FORM 10-K
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 (FEE REQUIRED)
FOR THE FISCAL YEAR ENDED: December 31, 1995
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
FOR THE TRANSITION PERIOD FROM ___________ TO ______________
Commission File Number: 1-7864
TRITON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 75-1151855
(State or other jurisdiction of (I.R.S.Employer
incorporation or organization) Identification No.)
6688 NORTH CENTRAL EXPRESSWAY
SUITE 1400
DALLAS, TEXAS 75206
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 214-691-5200
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
Common Stock, $1.00 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 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 1, 1996 (FOR SUCH PURPOSES ONLY, ALL DIRECTORS AND
EXECUTIVE OFFICERS ARE PRESUMED TO BE AFFILIATES) WAS APPROXIMATELY $1.8
BILLION, BASED ON THE CLOSING SALES PRICE OF $49.25 ON THE NEW YORK STOCK
EXCHANGE.
AS OF MARCH 1, 1996, 35,926,258 SHARES OF THE REGISTRANT'S COMMON STOCK
WERE OUTSTANDING.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE PROXY STATEMENT PERTAINING TO THE 1996 ANNUAL MEETING OF
STOCKHOLDERS OF TRITON ENERGY CORPORATION (OR, IF THE REORGANIZATION TO BE
CONSIDERED BY THE STOCKHOLDERS OF TRITON ENERGY CORPORATION AT THE SPECIAL
MEETING PROPOSED TO BE HELD ON MARCH 25, 1996 IS CONSUMMATED, OF TRITON ENERGY
LIMITED) ARE INCORPORATED BY REFERENCE INTO PART III HEREOF.
TRITON ENERGY CORPORATION
TABLE OF CONTENTS
Form 10-K Item Page
PART I
ITEM 1. Business 1
ITEM 2. Properties 7
ITEM 3. Legal Proceedings 21
ITEM 4. Submission of Matters to a Vote of Security Holders 22
PART II
ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters
Stockholder Matters 23
ITEM 6. Selected Financial Data 26
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations 27
ITEM 8. Financial Statements and Supplementary Data 36
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure 36
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
ITEM 1. BUSINESS
GENERAL
Triton Energy Corporation is an international oil and gas
exploration company primarily engaged in exploration and production through
subsidiaries and affiliates. The Company's principal properties and operations
are located in Colombia and Malaysia-Thailand. The Company also has oil and
gas interests in other Latin American and Asian countries, Europe, Australia
and North America.
Triton was incorporated in Texas in 1962 and reincorporated in
Delaware in 1995. The Company's principal executive offices are located at
6688 North Central Expressway, Suite 1400, Dallas, Texas 75206, and its
telephone number is 214/691-5200. The terms "Company" and "Triton" when used
herein mean Triton Energy Corporation and its subsidiaries and other
affiliates through which Triton conducts its business, unless the context
otherwise implies.
The Company has called a special meeting of its stockholders to be
held on March 25, 1996 at which the stockholders will vote on the proposed
reorganization of the Company (the "Reorganization"). Pursuant to the
Reorganization, Triton Energy Limited ("Triton Cayman"), a newly formed Cayman
Islands company and a wholly owned subsidiary of the Company, would become the
parent holding company of Triton through the merger of a wholly owned
subsidiary of Triton Cayman with and into the Company. If the Reorganization
is consummated, the Company will become a subsidiary of Triton Cayman, and
Triton Cayman will continue to conduct the businesses (through subsidiaries
and affiliates) in which the Company is now engaged. The Company and Triton
Cayman have filed with the Securities and Exchange Commission a Proxy
Statement/Joint Prospectus dated as of February 23, 1996 relating to the
special meeting and the securities to be issued if the Reorganization is
consummated. Subsequent to the Reorganization, the Company intends to
transfer substantially all of its businesses or subsidiaries located outside
the United States, other than the Company's interests in the Cusiana and
Cupiagua fields, and interests in Argentina, to Triton Cayman. See note 22 of
Notes to Consolidated Financial Statements.
OIL AND GAS OPERATIONS
General
Oil and gas exploration and development activities are, or have
been, conducted through the Company's wholly owned subsidiaries, except in
Malaysia-Thailand, where activities are, or have been, conducted by the
Company's wholly owned subsidiaries, Triton Oil Company of Thailand and Triton
Oil Company of Thailand (JDA), Ltd. (collectively, "Triton Thailand"), and
Triton Thailand's 50% owned affiliate, Carigali - Triton Operating Company
SDN. BHD. ("CTOC"); in Europe, where activities are, or have been, conducted
by the Company's wholly owned (but until March 1994, 59.5% owned) subsidiary,
Triton Europe Limited ("Triton Europe"); in Indonesia, where activities are,
or have been, conducted by the Company's wholly owned subsidiary, Triton
Indonesia, Inc. ("Triton Indonesia") and the Company's 33.7% owned (but until
August 1994, 63.7% owned) affiliate, New Zealand Petroleum Company Limited
("New Zealand Petroleum"); in the United States by the Company's wholly owned
subsidiary, Triton Oil & Gas Corp. ("Triton Oil"), and the Company's 49.9%
owned affiliate, Crusader Limited ("Crusader") until September 1994; in New
Zealand by New Zealand Petroleum and Crusader; in Canada by Crusader, until
June 1995, and by Triton Canada Resources Ltd. ("Triton Canada") until August
1993; and in Australia by Crusader.
A significant portion of Triton's reserves is held through the
Company's wholly owned subsidiaries, Triton Colombia, Inc. and Triton
Resources Colombia, Inc. (collectively, "Triton Colombia"). Additional
reserves are held through Triton's publicly held affiliate, Crusader. For
further information relating to the Company's oil and gas business activities,
see Item 2, "Properties" and note 25 of Notes to Consolidated Financial
Statements.
Production and Sales
The following table sets forth for the year ended December 31, 1995,
the seven months ended December 31, 1994, and the years ended May 31, 1994
and 1993, the net quantities of oil and gas produced, including that
attributable to the Company's 49.9% ownership interest in Crusader (which
includes the minority interests in Crusader's consolidated subsidiaries). The
production and sales information relating to properties or subsidiary
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 SEVEN MOS.
ENDED ENDED YEAR ENDED YEAR ENDED
DEC. 31, DEC. 31, MAY 31, DEC. 31,
1995 1994 1994 1993 1995
(IN MBBLS) (IN MMCF)
Colombia(2) 5,089 435 467 219 158
Argentina --- --- 18 6 ---
France(3) 498 514 1,053 1,467 ---
Indonesia(4) 255 186 441 536 ---
United States(5) 121 66 156 397 1,207
Canada(5) --- --- 102 279 ---
Crusader(6):
Australia 287 180 404 491 3,884
Canada 53 99 213 231 63
United States --- 8 32 65 ---
Total 6,303 1,488 2,886 3,691 5,312
GAS PRODUCTION
SEVEN MOS.
ENDED YEAR ENDED
DEC. 31, MAY 31,
1994 1994 1993
(IN MMCF)
Colombia(2) --- --- ---
Argentina --- --- ---
France(3) --- --- ---
Indonesia(4) --- --- ---
United States(5) 618 1,150 3,421
Canada(5) --- 3,521 14,329
Crusader(6):
Australia 2,707 4,202 3,988
Canada 96 150 121
United States 6 55 99
Total 3,427 9,078 21,958
____________________
(1) Includes natural gas liquids and condensate.
(2) Includes Ecopetrol reimbursement and excludes .4 million barrels of
oil produced and delivered 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 2 of Notes to Consolidated Financial Statements.
(3) In August 1995, Triton Europe sold its interest in its subsidiary,
Triton France S.A. ("Triton France").
(4) The Company has entered into an agreement to sell substantially all of
its assets in Indonesia, the consummation of which is subject to certain
conditions.
(5) During the fiscal year ended May 31, 1994, Triton Oil sold
substantially all its working interests in oil and gas reserves in the
United States and its common equity interest in Triton Canada. See note 3
of Notes to Consolidated Financial Statements. The Company has entered
into an agreement providing for the sale of substantially all of its
domestic royalty and mineral interests. See Item 2, "Properties - Oil and
Gas - United States."
(6) In June 1995, Crusader sold all of its interest in Ausquacan Energy
Limited and in September 1994, Crusader sold all of its oil and gas
interests in the United States.
The following tables summarize for the year ended December 31, 1995,
the seven months ended December 31, 1994, and the years ended May 31, 1994 and
1993: (i) the average sales price per barrel of oil and 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 SEVEN MOS. YEAR
ENDED ENDED YEAR ENDED ENDED
DEC. 31, DEC. 31, MAY 31, MAY 31, DEC. 31,
1995 1994 1994 1993 1995
Colombia $ 16.29 $ 14.37 $ 12.66 $15.86 $ 1.96
Argentina --- --- 9.22 14.00 ---
France 18.11 17.64 16.38 20.84 ---
Indonesia 17.77 17.06 16.29 19.49 ---
United States 13.62 15.65 14.19 16.83 1.49
Canada --- --- 16.43 16.75 ---
Crusader:
Australia 20.38 18.39 15.33 16.68 1.69
Canada 15.42 14.62 12.43 15.14 0.99
United States --- 17.75 15.23 19.90 ---
AVERAGE SALES PRICE
PER MCF OF GAS
SEVEN MOS.
ENDED YEAR ENDED
DEC. 31, MAY 31,
1994 1994 1993
Colombia $ --- $ --- $ ---
Argentina --- --- ---
France --- --- ---
Indonesia --- --- ---
United States 1.55 2.23 2.02
Canada --- 1.11 1.01
Crusader:
Australia 1.43 1.50 1.57
Canada 1.01 1.11 1.18
United States 1.25 1.53 1.57
PER EQUIVALENT BARREL (2)
AVERAGE SALES PRICE
YEAR SEVEN MOS.
ENDED ENDED YEAR ENDED
DEC. 31, DEC. 31, MAY 31,
1995 1994 1994 1993
Colombia $ 16.26 $ 14.37 $ 12.66 $ 15.86
Argentina --- --- 9.22 14.00
France 18.11 17.64 16.38 20.84
Indonesia 17.77 17.06 16.29 19.49
United States 10.68 11.77 13.75 14.06
Canada --- --- 8.13 7.18
Crusader:
Australia 13.29 9.53 11.31 12.50
Canada 13.87 13.43 11.83 14.50
United States --- 16.56 13.88 17.78
PER EQUIVALENT BARREL (2)
DEPLETION(3)
YEAR SEVEN MOS.
ENDED ENDED YEAR ENDED
DEC. 31, DEC. 31, MAY 31,
1995 1994 1994 1993
Colombia $2.67 $ 2.57 $ 1.96 $ 2.48
Argentina --- --- --- ---
France 3.14 4.15 8.97 15.19
Indonesia 0.95 1.60 3.09 7.93
United States 6.05 7.04 6.58 6.81
Canada --- --- 3.60 3.24
Crusader:
Australia 3.35 3.99 3.33 2.84
Canada 2.35 2.31 2.97 1.89
United States --- 5.22 13.82 19.95
PER EQUIVALENT BARREL (2)
PRODUCTION COST
YEAR SEVEN MOS.
ENDED ENDED YEAR ENDED
DEC. 31, DEC. 31, MAY 31,
1995 1994 1994 1993
Colombia $ 5.52 $ 9.87 $9.06 $11.01
Argentina --- --- 13.83 16.17
France 10.96 11.25 9.83 9.20
Indonesia 17.34 11.04 14.54 11.16
United States 1.03 0.85 7.00 2.55
Canada --- --- 4.24 3.91
Crusader:
Australia 4.77 4.01 3.97 4.22
Canada 7.52 7.96 7.44 7.42
United States --- 6.00 7.77 6.18
_________
(1) Includes natural gas liquids and condensate.
(2) Natural gas has been converted into equivalent barrels based on six
Mcf of natural gas per barrel.
(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 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 Field is
transported to the export terminal through pipelines owned by the Colombian
national oil company or joint stock companies partially owned by the Company.
This pipeline system is in the process of being upgraded to accommodate
additional production from the Cusiana and Cupiagua fields. See Item 2,
"Properties - Oil and Gas - Colombia" and Item 7, "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
Pertamina, the Indonesian national oil company, purchases crude oil
under a contract from the Triton-operated Enim concession in Indonesia, which
expires in October 1996, using a formula based on the average market price of
five different crude oils.
In the United States, the Company receives royalties on oil and gas
sold by others.
In Australia, natural gas is sold to the South Australian and New
South Wales markets primarily through the Pipelines Authority of South
Australia and the Australian Gas Light Company, respectively. Gas is supplied
to both of these markets under long-term contracts. Small volumes may be sold
outside these contracts on a "spot" basis when market demands allow. Crude
oil, condensate, natural gasolines and liquefied petroleum gases are freely
traded in both the domestic and export markets.
For a discussion of certain factors regarding the Company's markets
and potential markets that could affect future operations, see note 18 of
Notes to Consolidated Financial Statements.
Employees
At March 1, 1996, the Company employed approximately 245 full-time
employees in its oil and gas exploration and production operations, excluding
employees of Crusader and its subsidiaries.
OTHER OPERATIONS
In Australia, coal mining activities are conducted through
Crusader's 58.3%-owned subsidiary, Allied Queensland Coalfields Limited
("AQC"), the shares of which are publicly traded in Australia. AQC and its
subsidiaries have interests under exploration permits and mining leases
primarily in Australia. In November 1995, Crusader contributed all of its
interest in Koala Smokeless Fuels Limited, an operator of a coal briquetting
factory in Ireland, to a joint venture in exchange for preferred stock and 49%
of the common shares of the joint venture.
Crusader sold in March 1995 its gold business previously held by its
wholly owned subsidiary, Saracen Minerals Limited, for proceeds of $14.3
million.
DISCONTINUED AVIATION OPERATIONS
During the year ended December 31, 1995, the Company sold its
aviation services businesses and, therefore, has reflected the aviation sales
and services segment as discontinued operations.
EXECUTIVE OFFICERS OF THE COMPANY
The following table sets forth certain information regarding the
executive officers of the Company at March 1, 1996:
SERVED WITH
THE COMPANY
NAME AGE POSITION WITH THE COMPANY SINCE
Thomas G. Finck 49 Chairman of the Board and Chief
Executive Officer 1992
John P. Tatum 61 Executive Vice President,
Operations 1980
Nick De'Ath 47 Senior Vice President, Exploration 1993
Robert B. Holland, III 43 Senior Vice President, General Counsel and Secretary 1993
Peter Rugg 48 Senior Vice President and Chief Financial Officer 1993
A.E. Turner, III 47 Senior Vice President, Operations 1994
In August 1992, Mr. Finck became Director, President and Chief
Operating Officer of the Company. Effective January 1993, Mr. Finck became
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. Tatum has served as Executive Vice President, Operations of the
Company since 1991, and has served in various positions with the Company since
1980.
Mr. De'Ath became 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 1991 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 has served as Senior Vice President, General Counsel and
Secretary of the Company since 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 became 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 became 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 appointed 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 2. PROPERTIES
Certain statements in this Annual Report on Form 10-K, including
statements of the Company's and management's expectations, intentions, plans
and beliefs, including those contained in or implied by this Item 2,
"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 of
the Company's control. These forward-looking statements include statements
regarding proposed capital expenditures, management's plans and objectives for
future operations, and future economic performance; information on drilling
schedules, expected or planned production or transportation capacity,
employment of drilling rigs, completion of pipeline construction, 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 18 and 19 of Notes to Consolidated Financial Statements.
OIL AND GAS
Colombia
Through Triton Colombia, the Company has varying participation
interests in nine 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, 41,400 and
11,600 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, 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, as a result of
which 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 16 producing
wells and five gas injection wells. The injection wells will recycle to the
reservoir most of the gas that is associated with the oil production to
increase the oil recoverable over the life of the field. There are currently
six wells being drilled as part of 1996 activity. The plan for the year
includes the drilling and completion of 16 oil production and gas injection
wells, which would bring the year end total to 37 production and gas injection
wells. Full field development drilling is proceeding on a schedule which is
intended to have sufficient well capacity at all times to meet production
capacities of field facilities and export pipelines from the area.
In the Cupiagua Field, Triton Colombia and its working interest
partners completed the Cupiagua-4 well in the Barco Formation and the well
awaits connection to a pipeline system for early field production beginning in
1996. Tests of the well yielded 11,500 barrels of oil and 43 million cubic
feet of gas per day and confirmed the presence of oil and gas in the lower
inverted Mirador and Barco formations. The well extended the total oil column
in the field to 3,671 feet and no water contact was found. The Cupiagua-5
well, spudded in April, has penetrated the Mirador and Barco reservoirs and
the Cupiagua-6 well, spudded in May, has penetrated the Mirador, Barco and
Guadalupe reservoirs. The Cupiagua-5 well was the deepest well to date in
either the Cusiana Field or the Cupiagua Field. The well has reached a total
depth of approximately 18,000 feet and is currently being flow tested.
Appraisal and development drilling is proceeding with a three-rig drilling
program, which is expected to increase to four rigs by mid-year, and which is
expected to result in the completion of at least seven additional wells in
1996.
The Company believes considerable progress has been achieved in
reducing the time and expenditures required to drill and complete wells in the
Cusiana and Cupiagua fields. Although there can be no assurance, the Company
believes that further improvements can be achieved with experience gained in
the area. The Company expects that an additional rig will be mobilized as
needed in both fields to efficiently develop the oil and gas reserves.
Production Facilities and Pipelines. The four early production units of
the Cusiana Field central processing facility have been placed in service and
are designed to handle approximately 180,000 barrels of daily production
throughput from the Cusiana Field. Construction is under way to increase
production from the Cusiana and Cupiagua fields to at least 500,000 barrels
per day by the end of 1997. Additional pipeline capacity is required to meet
the transportation needs associated with full field development of these
fields. To that end, in April 1995, Triton Pipeline Colombia, Inc., a wholly
owned subsidiary of the Company, along with Ecopetrol, BP Colombia Pipelines
Ltd., Total Pipeline Colombie, S.A., IPL Enterprises (Colombia) Inc. and TCPL
International Investments Inc., completed the formation of a company,
Oleoducto Central S.A. ("OCENSA"), to own and finance pipeline and port
facilities to be constructed and operated for the transport of crude oil from
the Cusiana and Cupiagua fields to the port of Covenas. Triton's equity
participation in OCENSA is 9.6%. See Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Funding
Alternatives."
This pipeline project consists of a 793-kilometer (495-mile)
pipeline system from the Cusiana and Cupiagua fields to the Caribbean port of
Covenas. It loops and generally follows the route of the two existing
pipelines: the Central Llanos pipeline from El Porvenir to Vasconia and the
Oleoducto de Colombia ("ODC") pipeline from Vasconia to Covenas. A portion of
the Central Llanos loop already completed and pump station upgrades at El
Porvenir and Miraflores were acquired by OCENSA during 1995. Construction of
the remainder of the system is currently under way and scheduled to be
completed in 1997. Production from the Fields in 1995 was 5.1 million barrels
of oil, including Ecopetrol reimbursements. The current plan is to increase
production capacity to at least 500,000 barrels of oil per day by the end of
1997.
Other Colombia Areas
Triton owns the rights to six additional licenses in Colombia. In
the Middle Magdalena Valley basin and adjacent foothills, Triton owns a 100%
interest (before certain royalties and government participation) in the El
Pinal contract area, which covers approximately 142,250 acres approximately 330
kilometers (205 miles) north of Bogota. In the southern part of El Pinal,
Triton discovered and confirmed the La Liebre Field with two wells (the La
Liebre-1 and -2), which were tested at an aggregate of approximately 1,800
barrels of oil per day. In 1995, Ecopetrol approved Triton's application to
declare the La Liebre Field commercial, and initial production from the field
is expected to begin in 1996.
The Yumeca-1 exploratory well, located in the northern part of El
Pial, was drilled and tested in 1995. It was intended that the well test a
new play concept in the foothills of the Middle Magdalena Valley. The well
encountered hydrocarbon shows at various intervals but was plugged and
abandoned after four zones were tested. The well was drilled to a total depth
of 13,675 feet and failed to produce on test. Triton intends to drill an
additional exploratory well on the Yumeca trend in 1996.
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 in Colombia. 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 is
conducting environmental studies over the blocks and intends to acquire 175
kilometers (110 miles) of seismic over the Las Amelias block and 100
kilometers (62 miles) of seismic over the Guayabo A block.
In March 1996, the Company executed an agreement with Deminex
Colombia Petroleum GmbH ("Deminex") providing Deminex the right to earn a 50%
interest in the El Pinal, Guayabo A and B and Las Amelias contract areas. The
effectiveness of the agreement is conditioned on the approval by December 31,
1996 of Ecopetrol and the Ministry of Mines and Energy of Colombia. The
agreement provides for an initial payment by Deminex of approximately $13.4
million. In addition to costs associated with its 50% interest in the
contract areas, Deminex would pay certain direct exploratory costs of the
Company up to a maximum of approximately $16.8 million. All payments due
prior to the receipt of the requisite approvals will be held in escrow.
In the Upper Magdalena Valley basin, Triton Colombia has 22.5% and
20% interests (before certain royalties), respectively, in the 32,834-acre
Tolima-B and 32,240-acre San Luis contract areas, approximately 180 and 130
kilometers (110 and 80 miles), respectively, southwest of Bogota. HOCOL S.A.
is operator in both areas. Ecopetrol has granted commerciality of one field
in each of the two areas.
