and depreciation and depletion by $3.6 million. Operating
expenses from properties sold in late 1995 and early 1996 were $1.8 million
and $10.2 million in 1996 and 1995, respectively.
General and administrative expenses before capitalization increased
$3.8 million in 1996 to $50.5 million, primarily due to greater exploration
activities. Capitalized general and administrative costs were $24.6 million
and $21.1 million in 1996 and 1995, respectively.
Other Income and Expenses
----------------------------
Interest expense before capitalization increased $2.7 million in
1996 to $43 million. Capitalized interest increased from $16.2 million in
1995 to $27.1 million in 1996 due to construction of support equipment and
facilities in the Fields and greater exploration activities throughout the
world.
Other income, net in 1996 included a $10.4 million gain on the sale
of the Company's shareholdings in Crusader, a $7.6 million benefit for
settlement of a lawsuit in which the Company was plaintiff and an $11 million
unrealized gain representing the change in fair market value of the WTI
benchmark call options purchased in 1995. These gains were offset by $3.2
million in loss provisions for certain legal matters. Other income, net in
1995 included $7.2 million received from legal settlements, a $3.5 million
gain on the sale of Triton France and $2.9 million received from the early
redemption of the Crusader convertible notes. These gains were offset by a
$4.2 million unrealized expense representing the change in fair market value
of the WTI benchmark call options.
Income Taxes
-------------
The income tax provision for 1996 decreased primarily due to the
recognition of a deferred tax benefit in the United States totaling $23.5
million related to anticipated future utilization of NOLs, compared with a
similar benefit of $12.8 million in 1995. Foreign current tax expense of $5.4
million in 1996 increased $1.4 million from 1995, mainly due to increased
profitability from the Company's Colombian operations. Foreign deferred tax
expense of $15.4 million in 1996 decreased $2.9 million from 1995, primarily
due to the writedown of the Company's Argentine assets, which lowered taxes by
$3.7 million in 1996 compared with 1995.
Discontinued Operations
------------------------
The results of operations for the aviation sales and services
segment have been reported as discontinued operations. In June 1995, the
Company sold the assets of its subsidiary, Jet East, Inc., for $2.9 million in
cash and a note, and realized a loss of $1.4 million on the sale. The Company
accrued $.6 million for costs associated with final disposal of the segment,
which occurred in August 1995.
Petroleum Price 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 may also enter into financial
market transactions to benefit from its assessment of the future prices of its
production relative to other benchmark prices. There can be no assurance that
the use of financial market transactions will not result in losses.
In anticipation of entering into a forward oil sale, the Company
purchased WTI benchmark call options to retain the ability to benefit from
future 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. During the years
ended December 31, 1997, 1996 and 1995, the Company recorded an unrealized
gain (loss) of ($9.7 million), $11 million and ($4.2 million), respectively,
in other income, net related to the change in the fair market value of the
call options. Future fluctuations in the fair market value of the call
options will continue to affect other income as noncash adjustments.
During the year ended December 31, 1997, markets provided the
Company the opportunity to realize WTI benchmark oil prices on average $2.35
per barrel above the WTI benchmark oil price the Company set as part of its
1997 annual plan. As a result of financial and commodity market transactions
settled during the year ended December 31, 1997, the Company's risk management
program resulted in an average net realization of approximately $.11 per
barrel lower than if the Company had not entered into such transactions.
International Operations
------------------------
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, 1997, the Company did not realize any material
foreign exchange losses from its international operations.
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 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. Financial information concerning
the Company's assets, 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. Also, the Company may remain liable for certain environmental matters
that may arise from formerly owned fuel businesses. 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 and Disclosure Pronouncements
-----------------------------------------------
In January 1997, the Securities and Exchange Commission issued
"Disclosure of Accounting Policies for Derivative Financial Instruments and
Derivative Commodity Instruments and Disclosure of Quantitative and
Qualitative Information about Market Risk Inherent in Derivative Financial
Instruments, Other Financial Instruments, and Derivative Commodity
Instruments." The rule amends and expands existing disclosure requirements to
include quantitative and qualitative information about market risks inherent
in market-risk sensitive instruments, including derivative financial
instruments, other financial instruments and derivative commodity financial
instruments. The Company is required to adopt the disclosure requirements for
quantitative and qualitative information beginning with filings with the
Commission that include the Company's annual financial statements for the year
ended December 31, 1998. The required quantitative and qualitative
information must be disclosed outside the financial statements and related
notes thereto.
In 1997, the Financial Accounting Standards Board issued Statement
No. 128 ("SFAS 128"), "Earnings Per Share." This Statement is effective for
financial statements issued for periods ending after December 15, 1997. SFAS
128 requires the presentation of basic and diluted earnings per share for
entities with complex capital structures. Prior-year earnings per share
amounts have been restated to conform with SFAS 128.
In June 1997, the Financial Accounting Standards Board issued
Statement No. 130 ("SFAS 130"), "Reporting Comprehensive Income."
Comprehensive income includes net income and several other items that current
accounting standards require to be recognized outside of net income. This
standard established standards for 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. SFAS 130 is effective for fiscal years
beginning after December 15, 1997, and the Company will adopt the standard for
its fiscal year beginning January 1, 1998. This statement will not have any
effect on the Company's results of operations or financial position.
In June 1997, the Financial Accounting Standards Board issued
Statement No. 131 ("SFAS 131"), "Disclosures about Segments of an Enterprise
and Related Information," replacing Statement No. 14 and its amendments. This
standard requires enterprises to report certain information about operating
segments in annual financial statements to shareholders. Additionally, it
requires that enterprises report selected information about operating segments
in interim financial reports issued to shareholders. The basis for
determining an enterprise's operating segments is the manner in which
financial information is used internally by the enterprise's chief operating
decision maker. SFAS 131 is effective for fiscal years beginning after
December 15, 1997, and the Company intends to adopt the standard in fiscal
year 1998. This statement will not have any effect on the Company's results
of operations or financial position.
Information Systems and the Year 2000
-------------------------------------
The Company has reviewed its operational, financial and other
information systems for potential conflicts with the Year 2000. The Company
believes that the Year 2000 will not cause any significant disruptions to its
information systems, and any costs to resolve Year 2000 issues will not be
material.
The Company has begun an investigation into the potential impact to
its operations caused by Year 2000 problems that may occur at third parties,
including its oil and gas partners, financial institutions, and vendors. The
Company has identified certain third parties that may encounter Year 2000
problems, but has not yet determined the potential impact to the Company's
operations or the costs to the Company, if any, associated with these issues.
The Company intends to engage a third-party Year 2000 consultant in 1998 to
validate the Company's assumptions and identify nonconformance.
Certain Factors that Could Affect Future Operations
-------------------------------------------------
Certain statements in this report, including expectations,
intentions, plans and beliefs of the Company and management, are
forward-looking statements, as defined in Section 21D of the Securities
Exchange Act of 1934, that are dependent on certain events, risks and
uncertainties that may be outside the Company's control. These
forward-looking statements include statements of management's plans and
objectives for the Company's future operations and statements of future
economic performance; information regarding drilling schedules and schedules
for the start-up of production facilities; expected or planned production or
transportation capacity; when the Fields might become self-financing; future
production of the Fields; the negotiation of a heads of agreement to a
gas-sales contract and a gas-sales contract and commencement of production in
Malaysia-Thailand; the Company's capital budget and future capital
requirements; the Company's meeting its future capital needs; the amount by
which production from the Fields may increase or when such increased
production may commence; the Company's realization of its deferred tax asset;
the level of future expenditures for environmental costs; the outcome of
regulatory and litigation matters; the impact of Year 2000 issues; and proven
oil and gas reserves and discounted future net cash flows therefrom; and the
assumptions described in this report underlying such forward-looking
statements. Actual results and developments could differ materially from
those expressed in or implied by such statements due to a number of factors,
including those described in the context of such forward-looking statements
and in notes 19 and 20 of Notes to Consolidated Financial Statements.
ITEM 7. A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
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 1998 Annual Meeting of Shareholders of the Company
(the "Proxy Statement"), specifically the discussion under the heading
"Election of Directors." It is currently anticipated that the Proxy Statement
will be publicly available and mailed in April 1998. 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 "Voting and Principal Shareholders" in the
Proxy Statement is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The discussion under "Management Compensation" 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.(1)
3.2 Articles of Association.(1)
4.1 Specimen Share Certificate of Ordinary Shares, $.01 par value, of the Company.(2)
4.2 Rights Agreement dated as of March 25, 1996, between Triton and Chemical Bank, as
Rights Agent, including, as Exhibit A thereto, Resolutions establishing the Junior
Preference Shares.(1)
4.3 Resolutions Authorizing the Company's 5% Convertible Preference Shares.(3)
4.4 Amendment No. 1 to Rights Agreement dated as of August 2, 1996, between Triton and
Chemical Bank, as Rights Agent.(4)
10.1 Amended and Restated Retirement Income Plan.(5)(23)
10.2 Amended and Restated Supplemental Executive Retirement Income Plan.(23)(24)
10.3 1981 Employee Non-Qualified Stock Option Plan.(6)(23)
10.4 Amendment No. 1 to the 1981 Employee Non-Qualified Stock Option Plan.(7)(23)
10.5 Amendment No. 2 to the 1981 Employee Non-Qualified Stock Option Plan.(6)(23)
10.6 Amendment No. 3 to the 1981 Employee Non-Qualified Stock Option Plan.(5)(23)
10.7 1985 Stock Option Plan.(8)(23)
10.8 Amendment No. 1 to the 1985 Stock Option Plan.(6)(23)
10.9 Amendment No. 2 to the 1985 Stock Option Plan.(5)(23)
10.10 Amended and Restated 1986 Convertible Debenture Plan.(5)(23)
10.11 1988 Stock Appreciation Rights Plan.(9)(23)
10.12 1989 Stock Option Plan.(10)(23)
10.13 Amendment No. 1 to 1989 Stock Option Plan.(6)(23)
10.14 Amendment No. 2 to 1989 Stock Option Plan.(5)(23)
10.15 Second Amended and Restated 1992 Stock Option Plan.(11)(23)
10.16 Form of Amended and Restated Employment Agreement with Triton Energy Limited
and its executive officers.(23)(24)
10.17 Form of Amended and Restated Employment Agreement with Triton Energy Limited
and certain officers.(23)(24)
10.18 Amended and Restated 1985 Restricted Stock Plan.(5)(23)
10.19 First Amendment to Amended and Restated 1985 Restricted Stock Plan.(13)(23)
10.20 Second Amendment to Amended and Restated 1985 Restricted Stock Plan.(11)(23)
10.21 Executive Life Insurance Plan.(14)(23)
10.22 Long Term Disability Income Plan.(14)(23)
10.23 Amended and Restated Retirement Plan for Directors.(8)(23)
10.24 Amended and Restated Indenture dated as of March 25, 1996 between Triton and
Chemical Bank, with respect to the issuance of Senior Subordinated Discount Notes
due 1997.(11)
10.25 Amended and Restated Senior Subordinated Indenture by and between the Company and
United States Trust Company of New York, dated as of March 25, 1996.(11)
10.26 Contract for Exploration and Exploitation for Santiago de Atalayas I with an effective
date of July 1, 1982, between Triton Colombia, Inc., and Empresa Colombiana
De Petroleos.(8)
10.27 Contract for Exploration and Exploitation for Tauramena with an effective date of July
4, 1988, between Triton Colombia, Inc., and Empresa Colombiana De Petroleos.(9)
10.28 Summary of Assignment legalized by Public Instrument No. 1255 dated September 15,
1987 (Assignment is in Spanish language).(9)
10.29 Summary of Assignment legalized by Public Instrument No. 1602 dated June 11, 1990
(Assignment is in Spanish language).(9)
10.30 Summary of Assignment legalized by Public Instrument No. 2586 dated September 9,
1992 (Assignment is in Spanish language).(9)
10.31 401(K) Savings Plan.(5)(23)
10.32 Contract between Malaysia-Thailand and Joint Authority and Petronas Carigali
SDN.BHD.and Triton Oil Company of Thailand relating to Exploration and Production
of Petroleum for Malaysia-Thailand Joint Development Area Block A-18.(15)
10.33 Triton Crude Purchase Agreement between Triton Colombia, Inc. and Oil Co., LTD.
dated May 25, 1995.(16)
10.34 Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation,
NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States.(13)
10.35 Amendment No. 1 to Credit Agreement among Triton Colombia, Inc., Triton Energy
Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
States.(13)
10.36 Amendment No. 2 to Credit Agreement among Triton Colombia, Inc., Triton Energy
Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
States.(11)
10.37 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.(24)
10.38 Agreement and Plan of Merger among Triton Energy Corporation, Triton Energy
Limited and TEL Merger Corp.(13)
10.39 Credit Agreement among Triton Energy Limited and Triton Energy Corporation, as
Borrowers, and NationsBank of Texas, N.A., Barclays Bank PLC, Meespierson N.V.,
The Chase Manhattan Bank and Societe Generale, Southwest Agency dated
August 30, 1996.(17)
10.40 Form of Indemnity Agreement entered into with each director and officer of the
Company.(17)
10.41 Restated Employment Agreement between John Tatum and the Company. (12)(23)
10.42 Description of Performance Goals for Executive Bonus Compensation. (12)(23)
10.43 Stock Purchase Agreement dated September 2, 1997 between The Strategic
Transaction Company and Triton International Petroleum, Inc. ( 24)
10.44 Fourth Amendment to Stock Purchase Agreement dated February 2, 1998 between
The Strategic Transaction Company and Triton International Petroleum, Inc. (24 )
10.45 Supplemental Indenture dated April 17, 1997 among Triton Energy Corporation
Triton Energy Limited and The Chase Manhattan Bank (formerly known as
Chemical Bank) amending Amended and Restated Indenture dated as of March 25, 1996
relating to the Senior Subordinated Discount Notes due 1997. (18)
10.46 Supplemental Indenture dated April 17, 1997 among Triton Energy Corporation,
Triton Energy Limited and United States Trust Company of New York amending
Amended and Restated Senior Subordinated Indenture dated as of March 25,
1996 relating to the 9 3/4% Senior Subordinated Discount Notes due 2000. (18)
10.47 Senior Indenture dated April 10, 1997 among Triton Energy Limited and The
Chase Manhattan Bank. (18)
10.48 First Supplemental Indenture dated April 10, 1997 among Triton Energy Corporation,
Triton Energy Limited and The Chase Manhattan Bank amending Senior
Indenture dated as of April 10, 1997 relating to the 8 3/4% Senior
Notes due 2002. (18)
10.49 Second Supplemental Indenture dated April 10, 1997 among Triton Energy Corporation,
Triton Energy Limited and The Chase Manhattan Bank amending Senior
Indenture dated as of April 10, 1997 relating to the 9 1/4% Senior Notes
due 2005. (18)
10.50 First Amendment to Credit Agreement dated as of April 4, 1997 among Triton
Energy Limited and Triton Energy Corporation, as Borrowers, and
NationsBank of Texas, N.A., Barclays Bank PLC, Meespierson N.V., The
Chase Manhattan Bank and Societe Generale, Southwest Agency. (18)
10.51 1997 Share Compensation Plan. (18)(23)
10.52 First Amendment to 1997 Share Compensation Plan. (23 )(24)
10.53 First Amendment to Amended and Restated Retirement Plan for Directors.(23)(24)
10.54 First Amendment to Second Amended and Restated 1992 Stock Option Plan. (18)(23)
10.55 Second Amendment to Second Amended and Restated 1992 Stock Option Plan. (23)(24)
10.56 Agreement to Release Triton Energy Corporation and Second Amendment
to Credit Agreement dated as of July 21, 1997 among Triton Energy Limited
and Triton Energy Corporation, as Borrowers, and NationsBank of Texas,
N.A., Barclays Bank PLC, MeesPierson N.V., The Chase Manhattan Bank
and Societe Generale, Southwest Agency. (19)
10.57 Amended and Restated Indenture dated July 25, 1997 between Triton Energy
Limited and The Chase Manhattan Bank. (19)
10.58 Amended and Restated First Supplemental Indenture dated July 25, 1997
between Triton Energy Limited and The Chase Manhattan Bank relating
to the 8 3/4% Senior Notes due 2002. (19)
10.59 Amended and Restated Second Supplemental Indenture dated July 25, 1997
between Triton Energy Limited and The Chase Manhattan Bank relating
to the 9 1/4% Senior Notes due 2005. (19)
10.60 Third Amendment to Credit Agreement dated as of September 30, 1997
among Triton Energy Limited, NationsBank of Texas, N.A., Barclays Bank PLC,
MeesPierson N.V., The Chase Manhattan Bank and Societe Generale,
Southwest Agency. (20)
12.1 Computation of Ratio of Earnings to Fixed Charges. (24)
12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preference
Dividends(24)
21.1 Subsidiaries of the Company.(24)
23.1 Consent of Price Waterhouse LLP.(24)
23.2 Consent of DeGolyer and MacNaughton.(24)
24.1 The power of attorney of officers and directors of the Company (set forth on the
signature page hereof).(24)
27.1 Financial Data Schedule.(24)
99.1 Rio Chitamena Association Contract.(21)
99.2 Rio Chitamena Purchase and Sale Agreement.(21)
99.3 Integral Plan - Cusiana Oil Structure.(21)
99.4 Letter Agreements with co-investor in Colombia.(21)
99.5 Colombia Pipeline Memorandum of Understanding.(21)
99.6 Amended and Restated Oleoducto Central S.A. Agreement dated as of March 31,
1995.(22)
____________________
(1) Previously filed as an exhibit to the Company's Registration Statement on Form S-3
(No 333-08005) and incorporated herein by reference.
(2) Previously filed as an exhibit to the Company's Registration Statement on Form 8-A
dated March 25, 1996 and incorporated herein by reference.
(3) Previously filed as an exhibit to the Company's and Triton Energy Corporation's
Registration Statement on Form S-4 (No. 333-923) and incorporated herein
by reference.
(4) Previously filed as an exhibit to the Company's Registration Statement on Form 8-A/A
(Amendment No. 1) dated August 14, 1996 and incorporated herein by reference.
(5) Previously filed as an exhibit to Triton Energy Corporation's Quarterly Report on Form
10-Q for the quarter ended November 30, 1993 and incorporated by reference herein.
(6) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended May 31, 1992 and incorporated herein by reference.
(7) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended May 31, 1989 and incorporated by reference herein.
(8) 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.
(9) 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.
(10) 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.
(11) 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.
(12) 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.
(13) 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.
(14) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended May 31, 1991 and incorporated herein by reference.
(15) Previously filed as an exhibit to Triton Energy Corporation's current report on Form
8-K dated April 21, 1994 and incorporated by reference herein.
(16) Previously filed as an exhibit to Triton Energy Corporation's Current Report on Form
8-K dated May 26, 1995 and incorporated herein by reference.
(17) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1996 and incorporated herein by reference.
(18) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1997 and incorporated herein by reference.
(19) 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.
(20) Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1997 and incorporated herein by reference.
(21) Previously filed as an exhibit to Triton Energy Corporation's current report on Form
8-K/A dated July 15, 1994 and incorporated by reference herein.
(22) 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.
(23) Management contract or compensatory plan or arrangement.
(24) Filed herewith.
(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 Annual Report on
Form 10-K to be signed by the undersigned thereunto duly authorized on the 27
day of March, 1998.
TRITON ENERGY LIMITED
By: /s/Thomas G. Finck
------------------------
Thomas G. Finck
Chairman of the Board and Chief Executive
Officer
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and
directors of Triton Energy Limited (the "Company") hereby constitutes and
appoints Thomas G. Finck, Robert B. Holland, III, and Peter Rugg, or any of
them ( with full power to each of them to act alone), his true and lawful
attorney-in-fact and agent, with full power of substitution, for him and on
his behalf and in his name, place and stead, in any and all capacities, to
sign, execute, and file any and all documents relating to the Company's Annual
Report on Form 10-K for the year ended December 31, 1997, including any and
all amendments and supplements thereto, with any regulatory authority,
granting unto said attorneys, and each of them, full power and authority to do
and perform each and every act and thing requisite and necessary to be done in
and about the premises in order to effectuate the same as fully to all intents
and purposes as he himself might or could do if personally present, hereby
ratifying and confirming all that said attorneys-in-fact and agents, or any of
them, or their or his substitute or substitutes, may lawfully do or cause to
be done.
Pursuant to the requirements of the Securities Exchange Act of 1934, this
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 27 day of
March, 1998.
Signatures Title
---------- -----
/s/Thomas G. Finck Chairman of the Board and Chief
- ------------------------------------- Financial Officer
Thomas G. Finck
/s/Peter Rugg Senior Vice President and
- ------------------------------------- Chief Financial Officer
Peter Rugg (Principal Accounting and
Financial Officer)
/s/John P. Lewis Director March 17, 1998
- -------------------------------------
John P. Lewis
/s/Michael E. McMahon Director March 17, 1998
- -------------------------------------
Michael E. McMahon
/s/Ernest E. Cook Director March 17, 1998
- -------------------------------------
Ernest E. Cook
/s/Sheldon R. Erikson Director March 17, 1998
- -------------------------------------
Sheldon R. Erikson
/s/Jesse E. Hendricks Director March 17, 1998
- ---------------------------------------
Jesse E. Hendricks
/s/Fitzgerald S. Hudson Director March 17, 1998
- ---------------------------------------
Fitzgerald S. Hudson
/s/John R. Huff Director March 17, 1998
- ---------------------------------------
John R. Huff
/s/Thomas P. Kellogg, Jr. Director March 17, 1998
- ---------------------------------------
Thomas P. Kellogg, Jr.
/s/Edwin D. Williamson Director March 17, 1998
- ---------------------------------------
Edwin D. Williamson
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, 1997, 1996
and 1995 F-3
Consolidated Balance Sheets - December 31, 1997 and 1996 F-4
Consolidated Statements of Cash Flows - Years ended December 31, 1997, 1996
and 1995 F-5
Consolidated Statements of Shareholders' Equity - Years ended December 31, 1997,
1996 and 1995 F-6
Notes to Consolidated Financial Statements F-7
SCHEDULE:
II - Valuation and Qualifying Accounts - Years ended December 31, 1997,
1996 and 1995 F-47
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, 1997
and 1996, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1997, in conformity with
generally accepted accounting principles. 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 generally accepted auditing
standards 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.