Malaysia-Thailand
In April 1994, Triton Thailand became a party to a production
sharing contract covering an area located offshore, designated as Block A-18
of the Malaysia-Thailand Joint Development Area. The contract area, 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, which has been
established by treaty to administer the Joint Development Area, and the
Malaysian national oil company. The treaty provides for the development of a
Joint Development Area that includes Block A-18. Triton Thailand previously
held a concession from Thailand that covered part of the Joint Development
Area.
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, CTOC, a
company owned equally by Triton Thailand and the Malaysian national oil
company.
The first phase of Block A-18 operations included a 2D seismic
survey covering approximately 5,700 kilometers (3,542 miles), a 3D seismic
survey conducted in 1995 and covering approximately 620 square kilometers (239
square miles) over the Cakerawala field, data analysis and the drilling of
three exploratory wells.
In August 1995, the first of the three wells, the Cakerawala-1A, was
tested at a combined flow rate of 58 MMcf of gas and 945 barrels of condensate
and oil per day. The well was drilled in approximately 200 feet of water to a
total depth of 7,878 feet. A second well, Suriya-1, was tested at 58 MMcf of
gas and 351 barrels of condensate per day. The Suriya-1 well was drilled in
approximately 180 feet of water to a total depth of 7,273 feet and is located
on a separate structure. The Suriya-1 well is located approximately 11
kilometers (7 miles) east-southeast of the Cakerawala-1A well.
A third well, Cakerawala East-1, was drilled in approximately 180
feet of water to a total depth of 11,808 feet. Cakerawala East-1 tested at
approximately 22 MMcf of gas and 138 barrels of condensate per day from the
two shallow sequences that constitute the principal producing zones for phase
one field development. The well confirmed anticipated fault separations from
the structure on which the Cakerawala-1A and Pilong wells (drilled by Exxon in
1979) were drilled, and experienced comparable sand thickness, flow rates and
gas-water contact, and lesser CO2 content, than the same sequences in the
Cakerawala-1A and Pilong wells. Intermediate sequences were wet and were not
tested. The well also confirmed the presence of deeper, overpressure
sandstone sequences, but the deeper zones tested wet or inconclusively due to
mechanical difficulties. The deeper zones remain an exploratory prospect for
future drilling.
CTOC's highest priority in 1996 is expected to be the further
delineation and development of the main Cakerawala field in anticipation of
negotiation of an initial gas sales contract. The Company believes that it
will be necessary to convince a buyer of the field's capacity to produce at
least 300 MMcf per day for at least 6,000 days in order to negotiate any
acceptable contract. To that end, CTOC expects to drill up to four appraisal
wells to delineate the Cakerawala Field in 1996. In addition, CTOC plans to
drill the last two wells of the initial five-well exploration program on two
structures adjacent to the gas-field discoveries.
The nature and extent of the second phase of development and
appraisal of the area will depend on the parties' assessment of the results of
phase-one activities.
Argentina
Through the Company's subsidiaries, Triton Argentina, Inc. and
Triton Resources Argentina, Inc. (collectively, "Triton Argentina"), the
Company holds a 100% working interest in the approximately 50,000 acre-Sierra
Azul Sur concession in the oil and gas producing Neuquen Basin in western
Argentina.
Triton Argentina also holds working interests in the Malargue Sur,
Cerro Doa Juana and Loma Cortaderal concessions in Argentina. In 1995, the
Company drilled two exploratory wells in the Malarge Sur Block, the El Fortin
X-1 and the Cerro Negro X-1. The El Fortin X-1 well was drilled to a total
depth of 7,485 feet and, although the well exhibited oil and gas shows, three
tests failed to produce oil to surface and the well was plugged and abandoned.
The Cerro Negro X-1 well was drilled to 12,153 feet and plugged and abandoned
after five tests failed to produce economic quantities of oil. A third well,
Cerro Chimango X-1, was drilled to a total depth of 6,067 feet and plugged and
abandoned in January 1996. Triton expects to relinquish its interest in the
Malarge Sur concession in March 1996.
Guatemala
Through the Company's subsidiary, Triton Guatemala S.A. ("Triton
Guatemala"), the Company has acquired an interest in two contiguous blocks in
Guatemala. During 1995, Triton Guatemala acquired 270 kilometers (169 miles)
of seismic data. The blocks lie on the border with Mexico in an extension of
the Chiapas fold belt province. Triton expects to test the extension of the
Chiapas fold belt trend into Guatemala.
Ecuador
Through the Company's subsidiary, Triton Ecuador, Inc. LLC ("Triton
Ecuador"), the Company holds an interest in Block 19 located in the Ecuadorian
foothills in the Oriente Basin. During 1995, Triton farmed out a 30% interest
in the area to Vintage Petroleum Ecuador, Inc. and a 15% interest to Ranger
Oil Limited, in each case subject to government approval. The partners' work
program commitments for Block 19 consist of the acquisition of 400 kilometers
of new seismic data and the drilling of two exploratory wells during a
four-year exploration period. An environmental impact study was completed in
1995 and a 420 kilometer (263 mile)-seismic acquisition program is expected to
be completed in 1996. Exploratory drilling is planned to begin in 1997.
China
The Company's subsidiary, Triton China, Inc. LLC ("Triton China"),
signed a production sharing contract with the China National Offshore Oil
Company in February 1995 giving the Company the right to explore and develop
Contract Area 16/22 located approximately 175 kilometers (110 miles) offshore
from Hong Kong in water depths ranging from 300 to 650 feet. The 791,000-acre
block is in the Huizhou Sub-basin of the Pearl River Mouth Basin. The block
has a primary three year exploration term with a commitment of reprocessing
500 kilometers (310 miles) of existing seismic and the drilling of an
exploratory well for a total expenditure of not less than $7.5 million. In
April 1995, the Company was awarded the adjacent 1.9 million acre block,
Contract Area 16/01, as a Joint Study Area. Seismic reprocessing on both
blocks, of an aggregate of approximately 4,000 kilometers (2,500 miles), was
completed in 1995 and the Company expects to drill its first exploratory well
in Contract Area 16/22 in 1996.
Italy
The Company's subsidiary, Triton Mediterranean Oil & Gas N.V.
("Triton Mediterranean"), has a 40% interest in the DR71 and DR72 licenses
operated by Enterprise Oil, plc, in the Adriatic Sea offshore Italy. One
exploratory well is planned for 1996. Triton has applied for four new
licenses onshore in the southern Apennine Mountains and one new license
offshore. In 1995, the Monte Caruso license, in which Triton Mediterranean
held a 10.91% interest, was relinquished.
France
In August 1995, the Company sold its wholly owned subsidiary, Triton
France, to Coparex International, a French oil and gas company. The Company's
assets in France primarily consisted of the Villeperdue field in which Triton
France had a 50% interest.
Crusader
Oil and gas activities in Australia are conducted through the
Company's 49.9% owned affiliate, Crusader, whose shares are publicly traded in
Australia. Crusader has an interest in the Cooper Basin Gas and Liquids Unit
of South Australia. Within the Gippsland and Otway Basins of Victoria,
Crusader has interests in two offshore and one onshore exploration licenses,
respectively. Crusader has an approximate 48.9% equity interest in Australian
Hydrocarbons Limited ("AHY"), a publicly traded Australian company. Two
Crusader directors and one alternate Crusader director are members of the
three-member AHY Board of Directors and Crusader consolidates AHY in its
financial and reserve disclosures. AHY owns various interests in oil and gas
exploration projects in Australia including the South West Queensland Gas
Unit.
In 1995, Crusader sold substantially all of its interests in oil and
gas exploration, production and processing in Canada and Argentina.
Indonesia
Triton Indonesia is the operator of a secondary
recovery/rehabilitation project on the southeastern portion of the island of
Sumatra pursuant to a contract that expires in October 1996. In 1995, Triton
Indonesia acquired the 6% interest in this project owned by New Zealand
Petroleum, through its wholly owned subsidiary Triton Oil (N.Z.) Limited, and
entered into a definitive agreement to sell its entire interest in this
project, the consummation of which is subject to certain conditions.
United States
During the fiscal year ended May 31, 1994, the Company sold
substantially all of its working interests in oil and gas reserves in the
United States, retaining primarily royalty and mineral interests. In March
1996, the Company entered into an agreement providing for the sale of
substantially all of its royalty and mineral interests, the consummation of
which is subject to customary conditions. The net proceeds from the sale,
which will be made effective as of January 1, 1996, are expected to be
approximately $23.8 million and are expected to result in a gain of
approximately $4 million.
RESERVES
The following tables set forth the estimated oil and gas reserves of
the Company and the estimated discounted future net cash flows before income
taxes at December 31, 1995. The first table is a summary of separate reports
of estimates of the Company's net proved reserves, estimated 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 own petroleum engineers with respect to all other reserves. 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 in Colombia, Indonesia and
the United States and its proportionate interest in reserves owned in
Australia by Crusader. The second table sets forth, for the net quantities so
reported, the future net cash flows (by reserve categories and country of
location) discounted to present value at an annual rate of 10%. The discounted
future net cash flows were calculated in accordance with current Securities
and Exchange Commission ("Commission") guidelines concerning the use of
constant oil and gas prices and operating costs in reserve evaluations.
Future income tax expenses have not been taken into account in estimating the
future net cash flows. At December 31, 1995, the Company had no proved
developed or proved undeveloped reserves in Malaysia-Thailand, Argentina,
Guatemala, Ecuador, Italy or China. See note 25 of Notes to Consolidated
Financial Statements.
The estimated reserves and future net cash flows set forth in the
tables below include information attributable to the Company's 49.9% ownership
interest in Crusader (which includes the minority interests in Crusader's
consolidated subsidiaries). Oil reserves data include natural gas liquids and
condensate.
Net Proved Reserves at December 31, 1995:
PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
Colombia(1) 65,856 10,515 55,570 5,175 121,426 15,690
Indonesia 170 -- -- -- 170 --
United States 594 6,957 -- -- 594 6,957
Crusader:
Australia 2,508 45,390 811 15,525 3,319 60,915
Total 69,128 62,862 56,381 20,700 125,509 83,562
Future net cash flows before income taxes discounted at 10% per annum at
December 31, 1995 (in thousands of dollars):
PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
Colombia(1) $ 558,420 $ 245,245 $ 803,665
Indonesia 626 -- 626
United States 11,150 -- 11,150
Crusader:
Australia 41,207 7,136 48,343
Total $ 611,403 $ 252,381 $ 863,784
___________________
(1) Includes liquids to be recovered from Ecopetrol as reimbursement for
precommerciality expenditures. See Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
Future net cash flows from reserves at December 31, 1995, were calculated on
the basis of prices in effect on that date. The prices used by country in
this calculation were:
OIL GAS
(PER BBL) (PER MCF)
Colombia $18.96 $1.22
Indonesia 17.15 --
United States 14.18 1.69
Crusader:
Australia 16.72 1.77
Revenue and costs associated with the Australian reserves are
reported in US dollar equivalents based on an exchange value of Australian $1
equivalent to US$0.7428. The Colombian and Indonesian reserves are evaluated
in United States dollars.
The foregoing estimated pretax discounted future net cash flow
figures relate only to the reserves tabulated above. The estimates were
prepared without consideration of income taxes and indirect costs such as
interest and administrative expenses (except administrative expenses billed by
the operator), and are not to be construed as representative of the fair
market values of the properties to which they relate.
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 nor can there be assurance that the proved undeveloped
reserves will be developed within the periods anticipated. The Company
emphasizes with respect to the estimates prepared by independent petroleum
engineers, as well as those estimates prepared by the Company's engineers,
that the discounted future net cash flows should not be construed as
representative of the fair market value of the proved oil and gas properties
belonging to the Company, since discounted future net cash flows are based
upon projected cash flows that provide for neither changes in oil and gas
prices nor for escalation of expenses and capital costs. The meaningfulness
of such estimates is highly dependent upon the accuracy of the assumptions
upon which they were based. See note 25 of Notes to Consolidated Financial
Statements.
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.
ACREAGE
The following table shows the total gross and net developed and
undeveloped oil and gas acreage (including acreage attributable to mineral,
royalty and overriding royalty interests) held by Triton at December 31, 1995,
including acreage attributable to the Company's 49.9% ownership interest in
Crusader (which includes the minority interests in Crusader's consolidated
subsidiaries). "Gross" refers to the total number of acres in an area in
which the Company holds any 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 28 3 1,996 1,960
Malaysia-Thailand -- -- 731 366
Argentina -- -- 372 372
Guatemala -- -- 608 608
Ecuador -- -- 494 272
Italy -- -- 494 198
United Kingdom (North Sea) -- -- 111 12
China -- -- 2,742 2,742
Indonesia 3 3 70 70
United States 223 14 607 120
Crusader:
Australia 1,081 21 26,557 514
Total 1,335 41 34,782 7,234
____________________
(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. Well interests include wells attributable to the Company's
49.9% ownership interest in Crusader (which includes the minority interests in
Crusader's consolidated subsidiaries).
The following table summarizes the approximate total gross and net
working interests held by Triton in productive wells at December 31, 1995:
PRODUCTIVE WELLS
GROSS NET
OIL GAS OIL GAS
Colombia 27 1 5.96 0.20
Indonesia 73 -- 73.00 --
Crusader:
Australia 442 488 10.00 11.00
Total 542 489 88.96 11.20
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 year ended December 31, 1995, the seven months ended December
31, 1994, and for the years ended May 31, 1994 and 1993.
GROSS EXPLORATORY WELLS
PRODUCTIVE (1)
YEAR SEVEN MOS.
ENDED ENDED YEAR ENDED
DEC. 31, DEC. 31, MAY 31,
1995 1994 1994 1993
Colombia 1 1 3 4
Malaysia-Thailand 2 --- --- ---
Argentina --- --- --- ---
Italy --- --- --- ---
New Zealand --- --- 1 ---
Canada --- --- --- 2
Crusader(1):
Argentina 1 1 --- ---
Australia 23 9 5 ---
Canada --- --- --- 1
United States --- --- 2 2
Philippines --- --- --- ---
Total 27 11 11 9
GROSS EXPLORATORY WELLS
DRY
YEAR SEVEN MOS.
ENDED ENDED YEAR ENDED
DEC. 31, DEC. 31, MAY 31,
1995 1994 1994 1993
Colombia 2 --- --- ---
Malaysia-Thailand --- --- --- ---
Argentina 2 --- --- ---
Italy --- --- 1 ---
New Zealand --- --- --- ---
Canada --- --- --- 3
Crusader(1):
Argentina 2 --- --- ---
Australia 11 3 2 2
Canada --- --- 1 1
United States --- 2 1 4
Philippines --- 1 --- ---
Total 17 6 5 10
GROSS EXPLORATORY WELLS
TOTAL
SEVEN MOS.
YEAR ENDED ENDED YEAR ENDED
DEC. 31, DEC. 31, MAY 31,
1995 1994 1994 1993
Colombia 3 1 3 4
Malaysia-Thailand 2 --- --- ---
Argentina 2 --- --- ---
Italy --- --- 1 ---
New Zealand --- --- 1 ---
Canada --- --- --- 5
Crusader(1):
Argentina 3 1 --- ---
Australia 34 12 7 2
Canada --- --- 1 2
United States --- 2 3 6
Philippines --- 1 --- ---
Total 44 17 16 19
GROSS DEVELOPMENT WELLS
PRODUCTIVE (1) DRY
YEAR SEVEN MOS. YEAR
ENDED ENDED YEAR ENDED ENDED
DEC. 31, DEC. 31, MAY 31, DEC. 31,
1995 1994 1994 1993 1995
Colombia 9 3 --- --- ---
France --- --- --- 1 ---
Indonesia --- --- 3 --- ---
Canada --- --- --- 26 ---
Crusader(1):
Australia 5 8 13 15 1
Canada --- --- 9 26 ---
United States --- 1 --- --- ---
Total 14 12 25 68 1
GROSS DEVELOPMENT WELLS
DRY
TOTAL
SEVEN MOS. YEAR SEVEN MOS.
ENDED YEAR ENDED ENDED ENDED YEAR ENDED
DEC. 31, MAY 31, DEC. 31, DEC. 31, MAY 31,
1994 1994 1993 1995 1994 1994 1993
Colombia --- --- --- 9 3 --- ---
France --- --- --- --- --- --- 1
Indonesia --- 1 --- --- --- 4 ---
Canada --- --- 3 --- --- --- 29
Crusader(1):
Australia 1 1 5 6 9 14 20
Canada --- --- 4 --- --- 9 30
United States --- 1 --- --- 1 1 ---
Total 1 3 12 15 13 28 80
____________________
(1) 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 year ended
December 31, 1995, the seven months ended December 31, 1994 and for the years
ended May 31, 1994 and 1993 (those wells acquired or disposed of since May 31,
1992 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
YEAR SEVEN MOS. YEAR SEVEN MOS.
ENDED ENDED YEAR ENDED ENDED ENDED
DEC. 31, DEC. 31, MAY 31, DEC. 31, DEC. 31,
1995 1994 1994 1993 1995 1994
Colombia(2) 0.12 0.12 1.24 1.36 2.00 ---
Malaysia-Thailand 1.00 --- --- --- --- ---
Argentina --- --- --- --- 2.00 ---
Italy --- --- --- --- --- ---
New Zealand --- --- 0.20 --- --- ---
Canada(3) --- --- --- 1.50 --- ---
Crusader(4):
Argentina 0.06 0.12 --- --- 0.12 ---
Australia 0.35 0.15 0.10 --- 0.29 0.63
Canada --- --- --- 0.10 --- ---
United States --- --- 0.20 0.10 --- 0.40
Philippines --- --- --- --- --- 0.20
Total 1.53 0.39 1.74 3.06 4.41 1.23
NET EXPLORATORY WELLS
TOTAL
YEAR SEVEN MOS.
YEAR ENDED ENDED ENDED YEAR ENDED
MAY 31, DEC. 31, DEC. 31, MAY 31,
1994 1993 1995 1994 1994 1993
Colombia(2) --- --- 2.12 0.12 1.24 1.36
Malaysia-Thailand --- --- 1.00 --- --- ---
Argentina --- --- 2.00 --- --- ---
Italy 0.10 --- --- --- 0.10 ---
New Zealand --- --- --- --- 0.20 ---
Canada(3) --- 1.50 --- --- --- 3.00
Crusader(4):
Argentina --- --- 0.18 0.12 --- ---
Australia 0.02 0.30 0.64 0.78 0.12 0.30
Canada 0.50 0.10 --- --- 0.50 0.20
United States 0.10 0.30 --- 0.40 0.30 0.40
Philippines --- --- --- 0.20 --- ---
Total 0.72 2.20 5.94 1.62 2.46 5.26
NET DEVELOPMENT WELLS
PRODUCTIVE (1)
YEAR SEVEN MOS.
ENDED ENDED YEAR ENDED
DEC. 31, DEC. 31, MAY 31,
1995 1994 1994 1993
Colombia (2) 1.08 0.36 --- ---
France --- --- --- 0.50
Indonesia(3) --- --- 3.00 ---
Canada(3) --- --- --- 13.50
Crusader(4):
Australia 0.10 0.17 0.40 0.40
Canada --- --- 2.00 4.20
United States --- 0.20 --- ---
Total 1.18 0.73 5.40 18.60
NET DEVELOPMENT WELLS
DRY
YEAR SEVEN MOS.
ENDED ENDED YEAR ENDED
DEC. 31, DEC. 31, MAY 31,
1995 1994 1994 1993
Colombia (2) --- --- --- ---
France --- --- --- ---
Indonesia(3) --- --- 1.00 ---
Canada(3) --- --- --- 1.60
Crusader(4):
Australia 0.02 0.01 0.02 0.10
Canada --- --- --- 0.70
United States --- --- 0.20 ---
Total 0.02 0.01 1.22 2.40
NET DEVELOPMENT WELLS
TOTAL
YEAR SEVEN MOS.
ENDED ENDED YEAR ENDED
DEC. 31, DEC. 31, MAY 31,
1995 1994 1994 1993
Colombia (2) 1.08 0.36 --- ---
France --- --- --- 0.50
Indonesia(3) --- --- 4.00 ---
Canada(3) --- --- --- 15.10
Crusader(4):
Australia 0.12 0.18 0.42 0.50
Canada --- --- 2.00 4.90
United States --- 0.20 0.20 ---
Total 1.20 0.74 6.62 21.00
____________________
(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) Not adjusted to reflect any minority interests.
(4) Adjusted to reflect the Company's 49.9% interest in Crusader.
OTHER
The Company owns or has interests in oil and gas production
facilities relating to its oil and gas production operations throughout the
world. In addition, 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 19 of Notes to Consolidated Financial Statements.
ITEM 3. LEGAL PROCEEDINGS
LITIGATION
The Company's domestic oil and gas subsidiary, Triton Oil, is among
several defendants in two related lawsuits brought in the Superior Court of
the State of California, County of Los Angeles, by National Union Fire
Insurance Company ("National Union"), The Restaurant Enterprises Group and
Travelers Indemnity Company ("Travelers"). The lawsuits allege, among other
things, that the defendants' negligence contributed to the collapse of a hotel
and the flooding of a restaurant in a 1988 tidal wave at King Harbor in
Redondo Beach, California, which allegedly caused $22 million in damages and
related attorneys' fees. In the case of Triton Oil, the alleged negligence
was Triton Oil's drilling of nearby oil wells and alleged resulting ground
subsidence which purportedly lowered the height of the King Harbor breakwater.
The City of Redondo Beach has also filed a suit in the Superior Court against
the Company and Triton Oil seeking indemnity for certain amounts paid by the
City to settle the foregoing lawsuits and other claims arising out of the
flooding. The Company believes that it and Triton Oil have meritorious
defenses and intends to defend the suits vigorously.