Price Waterhouse LLP
Dallas, Texas
February 5, 1998
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
---------- --------- ---------
SALES AND OTHER OPERATING REVENUES:
Oil and gas sales $ 145,419 $129,795 $106,844
Other operating revenues 4,077 4,182 628
---------- --------- ---------
149,496 133,977 107,472
---------- --------- ---------
COSTS AND EXPENSES:
Operating 51,357 36,654 35,276
General and administrative 28,607 25,945 25,672
Depreciation, depletion and amortization 36,828 25,640 23,208
Writedown of assets --- 42,960 ---
---------- --------- ---------
116,792 131,199 84,156
---------- --------- ---------
OPERATING INCOME 32,704 2,778 23,316
Interest income 5,178 6,703 7,954
Interest expense, net (23,858) (15,897) (24,055)
Other income, net 2,872 27,361 9,385
---------- --------- ---------
(15,808) 18,167 (6,716)
---------- --------- ---------
EARNINGS FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES AND EXTRAORDINARY ITEM 16,896 20,945 16,600
Income tax expense (benefit) 11,301 (2,860) 10,059
---------- --------- ---------
5,595 23,805 6,541
DISCONTINUED OPERATIONS:
Loss from operations --- --- (1,858)
Loss on disposal --- --- (1,963)
---------- --------- ---------
EARNINGS BEFORE EXTRAORDINARY ITEM 5,595 23,805 2,720
Extraordinary item - extinguishment of debt (14,491) (1,196) ---
---------- --------- ---------
NET EARNINGS (LOSS) (8,896) 22,609 2,720
DIVIDENDS ON PREFERENCE SHARES 400 985 802
---------- --------- ---------
EARNINGS (LOSS) APPLICABLE TO ORDINARY SHARES $ (9,296) $ 21,624 $ 1,918
---------- --------- ---------
Average ordinary shares outstanding 36,471 35,929 35,147
---------- --------- ---------
BASIC EARNINGS (LOSS) PER ORDINARY SHARE:
Continuing operations $ 0.14 $ 0.64 $ 0.16
Discontinued operations --- --- (0.11)
Extraordinary item (0.40) (0.03) ---
---------- --------- ---------
NET EARNINGS (LOSS) $ (0.26) $ 0.61 $ 0.05
---------- --------- ---------
DILUTED EARNINGS (LOSS) PER ORDINARY SHARE:
Continuing operations $ 0.14 $ 0.62 $ 0.16
Discontinued operations --- --- (0.11)
Extraordinary item (0.39) (0.03) ---
---------- --------- ---------
NET EARNINGS (LOSS) $ (0.25) $ 0.59 $ 0.05
---------- --------- ---------
See accompanying Notes to Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
ASSETS DECEMBER 31,
------------------------
1997 1996
------------ ----------
CURRENT ASSETS:
Cash and equivalents $ 13,451 $ 11,048
Short-term marketable securities --- 3,866
Trade receivables, net 12,963 11,526
Other receivables 52,162 49,000
Inventories, prepaid expenses and other 5,219 8,920
Assets held for sale 58,178 ---
------------ ----------
TOTAL CURRENT ASSETS 141,973 84,360
Property and equipment, at cost, net 835,506 676,833
Deferred income taxes 87,148 71,416
Investments and other assets 33,412 81,915
------------ ----------
$ 1,098,039 $ 914,524
------------ ----------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt $ 130,375 $ 199,552
Short-term borrowings 54,600 ---
Accounts payable and accrued liabilities 36,964 38,545
Deferred income 35,254 28,466
------------ ----------
TOTAL CURRENT LIABILITIES 257,193 266,563
Long-term debt, excluding current maturities 443,312 217,078
Deferred income taxes 50,968 45,431
Deferred income and other 49,946 84,808
Convertible debentures due to employees --- ---
SHAREHOLDERS' EQUITY:
Preference shares, par value $.01; authorized
20,000,000 shares; issued 218,285 and 247,469
shares at December 31, 1997 and 1996, respectively;
stated value $34.41 7,511 8,515
Ordinary shares, par value $.01; authorized
200,000,000 shares; issued 36,541,064 and
36,342,181 shares at December 31, 1997 and
1996, respectively 365 363
Additional paid-in capital 588,454 582,581
Accumulated deficit (297,581) (288,685)
Other (2,126) (2,128)
------------ ----------
296,623 300,646
Less cost of ordinary shares in treasury 3 2
------------ ----------
TOTAL SHAREHOLDERS' EQUITY 296,620 300,644
Commitments and contingencies (note 20) --- ---
------------ ----------
$ 1,098,039 $ 914,524
------------ ----------
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,
------------------------------------
1997 1996 1995
------------ ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ (8,896) $ 22,609 $ 2,720
Adjustments to reconcile net earnings to net cash provided
(used) by operating activities:
Depreciation, depletion and amortization 36,828 25,640 23,467
Amortization of debt discount 7,949 15,897 23,928
Proceeds from forward oil sale --- --- 86,610
Amortization of deferred income (28,467) (8,105) (4,725)
Gain on sale of assets, net (5,486) (15,831) (2,938)
Payment of accreted interest on extinguishment of debt (124,794) --- ---
Extraordinary loss on extinguishment of debt, net of tax 14,491 1,196 ---
Writedowns, loss provisions and discontinued operations --- 45,753 7,192
Deferred income taxes 8,078 (8,115) 5,444
Other, net 6,100 (7,655) (536)
Changes in working capital:
Marketable debt securities - trading 1,856 4,149 8,074
Receivables (2,408) (5,048) (1,677)
Inventories, prepaid expenses and other (62) (787) (790)
Accounts payable and accrued liabilities (2,605) 11,002 2,325
------------ ---------- ----------
Net cash provided (used) by operating activities (97,416) 80,705 149,094
------------ ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures and investments (219,216) (252,684) (178,161)
Purchases of investments and marketable securities --- --- (45,281)
Proceeds from sale of investments and marketable securities 2,000 38,507 42,050
Proceeds from sale of shareholdings in Crusader --- 69,583 ---
Sales of property and equipment and other assets 5,899 38,505 20,866
Other (1,383) 571 732
------------ ---------- ----------
Net cash used by investing activities (212,700) (105,518) (159,794)
------------ ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving lines of credit and long-term debt 620,413 53,911 85,627
Payments on revolving lines of credit and long-term debt (321,515) (70,884) (39,366)
Short-term notes payable, net 9,600 --- (10,000)
Issuance of ordinary shares 5,260 5,874 8,398
Other (390) (1,879) (5,756)
------------ ---------- ----------
Net cash provided (used) by financing activities 313,368 (12,978) 38,903
------------ ---------- ----------
Effects of exchange rate changes on cash and equivalents (849) (211) (1,494)
------------ ---------- ----------
Net increase (decrease) in cash and equivalents 2,403 (38,002) 26,709
CASH AND EQUIVALENTS AT BEGINNING OF YEAR 11,048 49,050 22,341
------------ ---------- ----------
CASH AND EQUIVALENTS AT END OF YEAR $ 13,451 $ 11,048 $ 49,050
------------ ---------- ----------
See accompanying Notes to Consolidated Financial Statements.
TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
-----------------------------------
1997 1996 1995
----------- ---------- ----------
PREFERENCE SHARES:
Balance at beginning of year $ 8,515 $ 14,109 $ 17,976
Conversion of 5% preference shares (1,004) (5,594) (3,867)
----------- ---------- ----------
Balance at end of year 7,511 8,515 14,109
----------- ---------- ----------
ORDINARY SHARES:
Balance at beginning of year 363 35,927 35,577
Exercise of employee stock options and debentures 2 81 238
Conversion of 5% preference shares --- 153 112
Reduction in par value --- (35,783) ---
Other, net --- (15) ---
----------- ---------- ----------
Balance at end of year 365 363 35,927
----------- ---------- ----------
ADDITIONAL PAID-IN CAPITAL:
Balance at beginning of year 582,581 516,326 505,256
Cash dividends, 5% preference shares (400) (985) (802)
Exercise of employee stock options and debentures 3,831 7,974 8,160
Issuances under stock plans 1,427 702 313
Conversion of 5% preference shares 1,004 5,441 3,755
Reduction in par value --- 35,783 ---
Sale of shareholdings in Crusader --- 20,413 ---
Other, net 11 (3,073) (356)
----------- ---------- ----------
Balance at end of year 588,454 582,581 516,326
----------- ---------- ----------
ACCUMULATED DEFICIT:
Balance at beginning of year (288,685) (311,294) (314,014)
Net earnings (loss) (8,896) 22,609 2,720
----------- ---------- ----------
Balance at end of year (297,581) (288,685) (311,294)
----------- ---------- ----------
FOREIGN CURRENCY TRANSLATION ADJUSTMENT:
Balance at beginning of year (2,126) (8,616) (5,639)
Sale of foreign operations --- --- (3,268)
Sale of shareholdings in Crusader --- 4,890 ---
Translation rate changes --- 1,600 291
----------- ---------- ----------
Balance at end of year (2,126) (2,126) (8,616)
----------- ---------- ----------
OTHER, NET:
Balance at beginning of year (2) (89) (1,384)
Valuation reserve on marketable securities 2 87 1,295
----------- ---------- ----------
Balance at end of year --- (2) (89)
----------- ---------- ----------
TREASURY SHARES:
Balance at beginning of year (2) (338) (577)
Purchase of treasury shares (1) (5) (4)
Transfer of shares to employee benefit plans --- 137 243
Retirement of treasury shares --- 204 ---
----------- ---------- ----------
Balance at end of year (3) (2) (338)
----------- ---------- ----------
TOTAL SHAREHOLDERS' EQUITY $ 296,620 $ 300,644 $ 246,025
----------- ---------- ----------
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 and Malaysia-Thailand. The Company is
actively exploring for oil and gas in these areas, as well as in southern
Europe, Africa, Asia and the Middle East. All sales 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
in 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 AND MARKETABLE SECURITIES
Cash equivalents are highly liquid investments purchased with an original
maturity of three months or less.
Investments in marketable debt securities are reported at fair value except
for those investments that management has the positive intent and the ability
to hold to maturity. Investments available-for-sale are classified based on
the stated maturity of the securities, and changes in fair value are reported
as a separate component of shareholders' equity. Trading investments are
classified as current regardless of the stated maturity of the underlying
securities, and changes in fair value are reported in other income, net.
Investments that will be held to maturity are classified based on the stated
maturity of the securities.
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, aircraft 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 yearend. 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
Oil and gas revenues are recognized at the point of first measurement after
production, which is generally upon delivery into field storage
tank/processing facilities or pipelines. 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, except for foreign operations of certain affiliates where
the local currencies are used as the functional currency. The cumulative
translation effects from translating balance sheet accounts from the
functional currency into U.S. dollars at current exchange rates are included
as a separate component of shareholders' equity.
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 may also enter
into financial market transactions to benefit from its assessment of the
future prices of its production relative to other benchmark prices.
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, 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.
The Company occasionally enters into foreign exchange contracts to reduce risk
of unfavorable exchange-rate movements. The gains or losses arising from
currency exchange contracts offset foreign exchange gains or losses on the
underlying assets or liabilities or are deferred and offset against the
carrying value of the firm commitment.
DISCONTINUED OPERATIONS AND RECLASSIFICATIONS
The results of operations for the Company's aviation sales and services
segment in 1995 have been reported as discontinued operations.
Certain other previously reported financial information has been reclassified
to conform to the current period's presentation.
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
In 1997, the Financial Accounting Standards Board issued Statement No. 128
("SFAS 128"), "Earnings Per Share." This Statement is effective for financial
statements issued for periods ending after December 15, 1997. SFAS 128
requires the presentation of basic and diluted earnings per share for entities
with complex capital structures. Prior-year earnings per share amounts have
been restated to conform with SFAS 128.
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.
Prior to the Company's sale of its investment in Crusader Limited ("Crusader")
in July 1996, the Company's proportionate shares owned by Crusader were not
considered outstanding for purposes of determining weighted average number of
shares outstanding. Diluted earnings (loss) per ordinary share is calculated
to show earnings per share assuming 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.
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.
2. DIVESTITURES AND DISCONTINUED OPERATIONS
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 other operating
revenues.
In June and July 1996, the Company sold its 49.9% shareholdings in Crusader
for total cash proceeds of $69.6 million in conjunction with a May 1996
takeover bid for the outstanding shares of Crusader. The Company recorded a
total gain of $10.4 million in other income, net, and an increase to
additional paid-in capital of $20.4 million, representing the Company's
proportion of Triton ordinary shares owned by Crusader that were previously
treated as Triton owned.
In March 1996, the Company sold its royalty interests in U.S. properties for
$23.8 million based on an effective date of January 1, 1996. The Company
recorded the resulting gain of $4.1 million in other operating revenues.
In August 1995, the Company sold Triton France S.A. The Company received net
proceeds, including repayment of intercompany debt, of approximately $16
million and recorded a net gain of $3.5 million and a reduction in
shareholders' equity of approximately $3.3 million for the foreign currency
translation adjustment.
In June 1995, the Company sold the assets of its subsidiary, Jet East, Inc.,
for $2.9 million in cash and a note, and realized a loss of $1.4 million on
the sale. The Company accrued $.6 million for costs associated with final
disposal of the segment, which occurred in August 1995. Revenues and net loss
for the aviation sales and services segment during the year ended December 31,
1995, were $4.7 million and $2 million, respectively.
3. FORWARD SALE OF COLOMBIAN OIL PRODUCTION
In May 1995, the Company sold 10.4 million barrels of oil from the Cusiana and
Cupiagua fields (the "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 and is entitled to receive
substantially all of the remaining proceeds (now held in various
interest-bearing reserve accounts) when the Company's Cusiana and Cupiagua
fields project becomes self-financing, which is expected in 1998, and when
certain other conditions are met. At December 31, 1997, proceeds held in
interest-bearing reserve accounts of $31.8 million and $3 million have been
recorded as current and long-term receivables, respectively. The Company has
recorded the net proceeds as deferred income and will recognize such revenue
when the barrels of oil are delivered during a 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.
4. OTHER RECEIVABLES
Other receivables consisted of the following:
DECEMBER 31,
----------------
1997 1996
------- -------
Receivable from the forward oil sale $31,770 $30,000
Receivable from partners 11,152 5,371
Central Llanos pipeline upgrade receivable --- 6,380
Other 9,240 7,249
------- -------
$52,162 $49,000
------- -------
5. ASSETS HELD FOR SALE
Assets held for sale consisted of the following:
DECEMBER 31,
1997
-------------
Investment in OCENSA $ 47,429
Corporate assets 10,749
-------------
$ 58,178
-------------
The Company's wholly owned subsidiary, Triton Pipeline Colombia, Inc. ("TPC"),
owns the Company's 9.6% equity interest in Oleoducto Central S.A. ("OCENSA").
See note 22 - Subsequent Events.