During the quarter ending September 30, 1995, the United States
Environmental Protection Agency 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 June 1994, the Company and numerous other defendants were served
by the State of Nevada, Division of Environmental Protection (the "NDEP") in a
state court proceeding in Clark County, Nevada. The action seeks to hold the
defendants responsible for remediation of certain underground water
contamination at the McCarran International Airport and seeks civil penalties
of up to $25,000 per day. The Company has been advised by the NDEP that the
action was filed to toll the running of the statute of limitations on certain
potential causes of action. The Company denies responsibility for the
contamination at issue and does not believe that the action will have a
material adverse affect on its consolidated financial position.
The Company is also subject to ordinary litigation that is
incidental to its business.
REGULATORY MATTER
The Company continues to cooperate with inquiries by the Securities
and Exchange Commission and the Department of Justice regarding possible
violations of the Foreign Corrupt Practices Act in connection with the
Company's operations in Indonesia. Based upon the information available to
the Company to date, the Company believes that it will be able to resolve any
issues that either agency ultimately might raise concerning these matters in a
manner that would not have a material adverse effect on the Company's
consolidated financial position.
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 fiscal year covered by this report to security holders, through the
solicitation of proxies or otherwise. In November 1995, the Company obtained
the consent of the holders of its publicly traded notes to certain amendments
to the indentures under which they were issued. See Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations." The
Company has called a special meeting of its stockholders to be held on March
25, 1996 at which the stockholders will vote on the Reorganization. The
Company and Triton Cayman have filed with the Securities and Exchange
Commission a Proxy Statement/Joint Prospectus dated as of February 23, 1996
relating to the special meeting and the securities to be issued if the
Reorganization is consummated.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Triton's common stock is listed on the New York Stock Exchange and
is traded under the symbol OIL. Set forth below are the high and low closing
sales prices of Triton's common stock as reported on the New York Stock
Exchange Composite Tape for the periods indicated:
CALENDAR PERIODS HIGH LOW
1993:
First Quarter 38 7/8 28 3/8
Second Quarter 43 7/8 33 1/2
Third Quarter 34 3/4 27 3/4
Fourth Quarter 33 3/4 28 3/4
1994:
First Quarter 32 26 3/4
Second Quarter 35 7/8 25 1/8
Third Quarter 36 30
Fourth Quarter 37 1/4 31
1995:
First Quarter 38 1/4 31
Second Quarter 48 1/2 37 1/8
Third Quarter 55 44 1/4
Fourth Quarter 57 3/8 44
1996:
First Quarter* 57 1/2 47 7/8
_______________________
*Through March 7, 1996.
Triton has not declared any cash dividends on its shares of common
stock 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 indentures under which its publicly traded notes
were issued.
Under applicable corporate law, the Company may pay dividends or
make other distributions to its shareholders, out of surplus and, if there is
no surplus, out of net profits for the current year and/or the preceding year,
unless the net assets of the corporation are less than the capital represented
by issued and outstanding stock having a preference on asset distributions.
"Surplus" is defined as the excess of the net assets of the Company over its
stated capital (stated capital being the total par value of the Company's
outstanding capital stock plus all amounts transferred to stated capital,
minus legal reductions from such sum).
In connection with the acquisition in March 1994 of the common
shares of Triton Europe not owned by Triton, the Company issued 522,460 shares
of its 5% Convertible Preferred Stock ("5% preferred stock") to the former
holders of the Triton Europe ordinary shares. Each share of the 5% preferred
stock may be converted into one share of Triton common stock at any time on or
after October 1, 1994. Each share of 5% preferred stock bears a cash
dividend, which has priority over dividends on Triton's common stock, equal to
5% per annum on the redemption price of $34.41 per share, payable
semi-annually on March 30 and September 30, commencing on September 30, 1994.
The 5% preferred stock has priority over Triton common stock upon liquidation,
and may be redeemed at Triton's option at any time on or after March 30, 1998
(or such earlier date as at least 75% of the shares originally issued have
been converted into common stock) for cash equal to the redemption price. Any
shares of 5% preferred stock that remain outstanding on March 30, 2004 must be
redeemed at the redemption price either for cash or, at the Company's option,
for shares of Triton common stock. See notes 4 and 13 of Notes to
Consolidated Financial Statements.
In May 1995, the Board of Directors of the Company adopted a new
Shareholder Rights Plan under which preferred stock rights were issued to
holders of its common stock at the rate of one right for each share of common
stock held as of the close of business on June 2, 1995. The rights were
issued in place of the Company's previous preferred share purchase rights
issued in 1990, which were redeemed.
Generally, the rights become exercisable only if a person acquires
beneficial ownership of 15% or more of Triton's Common Stock or announces a
tender offer for 15% or more of the common stock. If, among other events, any
person becomes the beneficial owner of 15% or more of Triton's common stock,
each right not owned by such person generally becomes the right to purchase
such number of shares of common stock of the Company, which is equal to the
amount obtained by dividing the right's exercise price (currently $120) by 50%
of the market price of the common stock 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 Triton's Common Stock, 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 7, 1996, there were 6,236 record holders of the Company's
common stock.
THE REORGANIZATION
If the Reorganization is consummated, each outstanding share of
common stock of the Company at the effective time of the Reorganization (the
"Effective Time") (other than shares held in treasury and shares as to which
an election to receive Equity Units (as defined below) has been made and not
withdrawn, subject to certain limitations) will be automatically converted
into one Class A Ordinary Share of Triton Cayman. Holders of not less than 15%
but not more than 25% of the outstanding shares of Common stock at the
Effective Time, in the aggregate, may make an unconditional election to
receive an equity unit ("Equity Unit") consisting of one Class B Ordinary
Share of Triton Cayman and one-tenth of one share of participating preferred
stock of the Company for each share of Common Stock of the Company
owned in lieu of such shares being converted into Class A Ordinary Shares.
Each such Class B Ordinary Share and one-tenth of a share of participating
preferred stock would be paired and after such pairing could only be traded
together as a unit. If holders of less than 15% of the outstanding shares of
the Company's common stock, in the aggregate, elect to receive Equity Units,
no Equity Units will be issued and all such shares would be automatically
converted into Class A Ordinary Shares of Triton Cayman. The Class A Ordinary
Shares have been approved for listing on the New York Stock Exchange under the
symbol "OIL," the same symbol under which the Company's common stock is
currently listed, and the Equity Units have been approved for listing on the
New York Stock Exchange under the symbol "OIL.B".
ITEM 6. SELECTED FINANCIAL DATA
AS OF OR
FOR SEVEN
AS OF OR FOR YEAR ENDED MONTHS ENDED
DECEMBER 31, DECEMBER 31,
1995 1994 1994
(unaudited)
OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA):
Sales and other operating revenues (1) $ 107,472 $ 32,952 $ 20,736
Earnings (loss) from continuing operations (1) (2) 6,541 (49,610) (26,630)
Earnings (loss) before extraordinary
items and cumulative effect of
accounting change 2,720 (52,701) (27,708)
Net earnings (loss) (2) 2,720 (52,701) (27,708)
Weighted average number of common
shares outstanding 35,147 34,916 34,944
Earnings (loss) per common share:
Continuing operations (1) (2) $ 0.16 $ (1.43) $ (0.78)
Before extraordinary item and
cumulative effect of accounting change 0.05 (1.52) (0.81)
Net earnings (loss) 0.05 (1.52) (0.81)
BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment $ 524,381 $ 399,658 $ 399,658
Total assets 824,167 619,201 619,201
Long-term debt 401,190 315,258 315,258
Redeemable preferred stock of
subsidiaries --- --- ---
Stockholders' equity 246,025 237,195 237,195
CERTAIN OIL AND GAS DATA (3):
Production
Oil (Mbbls) (4) 6,303 2,534 1,488
Gas (MMcf) 5,312 5,516 3,427
Average sales price
Oil (per bbl) $ 16.60 $ 15.26 $ 16.41
Gas (per Mcf) $ 1.64 $ 1.51 $ 1.44
AS OF OR FOR YEAR ENDED MAY 31,
1994 1993 1992 1991
OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA):
Sales and other operating revenues (1) $ 43,208 $ 84,414 $ 90,724 $ 118,667
Earnings (loss) from continuing operations (1) (2) (4,597) (76,509) (81,333) (7,390)
Earnings (loss) before extraordinary
items and cumulative effect of
accounting change (9,341) (93,552) (94,037) 4,745
Net earnings (loss) (2) (9,341) (89,535) (94,037) 6,185
Weighted average number of common
shares outstanding 34,775 34,241 29,898 20,368
Earnings (loss) per common share:
Continuing operations (1) (2) $ (0.13) $ (2.23) $ (2.77) $ (0.64)
Before extraordinary item and
cumulative effect of accounting change (0.27) (2.73) (3.19) (0.04)
Net earnings (loss) (0.27) (2.61) (3.19) 0.03
BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment $ 308,498 $ 330,151 $ 385,979 $ 391,862
Total assets 616,101 561,931 571,169 553,809
Long-term debt 294,441 159,147 27,587 160,667
Redeemable preferred stock of
subsidiaries --- 11,399 12,972 13,608
Stockholders' equity 263,422 255,432 336,013 186,503
CERTAIN OIL AND GAS DATA (3):
Production
Oil (Mbbls) (4) 2,886 3,691 3,777 4,034
Gas (MMcf) 9,078 21,958 24,366 25,607
Average sales price
Oil (per bbl) $15.15 $ 18.67 $ 19.26 $ 23.61
Gas (per Mcf) $ 1.44 $ 1.27 $ 1.21 $ 1.31
____________________
(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,
1993, 1992 and 1991 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 $1.1
million, $14.7 million, $1.0 million, $45.8 million, $99.9 million, $48.8
million and $2.7 million for the years ended December 31, 1995 and 1994
(unaudited), the seven months ended December 31, 1994 and the years ended
May 31, 1994, 1993, 1992 and 1991, respectively.
(3) Information presented includes the 49.9% equity investment in Crusader
Limited.
(4) Includes natural gas liquids and condensate. Production for the year
ended December 31, 1995 excludes .4 million barrels produced and delivered
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Liquidity, Capital Requirements and Funding Alternatives
Cash, cash equivalents and marketable securities totaled $95.5
million and $72.3 million at December 31, 1995 and December 31, 1994,
respectively. Working capital was $85.6 million at December 31, 1995, an
increase of $55.9 million from December 31, 1994.
The Company's capital expenditures and other capital investments
were $178.2 million, $89.9 million, $86.8 million and $124.9 million during
the year ended December 31, 1995, the seven months ended December 31, 1994 and
the years ended May 31, 1994 and 1993, respectively, primarily for exploration
and development of the Cusiana and Cupiagua fields (the "Fields") in Colombia.
The 1995 capital spending program was funded with cash flow from operations
(including a forward sale of Cusiana crude oil), cash on hand, proceeds from
marketable securities, sale of assets ($20.9 million) and net borrowings
($36.3 million).
In May 1995, the Company sold 10.4 million barrels of oil 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 in Colombia becomes self-financing, which is expected
in 1997, and when certain other conditions are met. The delivery requirement
represents approximately 15% of the Company's currently projected Cusiana and
Cupiagua production over the five-year delivery period that began in June
1995.
During 1995, the Company repaid $25 million of short-term debt, and
borrowed $48.6 million, net under a $65 million long-term revolving credit
facility. The facility matures in October 1997 and is secured by the
Company's marketable securities portfolio and Crusader common stock.
Capital expenditures incurred during the seven months ended December
31, 1994 were funded by cash on hand, net proceeds from marketable securities
($30.8 million) and borrowings ($17.2 million). The principal sources for
funds for the year ended May 31, 1994 used to support operations, capital
expenditures and debt repayment were $100 million in proceeds from the sale of
assets and approximately $124 million from the issuance of $170 million
principal amount of 9 3/4% Senior Subordinated Discount Notes ("9 3/4% Notes")
due December 2000. Proceeds of approximately $126 million from the issuance
of $240 million principal amount of 12 1/2% Senior Subordinated Discount Notes
("1997 Notes") due November 1997 and asset sales ($29.4 million) were the
primary sources of funds during fiscal 1993.
Continued development of the Fields, including drilling and
construction of additional production facilities, will require significant
capital. In 1995 and early 1996, Carigali-Triton Operating Company ("CTOC")
discovered gas on its first three wells on Block A-18 in the Malaysia-Thailand
Joint Development Area in the Gulf of Thailand. Further exploration and
development activities on Block A-18, as well as exploratory drilling in other
countries, will also require substantial capital. The Company's capital
budget for the year ending December 31, 1996 is approximately $260 million,
excluding capitalized interest, of which approximately $157 million relates to
the Fields, $34 million relates to Block A-18, $40 million relates to the
Company's exploration and drilling program in other parts of the world and $29
million relates to capital contributions to Oleoducto Central S.A. ("OCENSA").
Capital requirements for full field development of the Fields are expected to
continue at substantial levels into 1997 and capital requirements for
exploration and development relating to Block A-18 are expected to increase
significantly into 1998.
In December 1994, the Company, along with other investors formed an
independent company, OCENSA, to own, expand, finance and operate a pipeline
system from the Fields to the Caribbean port of Covenas. The Company's
ownership percentage is 9.6%. OCENSA's capitalization plan contemplates an
ultimate capital structure of approximately 30% equity from the Company and
other investors and 70% debt. OCENSA has raised significant amounts of debt
in separate tranches supported by various agreements with the Company or its
partners as the case may be (relating, in particular, to tariffs on each
partner's throughput). The Company assisted OCENSA in securing one such
tranche for $60 million in 1995, which is supported by the Company's tariff
commitments for its share of production from the Fields. The Company has
agreed to assist OCENSA in raising an additional $60 million in 1996. In the
event such amount cannot be raised, OCENSA may call for an advance from the
Company.
In November 1995, the Company signed a $45 million loan agreement
supported by a guarantee issued by the Export-Import Bank of the United
States. The loan finances expenditures for exported U.S. goods and services
for phase one development of the Cusiana Field in Colombia. The Company
borrowed approximately $43 million against this facility in early 1996.
As part of the forward oil sale transaction, Morgan Guaranty Trust
Company of New York agreed to purchase up to $40 million of additional
production on a forward sale basis in the event that the Company is otherwise
unable to meet its cash call obligations in respect of the Cusiana and
Cupiagua fields project. The number of barrels would be determined based on a
formula intended to reflect their fair market value. The Company does not
expect, however, to sell any production under this agreement.
The Company expects to meet capital needs in the future with a
combination of some or all of the following: the long-term revolving credit
facility described above, cash flow from its Colombian operations, cash on
hand and marketable securities, asset sales, and the issuance of debt and
equity securities. As a result of certain modifications to the indenture
relating to the 1997 Notes effected in November 1995, the Company's
indebtedness limitation was increased to permit the Company to incur total
indebtedness (excluding certain permitted indebtedness) of up to 25% of the
sum of its indebtedness and market capitalization of its capital stock. In
addition, the indenture relating to the 1997 Notes was modified to eliminate
the Company's repurchase obligation in the event the Company's net worth were
to fall below a certain level.
Results of Operations
The Company changed its fiscal year end from May 31 to December 31
beginning in 1995. The Consolidated Statements of Operations report the
Company's results of operations for the year ended December 31, 1995, the
seven months ended December 31, 1994 and the years ended May 31, 1994 and
1993; however, Management's Discussion and Analysis compares the calendar
years ended December 31, 1995 and 1994 and the fiscal years ended May 31, 1994
and 1993. The results of operations for the year ended December 31, 1994 have
not been audited.
Years Ended December 31, 1995 and 1994
Revenues
Sales and other operating revenues were $107.5 million and $33
million in 1995 and 1994, respectively. Revenues in Colombia increased by
$81.6 million in 1995 primarily due to greater production capacity from the
recent installation of four production units in the Cusiana central processing
facility and higher oil prices in Colombia ($16.29 per barrel in 1995,
compared with $13.16 per barrel in 1994) resulting from more favorable market
conditions and batching of Cusiana crude beginning in mid-1995. The 1995
results also included revenues of $14.5 million relating to the reimbursement
of pre-commerciality costs for the Cusiana Field. Ecopetrol is obligated to
reimburse the Company for an additional $7 million of Cusiana
pre-commerciality costs, most of which will be recorded as revenue. The
reimbursements depend on the timing and amount of Cusiana production. Oil
sales in France were $5.8 million higher in 1994 than in 1995, primarily
because of the sale of Triton France in August 1995.
Costs and Expenses
Operating expenses increased $14.1 million to $35.3 million in 1995,
while depreciation, depletion and amortization increased $9.5 million to $23.2
million in 1995. Higher production in Colombia increased operating expenses
by $19.1 million and depreciation, depletion and amortization by $13.4
million. The Company's operating costs per equivalent barrel were $6.28 and
$10.75 in 1995 and 1994, respectively. The sale of Triton France reduced
operating expenses and depletion in 1995 by $3.6 million and $3.7 million,
respectively. The 1994 results included an accrual of $1.1 million for
environmental clean-up costs in the United States.
General and administrative expenses decreased from $29.1 million in
1994 to $25.7 million in 1995, primarily due to increased capitalization of
general and administrative expenses from $14.9 million in 1994 to $21.1
million in 1995 resulting from increased exploration and development
activities.
Writedown of assets in 1994 was related to oil properties in France,
Indonesia and the United States under application of the Securities and
Exchange Commission (the "Commission") full cost ceiling limitation.
Other Income and Expenses
Interest income was $8 million and $8.1 million in 1995 and 1994,
respectively. Interest expense increased by $12 million in 1995 due to higher
debt outstanding and lower capitalized interest, primarily as a result of
commercial level production beginning in Colombia during late 1994.
Capitalized interest was $16.2 million and $20.6 million in 1995 and 1994,
respectively.
Equity in loss of affiliates, net was $2.2 million in 1995, compared
with $2.9 million in 1994. Equity in loss of Crusader for 1995 included a net
gain of $3.8 million on the sale of Saracen Minerals, a $2.7 million loss
related to the early redemption of Crusader's Convertible Notes and writedowns
of $2.9 million on unproved oil and gas properties and a coal mining property.
Other income, net was $11.6 million in 1995, compared with $2.8
million in 1994. Other income during 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 Crusader's Convertible Notes.
These increases were offset by a $4.2 million noncash charge representing the
change in fair market value of call options purchased in conjunction with the
Colombian forward oil sale.
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 realizability 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 the 1995 period represented deferred
taxes in Colombia, Argentina, Ecuador, Guatemala and China, 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 rate
for income statement purposes that will exceed statutory tax rates, at least
until the Cusiana and Cupiagua fields project reaches peak production. The
primary reason for the expected difference is the nondeductibility for
Colombian tax purposes of certain capitalized expenses and the treatment of
reimbursements for pre-commerciality costs as return of capital under
Colombian tax laws.
At December 31, 1995, the Company had NOLs of approximately $200
million and certain subsidiaries had separate return limitation years ("SRLY")
operating loss carryforwards of approximately $52 million. The NOLs expire
from 2001 through 2010 and the SRLY operating loss carryforwards expire from
1997 through 2002. See note 11 of Notes to the Consolidated Financial
Statements.
The Company recorded a net deferred tax asset of $47.3 million at
December 31, 1995, net of a valuation allowance of $54 million, an increase of
$12.8 million from December 31, 1994. The minimum amount of future taxable
income necessary to realize the deferred tax asset is approximately $135
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 in Colombia and tax planning
strategies involving the Company's corporate structure.
Minority Interest in Losses of Subsidiaries
The Company ceased to record minority interest related to Triton
Europe following the purchase of shares held by the minority interest owners
on March 31, 1994.
Years Ended May 31, 1994 and 1993
Revenues
Oil and gas sales decreased by $36.4 million in 1994 compared with
1993 primarily due to the sale of the Company's investment in Triton Canada
($13.5 million), sale of working interests properties in the United States
($8.6 million) and lower revenues in France resulting from a drop in
production. Average oil prices per barrel dropped by $3.88 between 1993 and
1994, resulting in an $8.1 million decrease in revenues during 1994,
principally from price decreases in France ($4.46 per barrel or a $4.7 million
effect). Price decreases in Indonesia, the United States and Colombia had a
lesser impact, representing in the aggregate a $3.3 million effect in 1994.
Colombian production increased to 467,000 barrels in 1994 from 219,000 barrels
in 1993.
Costs and Expenses
In 1994, operating expenses of $27.9 million decreased $12.4 million
from the previous year primarily due to oil and gas operations ($8.3 million)
and gas gathering and pipeline operations ($3.8 million) that were sold. Oil
and gas production costs (operating expenses) were $26.6 million in 1994 and
$34.9 million in 1993. The decrease in 1994 was principally due to the sale of
Triton Canada and United States properties ($9 million effect) and lower
production in France ($3.1 million effect), partially offset by increased
production in Colombia ($1.8 million effect) and an accrual for environmental
clean-up costs in the United States ($1.5 million). Average production costs
per equivalent barrel of oil and gas production were $8.83 in 1994 and $5.95
in 1993. The increase per barrel in 1994 was primarily due to an accrual for
environmental clean-up costs in the United States and lower United States
production from the sale of working interest properties.
General and administrative expenses decreased $4.2 million from 1993
to 1994 as lower costs from oil and gas operations were partially offset by
increases in personnel at the corporate office. Lower expenses in 1994 were
primarily due to the restructuring in Europe ($4.6 million effect), the sale
of Triton Canada ($1.4 million effect), and higher capitalization ($2 million
effect) reflecting increased activity in Malaysia-Thailand.
Depreciation, depletion and amortization of $19.8 million in 1994
decreased $25.2 million from 1993 due to lower depletion related to oil and
gas operations.
Writedowns of oil and gas properties totaled $44.4 million in 1994
and $91.2 million in 1993. During 1994, the writedowns primarily related to
the Commission's ceiling limitation requirements for the Company's cost pool
in France. The 1993 writedowns reflected a decision to eliminate certain
future development activities in the Villeperdue Field, for which the Company
recorded a significant decrease in its proved undeveloped reserves. A
resulting drop in the Commission's ceiling limitation for these properties led
to a $55.7 million writedown of costs associated with the Company's proved oil
properties. Additionally, in connection with Triton Europe's decision to
eliminate certain exploration activities in both France and the United
Kingdom, approximately $19.2 million of unevaluated properties were considered
to be impaired. These costs were associated with various license areas that
were relinquished or allowed to expire.
Other Income and Expenses
The increase in interest expense from 1993 to 1994 was due to higher
outstanding debt resulting from the issuance of the 1997 Notes in November
1992 and the 9 3/4% Notes in December 1993, offset by capitalized interest.
Equity in earnings (loss) of affiliates was comprised of the
following (in thousands):
YEAR ENDED MAY 31,
1994 1993
Crusader, 49.9% owned $ 554 $ (3,512)
Aero, 28% owned --- (9,481)
Other 91 500
$ 645 $ (12,493)
Crusader's 1994 earnings improvement resulted from a decrease in
losses from the smokeless fuel operation in Ireland of $3.4 million and lower
writedowns of $4.4 million. The 1993 Crusader loss was primarily a result of
pre-operating costs associated with the smokeless fuel operation in Ireland
($8.4 million) and writedowns of its United States oil and gas properties
($5.3 million). For the year ended May 31, 1993, the Company's equity in the
losses of Aero Services International, Inc. ("Aero") reflected a loss
provision of $7.3 million, which reduced the carrying amounts of preferred
stock, common stock, outstanding loans from the Company and receivables.
Other income, net in 1994 included a $7 million gain on the sale of
United States oil and gas properties and a $1.5 million gain on the sale of an
interest in Aero. In 1993, the Company settled or reached agreement to settle
a number of lawsuits for which a loss provision of $5.5 million was recorded.
Income Taxes
The Company adopted SFAS No. 109, "Accounting for Income Taxes",
effective June 1, 1992. The cumulative benefit of the change to the liability
based method under SFAS No. 109 in 1993 was $4 million, or $.12 per share.
The income tax benefit of $6.5 million in 1994 was due to a foreign
tax benefit of $10.7 million resulting from the ceiling test writedown of oil
and gas properties in France, a gain of $1 million relating to a refund
collected for taxes paid in connection with the 1991 sale of the North Sea
properties and a $2 million refund due in France for the use of net operating
losses. These benefits were partially offset by $6.7 million of Canadian
taxes due following the sale of the Company's investment in Triton Canada.
Also included in the 1994 tax provision is deferred tax expense of $10 million
related to Colombia and Argentina and a deferred tax benefit of $9.4 million
related to the United States.
The income tax benefit for fiscal 1993 was $43.9 million,
principally due to a foreign tax benefit resulting from the writedown of oil
properties in France and recognition of a $25 million net deferred tax asset
in the United States.
Minority Interest in Loss of Subsidiaries
The changes in minority interest corresponded with movements in
operating losses realized by Triton Europe in 1993 and up until March 31,
1994, the date on which the Company acquired the minority interest shares in
Triton Europe.
Discontinued Operations
The results of operations for the aviation sales and services
segment and wholesale fuel products 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. The 1994
losses of the wholesale fuel products segment were offset against a loss
provision of $16.1 million, net of tax, at May 31, 1993. An additional
accrual of $.7 million, net of tax, was recorded at May 31, 1994 for estimated
operating losses associated with the final disposition of this segment. The
Company realized a net gain of $13.8 million during its first quarter of 1993
from the sale of the Company's seismic equipment sales and services segment,
which was discontinued in fiscal 1992.
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 United States dollars.
The Company's risk of realizing currency exchange losses currently is largely
mitigated because the Company receives United States dollars for sales of its
petroleum products in Colombia and Indonesia.
The Company's 49.9%-owned affiliate, Crusader Limited, operates
primarily in Australia. In April 1994, Crusader issued $41 million of
exchangeable notes, which are denominated in United States dollars. The notes
are exchangeable into 1,114,000 shares of Triton common stock held in escrow
by Crusader. Although the notes are exposed to movements in exchange rates
for financial reporting purposes, the exchange feature to Triton common stock
acts as an economic hedge to Crusader. During the year ended December 31,
1995 and seven months ended December 31, 1994, the Company's share of
Crusader's unrealized gains (losses), associated with the exchangeable notes,
was approximately ($.9 million) and $1 million, respectively.
Petroleum Price Risk Management
Oil and natural gas sold by the Company is normally priced with
reference to a defined benchmark, such as light sweet crude oil traded on the
New York Mercantile Exchange (West Texas Intermediate or "WTI"). Actual
prices received vary from the benchmark depending on quality and location
differentials. It is the Company's policy to use financial market
transactions with credit-worthy counterparties from time to time primarily to
reduce risk associated with the pricing of a portion of the oil and natural
gas which it sells. The policy is structured to underpin the Company's
budgeted 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 the normal course of business, the Company enters into financial
and commodity market transactions for purposes other than trading to manage
its exposure to commodity price risk. As a result of such transactions to
date, the Company has set the price benchmark on approximately 44% of its
projected 1996 Colombian oil production at a weighted average WTI benchmark
price of $17.99 per barrel. In addition, in order to retain the opportunity
to participate in higher prices, the Company has purchased WTI benchmark call
options on a total of 500,000 barrels for various delivery dates during the
first half of 1996 at strike prices between $19.68 and $20.28.
In anticipation of entering into a forward oil sale, the Company
entered into five-year commodity price agreements in April and May 1995 to
hedge price risk associated with the portion of the Company's oil production
in Colombia expected to be sold in the forward oil sale. Sales of the
Company's Colombian production are priced with reference to WTI. The
agreements, which were entered into with a counterparty with a "AAA" credit
rating, fixed a WTI price benchmark of $18.42 per barrel on approximately 10.4
million barrels. Simultaneously, the Company purchased from a credit-worthy
counterparty call options to retain the ability to benefit from future WTI
price increases above $20.42 per barrel. The volumes and expiration dates on
the call options coincided with the volumes and delivery dates under the
commodity price agreements. Prior to completion of the forward oil sale, the
commodity price and call agreements had been accounted for as hedging
transactions. Upon completion of the forward oil sale, the commodity price
agreements were superseded and the call options, which no longer qualified for
hedge accounting, were recorded as a separate investment at their then fair
market value of $9.3 million. As a result of this accounting treatment,
fluctuations in the value of the call options affect other income, positively
or negatively, as noncash adjustments.
Exploration Operations
Costs related to acquisition, holding and initial exploration of
concessions in countries with no proved reserves are initially capitalized,
including internal costs directly identified with acquisition, exploration and
development activities. The Company's exploration concessions are
periodically assessed for impairment on a country by country basis. If the
Company's investment in exploration concessions within a country where no
proved reserves are assigned is deemed to be impaired, the concessions 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.
Environmental Matters
The Company is subject to extensive environmental laws and
regulations. These laws regulate the discharge of materials into the
environment and may require the Company to remove or mitigate the
environmental effects of the disposal or release of petroleum substances at
various sites. Also, the Company remains liable for certain environmental
matters that may arise from formerly owned fuel businesses that were involved
in the storage, handling and sale of hazardous materials, including fuel
storage in underground tanks. The Company believes that the level of future
expenditures for environmental matters, including clean-up obligations, is
impractical to determine with any 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.
Certain Factors That Could Affect Future Operations
Certain statements in this report, including statements of the Company's
and management's expectations, intentions, plans and beliefs, 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 of 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, expected or
planned production or transportation capacity, the future construction or
upgrades of pipelines (including costs), when the Cusiana and Cupiagua fields
might become self-financing, future production of the Cusiana and Cupiagua
fields, the negotiation of a gas 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 Company's
realization of its deferred tax asset, the level of future expenditures for
environmental costs and the outcome of regulatory and litigation matters; 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 18 and 19 of Notes to Consolidated Financial Statements.
Recent Accounting Pronouncements
In 1995, the Financial Accounting Standards Board issued Statement
No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of" and Statement No. 123, "Accounting for
Stock-Based Compensation." Both Statements must be adopted in 1996.
Statement No. 121 will require the review of long-lived assets for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. The impact of adopting
this standard will not have a material adverse effect on the Company's
operations or consolidated financial condition. Statement No. 123 will
require companies to record or disclose the fair value of stock-based
compensation to employees. The Company currently intends to disclose the fair
value of stock-based compensation to employees.
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 1996 Annual Meeting of Stockholders of the Company
(or, if the Reorganization is consummated, for the 1996 Annual Meeting of
Shareholders of Triton Cayman) (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 1996. Certain information as to executive officers is included herein
under Item 1, "Business - Executive Officers." The discussion under "Section
16 Requirements" 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 Stockholders" 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 Crusader's
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 Certificate of Incorporation, as amended.(1)
3.2 Bylaws of Triton Energy Corporation.(1)
4.1 Specimen Stock Certificate of Common Stock, $1.00 par value, of the
Company.(1)
4.2 Rights Agreement dated as of May 22, 1995, between Triton and Chemical
Bank, as Rights Agent.(2)
4.3 Form of Debt Securities.(3)
4.4 Proposed Form of Senior Indenture.(3)
4.5 Proposed Form of Senior Subordinated Indenture.(3)
4.6 Certificate of Designation Establishing and Designating a Series of
Shares of the Company's 5% Convertible Preferred Stock, no par
value.(1)
10.1 Triton Energy Corporation Amended and Restated Retirement Income
Plan.(4)(16)
10.2 Triton Energy Corporation Amended and Restated Supplemental
Executive Retirement Income Plan.(5)(16)
10.3 1981 Employee Non-Qualified Stock Option Plan of Triton Energy
Corporation.(6)(17)
10.4 Amendment No. 1 to the 1981 Employee Non-Qualified Stock Option Plan
of Triton Energy Corporation.(7)(17)
10.5 Amendment No. 2 to the 1981 Employee Non-Qualified Stock Option Plan
of Triton Energy Corporation.(6)(17)
10.6 Amendment No. 3 to the 1981 Employee Non-Qualified Stock Option Plan
of Triton Energy Corporation.(4)(17)
10.7 1985 Stock Option Plan of Triton Energy Corporation.(8)(17)
10.8 Amendment No. 1 to the 1985 Stock Option Plan of Triton Energy
Corporation.(6)(17)
10.9 Amendment No. 2 to the 1985 Stock Option Plan of Triton Energy
Corporation.(4)(17)
10.10 Triton Energy Corporation Amended and Restated 1986 Convertible
Debenture Plan.(4)(17)
10.11 1988 Stock Appreciation Rights Plan of Triton Energy
Corporation.(9)(17)
10.12 Triton Energy Corporation 1989 Stock Option Plan.(10)(17)
10.13 Amendment No. 1 to the Triton Energy Corporation 1989 Stock Option
Plan.(6)(17)
10.14 Amendment No. 2 to the Triton Energy Corporation 1989 Stock Option
Plan.(4)(17)
10.15 Triton Energy Corporation Amended and Restated 1992 Stock Option
Plan.(4)(17)
10.16 Form of Amended and Restated Employment Agreement by and among
Triton Energy Corporation and the executive officers of Triton
Energy Corporation.(5)(17)
10.17 Triton Energy Amended and Restated Restricted Stock Plan.(4)(17)
10.18 First Amendment to Amended and Restated Restricted Stock
Plan.(17)(18)
10.19 Triton Energy Corporation Executive Life Insurance Plan.(11)(17)
10.20 Triton Energy Corporation Long Term Disability Income Plan.(11)(17)
10.21 Triton Energy Corporation Amended and Restated Retirement Plan for
Directors.(8)(17)
10.22 Indenture dated as of November 13, 1992 between Triton and Chemical
Bank, with respect to the issuance of Senior Subordinated Discount
Notes due 1997.(12)
10.23 Supplemental Indenture dated as of July 1, 1993 between Triton
Energy Corporation and Chemical Bank.(9)
10.24 Supplemental Indenture dated as of August 16, 1993 between Triton
Energy Corporation and Chemical Bank.(9)
10.25 Third Supplemental Indenture dated as of May 12, 1995 between the
Company and Chemical Bank.(13)
10.26 Fourth Supplemental Indenture dated as of November 16, 1995 between
the Company and Chemical Bank.(18)
10.27 Senior Subordinated Indenture by and between the Company and United
States Trust Company of New York, dated as of December 15, 1993.(4)
10.28 First Supplemental Indenture by and between the Company and United
States Trust Company of New York, dated as of December 15, 1993.(4)
10.29 Second Supplemental Indenture dated as of May 12, 1995 between the
Company and United States Trust Company of New York.(13)
10.30 Third Supplemental Indenture dated as of November 16, 1995
between the Company and United States Trust Company of New York.(18)
10.31 Underwriting Agreement dated June 18, 1993 among Triton Canada
Resources Ltd., Triton Energy Corporation and the underwriters named
therein.(4)
10.32 Purchase and Sale Agreement among Triton Oil & Gas Corp., Triton
Energy Corporation and Torch Energy Advisors Incorporated dated
effective as of January 1, 1993.(9)
10.33 Agreement for Purchase and Sale of Assets Among Triton Fuel Group,
Inc. and AVFUEL Corporation dated August 25, 1993.(9)
10.34 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)
10.35 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)
10.36 Summary of Assignment legalized by Public Instrument No. 1255 dated
September 15, 1987 (Assignment is in Spanish language).(9)
10.37 Summary of Assignment legalized by Public Instrument No. 1602 dated
June 11, 1990 (Assignment is in Spanish language).(9)
10.38 Summary of Assignment legalized by Public Instrument No. 2586 dated
September 9, 1992 (Assignment is in Spanish language).(9)
10.39 Triton Energy Corporation 401(K) Savings Plan.(4)(17)
10.40 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.(14)
10.41 Credit Agreement between Triton Energy Corporation and Banque
Paribas Houston Agency dated as of May 28, 1995, together with
related form of revolving credit note.(1)
10.42 First Amendment to Credit Agreement between Triton Energy
Corporation and Banque Paribas Houston Agency darted May 16,
1995.(13)
10.43 Security Agreement between Triton Energy Corporation and Banque
Paribas Houston Agency.(1)
10.44 Second Amendment to Credit Agreement and First Amendment to
Security Agreement between Triton Energy Corporation and
Banque Paribas Houston Agency dated August 11, 1995.(5)
10.45 Third Amendment to Credit Agreement between Triton Energy
Corporation and Banque Paribas Houston Agency dated September 29,
1995.(5)
10.46 Triton Crude Purchase Agreement between Triton Colombia, Inc.
and Oil Co., LTD. dated May 25, 1995.(15)
10.47 Credit Agreement among Triton Colombia, Inc., Triton Energy
Corporation, NationsBank, N.A. (Carolinas) and Export-Import
Bank of the United States.(18)
10.48 Amendment No. 1 to Credit Agreement among Triton Colombia, Inc.,
Triton Energy Corporation, NationsBank, N.A. (Carolinas) and
Export-Import Bank of the United States.(18)
10.49 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.(18)
10.50 Agreement and Plan of Merger among Triton Energy Corporation,
Triton Energy Limited and TEL Merger Corp.(18)
21.1 Subsidiaries of the Company.(18)
23.1 Consent of Price Waterhouse LLP.(18)
23.2 Consent of DeGolyer and MacNaughton.(18)
24.1 The power of attorney of officers and directors of the
Company (set forth on the signature page hereof).(18)
27.1 Financial Data Schedule.(18)
99.1 Rio Chitamena Association Contract.(16)
99.2 Rio Chitamena Purchase and Sale Agreement.(16)
99.3 Integral Plan - Cusiana Oil Structure.(16)
99.4 Letter Agreements with co-investor in Colombia.(16)
99.5 Colombia Pipeline Memorandum of Understanding.(16)
99.6 Amended and Restated Oleoducto Central S.A. Agreement dated as
of March 31, 1995.(13)
(1) Previously filed as an exhibit to the Company's Quarterly Report on
Form 10-Q for the quarter ended March 31, 1995 and incorporated herein by
reference.
(2) Previously filed as an exhibit to the Company's Registration Statement
on Form 8-A dated June 2, 1995 and incorporated herein by reference.
(3) Previously filed as an exhibit to the Company's Registration Statement
on Form S-3 (No. 33-69230) and incorporated herein by reference.
(4) Previously filed as an exhibit to the Company's Quarterly Report on
Form 10-Q for the quarter ended November 30, 1993 and incorporated by
reference herein.
(5) Previously filed as an exhibit to the Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1995 and incorporated herein
by reference.
(6) Previously filed as an exhibit to the Company'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 the Company'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 the Company'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 the Company'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 the Company'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 Annual Report on Form
10-K for the fiscal year ended May 31, 1991 and incorporated herein by
reference.
(12)Previously filed as an exhibit to the Company's Quarterly Report on
Form 10-Q for the quarter ended November 30, 1992 and incorporated herein
by reference.
(13)Previously filed as an exhibit to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1995 and incorporated herein by
reference.
(14)Previously filed as an exhibit to the Company's current report on
Form 8-K dated April 21, 1994 and incorporated by reference herein.
(15)Previously filed as an exhibit to the Company's Current Report on
Form 8-K dated May 26, 1995 and incorporated herein by reference.
(16)Previously filed as an exhibit to the Company's current report on
Form 8-K/A dated July 15, 1994 and incorporated by reference herein.
(17)Management contract or compensatory plan or arrangement.
(18)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
12th day of March, 1996.
TRITON ENERGY CORPORATION
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 Corporation (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, 1995, 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 12th day of
March, 1996.
Signature Title
/s/ Thomas G. Finck Chairman of the Board and Chief
Thomas G. Finck Executive Officer
/s/ Peter Rugg Senior Vice President and
Peter Rugg Chief Financial Officer
/s/ Herbert L. Brewer Director March 12, 1996
Herbert L. Brewer
/s/ John P. Lewis Director March 12, 1996
John P. Lewis
/s/ Michael E. McMahon Director March 12, 1996
Michael E. McMahon
/s/ Ernest E. Cook Director March 12, 1996
Ernest E. Cook
/s/ Sheldon R. Erikson Director March 12, 1996
Sheldon R. Erikson
/s/ Ray H. Eubank Director March 12, 1996
Ray H. Eubank
/s/ Jesse E. Hendricks Director March 12, 1996
Jesse E. Hendricks
/s/ Fitgerald S. Hudson Director March 12, 1996
Fitzgerald S. Hudson
/s/ John R. Huff Director March 12, 1996
John R. Huff
/s/ Wellslake D. Morse, Jr. Director March 12, 1996
Wellslake D. Morse, Jr.
/s/ Edwin D. Williamson Director March 12, 1996
Edwin D. Williamson
/s/ J. Otis Winters Director March 12, 1996
J. Otis Winters
TRITON ENERGY CORPORATION AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
PAGE
TRITON ENERGY CORPORATION AND SUBSIDIARIES:
Report of Independent Accountants - December 31, 1995 and 1994, and
May 31, 1994 and 1993 F-2
Consolidated Statements of Operations - Year ended December 31, 1995, seven
months ended December 31, 1994 and years ended May 31, 1994 and 1993 F-3
Consolidated Balance Sheets - December 31, 1995 and 1994, and
May 31, 1994 F-4
Consolidated Statements of Cash Flows - Year ended December 31, 1995, seven
months ended December 31, 1994 and years ended May 31, 1994 and 1993 F-5
Consolidated Statements of Stockholders' Equity - Year ended December 31, 1995,
seven months ended December 31, 1994 and years ended May 31, 1994 and 1993 F-6
Notes to Consolidated Financial Statements F-7
SCHEDULES:
II - Valuation and Qualifying Accounts - Year ended December 31, 1995,
seven months ended December 31, 1994 and years ended
May 31, 1994 and 1993 F-54
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 Corporation
In our opinion, the consolidated financial statements as of and for the year
ended December 31, 1995, as of and for the seven months ended December 31,
1994, as of and for the year ended May 31, 1994 and for the year ended May 31,
1993 listed in the accompanying index present fairly, in all material
respects, the financial position of Triton Energy Corporation and its
subsidiaries at December 31, 1995 and 1994 and May 31, 1994, and the results
of their operations and their cash flows for the year ended December 31, 1995,
the seven months ended December 31, 1994 and the years ended May 31, 1994 and
1993, 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.
As discussed in notes 1 and 11, respectively, the Company changed its methods
of accounting for investments in marketable securities at May 31, 1994 and
income taxes in 1993.