6. PROPERTY AND EQUIPMENT
Property and equipment, at cost, are summarized as follows:
DECEMBER 31,
-----------------
1997 1996
-------- --------
Oil and gas properties, full cost method:
Evaluated $518,580 $465,097
Unevaluated 130,626 82,997
Support equipment and facilities 250,193 194,116
Other 25,121 31,044
-------- --------
924,520 773,254
Less accumulated depreciation and depletion 89,014 96,421
-------- --------
$835,506 $676,833
-------- --------
The Company capitalizes interest on qualifying assets, principally unevaluated
oil and gas properties and major development projects in progress.
Capitalized interest amounted to $25.8 million, $27.1 million and $16.2
million in the years ended December 31, 1997, 1996 and 1995, respectively.
The Company capitalized general and administrative expenses related to
exploration and development activities of $32.4 million, $24.6 million and
$21.1 million in the years ended December 31, 1997, 1996 and 1995,
respectively.
Evaluated oil and gas properties and accumulated depreciation and depletion
were reduced by $40 million each in 1997 due to the Company's sale of Triton
Argentina, Inc. In 1996, evaluated oil and gas properties and accumulated
depreciation and depletion were reduced by $246.9 million and $228.3 million,
respectively, due to the sales of the Company's royalty interests in U.S.
properties and the assets of Triton Indonesia, Inc.
7. INVESTMENTS AND OTHER ASSETS
Investments and other assets consisted of the following:
DECEMBER 31,
----------------
1997 1996
------- -------
Investment in OCENSA $ --- $34,311
Investment in ODC 11,108 11,108
WTI benchmark call options 2,678 11,048
Unamortized debt issue costs 2,538 6,878
Receivable from the forward oil sale 3,013 5,613
Other 14,075 12,957
------- -------
$33,412 $81,915
------- -------
The Company owns approximately 6.6% of Oleoducto de Colombia S.A. ("ODC").
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 $2 million, $3.6 million and $2.3 million in the years ended December 31,
1997, 1996 and 1995, respectively.
8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Accounts payable and accrued liabilities are summarized as follows:
DECEMBER 31,
----------------
1997 1996
------- -------
Accrued exploration and development $12,903 $21,082
Accrued interest payable 9,449 2,046
Accounts payable, principally trade 5,819 2,697
Litigation and environmental matters 2,715 3,282
Other 6,078 9,438
------- -------
$36,964 $38,545
------- -------
9. DEBT
SHORT-TERM BORROWINGS
At December 31, 1997, the Company had outstanding borrowings of $9.6 million
under a $10 million unsecured demand promissory note with a bank that renews
monthly. Borrowings bear interest at LIBOR plus .75%.
At December 31, 1997, the Company had outstanding borrowings totaling $45
million under two unsecured revolving credit facilities with banks providing
for borrowings of up to $30 million and $25 million, respectively. Borrowings
bear interest at various spreads over the Eurodollar rate or, at the option of
the Company, at LIBOR or prime. The revolving credit facilities contain
certain covenants requiring certain levels of production and limiting the
incurrence of certain liens, sales/leaseback transactions, dividends on
ordinary shares, and mergers and consolidations.
The weighted average interest rates on short-term borrowings outstanding at
December 31, 1997, was 7.3%.
LONG-TERM DEBT
A summary of long-term debt follows:
DECEMBER 31,
------------------
1997 1996
-------- --------
Senior Notes due 2005 $200,000 $ ---
Senior Notes due 2002 199,900 ---
Revolving credit facility maturing 1998 119,900 11,000
Term credit facility maturing 2001 31,595 40,622
Revolving credit facility maturing 1999 17,500 ---
Senior Subordinated Discount Notes due 2000 854 170,000
Senior Subordinated Discount Notes due 1997 --- 189,869
Other notes and capitalized leases 3,938 5,139
-------- --------
573,687 416,630
Less current maturities 130,375 199,552
-------- --------
$443,312 $217,078
-------- --------
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.
Interest on the Senior Notes is payable semi-annually on April 15 and October
15 commencing October 15, 1997. 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 1992, the Company completed the sale of $240 million in principal
amount of Senior Subordinated Discount Notes ("1997 Notes") due November 1,
1997, providing net proceeds to the Company of approximately $126 million.
The original issue price was 54.76% of par, representing a yield to maturity
of 12 1/2% per annum compounded on a semi-annual basis without periodic
payments of interest.
In 1993, the Company completed the sale of $170 million in principal amount of
9 3/4% Senior Subordinated Discount Notes ("9 3/4% Notes") due December 15,
2000, providing net proceeds to the Company of approximately $124 million.
The original issue price was 75.1% of par, representing a yield to maturity of
9 3/4%. No interest was payable on the 9 3/4% Notes during the first three
years of issue. Commencing December 15, 1996, interest on the 9 3/4% Notes
began to accrue at the rate of 9 3/4% per annum and is payable semi-annually
on June 15 and December 15, beginning on June 15, 1997.
In May and June 1997, the Company completed a tender offer and consent
solicitation with respect to the 1997 Notes and the 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 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 the 9 3/4% Notes. 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 the interest
accreted with respect to the 1997 Notes and the 9 3/4% Notes through the dates
of retirement.
During 1996, the Company purchased in the open market $30 million face value
of its 1997 Notes and realized an extraordinary expense of $1.2 million, net
of a $.6 million tax benefit.
During 1997, the Company signed two unsecured bank revolving credit facilities
providing for borrowings of up to $50 million and $25 million, respectively,
that mature in November and December 1999, respectively. Borrowings bear
interest at various spreads over the Eurodollar rate or, at the Company's
option, at LIBOR or prime. The revolving credit facilities contain certain
covenants requiring certain levels of production and limiting the incurrence
of certain liens, sales/leaseback transactions, dividends on ordinary shares,
and mergers and consolidations. Under the most restrictive covenant in the
Company's existing credit facilities, the Company generally could not permit
total indebtdness (as defined in the various agreements) to exceed $650
million. At December 31, 1997, the Company had outstanding borrowings of
$17.5 million under the $50 million facility.
In 1996, the Company signed a $125 million unsecured bank revolving credit
facility that matures in August 1998. Borrowings bear interest at various
spreads over either prime or LIBOR. The revolving credit facility contains
financial covenants that include certain limitations on dividends,
investments, prepayments of debt, transactions with affiliates, and mergers
and acquisitions, and include certain mandatory pay-down requirements. At
December 31, 1997, the Company had outstanding borrowings of $119.9 million
and letters of credit for $4.5 million under the facility. See note 22 -
Subsequent Events.
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 beginning on
July 15, 1996, and borrowings bear interest at LIBOR plus .25%, adjusted on a
semi-annual basis. At December 31, 1997, the Company had outstanding
borrowings of $31.6 million under the facility.
The aggregate maturities of long-term debt for the five years during the
period ending December 31, 2002, are as follows: 1998 -- $130.4 million; 1999
- -- $27.1 million; 2000 -- $9.6 million; 2001 -- $5.1 million; and 2002 --
$200.4 million.
10. INCOME TAXES
The components of earnings (loss) from continuing operations before income
taxes and extraordinary item were as follows:
YEAR ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
---------- --------- ---------
Cayman Islands $ (12,969) $ (452) $ ---
United States (31,694) (16,641) (21,412)
Foreign - other 61,559 38,038 38,012
---------- --------- ---------
$ 16,896 $ 20,945 $ 16,600
---------- --------- ---------
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,
-------------------------------
1997 1996 1995
--------- --------- ---------
Current:
Cayman Islands $ --- $ --- $ ---
United States (7) (172) 627
Foreign - other 3,230 5,427 3,988
--------- --------- ---------
Total current 3,223 5,255 4,615
--------- --------- ---------
Deferred:
Cayman Islands --- --- ---
United States (7,929) (23,489) (12,797)
Foreign - other 16,007 15,374 18,241
--------- --------- ---------
Total deferred 8,078 (8,115) 5,444
--------- --------- ---------
Total $ 11,301 $ (2,860) $ 10,059
--------- --------- ---------
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,
------------------------
1997 1996 1995
-------- ------- ------
Tax provision at statutory tax rate 0.0 % 0.0 % 35.0 %
Increase (decrease) resulting from:
Net change in valuation allowance 263.0 % (111.6)% (201.6)%
Recognition of outside basis adjustments --- % (20.3)% (107.6)%
Foreign items without tax benefit 77.8 % 25.8 % 23.9 %
Income tax rate changes --- % --- % 16.9 %
Income subject to tax in excess of statutory rate 36.9 % 58.4 % --- %
Branch loss recapture/Subpart F --- % --- % 97.1 %
Current year change in NOL/credit carryforwards (356.7)% (59.2)% 51.2 %
Temporary differences:
Oil and gas basis adjustments 32.5 % 80.6 % 116.4 %
Reimbursement of pre-commerciality costs 13.2 % 10.9 % 30.5 %
Other 0.2 % 1.8 % (1.2) %
--------- ------- ------
66.9 % (13.6)% 60.6 %
--------- ------- ------
The components of the net deferred tax asset and liability were as follows:
DECEMBER 31, 1997 DECEMBER 31, 1996
--------------------------------- -------------------------------
OTHER OTHER
U.S. COLOMBIA FOREIGN U.S. COLOMBIA FOREIGN
--------- ---------- ---------- --------- --------- ---------
Deferred tax asset:
Net operating loss carryforwards $ 156,579 $ 10,088 $ 8,187 $ 98,555 $ 9,540 $ 2,347
Depreciable/depletable property 2,046 --- --- 1,558 --- ---
Credit carryforwards 1,726 3,986 --- 2,054 --- ---
Reserves 1,090 --- --- 1,259 --- ---
Other 799 --- --- 792 --- ---
--------- ---------- ---------- --------- --------- --------
Gross deferred tax asset 162,240 14,074 8,187 104,218 9,540 2,347
Valuation allowances (75,092) --- --- (30,657) --- ---
--------- ---------- ---------- --------- --------- --------
Net deferred tax asset 87,148 14,074 8,187 73,561 9,540 2,347
--------- ---------- ---------- --------- --------- --------
Deferred tax liability:
Depreciable/depletable property --- (58,143) (15,086) --- (50,874) (6,444)
WTI benchmark call options --- --- --- (2,145) --- ---
--------- ---------- ---------- --------- --------- --------
Net deferred tax asset (liability) 87,148 (44,069) (6,899) 71,416 (41,334) (4,097)
Less current deferred tax asset (liability) --- --- --- --- --- ---
--------- ---------- ---------- --------- --------- --------
Noncurrent deferred tax asset (liability) $ 87,148 $ (44,069) $ (6,899) $ 71,416 $(41,334) $(4,097)
--------- ---------- ---------- --------- --------- --------
At December 31, 1997, the Company had net operating loss ("NOLs") and
depletion carryforwards for U.S. tax purposes of $406.8 million and $6.8
million, respectively. During 1997, the Company amended certain prior-year tax
returns that increased the Company's unused NOLs. In addition, at December
31, 1997, certain U.S. subsidiaries had separate return limitation year
("SRLY") operating loss and depletion carryforwards of $40.6 million and $13.5
million, respectively, which are available to offset only the future taxable
income of those subsidiaries. The depletion carryforwards are available
indefinitely. The U.S. NOLs and SRLY operating loss carryforwards expire from
1998 through 2013 as follows:
NOLS SRLYS
EXPIRING EXPIRING
BY YEAR BY YEAR
--------- ---------
May 1998 $ 11,594 $ 8,964
May 1999 8,809 9,660
May 2000 7,315 12,256
May 2001 20,713 9,675
May 2002 22,670 32
May 2003 20,566 ---
May 2004 - May 2013 315,114 ---
--------- ---------
$ 406,781 $ 40,587
--------- ---------
The deferred tax valuation allowance of $75.1 million at December 31, 1997, is
primarily attributable to management's assessment of the utilization of NOLs,
SRLY operating losses that are currently not realizable due to the lack of
potential future income in the applicable subsidiaries, and the expectation
that other tax credits will expire without being utilized. The minimum amount
of future taxable income necessary to realize the deferred tax asset is
approximately $249 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 increasing income from its operations.
At December 31, 1997, the Company's Colombian operations and other foreign
operations had NOLs totaling $28.8 million and $28.7 million, respectively.
The NOLs expire from 1998 through 2007.