Price Waterhouse LLP
Dallas, Texas
February 9, 1996
TRITON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT SHARE DATA)
SEVEN
YEAR ENDED MONTHS ENDED
DECEMBER 31, DECEMBER 31, YEAR ENDED MAY 31,
1995 1994 1994 1993
SALES AND OTHER OPERATING REVENUES:
Oil and gas sales $ 106,844 $ 20,477 $ 40,894 $ 77,324
Other operating revenues 628 259 2,314 7,090
107,472 20,736 43,208 84,414
COSTS AND EXPENSES:
Operating expenses 35,276 12,362 27,887 40,323
General and administrative 25,672 15,997 30,429 34,590
Depreciation, depletion and amortization 23,208 7,339 19,821 45,053
Writedown of assets --- 984 45,754 94,383
84,156 36,682 123,891 214,349
OPERATING INCOME (LOSS) 23,316 (15,946) (80,683) (129,935)
Gain on sale of Triton Canada Stock --- --- 47,865 ---
Interest income 7,954 4,144 6,542 4,116
Interest expense (24,055) (7,754) (7,504) (4,689)
Equity in earnings (loss) of affiliates, net (2,249) (4,102) 645 (12,493)
Other income (expense), net 11,634 824 10,031 (4,444)
(6,716) (6,888) 57,579 (17,510)
EARNINGS (LOSS) FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES, MINORITY INTEREST AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 16,600 (22,834) (23,104) (147,445)
Income tax expense (benefit) 10,059 3,796 (6,536) (43,881)
6,541 (26,630) (16,568) (103,564)
Minority interest in loss of subsidiaries --- --- 11,971 27,055
EARNINGS (LOSS) FROM CONTINUING OPERATIONS
BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 6,541 (26,630) (4,597) (76,509)
DISCONTINUED OPERATIONS:
Loss from operations (1,858) (1,078) (4,094) (14,807)
Loss on disposal (1,963) --- (650) (16,077)
Gain on public stock offering --- --- --- 13,841
EARNINGS (LOSS) BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE 2,720 (27,708) (9,341) (93,552)
CUMULATIVE EFFECT OF ACCOUNTING CHANGE --- --- --- 4,017
NET EARNINGS (LOSS) 2,720 (27,708) (9,341) (89,535)
DIVIDENDS ON PREFERRED STOCK 802 449 --- ---
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 1,918 $ (28,157) $ (9,341) $ (89,535)
Weighted average common shares outstanding 35,147 34,944 34,775 34,241
EARNINGS (LOSS) PER COMMON SHARE:
Continuing operations $ 0.16 $ (0.78) $ (0.13) $ (2.23)
Discontinued operations (0.11) (0.03) (0.14) (0.50)
Cumulative effect of accounting change --- --- --- 0.12
NET EARNINGS (LOSS) $ 0.05 $ (0.81) $ (0.27) $ (2.61)
See accompanying notes to consolidated financial statements.
TRITON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
ASSETS DECEMBER 31, MAY 31,
1995 1994 1994
CURRENT ASSETS:
Cash and equivalents $ 49,050 $ 22,341 $ 69,005
Short-term marketable securities 42,419 26,657 63,431
Trade receivables, net 6,504 6,087 6,454
Other receivables 16,683 14,154 8,125
Inventories, prepaid expenses and other 4,128 4,638 8,661
TOTAL CURRENT ASSETS 118,784 73,877 155,676
Long-term marketable securities 3,985 23,264 28,831
Investments in unconsolidated affiliates 33,803 34,162 36,809
Property and equipment, at cost, net 524,381 399,658 308,498
Deferred income taxes 47,283 34,486 34,426
Other assets 95,931 53,754 51,861
$ 824,167 $ 619,201 $ 616,101
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current installments of long-term debt $ 1,313 $ 257 $ 312
Short-term borrowings --- 17,351 1,640
Accounts payable and accrued liabilities 31,873 26,608 30,251
Liabilities of discontinued operations --- --- 6,700
TOTAL CURRENT LIABILITIES 33,186 44,216 38,903
Long-term debt, excluding current installments 401,190 315,258 294,441
Deferred income taxes 29,897 14,672 10,037
Deferred income and other 113,869 7,860 9,298
Convertible debentures due to employees --- --- ---
STOCKHOLDERS' EQUITY:
Preferred stock, without par value; authorized 5,000,000 shares;
issued 410,017, 522,412 and 522,460 shares at December 31, 1995
and 1994, and May 31, 1994, respectively; stated value $34.41 14,109 17,976 17,978
Common stock, par value $1; authorized 200,000,000 shares;
issued 35,927,279, 35,577,009 and 35,519,103 shares at
December 31, 1995 and 1994, and May 31, 1994, respectively 35,927 35,577 35,519
Additional paid-in capital 516,326 505,256 505,122
Accumulated deficit (311,294) (314,014) (286,306)
Foreign currency translation adjustment (8,616) (5,639) (7,163)
Other (89) (1,384) (1,046)
246,363 237,772 264,104
Less cost of common shares in treasury 338 577 682
TOTAL STOCKHOLDERS' EQUITY 246,025 237,195 263,422
Commitments and contingencies (note 19)
$ 824,167 $ 619,201 $ 616,101
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 CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
SEVEN
YEAR ENDED MONTHS ENDED
DECEMBER 31, DECEMBER 31, YEAR ENDED MAY 31,
1995 1994 1994 1993
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ 2,720 $ (27,708) $ (9,341) $ (89,535)
Adjustments to reconcile net earnings (loss) to net cash provided
(used) by operating activities:
Depreciation, depletion and amortization 23,467 7,587 20,490 50,742
Amortization of debt discount 23,928 7,939 7,852 7,810
Proceeds from forward oil sale 86,610 --- --- ---
Amortization of unearned revenue (4,725) --- --- ---
(Gain) loss on sale of assets, net (2,938) 201 (8,328) (14,069)
Gain on sale of Triton Canada common stock --- --- (47,865) ---
Equity in (earnings) loss of affiliates, net 2,249 4,102 (645) 13,600
Writedowns, loss provisions and discontinued operations 7,192 984 46,404 118,916
Cumulative effect of accounting change --- --- --- (4,017)
Deferred income taxes 5,444 4,569 (10,224) (43,877)
Minority interest in undistributed loss of subsidiaries --- --- (11,971) (27,055)
Other, net (2,785) 1,096 2,735 4,591
Changes in working capital:
Marketable debt securities - trading 8,074 10,429 --- ---
Receivables (1,677) (3,064) (1,797) (5,759)
Inventories, prepaid expenses and other (441) (2,314) 1,268 5,604
Net assets of discontinued operations (349) (2,094) (7,578) ---
Accounts payable and accrued liabilities 2,367 2,657 (12,126) (10,103)
Income taxes (42) (6,398) 6,162 (1,429)
Net cash provided (used) by operating activities 149,094 (2,014) (24,964) 5,419
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures and investments (178,161) (89,895) (86,819) (124,925)
Purchases of investments and marketable securities (45,281) (5,879) (190,025) (69,207)
Proceeds from sale of investments and marketable securities 42,050 36,664 119,905 44,970
Sales of property and equipment and other assets 20,866 539 22,816 29,386
Proceeds from sale of Triton Canada common stock --- --- 59,029 ---
Proceeds from sale of discontinued operations 2,100 1,737 18,450 ---
Other (1,368) (3,509) (4,370) (11,410)
Net cash used by investing activities (159,794) (60,343) (61,014) (131,186)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt 85,627 1,701 123,408 132,138
Proceeds from short-term borrowings with
maturities greater than three months --- 7,671 --- 9,117
Short-term borrowings, net (10,000) 8,040 (1,640) (8,179)
Payments on long-term debt (39,366) (212) (3,150) (10,492)
Payments on debt associated with discontinued operations (2,004) (1,883) (18,959) ---
Issuance of common stock 8,398 639 3,164 6,397
Other (3,752) (707) (1,054) (2,318)
Net cash provided by financing activities 38,903 15,249 101,769 126,663
Effects of exchange rate changes on cash and equivalents (1,494) 444 275 (558)
Net increase (decrease) in cash and equivalents 26,709 (46,664) 16,066 338
CASH AND EQUIVALENTS AT BEGINNING OF YEAR 22,341 69,005 52,939 52,601
CASH AND EQUIVALENTS AT END OF YEAR $ 49,050 $ 22,341 $ 69,005 $ 52,939
See accompanying notes to consolidated financial statements.
TRITON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
SEVEN
YEAR ENDED MONTHS ENDED
DECEMBER 31, DECEMBER 31, YEAR ENDED MAY 31,
1995 1994 1994 1993
PREFERRED STOCK:
Balance at beginning of year $ 17,976 $ 17,978 $ --- $ ---
Purchase of minority interest in Triton Europe --- --- 17,978 ---
Conversion of 5% preferred stock (3,867) (2) --- ---
Balance at end of year 14,109 17,976 17,978 ---
COMMON STOCK:
Balance at beginning of year 35,577 35,519 35,231 34,649
Exercise of employee stock options and debentures 238 58 288 582
Conversion of 5% preferred stock 112 --- --- ---
Balance at end of year 35,927 35,577 35,519 35,231
ADDITIONAL PAID-IN CAPITAL:
Balance at beginning of year 505,256 505,122 502,217 488,580
Cash dividends, 5% preferred stock (802) (449) --- ---
Exercise of employee stock options and debentures 8,160 464 2,876 5,815
Conversion of 5% preferred stock 3,755 --- --- ---
Sale of the Company's stock by Crusader --- --- --- 3,920
Utilization of tax loss carryforwards --- --- --- 3,920
Other, net (43) 119 29 (18)
Balance at end of year 516,326 505,256 505,122 502,217
ACCUMULATED DEFICIT:
Balance at beginning of year (314,014) (286,306) (276,965) (187,430)
Net earnings (loss) 2,720 (27,708) (9,341) (89,535)
Balance at end of year (311,294) (314,014) (286,306) (276,965)
FOREIGN CURRENCY TRANSLATION ADJUSTMENT:
Balance at beginning of year (5,639) (7,163) (4,087) 1,236
Sale of Triton Canada --- --- (3,341) ---
Sale of Triton France S.A. (3,268) --- --- ---
Translation rate changes 291 1,524 265 (5,323)
Balance at end of year (8,616) (5,639) (7,163) (4,087)
OTHER, NET:
Balance at beginning of year (1,384) (1,046) (246) (307)
Valuation reserve on marketable securities 1,295 (429) (955) ---
Debt guarantee for ESOP --- --- --- 307
Adjustment for minimum pension liability --- 91 155 (246)
Balance at end of year (89) (1,384) (1,046) (246)
TREASURY STOCK:
Balance at beginning of year (577) (682) (718) (715)
Purchase of treasury stock (4) (3) (5) (3)
Transfer of shares to employee benefit plans 243 108 41 ---
Balance at end of year (338) (577) (682) (718)
TOTAL STOCKHOLDERS' EQUITY $ 246,025 $ 237,195 $ 263,422 $ 255,432
See accompanying notes to consolidated financial statements.
TRITON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS IN TABLES IN THOUSANDS, EXCEPT FOR SHARE AND PER BARREL DATA)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BUSINESS ACTIVITIES
Triton Energy Corporation is an international oil and gas exploration company
primarily engaged in exploration and production through subsidiaries and
affiliates. The term "Company" means collectively, Triton Energy Corporation
and its subsidiaries and its affiliates through which it conducts business.
The Company's principal properties and operations are located in Colombia and
Malaysia-Thailand with the majority of its proved reserves and oil production
located in Colombia. The Company also has oil and gas interests in other
Latin American and Asian countries, Europe, Australia and North America.
CHANGE IN FISCAL YEAR END
Effective January 1, 1995, the Company changed its fiscal year end from May 31
to December 31. These financial statements include the Company's transition
period for the seven months ended December 31, 1994.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Triton Energy
Corporation and its majority-owned subsidiaries. All significant 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 stockholders' 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 (expense),
net. Investments that will be held-to-maturity are classified based on the
stated maturity of the securities. Prior to May 31, 1994, the Company
accounted for its investments in debt securities at amortized cost and
classified such investments according to the stated maturity of the underlying
securities. The cumulative effect of changing accounting policy of $1
million was recorded as a valuation reserve at May 31, 1994 in stockholders'
equity.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for exploration and
development of oil and gas reserves, whereby all productive and nonproductive
costs are capitalized. Individual countries are designated as separate cost
centers. All capitalized costs plus the undiscounted 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 concessions
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 concessions are
periodically assessed for impairment on a country by country basis. If the
Company's investment in exploration concessions within a country where no
proved reserves are assigned is deemed to be impaired, the concessions 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.
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 accrued during
production and classified as a long-term liability.
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 30 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.
INCOME TAXES
Deferred tax liabilities or assets are recognized for the anticipated future
tax effects of temporary differences between the financial statement basis and
the tax basis of the Company's assets and liabilities using the enacted tax
rates in effect at year end. A valuation allowance for deferred tax assets is
recorded when it is more likely than not that the benefit from the deferred
tax asset will not be realized.
REVENUE RECOGNITION
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
profits interest conveyances are recorded as operating expenses when the
obligation is incurred.
FOREIGN CURRENCY TRANSLATION
The United States 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 United States dollars at current exchange
rates are included as a separate component of stockholders' 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. It is the Company's policy to use financial market transactions
with credit-worthy counterparties from time to time primarily to reduce risk
associated with the pricing of a portion of the oil and natural gas which 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 income as offsets to gains and losses resulting
from the underlying hedged transactions. Premiums paid for financial market
contracts are capitalized and amortized over the contract period. Changes in
the fair market value of financial market transactions that do not qualify for
hedge accounting are reflected as noncash adjustments to other income
(expense), net in the period the change occurs.
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 Company discontinued its aviation sales and services segment in June
1995. The Consolidated Statements of Operations for the seven months ended
December 31, 1994 and the years ended May 31, 1994 and 1993 have been restated
to reflect the aviation sales and services segment as discontinued operations.
Certain other previously reported financial information has been reclassified
to conform to the current period's presentation.
EARNINGS (LOSS) PER COMMON SHARE
Earnings (loss) per common share is based on the weighted average number of
shares of common stock outstanding. The Company's proportionate shares owned
by Crusader Limited ("Crusader") are not considered outstanding for purposes
of determining weighted average number of shares outstanding. Common stock
equivalents were not material or were antidilutive for purposes of the primary
earnings per share calculation. Fully diluted earnings (loss) per common
share is not presented due to the antidilutive effect of including all
potentially dilutive securities.
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.
RECENT ACCOUNTING PRONOUNCEMENTS
In 1995, the Financial Accounting Standards Board issued Statement No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of" and Statement No. 123, "Accounting for Stock-Based
Compensation." Both Statements must be adopted in 1996.
Statement No. 121 will require the review of long-lived assets for impairment
whenever events or changes in circumstances indicate that the carrying amount
of an asset may not be recoverable. The impact of adopting this standard will
not have a material adverse effect on the Company's operations or consolidated
financial condition. Statement No. 123 will require companies to record or
disclose the fair value of stock-based compensation to employees. The Company
currently intends to disclose the fair value of stock-based compensation to
employees.
2. FORWARD SALE OF COLOMBIAN OIL PRODUCTION
In May 1995, the Company sold 10.4 million barrels of oil 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 in Colombia becomes self-financing, which is expected in 1997,
and when certain other conditions are met. The proceeds held in
interest-bearing reserve accounts have been recorded as long-term receivables.
The Company has recorded the net proceeds as deferred income and will
recognize such revenue when the barrels are delivered during a five-year
period that began in June 1995. The Company will deliver to the buyer 58,425
barrels per month through March 1997 and 254,136 barrels per month from April
1997 to March 2000, which represents approximately 15% of the Company's
currently projected Cusiana and Cupiagua production during the five-year
period.
The oil was sold to an unrelated entity. Morgan Guaranty Trust Company of New
York ("Morgan Guaranty") has agreed to purchase the oil delivered by the
Company to the unrelated entity at a fixed price.
The purchase prices and other terms of the transaction were determined by
arm's-length negotiations among the Company, J.P. Morgan Securities Inc.,
Morgan Guaranty and the unrelated entity. The prices reflected the various
parties' mutual agreement as to present fair market value of the barrels of
oil to be delivered, taking into account such factors as quality relative to
WTI, transportation costs and timing of deliveries.
3. DIVESTITURES AND DISCONTINUED OPERATIONS
In August 1995, the Company sold Triton France S. A. through which it held its
interest in the Villeperdue Field to the operator of the field, Coparex
International. 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 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.
Summarized information for the aviation sales and services segment portion of
discontinued operations follows:
SEVEN
YEAR ENDED MONTHS ENDED YEAR ENDED MAY 31,
DEC. 31, 1995 DEC. 31, 1994 1994 1993
Revenues $ 4,694 $ 6,117 $ 12,885 $ 19,864
Loss before income taxes $ (2,022) $ (1,078) $ (4,094) $ (5,333)
Income tax expense (benefit) --- --- --- ---
Net loss $ (2,022) $ (1,078) $ (4,094) $ (5,333)
In the first quarter of fiscal 1994, the Company completed the sale of its
76% interest in the common stock of Triton Canada Resources Ltd. ("Triton
Canada"). The Company received net proceeds of $59 million and recorded a
gain of $47.9 million.
In August and October 1993, the Company sold its United States working
interest properties for net proceeds of $19.5 million, resulting in a gain of
$7 million. The properties that were sold accounted for approximately 55.7%
of discounted future net revenues associated with United States proved
properties at May 31, 1993.
In fiscal 1993, the Company initiated a plan to discontinue its remaining
operations in the wholesale fuel products segment. An accrual of $16.1
million was recorded at May 31, 1993 as an estimate of the results of
operations for discontinued operations during fiscal 1994 and the anticipated
loss on disposal of the segment. An additional accrual of $.7 million was
recorded at May 31, 1994 for estimated operating losses caused by closing the
sale of several operating divisions later than originally anticipated. All
operations have been sold.
Summarized information for the wholesale fuel products segment portion of
discontinued operations follows:
SEVEN
MONTHS ENDED YEAR ENDED MAY 31,
DEC. 31, 1994 1994 1993
Revenues $ 8,820 $ 81,383 $170,493
Loss before income taxes $ (2,070) $ (14,422) $ (9,657)
Income tax expense (benefit) 5 7 (158)
Net loss $ (2,075) $ (14,429) $ (9,499)
On August 12, 1992, the Company sold its remaining 26.9% interest in
Input/Output, Inc. through a secondary public offering. The net proceeds from
the offering were $24.1 million, which resulted in a net gain of $13.8
million.
4. PURCHASE OF THE TRITON EUROPE MINORITY INTEREST
On March 31, 1994, the Company acquired all of the outstanding shares not
owned by the Company, representing the minority shareholders' 40.5% interest
in Triton Europe plc ("Triton Europe"), in exchange for 522,460 shares of the
Company's 5% Convertible Preferred Stock ("5% preferred stock"), with a value
of $18 million, and $2.6 million in cash, including transaction costs. The
transaction was recorded as a purchase, and accordingly, 100% of Triton
Europe's operating results have been included in the Company's results of
operations since March 31, 1994. The excess of the purchase price over the
carrying value of the minority interest in Triton Europe of $3.5 million was
allocated to the full cost pools within Triton Europe.
5. INVESTMENTS IN MARKETABLE SECURITIES
The carrying values of marketable securities are as follows:
DECEMBER 31, MAY 31,
1995 1994 1994
Short-term marketable securities:
Held-to-maturity $ 18,861 $ 7,437 $38,528
Available-for-sale 17,519 4,957 ---
Trading 6,039 14,263 24,903
Total short-term marketable securities $ 42,419 $26,657 $63,431
Long-term available for sale $ 3,985 $23,264 $28,831
At December 31, 1995, the maturites of investments in corporate and other
marketable debt securities classified as available-for-sale were less than two
years with the exception of one floating rate investment totaling $2 million
which had a stated maturity in excess of ten years. Proceeds from the sale of
available-for-sale securities were $7.7 million in the year ended December 31,
1995. Gross unrealized holding losses at December 31, 1995 and 1994 and May
31, 1994 were $.1 million, $1.4 million and $1.2 million, respectively.
6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
CRUSADER
Crusader, a 49.9% owned affiliate, is an Australian public company engaged in
oil and gas exploration and production and coal mining in Australia. The
Company's equity investment in Crusader's common stock was $31.5 million,
$26.2 million and $29.3 million at December 31, 1995 and 1994 and May 31,
1994, respectively. At December 31, 1994 and May 31, 1994, the Company's
investment in Crusader also included $8 million and $7.5 million,
respectively, of convertible subordinated debentures issued by Crusader in
1989. The quoted market value of the Company's investment in Crusader's
common stock at December 31, 1995 was approximately $56.2 million.
In March 1995, Crusader completed the sale of Saracen Minerals for proceeds of
$14.3 million. This sale resulted in a net gain to the Company of
approximately $3.8 million. In June 1995, Crusader recorded a $5.3 million
loss (the Company's share - $2.7 million) due to a payment to holders of their
12% Convertible Subordinated Unsecured Notes to effect early redemption of
these Notes to shares of Crusader common stock. The Company received
approximately $2.9 million from its exchange of such notes and recorded the
proceeds as other income. Also in 1995, Crusader contributed its Irish coal
briquetting operations to Phoenix Coal Limited ("Phoenix"), a corporate joint
venture, in exchange for preference shares and 49% of Phoenix' common
shares outstanding. Crusader recorded its investment in Phoenix at historical
book value.
On April 28, 1994, Crusader issued $40.9 million aggregate principal amount of
6% Exchangeable Senior Notes due February 14, 2004 (the "6% Notes"). The 6%
Notes are exchangeable at the option of the holder after July 27, 1994 into
the shares of the Company's common stock held by Crusader at a price of $36.75
per share upon certain terms.
At December 31, 1995 and 1994 and May 31, 1994, Crusader owned approximately
3% of the Company's common stock. Crusader's investment in the Company, using
the cost method of accounting, was $12.2 million, $12.2 million and $11.6
million at December 31, 1995 and 1994 and May 31, 1994, respectively. The
Company's investment in Crusader and additional paid-in capital have each been
reduced to eliminate the Company's proportionate share of its common stock
owned by Crusader. During 1993, Crusader recognized a gain of $4.6 million on
the sale of 245,000 shares of the Company's common stock. The Company's share
of the sale proceeds has been credited to additional paid-in capital.
Summarized financial information for Crusader follows:
DECEMBER 31, MAY 31,
1995 1994 1994
ASSETS
Current assets $ 44,190 $ 32,656 $ 37,656
Noncurrent assets 103,387 138,909 127,817
$ 147,577 $171,565 $165,473
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities $ 7,002 $ 14,251 $ 15,741
Noncurrent liabilities 56,114 79,705 66,212
Minority interest in subsidiaries 8,884 12,628 12,907
Shareholders' equity 75,577 64,981 70,613
$ 147,577 $171,565 $165,473
SEVEN
YEAR ENDED MONTHS ENDED YEAR ENDED MAY 31,
DEC. 31, 1995 DEC. 31, 1994 1994 1993
Revenues $ 46,867 $ 22,535 $ 40,193 $ 54,924
Costs and expenses (52,990) (25,145) (40,574) (54,477)
Income tax (expense) benefit (1,757) (6,934) 476 (3,419)
Minority interest 2,927 1,052 716 313
Earnings (loss) before cumulative effect of
accounting change (4,953) (8,492) 811 (2,659)
Cumulative effect of accounting change --- --- --- 1,734
Net earnings (loss) $ (4,953) $ (8,492) $ 811 $ (925)
Company's equity in earnings (loss) before
cumulative effect of accounting change $ (2,249) $ (4,102) $ 554 $ (3,512)
Company's share of dividends $ --- $ --- $ 620 $ 840
The Company's equity in undistributed earnings of Crusader accounted for by
the equity method was approximately $18.1 million at December 31, 1995.
AERO SERVICES INTERNATIONAL, INC. ("AERO")
The Company sold all of its interest in Aero except for 134,592 shares of
series A preferred stock as of May 20, 1994. The Company received proceeds of
$1.5 million and recorded a gain for the same amount. The Company loaned to
Aero $.4 million and $2.7 million in the years ended May 31, 1994 and 1993,
respectively, and during the year ended May 31, 1994 retired a $6.9 million
loan of Aero's that the Company had previously guaranteed and collateralized.
The Company's equity in Aero's loss (based on Aero's results of operations for
each of the two years in the period ended March 31, 1994) was nil and $9.5
million, in the years ended May 31, 1994 and 1993, respectively. The
Company's equity in Aero's loss included a loss provision of $7.3 million in
the year ended May 31, 1993 relating to the Company's investment in Aero's
common and preferred stock and receivables from Aero.
7. PROPERTY AND EQUIPMENT
DECEMBER 31, MAY 31,
1995 1994 1994
Oil and gas properties, full cost method:
Evaluated $ 506,405 $684,222 $629,871
Unevaluated 173,061 99,330 97,169
Support equipment and facilities 87,289 78,601 45,688
Other 22,422 30,555 24,394
789,177 892,708 797,122
Less accumulated depreciation and depletion 264,796 493,050 488,624
$ 524,381 $399,658 $308,498
The Company capitalizes interest on qualifying assets, principally unevaluated
oil and gas properties and support equipment and facilities under
construction. Capitalized interest amounted to $16.2 million in the year
ended December 31, 1995, $11.8 million in the seven months ended December 31,
1994, and $16.9 million and $6.4 million in the years ended May 31, 1994 and
1993, respectively. The Company capitalized general and administrative
expenses related to exploration and development activities of $21.1 million
in the year ended December 31, 1995, $9.5 million in the seven months ended
December 31, 1994, and $11.2 million and $9 million in the years ended May 31,
1994 and 1993, respectively.
Evaluated oil and gas properties and accumulated depreciation and depletion
decreased by $265.5 million and $247 million, respectively, in 1995 due to the
sale of Triton France S.A.
8. OTHER ASSETS
Other assets consisted of the following:
DECEMBER 31, MAY 31,
1995 1994 1994
Receivable from the forward oil sale $ 35,613 $ --- $ ---
Investment in OCENSA 15,789 7,740 ---
Investment in ODC 11,108 11,108 11,108
Securities pledged to secure guarantees --- --- 10,155
Central Llanos pipeline receivable 5,347 14,303 8,798
Unamortized debt issue costs 9,349 8,403 9,347
Other 18,725 12,200 12,453
$ 95,931 $53,754 $51,861
The Company's wholly owned subsidiary Triton Pipeline Colombia, Inc. ("Triton
Pipeline") owns the Company's 9.6% interest in Oleoducto Central S.A.
("OCENSA"). Triton Colombia, Inc. ("Triton Colombia"), a wholly owned
subsidiary of the Company, owns approximately 6.6% in Oleoducto de Colombia
S.A. ("ODC"). The investments by Triton Pipeline and Triton Colombia will
enable the Company to transport its full share of Cusiana and Cupiagua oil
production to the Caribbean port of Covenas.
As part of the purchase of ODC, the Company agreed to assume by counter
guarantee, directly and proportionally to part of the interest purchased, the
guarantees granted to bank creditors of ODC through Shell Petroleum Company
Ltd. and Shell Overseas Trading Limited. Securities pledged to secure the
guarantees as of May 31, 1994 have been replaced with letters of credit.
Triton Colombia, along with its joint venture partners in the Company's
Cusiana and Cupiagua fields in Colombia, advanced 50% of the cost to upgrade
the capacity of the Central Llanos pipeline that was formerly owned by Empresa
Colombiana de Petroleos ("Ecopetrol"). In November 1995, OCENSA acquired the
Central Llanos pipeline from Ecopetrol. The Company will recover the
remaining outstanding receivable based on the production from the Cusiana and
Cupiagua fields transported through the pipeline. The outstanding balance of
the receivable bears interest at the London Interbank Offered Rate ("LIBOR")
plus 1%. At December 31, 1995 and 1994, advances of $8 million and $7
million, respectively, were also recorded in other receivables. Full
repayment is expected in 1997.
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 $2.3 million in the year ended December 31, 1995, $1.3 million in the
seven months ended December 31, 1994 and $1.5 million and $.5 million in the
years ended May 31, 1994 and 1993, respectively.
9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
DECEMBER 31, MAY 31,
1995 1994 1994
Accounts payable, principally trade $8,004 $ 8,466 $ 7,088
Deferred income from the forward oil sale 8,079 --- ---
Accrued exploration and development 8,112 2,657 3,000
Employee compensation and benefits 2,405 3,584 2,799
Royalties and property taxes, franchise
taxes and other taxes 299 3,752 3,084
Litigation and environmental matters 1,836 2,769 3,102
Income taxes payable --- 42 6,440
Stock appreciation rights 1,234 1,137 1,328
Other 1,904 4,201 3,410
$31,873 $26,608 $30,251
10. DEBT
SHORT-TERM BORROWINGS
The Company borrowed $10 million in December 1994 under a $25 million
revolving credit facility with a bank. During 1995, another $15 million was
borrowed prior to the line of credit being repaid in full at maturity in March
1995.
The weighted average interest rates on short-term borrowings outstanding as
of December 31, 1994 and May 31, 1994 were 8.8% and 7.25%, respectively.
LONG-TERM DEBT
A summary of long-term debt follows:
DECEMBER 31, MAY 31,
1995 1994 1994
Senior Subordinated Discount Notes due 2000 $ 155,203 $ 141,122 $133,505
Senior Subordinated Discount Notes due 1997 192,220 170,274 158,618
Revolving credit facility 48,628 1,700 ---
Other notes and capitalized leases 6,452 2,419 2,630
402,503 315,515 294,753
Less current installments 1,313 257 312
$ 401,190 $ 315,258 $294,441
On December 15, 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 is 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 will accrue at the rate of 9 3/4% per annum and will be payable
semi-annually on June 15 and December 15, beginning on June 15, 1997. The
Indenture, as amended, for the 9 3/4% Notes contains financial covenants that
include certain limitations on indebtedness, dividends, certain investments,
transactions with affiliates, and engaging in mergers and consolidations.
Additional provisions include optional and mandatory redemptions, and
requirements associated with changes in control.
On November 13, 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. The Indenture, as amended, for the 1997 Notes
contains financial covenants including certain limitations on indebtedness,
dividends, certain investments, transactions with affiliates, mergers and
consolidations. Additional provisions include optional and mandatory
redemptions, and requirements associated with changes in control. As a result
of certain modifications to the indenture relating to the 1997 Notes effected
in November 1995, the Company's indebtedness limitation was increased to
permit the Company to incur total indebtedness (excluding certain permitted
indebtedness) of up to 25% of the sum of its indebtedness and market
capitalization of its capital stock. In addition, the indenture relating to
the 1997 Notes was modified to eliminate the Company's repurchase obligation
in the event the Company's net worth were to fall below a certain level.
In March 1995, the Company signed a $65 million revolving credit facility with
a bank. Borrowings bear interest at various rates either based on prime (8.5%
at December 31, 1995) or LIBOR and mature in October 1997. The facility is
secured by the Company's marketable securities portfolio and the Company's
ownership in Crusader common stock. As of December 31, 1995, the Company had
borrowed $48.6 million and issued a letter of credit for $2.8 million under
the facility.
In November 1995, the Company signed an unsecured 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 (5.5% at December 31,
1995) plus .25%, adjusted on a semi-annual basis. There were no borrowings at
December 31, 1995.
The aggregate maturities of long-term debt for the five years in the period
ending December 31, 2000 are as follows: 1996 - $1.3 million; 1997 - $241.5
million; 1998 - $.7 million; 1999 - $.7 million and 2000 - $155.9 million.
The 1997 and 2000 amounts exclude future accretion of interest on the 1997 and
the 9 3/4% Notes.
11. INCOME TAXES
Effective June 1, 1992, the Company adopted SFAS No. 109, "Accounting for
Income Taxes." The cumulative benefit of the change in fiscal 1993 was $4
million.
The components of earnings (loss) from continuing operations before income
taxes, minority interest, and cumulative effect of accounting change are as
follows:
SEVEN
YEAR ENDED MONTHS ENDED YEAR ENDED MAY 31,
DEC. 31, 1995 DEC. 31, 1994 1994 1993
United States $ (21,412) $ (23,197) $ 33,869 $ (40,068)
Foreign 38,012 363 (56,973) (107,377)
$ 16,600 $ (22,834) $ (23,104) $ (147,445)
The components of the provision for income taxes on continuing operations are
as follows:
SEVEN
YEAR ENDED MONTHS ENDED YEAR ENDED MAY 31,
DEC. 31, 1995 DEC. 31, 1994 1994 1993
Current:
United States $ 627 $ 71 $ (8) $ (411)
Foreign 3,988 (844) 3,696 176
Deferred:
United States (12,797) (61) (9,426) (21,080)
Foreign 18,241 4,630 (798) (22,566)
$ 10,059 $ 3,796 $ (6,536) $ (43,881)
A reconciliation of the differences between the United States federal
statutory tax rate and the Company's effective income tax rate follows:
SEVEN
YEAR ENDED MONTHS ENDED YEAR ENDED MAY 31,
DEC. 31, 1995 DEC. 31, 1994 1994 1993
Tax provision at statutory tax rate $ 5,807 $ (7,992) $ (8,086) $ (50,131)
Increase (decrease) resulting from:
United States losses without tax benefit --- (378) (1,433) 13,212
Net change in valuation allowance (33,472) 23,702 1,027 (21,080)
Recognition of outside basis adjustments (17,861) (19,222) --- ---
Foreign items without tax benefit 3,960 2,434 4,350 6,053
Tax on earnings of foreign subsidiaries --- --- --- 8,065
Income tax rate changes 2,807 --- (2,765) ---
Branch loss recapture/Subpart F 16,118 --- --- ---
Utilization of NOL/credit carryforwards 8,496 3,556 --- ---
Temporary differences: ---
Oil & gas basis adjustments 19,320 3,235 ---
Reimbursement of pre-commerciality costs 5,060 --- --- ---
Other (176) (1,539) 371 ---
$ 10,059 $ 3,796 $ (6,536) $ (43,881)
The components of the net deferred tax asset and liability under SFAS 109 are
as follows:
DECEMBER 31, 1995
U.S. FOREIGN
Deferred tax asset:
Net operating loss carryforwards $ 88,426 $ 8,250
Depreciable/depletable property 5,523 ---
Credit carryforwards 3,046 ---
Reserves 1,664 ---
Other 2,670 28
Gross deferred tax asset 101,329 8,278
Valuation allowances (54,046) ---
Net deferred tax asset 47,283 8,278
Deferred tax liability:
Depreciable/depletable property --- (38,175)
Net deferred tax asset (liability) 47,283 (29,897)
Less current deferred tax asset (liability) --- ---
Noncurrent deferred tax asset (liability) $ 47,283 $ (29,897)
DECEMBER 31, 1994
U.S. FOREIGN
Deferred tax asset:
Net operating loss carryforwards $ 105,250 $ 9,963
Depreciable/depletable property --- ---
Credit carryforwards 2,504 ---
Reserves 6,861 ---
Other 1,941 524
Gross deferred tax asset 116,556 10,487
Valuation allowances (80,555) (6,963)
Net deferred tax asset 36,001 3,524
Deferred tax liability:
Depreciable/depletable property (1,515) (18,196)
Net deferred tax asset (liability) 34,486 (14,672)
Less current deferred tax asset (liability) ---
Noncurrent deferred tax asset (liability) $ 34,486 $ (14,672)
MAY 31, 1994
U.S. FOREIGN
Deferred tax asset:
Net operating loss carryforwards $ 96,054 $ 8,884
Depreciable/depletable property --- ---
Credit carryforwards 4,515 ---
Reserves 5,354 ---
Other 2,035 316
Gross deferred tax asset 107,958 9,200
Valuation allowances (59,329) (4,487)
Net deferred tax asset 48,629 4,713
Deferred tax liability:
Depreciable/depletable property (14,203) (14,750)
Net deferred tax asset (liability) 34,426 (10,037)
Less current deferred tax asset (liability) --- ---
Noncurrent deferred tax asset (liability) $ 34,426 $ (10,037)
At December 31, 1995, the Company had net operating loss ("NOL") and
depletion carryforwards for United States tax purposes of $200.5 million
and $6.8 million, respectively. In addition, at December 31, 1995,
certain subsidiaries had separate return limitation year ("SRLY")
operating loss and depletion carryforwards of $52.1 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 NOL and SRLY operating loss carryforwards
expire from 1997 through 2010 as follows:
NOLS SRLYS
EXPIRING EXPIRING
BY YEAR BY YEAR
May 97 $ --- $ 11,602
May 98 --- 11,804
May 99 634 8,437
May 2000 7,315 10,224
May 2001 20,713 10,045
May 2002 - May 2010 171,837 32
Total $200,499 $ 52,144
The deferred tax valuation allowances were reduced by $33.5 million in 1995
due to changes in expectations of future U.S. taxable income resulting from
corporate restructuring during 1995, including redomiciliation of certain
domestic subsidiaries into controlled foreign corporations. Such
redomiciliation resulted in recognition of current taxable income and a
corresponding decrease in NOLs through recapture of previously recognized
losses. Furthermore, 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 in the future.
If certain changes in the Company's ownership should occur, there would be an
annual limitation on the amount of NOL carryforwards 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.
During the year ended May 31, 1993, the Company added $3.9 million to
additional paid-in capital for United States tax benefits attributable to the
utilization of net operating loss carryforwards. These carryforwards related
to periods prior to the Company's corporate readjustments.
12. 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 the 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, 1995 DECEMBER 31, 1994 MAY 31, 1994
DEFINED DEFINED DEFINED
BENEFIT SERP BENEFIT SERP BENEFIT SERP
PLAN PLAN PLAN PLAN PLAN PLAN
Actuarial present value of benefit
obligations:
Vested benefit obligations $ 3,632 $ 3,849 $ 3,440 $ 3,345 $ 3,669 $ 3,357
Accumulated benefit obligations $ 3,844 $ 3,849 $ 3,570 $ 3,345 $ 3,819 $ 3,357
Projected benefit obligations $ 4,513 $ 4,966 $ 4,136 $ 4,299 $ 4,408 $ 4,241
Plan assets at fair value, primarily
listed stocks and United States
government securities 4,326 --- 3,188 --- 3,475 ---
Unfunded projected benefit
obligations 187 4,966 948 4,299 933 4,241
Unrecognized net loss (54) (283) (576) (157) (696) (401)
Prior service cost not yet recognized
in net periodic pension cost (709) (155) (765) (165) (798) (172)
Unrecognized net asset (liability) at
adoption 13 (1,624) 15 (1,792) 16 (1,890)
Adjustment required to recognize
minimum liability --- 945 760 1,160 889 1,579
Accrued (prepaid) pension cost $ (563) $ 3,849 $ 382 $ 3,345 $ 344 $ 3,357
A summary of the components of pension expense follows:
SEVEN
YEAR ENDED MONTHS ENDED YEAR ENDED MAY 31,
DEC. 31, 1995 DEC. 31, 1994 1994 1993
Service cost - benefits earned
during the period $ 780 $ 454 $ 733 $ 259
Interest cost on projected benefit obligation 653 344 553 463
Actual return on plan assets (849) 219 111 (398)
Net amortization and deferral 793 (256) (173) 296
$ 1,377 $ 761 $ 1,224 $ 620
The projected benefit obligations at December 31, 1995 and 1994 and May 31,
1994 assume a discount rate of 8%, 8% and 7%, respectively, and a rate of
increase in compensation expense of 5%. The impact of the change in the
discount rate from 7% to 8% reduced the projected benefit obligation at
December 31, 1994 for both the defined benefit plan and SERP by $.5 million.
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 relating to the plan based on actual amounts contributed
since inception of the plan. The Company used the shares allocated method
prior to the January 1, 1994 amendment.
13. STOCKHOLDERS' EQUITY
PREFERRED STOCK
In connection with the acquisition of the minority interest in Triton Europe,
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. Each share of the Company's 5% preferred stock is convertible into one
common share, subject to adjustment in certain events. The 5% preferred stock
is convertible anytime on or after October 1, 1994, and bears a fixed
cumulative cash dividend of 5% per annum payable semi-annually on March 30 and
September 30, commencing September 30, 1994. If not converted earlier, each
5% preferred share will be redeemed on March 30, 2004, either for cash, or at
the option of the Company, for the Company's common stock. At December 31,
1995, 410,017 preferred shares were outstanding.
COMMON STOCK
Changes in issued common shares were as follows:
SEVEN
YEAR ENDED MONTHS ENDED
DEC. 31, DEC. 31, YEAR ENDED MAY 31,
1995 1994 1994 1993
Balance at beginning of period 35,577,009 35,519,103 35,231,142 34,649,148
Conversion of 5% preferred stock 112,395 48 --- ---
Exercise of employee stock options
and debentures 237,875 57,858 287,961 581,994
Balance at end of period 35,927,279 35,577,009 35,519,103 35,231,142
Changes in common shares held in treasury were
as follows:
SEVEN
YEAR ENDED MONTHS ENDED
DEC. 31, DEC. 31, YEAR ENDED MAY 31,
1995 1994 1994 1993
Balance at beginning of period 45,837 54,354 57,483 57,400
Purchase of treasury stock 89 98 149 83
Transfer of shares to employee benefit plans (19,291) (8,615) (3,278) ---
Balance at end of period 26,635 45,837 54,354 57,483
STOCK OPTIONS
Options to purchase the Company's common stock have been granted to officers
and employees under various stock option plans. Grants generally become
exercisable in 25% cumulative annual increments beginning one year from the
date of issuance and expire at the end of ten years. At December 31, 1995,
624,165 shares were available for grant under the plans. Pursuant to the
1992 stock option plan, each non-employee director receives an option to
purchase 15,000 shares each year. A summary of option transactions follows:
NUMBER OF OPTION PRICE
SHARES PER SHARE
Outstanding at May 31, 1992 1,644,324 $8.38 - 52.50
Granted 680,000 28.25 - 41.88
Exercised (552,828) 8.38 - 35.00
Canceled (50,090) 11.29 - 52.50
Outstanding at May 31, 1993 1,721,406 8.38 - 42.25
Granted 1,414,800 28.63 - 33.50
Exercised (133,411) 8.38 - 16.25
Canceled (336,250) 8.38 - 42.00
Outstanding at May 31, 1994 2,666,545 8.38 - 42.25
Granted 544,500 30.75 - 36.25
Exercised (48,691) 8.38 - 11.50
Canceled (87,500) 39.63 - 42.00
Outstanding at December 31, 1994 3,074,854 8.38 - 42.25
Granted 373,500 32.00 - 55.00
Exercised (237,875) 8.38 - 42.00
Canceled (33,175) 32.00 - 42.00
Outstanding at December 31, 1995 3,177,304 8.38 - 55.00
NUMBER OF OPTION PRICE
SHARES PER SHARE
Shares exercisable:
May 31, 1993 564,402 $8.38 - 42.25
May 31, 1994 563,741 8.38 - 42.25
December 31, 1994 873,551 8.38 - 42.25
December 31, 1995 1,449,424 8.38 - 42.25
The weighted average exercise price of options outstanding at December 31,
1995 was $35.49.
CONVERTIBLE DEBENTURE PLAN
The Company has a convertible debenture plan under which key management
personnel and others may purchase debentures that are convertible into shares
of the Company's common stock. The aggregate number of common 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 seven to ten years and may be redeemed after
three years at a redemption price of 120% of the principal amounts. The
debentures outstanding at December 31, 1995 bear interest at the prime rate,
have a conversion date of one year following the date of issuance and may be
converted into the Company's common stock at a price of $42.75 per share
(debentures covering 250,000 shares issued in May 1995) and $25.13 per share
(debentures covering 250,000 shares issued in April 1994), subject to
adjustment in certain events. At December 31, 1995, approximately 4,000
shares were available for issuance upon conversion of debentures eligible for
sale under the plan.