If certain changes in the Company's ownership should occur, there would be an
annual limitation on the amount of 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,
--------------------------------------
1997 1996
------------------- -----------------
DEFINED DEFINED
BENEFIT SERP BENEFIT SERP
PLAN PLAN PLAN PLAN
-------- --------- ------- --------
Actuarial present value of benefit obligations:
Vested benefit obligations $ 4,218 $ 4,781 $3,748 $ 4,079
-------- --------- ------- --------
Accumulated benefit obligations $ 4,790 $ 4,781 $4,037 $ 4,079
-------- --------- ------- --------
Projected benefit obligations $ 6,008 $ 6,621 $4,849 $ 5,288
Plan assets at fair value, primarily listed stocks
and U. S. government securities 5,531 --- 4,790 ---
-------- --------- ------- --------
Unfunded projected benefit obligations 477 6,621 59 5,288
Unrecognized net gain (loss) (250) (745) 2 (46)
Prior service cost not yet recognized in net periodic
pension cost (598) (133) (653) (144)
Unrecognized net asset (liability) at adoption 10 (1,288) 11 (1,456)
Adjustment required to recognize minimum liability --- 326 --- 437
-------- --------- ------- --------
Accrued (prepaid) pension cost $ (361) $ 4,781 $ (581) $ 4,079
-------- --------- ------- --------
A summary of the components of pension expense follows:
YEAR ENDED DECEMBER 31,
---------------------------
1997 1996 1995
--------- ------- -------
Service cost - benefits earned
during the year $ 832 $ 767 $ 780
Interest cost on projected benefit obligation 783 736 653
Actual return on plan assets (921) (387) (849)
Net amortization and deferral 738 244 793
--------- ------- -------
$ 1,432 $1,360 $1,377
--------- ------- -------
The projected benefit obligations at December 31, 1997 and 1996, assume a
discount rate of 7.5% and 8%, 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.
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.
12. SHAREHOLDERS' EQUITY
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% preference share, par value $.01. Each
share of the Company's 5% 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% 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, (or such earlier date as there are fewer than 133,005 5%
preference shares outstanding), 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, 1997, 1996 and 1995, 218,285, 247,469 and
410,017 preference shares were outstanding, respectively.
ORDINARY SHARES
Changes in issued ordinary shares were as follows:
YEAR ENDED DECEMBER 31,
-----------------------------------
1997 1996 1995
---------- ----------- ----------
Balance at beginning of year 36,342,181 35,927,279 35,577,009
Exercise of employee stock options
and debentures 133,736 258,333 237,875
Issuances under stock plans 35,961 9,910 ---
Conversion of 5% preference shares 29,184 162,548 112,395
Other, net 2 (15,889) ---
---------- ----------- ----------
Balance at end of year 36,541,064 36,342,181 35,927,279
---------- ----------- ----------
Changes in ordinary shares held in treasury were as follows:
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996 1995
-------- -------- --------
Balance at beginning of year 40 26,635 45,837
Purchase of treasury shares 33 91 89
Transfer of shares to employee benefit plans --- (10,797) (19,291)
Retirement of treasury shares --- (15,889) ---
-------- -------- --------
Balance at end of year 73 40 26,635
-------- -------- --------
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 of the Company at a price of $120 per one one-thousandth of a share.
Generally, the rights become distributable only if a person acquires
beneficial ownership of 15% or more of the Company's ordinary shares or
announces a tender offer for 15% or more of the ordinary shares. If, among
other events, any such person becomes the beneficial owner of 15% or more of
the Company's ordinary shares, each right not owned by such person generally
becomes the right to purchase such 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 such number of shares of common stock of
the acquiring person, which is equal to the amount 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. The rights will expire on May 22, 2005, unless
such expiration date is extended or unless the rights are earlier redeemed or
exchanged by the Company. At any time prior to a person acquiring beneficial
ownership of 15% or more of the Company's ordinary shares, the Company may
redeem the rights in whole, but not in part, at a price of $.01 per right.
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 equals the market price of the Company's ordinary shares on the date of
grant. Grants generally become exercisable in 25% cumulative annual increments
beginning one year from the date of issuance and 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 in 33% cumulative annual
increments beginning one year from the date of issuance and expire at the end
of 10 years. At December 31, 1997 and 1996, shares available for grant were
1,040,965 and 731,090, respectively.
A summary of the status of the Company's stock option plans is presented
below:
DECEMBER 31, 1997 DECEMBER 31, 1996 DECEMBER 31, 1995
--------------------------- ---------------------- ---------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
----------- --------- ----------- --------- --------- ---------
Outstanding at beginning of year 3,854,046 $38.81 3,177,304 $35.49 3,074,854 $33.80
Granted 744,250 39.99 971,000 47.97 373,500 49.33
Exercised (83,736) 30.76 (216,333) 30.40 (237,875) 35.30
Canceled (65,125) 46.09 (77,925) 40.74 (33,175) 35.62
---------- ----------- ----------
Outstanding at end of year 4,449,435 39.05 3,854,046 38.81 3,177,304 35.49
---------- ----------- ----------
Options exercisable at yearend 2,728,254 2,042,492 1,449,424
Weighted average fair value per share
of options granted during the year $ 16.37 $ 19.89 $ 20.75
The following table summarizes information about stock options outstanding at
December 31, 1997:
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, 1997 LIFE PRICE DEC. 31, 1997 PRICE
- -------------- -------------- ----------- ---------- -------------- ----------
$ 8.38 - 19.88 58,343 2.9 years $ 10.83 58,343 $ 10.83
28.50 - 39.63 2,556,117 6.6 years 34.37 1,802,613 33.17
40.00 - 49.13 1,082,375 6.1 years 42.35 536,748 42.12
50.25 - 57.38 752,600 8.1 years 52.43 330,550 51.97
-------------- ---------
4,449,435 2,728,254
-------------- ---------
CONVERTIBLE DEBENTURE PLAN
The Company has a convertible debenture plan under which key management
personnel and others may purchase debentures that are convertible into
ordinary shares of the Company. The aggregate number of ordinary shares
issuable upon conversion of the debentures cannot exceed 1,000,000 shares,
subject to adjustment in certain events. Each debenture represents an
unsecured, subordinated obligation due in 10 years and may be redeemed after
three years at a redemption price of 120% of the principal amounts. The
debentures outstanding at December 31, 1997, bear interest at the prime rate.
The participants in the plan purchased debentures by delivery of promissory
notes to the Company. The promissory notes are secured by the debentures that
are held as security by the Company, are due on the earlier of 10 years from
the date of issue or termination of employment and require annual interest
payments equal to prime plus 1/8%. The debentures are reflected as a
noncurrent liability, net of the related promissory notes, in the Consolidated
Balance Sheets as follows:
DECEMBER 31,
--------------------
1997 1996
---------- --------
Convertible debentures due employees $ 14,234 $ 15,491
Promissory notes (14,234) (15,491)
---------- --------
$ --- $ ---
---------- --------
A summary of the status of the Company's convertible debenture plan is
presented below:
DECEMBER 31, 1997 DECEMBER 31, 1996 DECEMBER 31, 1995
------------------------ ------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
---------- ----------- -------- --------- --------- --------
Outstanding at beginning of year 458,000 $ 33.82 500,000 $ 33.94 250,000 $ 25.13
Granted --- --- --- --- 250,000 42.75
Exercised (50,000) 25.13 (42,000) 35.20 --- ---
---------- -------- ---------
Outstanding at yearend 408,000 34.89 458,000 33.82 500,000 33.94
---------- -------- ---------
Options exercisable at yearend 408,000 458,000 250,000
Weighted average fair value per share
of convertible debentures granted during
the year $ --- $ --- $ 19.45
The following table summarizes information about convertible debentures
outstanding at December 31, 1997:
DEBENTURES OUTSTANDING DEBENTURES EXERCISABLE
---------------------------------------- ------------------------
WEIGHTED
RANGE AVERAGE WEIGHTED WEIGHTED
OF NUMBER REMAINING AVERAGE NUMBER AVERAGE
EXERCISE OUTSTANDING AT CONTRACTUAL EXERCISE EXERCISABLE AT EXERCISE
PRICES DEC. 31, 1997 LIFE PRICE DEC. 31, 1997 PRICE
------- -------------- ----------- -------- -------------- --------
$ 25.13 182,000 6.3 years $ 25.13 182,000 $ 25.13
42.75 226,000 7.4 years 42.75 226,000 42.75
-------------- --------------
408,000 408,000
-------------- --------------
EMPLOYEE STOCK PURCHASE PLAN
The Company has an employee stock purchase plan that provides for the award of
up to 100,000 ordinary shares to key officers and employees. At December 31,
1997 and 1996, shares available for grant were 24,456 and 49,417,
respectively. 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 24,961 shares and 20,707
shares to employees for the years ended December 31, 1997 and 1996,
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,
convertible debenture plan 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 and earnings per share would
have been as follows:
YEAR ENDED DECEMBER 31,
---------------------------
1997 1996 1995
--------- ------- -------
Net earnings (loss) applicable to ordinary shares:
As reported $ (9,296) $21,624 $1,918
Pro forma (16,802) 17,414 (587)
Basic earnings (loss) per ordinary share:
As reported $ (0.26) $ 0.61 $ 0.05
Pro forma (0.46) 0.48 (0.02)
Diluted earnings (loss) per ordinary share:
As reported $ (0.25) $ 0.59 $ 0.05
Pro forma (0.46) 0.47 (0.02)
The fair value of each option or debenture 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 1997, 1996 and 1995: dividend
yield of 0%; expected volatility of 26.1%, 26.9% and 27.8%, respectively;
risk-free interest rates of approximately 6%; and an expected life of five to
seven years.
STOCK APPRECIATION RIGHTS PLAN
The Company has a stock appreciation rights ("SARs") plan which authorizes the
granting of 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, 1997, SARs covering 25,000 ordinary shares, with an exercise price of $8
per share, were outstanding.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS, RISK MANAGEMENT
AND CREDIT RISK CONCENTRATIONS
FAIR VALUE OF FINANCIAL INSTRUMENTS
At December 31, 1997 and 1996, the Company's financial instruments included
cash, cash equivalents, short-term receivables, marketable securities,
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
marketable securities, long-term receivables and financial market
transactions, based on broker quotes, quoted market prices 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 $596 million (carrying value - $574 million) and $433
million (carrying value - $417 million) at December 31, 1997 and 1996,
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 may also enter into financial market
transactions to benefit from its assessment of the future prices of its
production relative to other benchmark prices. There can be no assurance that
the use of financial market transactions will not result in losses.
In anticipation of entering into a forward oil sale, the Company purchased
WTI benchmark call options to retain the ability to benefit from future 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. During the years ended December 31,
1997, 1996 and 1995, the Company recorded an unrealized gain (loss) of ($9.7
million), $11 million and ($4.2 million), respectively, in other income, net,
related to the change in the fair market value of the call options. Future
fluctuations in the fair market value of the call options will continue to
affect other income as noncash adjustments.
During the year ended December 31, 1997, markets provided the Company the
opportunity to realize WTI benchmark oil prices on average $2.35 per barrel
above the WTI benchmark oil price the Company set as part of its 1997 annual
plan. As a result of financial and commodity market transactions settled
during the year ended December 31, 1997, the Company's risk management program
resulted in an average net realization of approximately $.11 per barrel lower
than if the Company had not entered into such transactions.
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 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, NET
Other income, net is summarized as follows:
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996 1995
------- -------- --------
Change in fair market value of WTI
benchmark call options $(9,689) $ 10,987 $(4,171)
Foreign exchange gain (loss) 9,549 (561) 1,874
Gain on sale of corporate asset 1,414 --- ---
Proceeds from legal settlements 765 7,624 7,222
Gain on sale of shareholdings in Crusader --- 10,417 ---
Gain on the sale of Triton France --- --- 3,496
Gain on early redemption of Crusader's
convertible notes --- --- 2,899
Loss provisions --- (3,193) (1,058)
Equity in earnings (loss) of affiliates, net --- 118 (2,249)
Other 833 1,969 1,372
-------- -------- --------
$ 2,872 $ 27,361 $ 9,385
-------- -------- --------
In 1997, the Company recognized a foreign exchange gain of $9.6 million,
primarily noncash adjustments to deferred tax liabilities in Colombia
associated with devaluation of the Colombian peso versus the U.S. dollar.
16. WRITEDOWN OF ASSETS
In 1996, the Company's oil and gas properties and other assets in Argentina
were written down $40 million and $3 million, respectively, following a review
of technical information that indicated the acreage portfolio did not meet the
Company's exploration objectives.
17. 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.