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 ten 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,
1995 1994 MAY 31, 1994
Convertible debentures due employees $ 16,969 $ 6,281 $ 6,355
Promissory notes (16,969) (6,281) (6,355)
--- $ --- $ ---
Number of shares covered by
outstanding debentures 500,000 250,000 259,167
SHAREHOLDER RIGHTS PLAN
In May 1995, the Board of Directors of the Company adopted a new Shareholder
Rights Plan under which preferred stock rights were issued to holders of its
common stock at the rate of one right for each share of common stock held as
of the close of business on June 2, 1995. The rights were issued in place of
the Company's previous preferred share purchase rights issued in 1990, which
have been redeemed.
Generally, the rights become exercisable only if a person acquires beneficial
ownership of 15% or more of the Company's common stock or announces a tender
offer for 15% or more of the common stock. If, among other events, any person
becomes the beneficial owner of 15% or more of the Company's common stock,
each right not owned by such person generally becomes the right to purchase
such number of shares of common stock of the Company, which is equal to the
amount obtained by dividing the right's exercise price (currently $120) by 50%
of the market price of the common stock 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 common stock, the Company may redeem
the rights in whole, but not in part, at a price of $.01 per right.
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 common shares covered by SARs on the
exercise date and expire at the earlier of ten years or a date based on the
termination of the holder's membership on the board of directors. At December
31, 1995, SARs covering 25,000 common shares, with an exercise price of $8
per share, were outstanding.
RESTRICTED STOCK PLAN
The Company has a restricted stock plan that provides for the award of up to
50,000 common shares to eligible key officers and employees. At the November
11, 1993 annual meeting, this plan was amended to also serve as an employee
stock purchase plan. At December 31, 1995, 20,124 shares were available for
issuance under the plan.
CORPORATE READJUSTMENTS
To permit payments of common stock dividends from future earnings without
being penalized by an accumulated deficit, Article 4.13B of the Texas Business
Corporation Act formerly provided that a company may, subject to its board of
directors' approval, eliminate that deficit through application of additional
paid-in capital. Pursuant to board of directors' approvals on January 12,
1987 and August 6, 1986, the Company eliminated accumulated deficits of $5.3
million at November 30, 1986 and $28.7 million at May 31, 1986.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND
CREDIT RISK CONCENTRATIONS
FAIR VALUE OF FINANCIAL INSTRUMENTS
At December 31, 1995 and 1994 and May 31, 1994, 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 $396 million, $300 million and $299 million at December 31, 1995 and 1994
and May 31, 1994, respectively.
RISK MANAGEMENT
In the normal course of business, the Company enters into financial and
commodity market transactions for purposes other than trading to manage its
exposure to commodity price risk. As a result of such transactions to date,
the Company has set the price benchmark on approximately 44% of its projected
1996 Colombian oil production at a weighted average WTI benchmark price of
$17.99 per barrel. In addition, in order to retain the opportunity to
participate in higher prices, the Company has purchased WTI benchmark call
options on a total of 500,000 barrels for various delivery dates during the
first half of 1996 at strike prices between $19.68 and $20.28.
In anticipation of entering into the forward oil sale, the Company entered
into five-year commodity price agreements in April and May 1995 to hedge price
risk associated with the portion of the Company's oil production in Colombia
expected to be sold in the forward oil sale. Sales of the Company's Colombian
production are priced with reference to WTI. The agreements, which were
entered into with a counterparty with a "AAA" credit rating, fixed a WTI price
benchmark of $18.42 per barrel on approximately 10.4 million barrels.
Simultaneously, the Company purchased from a credit-worthy counterparty call
options to retain the ability to benefit from future WTI price increases above
$20.42 per barrel. The volumes and expiration dates on the call options
coincided with the volumes and delivery dates under the commodity price
agreements. Prior to completion of the forward oil sale, the commodity price
and call agreements had been accounted for as hedging transactions. Upon
completion of the forward oil sale, the commodity price agreements were
superseded and the call options, which no longer qualified for hedge
accounting, were recorded as a separate investment at their then fair market
value of $9.3 million. Noncash charges of $4.2 million were recorded for the
year ended December 31, 1995.
The Company entered into a foreign exchange contract in fiscal 1994 to
purchase C$8.6 million to hedge exposure to a Canadian tax liability resulting
from the sale of Triton Canada common stock. At May 31, 1994, the fair value
of the foreign exchange contract, which matured in July 1994, was based on
quoted rates for contracts with similar terms and maturity dates; however,
such fair value was offset by gains on the tax liability hedged by the
contract, so there was no significant difference between the recorded value
and the fair value of the Company's net foreign exchange position.
CONCENTRATION OF CREDIT RISK
Financial instruments that are potentially subject to concentrations of credit
risk consist of cash equivalents, marketable securities, receivables and
financial market transactions. The Company places its cash equivalents,
marketable securities and financial market transactions with high credit
quality financial institutions. The Company believes the risk of incurring
losses related to credit risk is remote.
Triton Colombia sells its crude oil production from the Cusiana Field through
an agreement with the operator of the field to approximately ten to fifteen
refineries 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 operator would have a long-term material adverse effect on its
operations.
15. OTHER INCOME (EXPENSE), NET
Other income (expense), net is summarized as follows:
SEVEN
YEAR ENDED MONTHS ENDED YEAR ENDED MAY 31,
DEC. 31, 1995 DEC. 31, 1994 1994 1993
Proceeds from legal settlements $ 7,222 $ --- $ --- $ ---
Gain on the sale of Triton France 3,496 --- --- ---
Gain on early redemption of Crusader's
convertible notes 2,899 --- --- ---
Gain on sale of United States
working interest properties --- --- 7,028 ---
Gain on sale of Aero common stock --- --- 1,500 ---
Loss provisions (1,058) --- --- (5,500)
Change in fair market value of call options (4,171) --- --- ---
Foreign exchange gain (loss) 1,874 383 252 (776)
Other 1,372 441 1,251 1,832
$ 11,634 $ 824 $ 10,031 $ (4,444)
16. WRITEDOWN OF ASSETS
Writedown of assets are summarized as follows:
SEVEN
YEAR ENDED MONTHS ENDED YEAR ENDED MAY 31,
DEC. 31, 1995 DEC. 31, 1994 1994 1993
Evaluated oil and gas properties $--- $ 984 $ 44,123 $65,354
Unevaluated oil and gas properties --- --- 251 25,817
Inventory --- --- 1,064 500
Investments and other assets --- --- 316 2,712
$--- $ 984 $ 45,754 $94,383
During fiscal 1994, the carrying amounts of the Company's evaluated oil
properties in France were written down by $43.2 million through application of
the ceiling limitation prescribed by the Securities and Exchange Commission
(the "Commission") principally as a result of a temporary drop in oil prices
and a downward revision in estimated reserves.
Included in the writedowns of evaluated and unevaluated properties during
fiscal 1993 were $55.7 million and $11 million, respectively, of costs
associated with operations in France and an $8.2 million writedown of
unevaluated costs associated with onshore properties in the United Kingdom.
These writedowns resulted from Triton Europe's decision to curtail certain
exploration and development activities in Europe. As such, proved undeveloped
reserves in Europe were reduced, thereby requiring a writedown of evaluated
costs as a result of the Commission's ceiling limitation for these properties.
The writedowns of unevaluated costs in both France and the United Kingdom
were associated with various license areas that were relinquished or allowed
to expire. Similar cutbacks in Indonesia resulted in writedowns of costs
associated with evaluated properties of $8.7 million in fiscal 1993.
17. STATEMENTS OF CASH FLOWS
Supplemental disclosures of cash payments and noncash investing and financing
activities follows:
SEVEN
YEAR ENDED MONTHS ENDED YEAR ENDED MAY 31,
DEC. 31, 1995 DEC. 31, 1994 1994 1993
Cash paid during the year for:
Interest (net of amount capitalized) $ --- $ --- $ --- $ ---
Income taxes 920 5,557 222 1,321
Noncash investing and financing
activities:
Preferred stock issued for purchase of
Triton Europe minority interest --- --- 17,978 ---
Conversion of preferred stock into
common stock 3,867 --- --- ---
Sale of the Company's shares by Crusader --- --- --- 3,920
Liabilities resulting from acquisitions --- --- --- 1,265
Property and equipment exchanged for
a long-term note receivable 650 --- 1,980 ---
18. CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS
Certain statements in this report, including statements of the Company's and
management's expectations, intentions, plans and beliefs, 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 of
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, expected or planned production or transportation capacity, the
future construction or upgrades of pipelines (including costs), when the
Cusiana and Cupiagua fields might become self-financing, future production
of the Cusiana and Cupiagua fields, the negotiation of a gas 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 Company's realization of its deferred tax asset, the level
of future expenditures for environmental costs and the outcome of regulatory
and litigation matters; 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 and in note 19.
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 the Company will be successful in its exploration activities.
Oil prices have been subject to significant fluctuations over the past several
decades. The Company expects that levels of production maintained by the
Organization of Petroleum Exporting Countries member nations and other major
oil producing countries, and the actions of oil traders, will continue to be
major determinants of crude oil price movements in the near term. It is
impossible to predict future oil price movements with any certainty.
The Company's oil and gas business is subject to all of the operating risks
normally associated with the exploration for and production of oil and gas,
including blowouts, cratering, pollution, earthquakes, labor disruptions and
fires, each of which could result in damage to or destruction of oil and gas
wells, formations, production facilities or properties, or in personal injury.
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.
The Company's oil and gas business is also subject to laws, rules and
regulations in the countries in which it operates, which generally pertain to
production control, taxation, environmental and pricing concerns and other
matters relating to the petroleum industry.
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 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 United States 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.
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.
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.
CERTAIN FACTORS RELATING TO COLOMBIA
The Company is a participant in significant oil and gas discoveries located in
the Llanos Basin in the foothills of the Andes Mountains, approximately 160
kilometers (100 miles) northeast of Bogota, Colombia. The Company owns
interests in three contiguous areas known as the Santiago de las Atalayas
("SDLA"), Tauramena and Rio Chitamena contract areas. Well results to date
indicate that significant oil and gas deposits lie across the Cusiana and
Cupiagua fields.
Largely due to complex geology, drilling of wells in the Cusiana and Cupiagua
fields has been comparatively difficult, lengthy in duration and expensive.
The Company believes that considerable progress has been achieved in reducing
the time and expenditures required to drill and complete wells in the Cusiana
and Cupiagua fields based on experience gained from initial wells drilled.
Although there can be no assurance, the Company believes that the experience
gained in the area to date will allow the operator to continue to reduce the
time and expenditures required to drill and complete wells in the area.
However, because the Company is not the operator of these contract areas, the
Company does not control the timing or manner of these operations.
Full development of reserves in the Cusiana and Cupiagua fields will take
several years and require additional drilling and extensive production
facilities, which in turn will require significant additional capital
expenditures, the ultimate amount of which cannot be predicted. Pipelines
connect the major producing fields in Colombia to export facilities and to
refineries. These pipelines are in the process of being upgraded and expanded
to accommodate production from the Cusiana and Cupiagua fields.
Guerrilla activity in Colombia has from time to time disrupted the operation
of oil and gas projects and increased costs. Although the Colombian
government, the Company and its partners have taken steps to improve security
and improve relations with the local population, there can be no assurance
that attempts to reduce or prevent guerrilla activity will be successful or
that such activity will not disrupt operations in the future.
Numerous Colombian government officials, including the President, are the
subjects of investigations and allegations that they have accepted illegal
campaign contributions. These circumstances have led to speculation as to
whether these officials will remain in office. The President has stated that
any such illicit contributions were made without his knowledge. In response
to the allegations, the leadership of the opposition Conservative Party
withdrew its support of the Government and certain cabinet ministers and
ambassadors and a high ranking military officer resigned. Any changes in the
holders of significant government offices could have adverse consequences in
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. At the
same time, Colombia is among 31 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 March 1996, the President of the
United States announced that Colombia would neither be certified nor granted a
national interest waiver and the United States Congress is not expected to
oppose the President's action. The consequences of the failure to receive
certification generally include the following: all bilateral aid, except
anti-narcotics and humanitarian aid, will be suspended; EXIM and the Overseas
Private Investment Corporation will not approve financing for new projects in
Colombia, although currently approved EXIM financings are not expected to be
affected; U.S. representatives at multilateral lending institutions will be
required to vote against all loan requests from Colombia, although such votes
will not constitute vetoes; and the President and Congress retain the right to
apply future trade sanctions.
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. The Company is
a contractor under a Production Sharing Contract covering Block A-18 of the
Malaysia-Thailand Joint Development Area. Test results for the initial
exploratory wells indicate that significant gas deposits lie under 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 will also be required to be connected between Block A-18
and ultimate markets. The terms on which any gas produced from the Company's
contract area in Malaysia-Thailand may be sold may be adversely affected by
the present monopoly gas purchase and transportation conditions in both
Thailand and Malaysia, including the Thai national oil company's monopoly in
transportation within Thailand and its territorial waters.
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.
19. COMMITMENTS AND CONTINGENCIES
Continued development of the Cusiana and Cupiagua fields ("the Fields"),
including drilling and construction of additional production facilities, will
require significant capital. In 1995 and early 1996, Carigali-Triton
Operating Company ("CTOC") discovered gas on its first three wells on Block
A-18 in the Malaysia-Thailand Joint Development Area in the Gulf of Thailand.
Further exploration and development activities on Block A-18, as well as
exploratory drilling in other countries, will also require substantial
capital. The Company's capital budget for the year ending December 31, 1996
is approximately $260 million, excluding capitalized interest, of which
approximately $157 million relates to the Fields, $34 million relates to Block
A-18, $40 million relates to the Company's exploration and drilling program in
other parts of the world, and $29 million relates to capital contributions to
OCENSA. Capital requirements for full field development of the Fields are
expected to continue at substantial levels into 1997, and capital requirements
for exploration and development relating to Block A-18 are expected to
increase significantly into 1998.
In December 1994, the Company, along with other investors, formed an
independent company, OCENSA, to own, expand, finance and operate a pipeline
system from the Fields to the port of Covenas. The Company's ownership
percentage is 9.6%. OCENSA's capitalization plan contemplates an ultimate
capital structure of approximately 30% equity from the Company and other
investors and 70% debt. As part of the formation of OCENSA, Triton Colombia
entered into a transportation agreement with OCENSA in which Triton Colombia
commits to transport all crude from the Fields through OCENSA's pipeline
system.
OCENSA has raised significant amounts of debt in separate tranches supported
by various agreements with the Company or its partners as the case may be
(relating, in particular, to tariffs on each partner's throughput). The
Company assisted OCENSA in securing one such tranche for $60 million in 1995,
which is supported by the Company's tariff commitments for its share of
production from the Fields. The Company has agreed to assist OCENSA in
raising an additional $60 million in 1996. In the event such amount cannot be
raised, OCENSA may call for an advance from the Company.
In November 1995, the Company signed a $45 million loan agreement supported by
a guarantee issued by EXIM. The loan finances expenditures for exported U.S.
goods and services for phase one development of the Cusiana Field in Colombia.
The Company borrowed approximately $43 million against this facility in early
1996.
As part of the forward oil sale transaction, Morgan Guaranty agreed to
purchase up to $40 million of additional production on a forward sale basis in
the event that the Company is otherwise unable to meet its cash call
obligations in respect of the Cusiana and Cupiagua fields project. The number
of barrels would be determined based on a formula intended to reflect their
fair market value. The Company does not expect, however, to sell any
production under this agreement.
The Company expects to meet capital needs in the future with a combination of
some or all of the following: its long-term revolving credit facility, cash
flow from its Colombian operations, cash on hand and marketable securities,
asset sales, and the issuance of debt and equity securities. As a result of
certain modifications to the indenture relating to the 1997 Notes effected in
November 1995, the Company's indebtedness limitation was increased to permit
the Company to incur total indebtedness (excluding certain permitted
indebtedness) of up to 25% of the sum of its indebtedness and market
capitalization of its capital stock. In addition, the indenture relating to
the 1997 Notes was modified to eliminate the Company's repurchase obligation
in the event the Company's net worth were to fall below a certain level.
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 Malaysia-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 2001. Total rental expense was $1.9 million
for the year ended December 31, 1995, $1.3 million for the seven months ended
December 31, 1994 and $2.6 million and $4 million for the years ended May 31,
1994 and 1993, respectively. At December 31, 1995, the minimum payments
required over the next five years are as follow: 1996 - $2.3 million; 1997 -
$2.2 million; 1998 - $1.8 million; 1999 - $1.4 million; and 2000 - $.7
million.
GUARANTEES
At December 31, 1995, the Company had guaranteed loans of approximately $6.1
million of a Colombian pipeline company in which the Company has an ownership
interest and guaranteed performance of $11 million in future exploration
expenditures in various countries. These commitments are backed primarily by
unsecured letters of credit and bank guarantees.
REGULATORY MATTERS
The Company continues to cooperate with inquiries by the Commission and the
Department of Justice (the "Department") regarding possible violations of the
Foreign Corrupt Practices Act in connection with the Company's operations in
Indonesia. Based upon the information available to the Company to date, the
Company believes that it will be able to resolve any issues that either the
Commission or the Department ultimately might raise concerning these matters
in a manner that would not have a material adverse effect on the Company's
operations or consolidated financial condition.
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 remains liable for certain environmental matters
that may arise from formerly owned fuel businesses that were involved in the
storage, handling and sale of hazardous materials, including fuel storage in
underground tanks. 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.
During the year ended May 31, 1994, the Company accrued $4.4 million for
environmental costs.
LITIGATION
The Company is also subject to various litigation matters, none of which is
expected to have a material adverse effect on the Company's operations or
consolidated financial condition.
20. RELATED PARTY TRANSACTIONS
The Company charged Crusader $.6 million for the year ended December 31,
1995, $.3 million for the seven months ended December 31, 1994 and $.6 million
for the years ended May 31, 1994 and 1993 for administrative services. Also
during fiscal 1994, the Company was paid $1.2 million by Crusader for acting
as agent in issuing its 6% Notes and recorded $.6 million as other income.
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, 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
SEVEN MONTHS ENDED DECEMBER 31, 1994:
Sales and other operating revenues $ 6,249 $ --- $ 9,179 $ 3,174 $ 2,134 $ --- $ --- $ 20,736
Operating profit (loss) (192) --- 722 (75) (919) (2,258) (13,224) (15,946)
Trade and other receivables 11,759 --- 3,866 1,257 1,332 667 1,360 20,241
Identifiable assets 335,474 21,372 27,038 2,553 32,232 33,477 167,055 619,201
YEAR ENDED MAY 31, 1994:
Sales and other operating revenues $ 5,911 $ --- $ 17,494 $ 7,186 $ 5,629 $ 6,988 $ --- $ 43,208
Operating profit (loss) (503) --- (49,734) (4,582) (1,269) (3,332) (21,263) (80,683)
Trade and other receivables 5,508 --- 3,431 1,303 1,336 1,110 1,891 14,579
Identifiable assets 237,397 15,764 28,954 3,978 37,091 36,205 256,712 616,101
YEAR ENDED MAY 31, 1993:
Sales and other operating revenues $ 3,474 $ --- $ 30,897 $ 10,449 $16,838 $ 22,756 $ --- $ 84,414
Operating profit (loss) (672) --- (79,336) (10,425) 383 (21,081) (18,804) (129,935)
Trade and other receivables 510 --- 2,357 1,571 3,716 7,349 1,213 16,716
Identifiable assets 147,280 9,776 78,830 6,042 56,196 73,436 190,371 561,931
Corporate assets were principally cash and cash equivalents, marketable
securities, the United States deferred tax asset and investments in
unconsolidated affiliates. Other identifiable assets primarily represented
capitalized costs related to the Company's exploration activities in other
areas of the world, no one country of which is material except Argentina
($36.3 million at December 31, 1995).
22. SUBSEQUENT EVENTS (UNAUDITED)
During January and February 1996, the Company borrowed approximately $43
million against its credit line supported by the EXIM guarantee. The proceeds
from the borrowing were used primarily to pay down outstanding bank lines of
credit.
The Company has called a special meeting of its stockholders to be held on
March 25, 1996 at which the stockholders will vote on the proposed
reorganization of the Company (the "Reorganization"). Pursuant to the
Reorganization, Triton Energy Limited, a newly formed Cayman Islands company
and a wholly owned subsidiary of the Company ("Triton Cayman"), will become
the parent holding company of the Company through the merger of a wholly owned
subsidiary of Triton Cayman with and into the Company. If the Reorganization
is consummated, the Company will become a subsidiary of Triton Cayman and
Triton Cayman will continue to conduct the businesses (through subsidiaries
and affiliates) in which the Company is now engaged. The Company and Triton
Cayman have filed with the Securities and Exchange Commission a Proxy
Statement/Joint Prospectus dated as of February 23, 1996 relating to the
special meeting and the securities to be issued if the Reorganization is
consummated.