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
------------- -----------
YEAR ENDED DECEMBER 31, 1996:
Earnings before extraordinary item $ 23,805
Less: Preference share dividends (985)
-------------
Earnings available to ordinary shareholders 22,820
Basic earnings per ordinary share 35,929 $ 0.64
----------
Effect of dilutive securities
Stock options --- 843
Convertible debentures --- 147
------------- -------------
Earnings available to ordinary shareholders and
assumed conversions $ 22,820
-------------
Diluted earnings per ordinary share 36,919 $ 0.62
------------- -----------
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------- ------------- ----------
YEAR ENDED DECEMBER 31, 1995:
Earnings from continuing operations $ 6,541
Less: Preference share dividends (802)
--------------
Earnings available to ordinary shareholders 5,739
Basic earnings per ordinary share 35,147 $ 0.16
-----------
Effect of dilutive securities
Stock options --- 690
Convertible debentures --- 113
-------------- -------------
Earnings available to ordinary shareholders and
assumed conversions $ 5,739
--------------
Diluted earnings per ordinary share 35,950 $ 0.16
-------------- -----------
At December 31, 1997, 218,285 shares of 5% preference shares were outstanding.
Each preference share is convertible any time into one ordinary share, subject
to adjustment in certain events. The preference shares were not included in
the computation of diluted earnings per ordinary share because the effect of
assuming conversion of preference shares was antidilutive.
At December 31, 1995, the Company's proportionate shares owned by Crusader
were not included in the computation of diluted earnings per ordinary share
because the effect of assuming conversion of these shares was antidilutive.
18. STATEMENTS OF CASH FLOWS
Supplemental disclosures of cash payments and noncash investing and financing
activities follows:
YEAR ENDED DECEMBER 31,
------------------------
1997 1996 1995
------- ------ ------
Cash paid during the year for:
Interest (net of amount capitalized) $133,265 $ --- $ ---
Income taxes 4,666 200 920
Noncash financing acivities:
Conversion of preference shares into
ordinary shares $ 1,004 $5,594 $3,867
Cash paid for interest in 1997 included $124.8 million of interest accreted
with respect to the 1997 Notes and the 9 3/4% Notes through the dates of
retirement.
Proceeds from the sale of available-for-sale securities were $2 million, $19.5
million and $7.7 million in the years ended December 31, 1997, 1996 and 1995,
respectively.
19. CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS
Certain statements in this report, including expectations, intentions, plans
and beliefs of the Company and management, including those contained in or
implied by "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and these Notes to Consolidated Financial Statements,
are forward-looking statements, as defined in Section 21D of the Securities
Exchange Act of 1934, that are dependent on certain events, risks and
uncertainties that may be outside the Company's control. These
forward-looking statements include statements of management's plans and
objectives for the Company's future operations and statements of future
economic performance; information regarding drilling schedules and schedules
for the start-up of production facilities; expected or planned production or
transportation capacity; when the Fields might become self-financing; future
production of the Fields; the negotiation of a heads of agreement to a
gas-sales contract and a gas-sales contract and commencement of production in
Malaysia-Thailand; the Company's capital budget and future capital
requirements; the Company's meeting its future capital needs; the amount by
which production from the Fields may increase or when such increased
production may commence; the Company's realization of its deferred tax asset;
the level of future expenditures for environmental costs; the outcome of
regulatory and litigation matters; the impact of Year 2000 issues; and proven
oil and gas reserves and discounted future net cash flows therefrom; and the
assumptions described in this report underlying such forward-looking
statements. Actual results and developments could differ materially from
those expressed in or implied by such statements due to a number of factors,
including those described in the context of such forward-looking statements,
as well as those presented below.
CERTAIN FACTORS RELATING TO THE OIL AND GAS INDUSTRY
The Company's strategy is to focus its exploration activities on what the
Company believes are relatively high-potential prospects. No assurance can be
given that these prospects contain significant oil and gas reserves or that
the Company will be successful in its exploration activities thereon. The
Company follows the full cost method of accounting for exploration and
development of oil and gas reserves whereby all acquisition, exploration and
development costs are capitalized. Costs related to acquisition, holding and
initial exploration of licenses in countries with no proved reserves are
initially capitalized, including internal costs directly identified with
acquisition, exploration and development activities. The Company's
exploration licenses are periodically assessed for impairment on a
country-by-country basis. If the Company's investment in exploration licenses
within a country where no proved reserves are assigned is deemed to be
impaired, the licenses are written down to estimated recoverable value. If
the Company abandons all exploration efforts in a country where no proved
reserves are assigned, all exploration costs associated with the country are
expensed. The Company's assessments of whether its investment within a
country is impaired and whether exploration activities within a country will
be abandoned are made from time to time based on its review and assessment of
drilling results, seismic data and other information it deems relevant. Due
to the unpredictable nature of exploration drilling activities, the amount and
timing of impairment expense are difficult to predict with any certainty.
Financial information concerning the Company's assets at December 31, 1997,
including capitalized costs by geographic area, is set forth in note 21.
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. Subsequent to
yearend, the price of oil declined significantly which will have a negative
effect on earnings and cash flows in the first-quarter of 1998.
The Company's oil and gas business is also subject to all of the operating
risks normally associated with the exploration for and production of oil and
gas, including, without limitation, blowouts, cratering, pollution,
earthquakes, labor disruptions and fires, each of which could result in
substantial losses to the Company due to injury or loss of life and damage to
or destruction of oil and gas wells, formations, production facilities or
other properties. In accordance with customary industry practices, the
Company maintains insurance coverage limiting financial loss resulting from
certain of these operating hazards. Losses and liabilities arising from
uninsured or underinsured events would reduce revenues and increase costs to
the Company. There can be no assurance that any insurance will be adequate to
cover losses or liabilities. The Company cannot predict the continued
availability of insurance, or its availability at premium levels that justify
its purchase.
The Company's oil and gas business is also subject to laws, rules and
regulations in the countries where it operates, which generally pertain to
production control, taxation, environmental and pricing concerns, and other
matters relating to the petroleum industry. Many jurisdictions have at
various times imposed limitations on the production of natural gas and oil by
restricting the rate of flow for oil and natural-gas wells below their actual
capacity. There can be no assurance that present or future regulation will
not adversely affect the operations of the Company.
The Company is subject to extensive environmental laws and regulations. These
laws regulate the discharge of oil, gas or other materials into the
environment and may require the Company to remove or mitigate the
environmental effects of the disposal or release of such materials at various
sites. The Company does not believe that its environmental risks are
materially different from those of comparable companies in the oil and gas
industry. Nevertheless, no assurance can be given that environmental laws and
regulations will not, in the future, adversely affect the Company's
consolidated results of operations, cash flows or financial position.
Pollution and similar environmental risks generally are not fully insurable.
CERTAIN FACTORS RELATING TO INTERNATIONAL OPERATIONS
The Company derives substantially all of its consolidated revenues from
international operations. Risks inherent in international operations include
loss of revenue, property and equipment from such hazards as expropriation,
nationalization, war, insurrection and other political risks; trade protection
measures; risks of increases in taxes and governmental royalties; and
renegotiation of contracts with governmental entities; as well as changes in
laws and policies governing operations of other companies. Other risks
inherent in international operations are the possibility of realizing economic
currency-exchange losses when transactions are completed in currencies other
than U.S. dollars and the Company's ability to freely repatriate its earnings
under existing exchange control laws. To date, the Company's international
operations have not been materially affected by these risks.
CERTAIN FACTORS RELATING TO COLOMBIA
The Company is a participant in significant oil and gas discoveries in the
Fields, located approximately 160 kilometers (100 miles) northeast of Bogota,
Colombia. Development of reserves in the Fields is ongoing and will require
additional drilling and completion of the production facilities currently
under construction. The Company expects that the production facilities will
be completed in 1998. Pipelines connect the major producing fields in
Colombia to export facilities and to refineries.
From time to time, guerrilla activity in Colombia has disrupted the operation
of oil and gas projects causing increased costs. Such activity increased in
1997, causing delays in the development of the Cupiagua Field. Although the
Colombian government, the Company and its partners have taken steps to
maintain security and favorable relations with the local population, there can
be no assurance that attempts to reduce or prevent guerrilla activity will be
successful or that guerrilla activity will not disrupt operations in the
future.
Colombia is among several nations whose progress in stemming the production
and transit of illegal drugs is subject to annual certification by the
President of the United States. In 1998, the President of the United States
announced that Colombia would not be certified, but was granted a national
interest waiver. There can be no assurance that, in the future, Colombia will
receive certification or a waiver. The consequences of the failure to receive
certification or a national interest waiver generally include the following:
all bilateral aid, except anti-narcotics and humanitarian aid, would be
suspended; the Export-Import Bank of the United States and the Overseas
Private Investment Corporation would not approve financing for new projects in
Colombia; U.S. representatives at multilateral lending institutions would be
required to vote against all loan requests from Colombia, although such votes
would not constitute vetoes; and the President of the United States and
Congress would retain the right to apply future trade sanctions. Each of
these consequences could result in adverse economic consequences in Colombia
and could further heighten the political and economic risks associated with
the Company's operations in Colombia. Any changes in the holders of
significant government offices could have adverse consequences on the
Company's relationship with the Colombian national oil company and the
Colombian government's ability to control guerrilla activities and could
exacerbate the factors relating to foreign operations discussed above.
CERTAIN FACTORS RELATING TO MALAYSIA-THAILAND
The Company is a partner in a significant gas exploration project located in
the upper Malay Basin in the Gulf of Thailand approximately 450 kilometers
northeast of Kuala Lumpur and 750 kilometers south of Bangkok as a contractor
under a production-sharing contract covering Block A-18 of the
Malaysia-Thailand Joint Development Area. Test results to date indicate that
significant gas and oil deposits lie within the block. Development of gas
production is in the early planning stages but is expected to take several
years and require the drilling of additional wells and the installation of
production facilities, which will require significant additional capital
expenditures, the ultimate amount of which cannot be predicted. Pipelines
also will be required to be connected between Block A-18 and ultimate markets.
The terms under which any gas produced from the Company's contract area in
Malaysia-Thailand is sold may be affected adversely by the present monopoly,
gas-purchase and transportation conditions in both Thailand and Malaysia,
including the Thai national oil company's monopoly of transportation within
Thailand and its territorial waters.
COMPETITION
The Company encounters strong competition from major oil companies (including
government-owned companies), independent operators and other companies for
favorable oil and gas concessions, licenses, production-sharing contracts and
leases, drilling rights and markets. Additionally, the governments of certain
countries where the Company operates may from time to time give preferential
treatment to their nationals. The oil and gas industry as a whole also
competes with other industries in supplying the energy and fuel requirements
of industrial, commercial and individual consumers.
MARKETS
Crude oil, natural gas, condensate, and other oil and gas products generally
are sold to other oil and gas companies, government agencies and other
industries. The availability of ready markets for oil and gas that might be
discovered by the Company and the prices obtained for such oil and gas depend
on many factors beyond the Company's control, including the extent of local
production and imports of oil and gas, the proximity and capacity of pipelines
and other transportation facilities, fluctuating demands for oil and gas, the
marketing of competitive fuels, and the effects of governmental regulation of
oil and gas production and sales. Pipeline facilities do not exist in certain
areas of exploration and, therefore, any actual sales of discovered oil or gas
might be delayed for extended periods until such facilities are constructed.
LITIGATION
The outcome of litigation and its impact on the Company are difficult to
predict due to many uncertainties, such as jury verdicts, the application of
laws to various factual situations, the actions that may or may not be taken
by other parties and the availability of insurance. In addition, in certain
situations, such as environmental claims, one defendant may be responsible, or
potentially responsible, for the liabilities of other parties. Moreover,
circumstances could arise under which the Company may elect to settle claims
at amounts that exceed the Company's expected liability for such claims in
order to avoid costly litigation. Judgments or settlements could, therefore,
exceed any reserves.
20. COMMITMENTS AND CONTINGENCIES
Development of the Fields, including drilling and construction of additional
production facilities, will require further capital outlays. Further
exploration and development activities on Block A-18 in the Malaysia-Thailand
Joint Development Area in the Gulf of Thailand, as well as exploratory
drilling in other countries, also will require substantial capital outlays.
The Company's capital budget for the year ending December 31, 1998, is
approximately $176 million, excluding capitalized interest, of which
approximately $103 million relates to the Fields, $23 million relates to Block
A-18, and $50 million relates to the Company's activities in other parts of
the world. The 1998 capital budget includes funding requirements for
committed activities only. Substantial capital requirements for Block A-18
are expected prior to the first deliveries of gas, which are estimated to
occur between 30-36 months after signing of a heads of agreement to a
gas-sales contract.
The Company expects to fund capital expenditures and repay debt in the future
with a combination of some or all of the following: asset sales (which may
involve interests in material assets), cash flow from operations (including
additional proceeds of $30 million from the 1995 forward oil sale), cash,
credit facilities and additional facilities to be negotiated, and the issuance
of debt and equity securities. See note 22 - Subsequent Events.
As of yearend 1997, under the most restrictive covenant in the Company's
existing credit facilities, the Company generally could not permit total
indebtedness (as defined in the various agreements) to exceed $650 million.
The limitation on total indebtedness will increase to $725 million once the
Fields achieve a production rate of 340,000 barrels per day.
During the normal course of business, the Company is subject to the terms of
various operating agreements and capital commitments associated with the
exploration and development of its oil and gas properties. It is management's
belief that such commitments, including the capital requirements in Colombia
and Block A-18 in the Gulf of Thailand 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 2011. Total rental expense was $2 million,
$2 million and $1.9 million for the years ended December 31, 1997, 1996 and
1995, respectively. At December 31, 1997, the minimum payments required over
the next five years are as follows: 1998 -- $2.4 million; 1999 -- $2.2
million; 2000 -- $1.2 million; 2001 -- $.3 million; 2002 --$.2 million; and
thereafter -- $1.1 million.
GUARANTEES
At December 31, 1997, the Company had guaranteed loans of approximately $3.7
million for a Colombian pipeline company in which the Company has an ownership
interest. The Company also guaranteed performance of $32.3 million in future
exploration expenditures in various countries. These commitments are backed
primarily by unsecured letters of credit.
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. Also, the Company may remain liable for certain environmental matters
that may arise from formerly owned fuel businesses. 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
The Company and subsidiaries or former subsidiaries of the Company were among
numerous defendants in a lawsuit brought in the Superior Court of the State of
California, County of Los Angeles, by Travelers Indemnity Company arising out
of a 1988 tidal wave at King Harbor in Redondo Beach, California. The lawsuit
alleged, among other things, that the defendants' negligence contributed to
the collapse of a hotel and the flooding of a restaurant in the tidal wave.
This lawsuit was settled in 1998.
During the quarter ending September 30, 1995, the United States Environmental
Protection Agency ("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 subsidiary has a formal
period of negotiation regarding performing the final remediation design for
the clean-up of the site, and demanded reimbursement for certain unpaid costs
that have been incurred. The government estimates the aggregate amount being
negotiated as $217 million to be allocated among the 280 known operators.
The subsidiary's share would be approximately $1 million based upon a
volumetric allocation. The Company has been advised that the government
expects defendants such as the subsidiary will be given an opportunity to
settle some time in the second half of 1998. At that time, it is expected
that an allocation will be made as to such defendants, which may be greater or
less than the estimated volumetric allocation.
The Company is also subject to other various litigation matters, none of which
is expected to have a material, adverse effect on the Company's operations or
consolidated financial condition.
21. GEOGRAPHIC DATA
Information about the Company's operations by geographic area follows:
MALAYSIA- UNITED
COLOMBIA THAILAND FRANCE INDONESIA STATES OTHER CORPORATE TOTAL
---------- ---------- ------- ----------- -------- --------- ----------- ----------
YEAR ENDED DECEMBER 31, 1997:
Sales and other operating revenues $ 145,419 $ --- $ --- $ --- $ --- $ 4,077 $ --- $ 149,496
Operating profit (loss) 59,719 (536) --- --- --- (6,312) (20,167) 32,704
Trade and other receivables 54,758 2,047 --- --- --- 7,665 655 65,125
Identifiable assets 712,512 148,780 --- --- --- 110,561 126,186 1,098,039
YEAR ENDED DECEMBER 31, 1996:
Sales and other operating revenues $ 127,071 $ --- $ --- $ 1,856 $ 5,050 $ --- $ --- $ 133,977
Operating profit (loss) 70,874 (509) --- (340) 3,400 (47,158) (23,489) 2,778
Trade and other receivables 56,647 494 --- 53 --- 3,212 120 60,526
Identifiable assets 629,978 113,364 --- 2,592 --- 55,257 113,333 914,524
YEAR ENDED DECEMBER 31, 1995:
Sales and other operating revenues $ 89,851 $ --- $ 9,206 $ 4,531 $ 3,884 $ --- $ --- $ 107,472
Operating profit (loss) 49,086 (239) 1,123 (858) (230) (2,669) (22,897) 23,316
Trade and other receivables 19,823 366 --- 785 717 730 766 23,187
Identifiable assets 487,472 50,867 --- 1,744 23,261 63,159 197,664 824,167
At December 31, 1997, corporate assets were principally cash and cash
equivalents, the U.S. deferred tax asset and other fixed assets. Other
identifiable assets included $26.2 million, $21.4 million and $17.3 million of
capitalized costs relating to exploration activities in Guatemala, China and
Italy, respectively.
Other operating profit (loss) for the year ended December 31, 1996, included a
writedown of $43 million for the Company's oil and gas properties and other
assets in Argentina.
22. SUBSEQUENT EVENTS
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 after $2.3 million of expenses. The sale
resulted in an aftertax gain of $50.2 million, which will be recorded in the
first quarter of 1998.
In conjunction with the sale of TPC, the Company entered into a five-year
equity swap with a creditworthy financial institution (the "Counterparty").
The equity swap has a notional amount of $97 million and requires the Company
to make floating LIBOR-based payments on the notional amount to the
Counterparty. In exchange, the Counterparty is required to make payments to
the Company equivalent to 97% of the dividends TPC receives in respect of its
equity interest in OCENSA. Upon a sale by the Purchaser of the TPC shares,
the Company will receive from the Counterparty, or make a cash payment to the
Counterparty, an amount equal to the excess or deficiency, as applicable, of
the difference between 97% of the net proceeds from the Purchaser's sale of
the TPC shares and the notional amount. The equity swap will be carried in
the Company's financial statements at fair value during the five-year term.
Fluctuations in the fair value of the equity swap will affect other income as
noncash adjustments.
In February 1998, the Company used the proceeds from the sale of the TPC
shares and borrowings under other unsecured credit facilities to repay and
terminate its $125 million unsecured credit facility.
23. QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTER
--------------------------------------
FIRST SECOND THIRD FOURTH
-------- -------- -------- --------
YEAR ENDED DECEMBER 31, 1997:
Sales and other operating revenues $ 33,759 $ 32,569 $ 36,993 $ 46,175
Gross profit 15,095 13,645 14,583 17,988
Net earnings (loss) before extraordinary item 3,486 (308) 6,201 (3,784)
Net earnings (loss) 3,486 (14,799) 6,201 (3,784)
Basic earnings (loss) per ordinary share:
Before extraordinary item 0.09 (0.01) 0.16 (0.10)
Net earnings (loss) 0.09 (0.41) 0.16 (0.10)
Diluted earnings (loss) per ordinary share:
Before extraordinary item 0.09 (0.01) 0.16 (0.10)
Net earnings (loss) 0.09 (0.41) 0.16 (0.10)
YEAR ENDED DECEMBER 31, 1996:
Sales and other operating revenues $ 35,781 $ 31,170 $ 30,780 $ 36,246
Gross profit (loss) 19,839 15,885 15,936 (22,937)
Net earnings (loss) before extraordinary item 11,351 12,696 19,549 (19,791)
Net earnings (loss) 11,351 12,262 18,787 (19,791)
Basic earnings (loss) per ordinary share:
Before extraordinary item 0.30 0.36 0.53 (0.54)
Net earnings (loss) 0.30 0.35 0.51 (0.54)
Diluted earnings (loss) per ordinary share:
Before extraordinary item 0.29 0.34 0.52 (0.54)
Net earnings (loss) 0.29 0.33 0.50 (0.54)
Gross profit (loss) comprises of sales and other operating revenues less
operating expenses, depreciation, depletion and amortization, and writedowns
pertaining to operating assets.
In the second quarter of 1997, the Company incurred 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.
In the fourth quarter of 1996, the Company recorded a writedown of $43 million
($37.9 million net of tax) related to oil and gas properties and other assets
in Argentina.
24. OIL AND GAS DATA (UNAUDITED)
The following tables provide additional information about the Company's oil
and gas exploration and production activities. Equity affiliate amounts
reflect only the Company's proportionate interest in Crusader, which was sold
in 1996.
RESULTS OF OPERATIONS
The results of operations for oil- and gas-producing activities, considering
direct costs only, follow:
UNITED TOTAL
COLOMBIA FRANCE INDONESIA STATES OTHER WORLDWIDE
---------- ------- ---------- ------- -------- ---------
YEAR ENDED DECEMBER 31, 1997:
Revenues $ 145,419 $ --- $ --- $ --- $ --- $145,419
Costs:
Production costs 51,357 --- --- --- --- 51,357
General operating expenses 2,886 --- --- --- --- 2,886
Depletion 30,729 --- --- --- --- 30,729
Writedown of assets --- --- --- --- --- ---
Income taxes 22,167 --- --- --- --- 22,167
---------- ------- ----------- ------- --------- --------
Results of operations $ 38,280 $ --- $ --- $ --- $ --- $ 38,280
---------- ------- ----------- ------- --------- --------
YEAR ENDED DECEMBER 31, 1996:
Revenues $ 127,071 $ --- $ 1,856 $ 5,050 $ --- $133,977
Costs:
Production costs 34,822 --- 1,510 322 --- 36,654
General operating expenses 1,909 --- 553 774 --- 3,236
Depletion 18,515 --- 49 554 --- 19,118
Writedown of assets --- --- --- --- 42,960 42,960
Income taxes 25,766 --- --- --- --- 25,766
---------- ------- ----------- ------- --------- --------
Results of operations $ 46,059 $ --- $ (256) $ 3,400 $(42,960) $ 6,243
---------- ------- ----------- ------- --------- --------
UNITED TOTAL
COLOMBIA FRANCE INDONESIA STATES OTHER WORLDWIDE
---------- ------- ---------- ------- ------- --------
YEAR ENDED DECEMBER 31, 1995:
Revenues $ 89,851 $ 9,206 $ 4,531 $ 3,884 $ --- $107,472
Costs:
Production costs 24,942 5,460 4,422 452 --- 35,276
General operating expenses 740 1,061 726 1,030 --- 3,557
Depletion 14,776 1,562 241 1,950 --- 18,529
Writedown of assets --- --- --- --- --- ---
Income taxes 17,395 374 --- --- --- 17,769
---------- ------- ----------- ------- ------- --------
Results of operations $ 31,998 $ 749 $ (858) $ 452 $ --- $ 32,341
---------- ------- ----------- ------- ------- --------
Depletion includes depreciation on support equipment and facilities calculated
on the unit-of-production method.
The Company's equity share of Crusader's results of operations for oil- and
gas-producing activities follows:
AUSTRALIA CANADA OTHER TOTAL
---------- ------- -------- ------
December 31, 1996 $ 1,243 $ --- $ --- $1,243
---------- ------- -------- ------
December 31, 1995 $ 2,998 $ 269 $(1,401) $1,866
---------- ------- -------- ------
COSTS INCURRED AND CAPITALIZED COSTS
The costs incurred in oil and gas acquisition, exploration and development
activities and related capitalized costs follow:
MALAYSIA- UNITED TOTAL
COLOMBIA THAILAND FRANCE INDONESIA STATES OTHER WORLDWIDE
---------- --------- ------- ---------- ------- ------- --------
DECEMBER 31, 1997:
Costs incurred:
Property acquisition $ --- $ --- $ --- $ --- $ --- $ 3,128 $ 3,128
Exploration 7,583 36,373 --- --- --- 47,864 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 $ --- $ --- $ --- $98,127 $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
---------- --------- ------- ---------- ------- ------- --------
MALAYSIA- UNITED TOTAL
COLOMBIA THAILAND FRANCE INDONESIA STATES OTHER WORLDWIDE
--------- --------- ------- ---------- -------- ------- --------
DECEMBER 31, 1996:
Costs incurred:
Property acquisition $ --- $ --- $ --- $ --- $ --- $ 600 $ 600
Exploration 18,875 60,955 --- --- --- 33,103 112,933
Development 39,902 470 --- --- --- --- 40,372
Depletion per equivalent
barrel of production 2.83 --- --- 0.52 5.59 --- 2.84
Cost of properties at year-end:
Unevaluated $ 2,487 $ 30,500 $ --- $ --- $ --- $50,010 $ 82,997
--------- --------- ------- ---------- -------- ------- --------
Evaluated $ 338,955 $ 77,512 $ --- $ --- $ --- $48,630 $465,097
--------- --------- ------- ---------- -------- ------- --------
Support equipment and
facilities $ 194,116 $ --- $ --- $ --- $ --- $ --- $194,116
--------- --------- ------- ---------- -------- ------- --------
Accumulated depletion and
depreciation at year-end $ 35,723 $ --- $ --- $ --- $ --- $48,630 $ 84,353
--------- --------- ------- ---------- -------- ------- --------
DECEMBER 31, 1995:
Costs incurred:
Property acquisition $ 1,101 $ --- $ --- $ --- $ --- $ 250 $ 1,351
Exploration 45,961 25,948 --- --- --- 28,480 100,389
Development 48,419 --- --- 299 --- --- 48,718
Depletion per equivalent
barrel of production 2.67 --- 3.14 0.95 6.05 --- 2.81
Cost of properties at year-end:
Unevaluated $ 59,087 $ 46,282 $ --- $ --- $ 9,202 $58,490 $173,061
--------- --------- ------- ---------- -------- ------- --------
Evaluated $ 260,058 $ --- $ --- $ 47,301 $190,379 $ 8,667 $506,405
--------- --------- ------- ---------- -------- ------- --------
Support equipment and
facilities $ 87,289 $ --- $ --- $ --- $ --- $ --- $ 87,289
--------- --------- ------- ---------- -------- ------- --------
Accumulated depletion and
depreciation at year-end $ 17,355 $ --- $ --- $ 47,153 $180,574 $ 8,667 $253,749
--------- --------- ------- ---------- -------- ------- --------
A summary of costs excluded from depletion at December 31, 1997, by year
incurred follows:
DECEMBER 31,
--------------------------------------------------
TOTAL 1997 1996 1995 1994 AND PRIOR
------------- ------------ -------- --------- --------------
Property acquisition $ 5,292 $ 3,128 $ 600 $ 250 $ 1,314
Exploration 202,483 70,738 77,149 35,203 19,393
Capitalized interest 37,095 17,558 10,259 3,981 5,297
------------- ------------ ------- ------- --------------
Total worldwide $ 244,870 $ 91,424 $88,008 $ 39,434 $ 26,004
------------- ------------ ------- ------- --------------
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 $144.6 million ($114.3 million and $30.3
million classified as evaluated and unevaluated, respectively) for Block A-18
in the Malaysia-Thailand Joint Development Area that will become depletable
once production begins, which is estimated to occur between 30-36 months after
signing of a heads of agreement to a gas-sales contract. Additionally,
excluded costs include exploration costs of $23.3 million, $18.2 million and
$15.4 million in Guatemala, China and Italy, respectively. The balance of
excluded costs represents exploration work in other countries, none of which
is material. At this time, the Company is unable to predict either the timing
of the inclusion of these costs and the 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 equity share of costs incurred by Crusader follows:
AUSTRALIA CANADA OTHER TOTAL
---------- ------- ------ ------
Cost of property acquisition,
exploration and development:
December 31, 1996 $ 2,105 $ --- $ --- $2,105
---------- ------- ------ ------
December 31, 1995 $ 1,187 $ 507 $ 541 $2,235
---------- ------- ------ ------
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 all proved reserves in the Fields in Colombia
were prepared by the Company's independent petroleum engineers, DeGolyer and
MacNaughton. The estimates for all proved reserves in Malaysia-Thailand and
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, 1997, the Company did not have a contract for the sale of gas to
be produced from its interest in the Malaysia-Thailand Joint Development Area.
In estimating reserves attributable to such interest, the Company assumed that
production from the interest would be sold at natural-gas prices derived from
what the Company believed to be the most comparable market price at December
31, 1997. There can be no assurance that the price established in any gas
contract would be equal to the price used in the Company's calculations.
COLOMBIA MALAYSIA-THAILAND
-------------------- ------------------
OIL GAS OIL GAS
--------- --------- ------- ---------
PROVED DEVELOPED AND
UNDEVELOPED RESERVES:
AS OF DECEMBER 31, 1994 104,393 14,721 --- ---
Revisions --- --- --- ---
Sales (10,434) --- --- ---
Extensions and discoveries 32,556 1,127 --- ---
Production (5,089) (158) --- ---
--------- -------- ------- ---------
AS OF DECEMBER 31, 1995 121,426 15,690 --- ---
Revisions 270 (403) --- ---
Sales (548) (338) --- ---
Extensions and discoveries 19,900 --- 24,700 871,100
Production (5,738) (298) --- ---
--------- -------- ------- ----------
AS OF DECEMBER 31, 1996 135,310 14,651 24,700 871,100
Revisions 14,157 770 (2,000) (7,600)
Sales --- --- --- ---
Extensions and discoveries 2,308 --- 7,100 360,300
Production (5,776) (802) --- ---
--------- -------- ------- ---------
AS OF DECEMBER 31, 1997 145,999 14,619 29,800 1,223,800
--------- -------- ------- ---------
FRANCE INDONESIA UNITED STATES TOTAL WORLDWIDE
------- ---------- -------------- ---------------------
OIL OIL OIL GAS OIL GAS
------- ---------- ----- ------- -------- ----------
PROVED DEVELOPED AND
UNDEVELOPED RESERVES:
AS OF DECEMBER 31, 1994 6,244 402 596 7,197 111,635 21,918
Revisions --- 23 119 967 142 967
Sales (5,746) --- --- --- (16,180) ---
Extensions and discoveries --- --- --- --- 32,556 1,127
Production (498) (255) (121) (1,207) (5,963) (1,365)
------- ---------- ----- ------- -------- ----------
AS OF DECEMBER 31, 1995 --- 170 594 6,957 122,190 22,647
Revisions --- --- --- --- 270 (403)
Sales --- (75) (574) (6,482) (1,197) (6,820)
Extensions and discoveries --- --- --- --- 44,600 871,100
Production --- (95) (20) (475) (5,853) (773)
------- ---------- ----- ------- -------- ----------
AS OF DECEMBER 31, 1996 --- --- --- --- 160,010 885,751
Revisions --- --- --- --- 12,157 (6,830)
Sales --- --- --- --- --- ---
Extensions and discoveries --- --- --- --- 9,408 360,300
Production --- --- --- --- (5,776) (802)
------ ---------- ----- ------- -------- ----------
AS OF DECEMBER 31, 1997 --- --- --- --- 175,799 1,238,419
------ ---------- ----- ------- -------- ----------
COLOMBIA MALAYSIA-THAILAND FRANCE INDONESIA UNITED STATES TOTAL WORLDWIDE
------------------- ----------------- ------ --------- ------------- ---------------
OIL GAS OIL GAS OIL OIL OIL GAS OIL GAS
-------- --------- ------ --------- ------ --------- --- ----- ------ ------
PROVED DEVELOPED RESERVES AT:
DECEMBER 31, 1995 65,856 10,515 --- --- --- 170 594 6,957 66,620 17,472
-------- --------- ------ --------- ------ --------- --- ----- ------ ------
DECEMBER 31, 1996 67,193 11,146 --- --- --- --- --- --- 67,193 11,146
-------- --------- ------ --------- ------ --------- --- ----- ------ ------
DECEMBER 31, 1997 81,931 14,619 --- --- --- --- --- --- 81,931 14,619
-------- --------- ------ --------- ------ --------- --- ----- ------ ------
The Company's proportional equity interest in Crusader's estimated proved
developed and undeveloped oil and gas reserves at December 31, 1995, was 3.3
million barrels of oil and 60.9 billion cubic feet of gas.
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 yearend prices of oil and gas
relating to the Company's proved reserves to the estimated yearend quantities
of those reserves. As of December 31, 1997, the Company did not have a
contract for the sale of gas to be produced from its interest in the
Malaysia-Thailand Joint Development Area. In estimating discounted future net
cash inflows attributable to such interest, the Company assumed that
production from the interest would be sold at natural-gas prices derived from
what the Company believed to be the most comparable market price at December
31, 1997. Future price changes were considered only to the extent provided by
contractual agreements in existence at yearend. 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 yearend 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 considerably.
MALAYSIA- UNITED TOTAL
COLOMBIA THAILAND INDONESIA STATES 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
---------- ---------- ---------- ------- ----------
DECEMBER 31, 1996:
Future cash inflows $3,519,893 $2,530,702 $ --- $ --- $6,050,595
Future production and
development costs 1,283,851 1,188,981 --- --- 2,472,832
---------- ---------- ---------- ------- ----------
Future net cash inflows before
income taxes $2,236,042 $1,341,721 $ --- $ --- $3,577,763
---------- ---------- ---------- ------- ----------
Future net cash inflows before
income taxes discounted at 10%
per annum $1,283,158 $ 320,900 $ --- $ --- $1,604,058
Future income taxes discounted at
10% per annum 290,763 21,100 --- --- 311,863
---------- ---------- ---------- ------- ----------
Standardized measure of discounted
future net cash inflows $ 992,395 $ 299,800 $ --- $ --- $1,292,195
---------- ---------- ---------- ------- ----------
MALAYSIA- UNITED TOTAL
COLOMBIA THAILAND INDONESIA STATES WORLDWIDE
---------- --------- ---------- ------- ----------
DECEMBER 31, 1995:
Future cash inflows $2,321,424 $ --- $ 2,909 $19,076 $2,343,409
Future production and
development costs 730,139 --- 2,250 2,037 734,426
---------- --------- ---------- ------- ----------
Future net cash inflows before
income taxes $1,591,285 $ --- $ 659 $17,039 $1,608,983
---------- --------- ---------- ------- ----------
Future net cash inflows before
income taxes discounted at 10%
per annum $ 803,665 $ --- $ 626 $11,150 $ 815,441
Future income taxes discounted at
10% per annum 173,745 --- --- --- 173,745
---------- --------- ---------- ------- ----------
Standardized measure of discounted
future net cash inflows $ 629,920 $ --- $ 626 $11,150 $ 641,696
---------- --------- ---------- ------- ----------
Subsequent to yearend, the price of oil declined significantly. Each $1
decrease in oil prices would have reduced the standardized measure of
discounted future net cash inflows (aftertax) in Colombia at December 31,
1997, by $58 million. The Company's proportional equity interest in
Crusader's standardized measure of discounted future net cash inflows was
$30.4 million at December 31, 1995.
Changes in the standardized measure of discounted future net cash inflows
follow:
DECEMBER 31,
---------------------------------------
1997 1996 1995
-------------- ----------- ----------
Total worldwide, excluding equity share:
Beginning of year $ 1,292,195 $ 641,696 $ 499,670
Sales, net of production costs (94,062) (97,323) (67,471)
Sales of reserves --- (10,473) (144,361)
Revisions of quantity estimates 75,253 2,617 2,348
Net change in prices and production costs (552,863) 228,349 42,044
Extensions, discoveries and improved recovery 42,918 1,125,733 339,413
Change in future development costs (5,936) (652,902) (102,323)
Development and facilities costs incurred 53,199 92,856 28,068
Accretion of discount 160,406 80,672 62,188
Changes in production rates and other (3,089) 19,088 22,917
Net change in income taxes 101,322 (138,118) (40,797)
-------------- ----------- ----------
End of year $ 1,069,343 $1,292,195 $ 641,696
-------------- ----------- ----------
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, 1995:
Allowance for doubtful
receivables $ 897 $ --- $ 41 $ (128) $ 810
----------- ------------ --------- ------------ --------
Allowance for deferred
tax asset $ 87,518 $ (33,472) $ --- $ --- $ 54,046
----------- ------------ --------- ------------ --------
Year ended Dec. 31, 1996:
Allowance for doubtful
receivables $ 810 $ 35 $ --- $ (769) $ 76
----------- ------------ --------- ------------ --------
Allowance for deferred
tax asset $ 54,046 $ (23,389) $ --- $ --- $ 30,657
----------- ------------ --------- ------------ --------
Year ended Dec. 31, 1997:
Allowance for doubtful
receivables $ 76 $ --- $ --- $ (35) $ 41
----------- ------------ --------- ------------ --------
Allowance for deferred
tax asset $ 30,657 $ 44,435 $ --- $ --- $ 75,092
----------- ------------ --------- ------------ --------
___________________
Note -- Deductions for the allowance for doubtful receivables in the year
ended December 31, 1996, related primarily to disposal of other assets.