Upon consummation of the Reorganization, each outstanding share of common
stock of Triton Energy Corporation at the effective time of the Reorganization
(the "Effective Time") (other than shares held in treasury and shares as to
which an election to receive Equity Units (as defined below) has been made and
not withdrawn, subject to certain limitations) will be automatically converted
into one Class A Ordinary Share of Triton Cayman. Holders of not less than
15% but not more than 25% of the outstanding shares of common stock at the
Effective Time, in the aggregate, may make an unconditional election to
receive an equity unit ("Equity Unit") consisting of one Class B Ordinary
Share of Triton Cayman and one-tenth of one share of participating preferred
stock of Triton Energy Corporation for each share of common stock of Triton
Energy Corporation owned in lieu of such shares being converted into Class A
Ordinary Shares. Each such Class B Ordinary Share and one-tenth of a share of
participating preferred stock would be paired and after such pairing could
only be traded together as a unit. If holders of less than 15% of the
outstanding shares of common stock, in the aggregate, elect to receive Equity
Units, no Equity Units will be issued and all such shares would be
automatically converted into Class A Ordinary Shares of Triton Cayman.
Subsequent to the Reorganization, the Company intends to transfer
substantially all of its businesses or subsidiaries located outside the United
States, other than the Company's interests in the Cusiana and Cupiagua fields
in Colombia, and interests in Argentina, to Triton Cayman. The value of the
assets to be transferred will be determined by the Company based on
independent third party appraisals as of the dates of the transfers.
Colombia is among 31 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 March 1996, the President of the United States
announced that Colombia would neither be certified nor granted a national
interest waiver and the United States Congress is not expected to oppose the
President's action. See "Certain Factors Relating to Colombia" in note 18 for
further discussion of the implications of this announcement.
In March 1996, the Company entered into an agreement providing for the sale of
substantially all of its royalty and mineral interests in the United States,
the consummation of which is subject to customary conditions. The net
proceeds from the sale, which will be made effective January 1, 1996, are
expected to be approximately $23.8 million and will result in a gain of
approximately $4 million.
In March 1996, the Company executed an agreement with Deminex Colombia
Petroleum GmbH ("Deminex") providing Deminex the right to earn a 50% interest
in the El Pinal, Guayabo A and B and Las Amelias contract areas. The
effectiveness of the agreement is conditioned on the approval by December 31,
1996 of Ecopetrol and the Ministry of Mines and Energy of Colombia. The
agreement provides for an initial payment by Deminex of approximately $13.4
million. In addition to costs associated with its 50% interest in the
contract areas, Deminex shall pay certain direct exploratory costs of the
Company up to a maximum of approximately $16.8 million. All payments due
prior to the receipt of the requisite approvals will be held in escrow.
23. QUARTERLY FINANCIAL DATA (UNAUDITED)
Amounts in the following tables have been restated to account for
discontinued operations:
QUARTER
FIRST SECOND THIRD FOURTH
YEAR ENDED
December 31, 1995:
Sales and other operating revenues $ 19,751 $ 28,504 $ 32,586 $ 26,631
Gross profit 7,013 13,670 15,351 12,954
Net earnings (loss) (1,555) 2,388 1,279 608
Net earnings (loss) per common share (0.06) 0.07 0.03 0.02
FIRST SECOND ONE
QUARTER QUARTER MONTH
SEVEN MONTHS ENDED
December 31, 1994:
Sales and other operating revenues $ 9,758 $ 7,932 $ 3,046
Gross profit (loss) 112 (38) (23)
Net earnings (loss) (8,173) (11,100) (8,435)
Net earnings (loss) per common share (0.23) (0.33) (0.24)
QUARTER
FIRST SECOND THIRD FOURTH
FISCAL YEAR ENDED
May 31, 1994:
Sales and other operating revenues $ 18,474 $ 10,129 $ 6,962 $ 7,643
Gross loss (11,419) (13,087) (17,652) (7,780)
Net earnings (loss) 35,078 (11,237) (19,985) (13,197)
Net earnings (loss) per common share 1.01 (0.32) (0.57) (0.38)
Gross profit (loss) consists of sales and other operating revenues less
operating expenses, depreciation, depletion and amortization and writedowns
pertaining to operating assets.
In the fourth quarter of 1995, the Company recorded a loss provision of $1.1
million related to property available for sale, and Crusader recorded a
writedown of $3 million (the Company's share - $1.5 million) related to a coal
property of its majority-owned affiliate. Also, the Company recorded a charge
to deferred tax expense of $2.8 million due to a change in income tax rates in
Colombia and a benefit of $8.5 million based on a reduction in the valuation
allowance on its deferred United States tax asset.
In December 1994, the Company recorded equity in losses of Crusader of $4.2
million due principally to adjustments to deferred taxes and writedowns of
unproved oil and gas properties in the Philippines and Argentina.
In the fourth quarter of the year ended May 31, 1994, the Company recorded
writedowns of $6.8 million, primarily resulting from application of the
Commission's ceiling limitation caused by a downward revision in the estimated
reserves for France. The Company also recognized a gain of $1.5 million on
the sale of its investment in Aero.
24. CHANGE IN FISCAL YEAR END
In May 1994, the Company changed its fiscal year end from May 31 to December
31 effective January 1, 1995. These financial statements cover the Company's
transition period for the seven months ended December 31, 1994.
The results of operations of the Company for the seven months ended December
31, 1994 and 1993 were as follows:
SEVEN MONTHS ENDED
DEC. 31, 1994 DEC. 31, 1993
(UNAUDITED)
Sales and other operating revenues $ 20,736 $ 30,992
Gross profit (loss) 51 (33,532)
Income tax expense (benefit) 3,796 (4,288)
Earnings (loss) from continuing operations (26,630) 18,383
Earnings (loss) from discontinued operations (1,078) (2,731)
Net earnings (loss) (27,708) 15,652
Dividends on preferred stock 449 ---
Net earnings (loss) applicable to common stock (28,157) 15,652
Earnings (loss) per common share:
Continuing operations (0.78) 0.53
Discontinued operations (0.03) (0.08)
Net earnings (loss) per common share (0.81) 0.45
The results of operations for the seven months ended December 31, 1993
included a net after-tax benefit of $48 million, or $1.38 per common share,
relating to the sales of the Company's Canadian subsidiary and certain working
interest properties in the United States, which was partially offset by a
writedown of oil properties in France of $12.8 million, after taxes and
minority interest, or $0.37 per common share.
Quarterly results restated for calendar 1994 are as follows:
QUARTER
FIRST SECOND THIRD FOURTH
December 31, 1994:
Sales and other operating revenues $ 6,923 $ 8,950 $ 8,637 $ 8,442
Gross profit (loss) (8,662) (7,914) (27) (68)
Net earnings (loss) (14,058) (13,826) (7,870) (16,947)
Net earnings (loss) per common share (0.40) (0.40) (0.24) (0.48)
In the fourth calendar quarter of 1994, the Company recorded equity in losses
of Crusader of $4.5 million due principally to adjustments to deferred taxes
and writedowns of unproved oil and gas properties in the Philippines and
Argentina.
25. OIL AND GAS DATA
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.
RESULTS OF OPERATIONS
The results of operations for oil and gas producing activities, considering
direct costs only, follow:
UNITED TOTAL
COLOMBIA FRANCE INDONESIA STATES CANADA 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
SEVEN MONTHS ENDED DECEMBER 31, 1994:
Revenues $ 6,249 $ 9,179 $ 3,174 $ 1,919 $ --- $ --- $ 20,521
Costs:
Production costs 4,290 5,784 2,054 144 --- --- 12,272
General operating expenses 997 541 897 502 --- --- 2,937
Depletion 1,184 2,132 298 1,189 --- --- 4,803
Writedown of assets --- --- --- 984 --- --- 984
Income taxes 82 318 --- --- --- --- 400
Results of operations $ (304) $ 404 $ (75) $ (900) $ --- $ --- $ (875)
YEAR ENDED MAY 31, 1994:
Revenues $ 5,911 $ 17,252 $ 7,186 $ 4,700 $ 5,961 $ 229 $ 41,239
Costs:
Production costs 4,230 10,347 6,413 2,436 2,919 281 26,626
General operating expenses 1,267 4,237 3,070 1,044 614 --- 10,232
Depletion 917 9,443 1,363 2,290 2,482 --- 16,495
Writedown of assets --- 43,201 922 --- --- 251 44,374
Income taxes 8 --- --- --- 195 --- 203
Results of operations $ (511) $ (49,976) $ (4,582) $ (1,070) $ (249) $ (303) $ (56,691)
YEAR ENDED MAY 31, 1993:
Revenues $ 3,474 $ 30,574 $ 10,449 $ 14,032 $ 20,423 $ 105 $ 79,057
Costs:
Production costs 2,411 13,494 5,984 2,471 10,431 97 34,888
General operating expenses 1,191 7,687 1,906 1,698 2,494 --- 14,976
Depletion 544 22,287 4,250 6,587 8,633 --- 42,301
Writedown of assets --- 66,765 8,734 879 --- 14,793 91,171
Income taxes 84 --- --- --- 369 --- 453
Results of operations $ (756) $ (79,659) $ (10,425) $ 2,397 $ (1,504) $ (14,785) $ (104,732)
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:
UNITED
AUSTRALIA CANADA STATES OTHER TOTAL
December 31, 1995 $ 2,998 $ 269 $ --- $ (1,401) $1,866
December 31, 1994 $ 1,339 $ 243 $ 36 $ (1,662) $ (44)
May 31, 1994 $ 2,904 $ 712 $ (1,270) $ --- $2,346
May 31, 1993 $ 3,771 $1,259 $ (3,338) $ --- $1,692
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 CANADA OTHER WORLDWIDE
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 period-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 period-end $ 17,355 $ --- $ --- $ 47,153 $ 180,574 $ --- $ 8,667 $ 253,749
MALAYSIA- UNITED TOTAL
COLOMBIA THAILAND FRANCE INDONESIA STATES CANADA OTHER WORLDWIDE
December 31, 1994:
Costs incurred:
Property acquisition $ 9,824 $ --- $ --- $ --- $ --- $ --- $ 1,058 $ 10,882
Exploration 21,691 5,151 79 --- --- --- 7,088 34,009
Development 31,892 --- 5 1 1 --- --- 31,899
Depletion per equivalent
barrel of production 2.57 --- 4.15 1.60 7.04 --- --- 3.63
Cost of properties at period-end:
Unevaluated $ 38,000 $ 20,334 $ 281 $ --- $ 9,202 $ --- $31,513 $ 99,330
Evaluated $175,281 $ --- $265,284 $ 44,594 $ 190,396 $ --- $ 8,667 $ 684,222
Support equipment and
facilities $ 78,601 $ --- $ --- $ --- $ --- $ --- $ --- $ 78,601
Accumulated depletion
at period-end $ 2,645 $ --- $244,264 $ 44,097 $ 178,623 $ --- $ 8,667 $ 478,296
May 31, 1994:
Costs incurred:
Property acquisition $ --- $ 750 $ --- $ --- $ --- $ 94 $ --- $ 844
Exploration 24,865 4,775 205 --- --- 260 12,366 42,471
Development 29,833 --- 3,575 1,050 300 2,022 --- 36,780
Depletion per equivalent
barrel of production 1.96 --- 8.97 3.09 6.58 3.60 --- 5.47
Cost of properties at period-end:
Unevaluated $ 47,833 $ 15,183 $ 212 $ --- $ 10,094 $ --- $23,847 $ 97,169
Evaluated $118,215 $ --- $266,231 $ 47,677 $ 190,033 $ --- $ 7,715 $ 629,871
Support equipment and
facilities $ 45,688 $ --- $ --- $ --- $ --- $ --- $ --- $ 45,688
Accumulated depletion
at period-end $ 1,461 $ --- $243,084 $ 46,560 $ 176,450 $ --- $ 7,715 $ 475,270
May 31, 1993:
Costs incurred:
Property acquisition $ --- $ --- $ --- $ --- $ --- $ 205 $ 2,781 $ 2,986
Exploration 27,115 2,431 1,677 --- --- 1,487 3,647 36,357
Development 27,988 --- 2,512 1,417 348 5,703 --- 37,968
Depletion per equivalent
barrel of production 2.48 --- 15.19 7.93 6.81 3.24 --- 7.22
Cost of properties at period-end:
Unevaluated $ 33,460 $ 9,658 $ 164 $ --- $ 10,514 $ 1,321 $11,483 $ 66,600
Evaluated $ 77,890 $ --- $264,004 $ 46,246 $ 202,874 $119,393 $15,589 $ 725,996
Support equipment and
facilities $ 24,983 $ --- $ --- $ --- $ --- $ --- $ --- $ 24,983
Accumulated depletion
at period-end $ 544 $ --- $190,440 $ 43,983 $ 174,419 $ 76,940 $15,589 $ 501,915
A summary of costs excluded from depletion at December 31, 1995 by year
incurred follows:
MAY 31,
DECEMBER 31, MAY 31, MAY 31, 1992
TOTAL 1995 1994 1994 1993 AND PRIOR
Property acquisition $ 5,229 $ 250 $ --- $ 750 $ 996 $ 3,233
Exploration 142,183 87,759 20,290 13,824 3,993 16,317
Capitalized interest 25,649 12,632 5,994 2,986 1,482 2,555
Total worldwide $173,061 $ 100,641 $26,284 $17,560 $ 6,471 $ 22,105
The Company has significant property acquisition and exploration costs that
have not been evaluated and are not currently subject to depletion. At this
time the Company is unable to predict either the timing of the inclusion of
those 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:
UNITED
AUSTRALIA CANADA STATES OTHER TOTAL
Cost of property acquisition,
exploration and development:
December 31, 1995 $ 1,187 $ 507 $ --- $ 541 $ 2,235
December 31, 1994 $ 3,557 $ 313 $ 26 $1,028 $ 4,924
May 31, 1994 $ 2,955 $1,099 $1,687 $ --- $ 5,741
May 31, 1993 $ 1,631 $1,153 $ 807 $ --- $ 3,591
Net capitalized costs:
December 31, 1995 $ 25,818 $ --- $ --- $ 299 $26,117
December 31, 1994 $ 28,987 $3,889 $ --- $1,340 $34,216
May 31, 1994 $ 27,001 $4,395 $3,750 $ --- $35,146
May 31, 1993 $ 26,336 $4,374 $2,846 $ --- $33,556
OIL AND GAS RESERVE DATA (UNAUDITED)
The following tables present the Company's estimates of its proved oil and
gas reserves. These estimates were prepared by the Company's independent and
internal petroleum reservoir engineers. The Company emphasizes that reserve
estimates are approximates 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 nor can there be assurance that the proved
undeveloped reserves will be developed within the periods anticipated. Oil
reserves are stated in thousands of barrels and gas reserves are stated in
millions of cubic feet. The largest portion of the Company's reserves relate
to the SDLA, Tauramena and Rio Chitamena Association Contract Areas in
Colombia. The Company had a 20% interest in the reserves of SDLA and
Tauramena for 1992. The reserves for 1995, 1994 and 1993 reflect the
equalization of these interests to 24% and Ecopetrol's decision to exercise
its contractual right to acquire 50% of the working interest through the
declaration of commerciality. The Company consequently has a 9.6% working
interest in these areas after 20% governmental royalties.
COLOMBIA FRANCE INDONESIA UNITED STATES CANADA
OIL GAS OIL OIL OIL GAS OIL
Proved developed and
undeveloped reserves:
As of May 31, 1992 29,236 1,530 24,129 1,724 2,289 16,595 2,018
Revisions 5,398 14,720 (14,574) (237) 57 8,271 197
Purchases of minerals in place --- --- 101 --- --- --- ---
Extensions and discoveries 51,801 --- --- --- 3 104 750
Production (219) --- (1,467) (536) (397) (3,421) (279)
As of May 31, 1993 86,216 16,250 8,189 951 1,952 21,549 2,686
Revisions 3,682 --- (2,177) 165 23 (1,644) ---
Sales --- --- (502) --- (1,171) (11,426) (2,584)
Extensions and discoveries 3,173 --- --- --- --- --- ---
Production (467) --- (1,053) (441) (156) (1,150) (102)
As of May 31, 1994 92,604 16,250 4,457 675 648 7,329 ---
Revisions 10,113 (1,529) 2,301 (87) 14 486 ---
Purchases of minerals in place 2,111 --- --- --- --- --- ---
Production (435) --- (514) (186) (66) (618) ---
As of December 31, 1994 104,393 14,721 6,244 402 596 7,197 ---
Revisions --- --- --- 23 119 967 ---
Sales (10,434) --- (5,746) --- --- --- ---
Extensions and discoveries 32,556 1,127 --- --- --- --- ---
Production (5,089) (158) (498) (255) (121) (1,207) ---
As of December 31, 1995 121,426 15,690 --- 170 594 6,957 ---
CANADA ARGENTINA TOTAL WORLDWIDE
GAS OIL OIL GAS
Proved developed and
undeveloped reserves:
As of May 31, 1992 79,948 --- 59,396 98,073
Revisions 6,332 6 (9,153) 29,323
Purchases of minerals in place --- --- 101 ---
Extensions and discoveries 6,498 --- 52,554 6,602
Production (14,329) (6) (2,904) (17,750)
As of May 31, 1993 78,449 --- 99,994 116,248
Revisions --- 18 1,711 (1,644)
Sales (74,928) --- (4,257) (86,354)
Extensions and discoveries --- --- 3,173 ---
Production (3,521) (18) (2,237) (4,671)
As of May 31, 1994 --- --- 98,384 23,579
Revisions --- --- 12,341 (1,043)
Purchases of minerals in place --- --- 2,111 ---
Production --- --- (1,201) (618)
As of December 31, 1994 --- --- 111,635 21,918
Revisions --- --- 142 967
Sales --- --- (16,180) ---
Extensions and discoveries --- --- 32,556 1,127
Production --- --- (5,963) (1,365)
As of December 31, 1995 --- --- 122,190 22,647
COLOMBIA FRANCE INDONESIA UNITED STATES CANADA ARGENTINA
OIL GAS OIL OIL OIL GAS OIL GAS OIL
Proved developed reserves at:
May 31, 1993 --- --- 8,189 951 1,945 21,540 2,516 78,449 ---
May 31, 1994 1,237 --- 4,457 675 648 7,329 --- --- ---
December 31, 1994 47,789 14,721 6,244 402 596 7,197 --- --- ---
December 31, 1995 65,856 10,515 --- 170 594 6,957 --- --- ---
TOTAL WORLDWIDE
OIL GAS
Proved developed reserves at:
May 31, 1993 13,601 99,989
May 31, 1994 7,017 7,329
December 31, 1994 55,031 21,918
December 31, 1995 66,620 17,472
The Company's proportional equity interest in Crusader's estimated proved
developed and undeveloped oil and gas reserves is as follows:
AUSTRALIA CANADA UNITED STATES TOTAL
OIL GAS OIL GAS OIL GAS OIL GAS
May 31, 1993 2,803 39,646 1,108 2,615 83 167 3,994 42,428
May 31, 1994 2,574 40,174 963 2,790 48 122 3,585 43,086
December 31, 1994 3,163 59,115 823 1,836 --- --- 3,986 60,951
December 31, 1995 3,319 60,915 --- --- --- --- 3,319 60,915
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH INFLOWS AND CHANGES
THEREIN (UNAUDITED)
The following table presents a standardized measure of discounted future net
cash inflows relating to proved oil and gas reserves. Future cash inflows
were computed by applying year end prices of oil and gas relating to the
Company's proved reserves to the estimated year end quantities of those
reserves. Future price changes were considered only to the extent provided by
contractual agreements in existence at year end. Future production and
development costs were computed by estimating those expenditures expected to
occur in developing and producing the proved oil and gas reserves at the end
of the year, based on year end costs. Actual future cash inflows may vary
considerably and the standardized measure does not necessarily represent the
fair value of the Company's oil and gas reserves.
UNITED TOTAL
COLOMBIA FRANCE INDONESIA STATES CANADA 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
December 31, 1994:
Future cash inflows $ 1,764,939 $105,523 $ 6,677 $20,072 $ --- $1,897,211
Future production and
development costs 440,227 59,558 5,645 1,845 --- 507,275
Future net cash inflows before
income taxes $ 1,324,712 $ 45,965 $ 1,032 $18,227 $ --- $1,389,936
Future net cash inflows before
income taxes discounted at 10%
per annum $ 594,061 $ 25,759 $ 974 $11,824 $ --- $ 632,618
Future income taxes discounted at
10% per annum 132,948 --- --- --- --- 132,948
Standardized measure of discounted
future net cash inflows $ 461,113 $ 25,759 $ 974 $11,824 $ --- $ 499,670
UNITED TOTAL
COLOMBIA FRANCE INDONESIA STATES CANADA WORLDWIDE
May 31, 1994:
Future cash inflows $1,591,448 $ 76,755 $ 10,278 $23,562 $ --- $1,702,043
Future production and
development costs 474,382 44,603 7,575 1,945 --- 528,505
Future net cash inflows before
income taxes $1,117,066 $ 32,152 $ 2,703 $21,617 $ --- $1,173,538
Future net cash inflows before
income taxes discounted at 10%
per annum $ 506,022 $ 23,147 $ 2,570 $14,008 $ --- $ 545,747
Future income taxes discounted at
10% per annum 150,537 --- --- --- --- 150,537
Standardized measure of discounted
future net cash inflows $ 355,485 $ 23,147 $ 2,570 $14,008 $ --- $ 395,210
May 31, 1993:
Future cash inflows $1,608,471 $163,367 $ 18,095 $70,347 $162,208 $2,022,488
Future production and
development costs 498,032 79,593 13,926 10,575 85,035 687,161
Future net cash inflows before
income taxes $1,110,439 $ 83,774 $ 4,169 $59,772 $ 77,173 $1,335,327
Future net cash inflows before
income taxes discounted at 10%
per annum $ 455,077 $ 54,594 $ 3,630 $38,693 $ 56,322 $ 608,316
Future income taxes discounted at
10% per annum 149,033 --- --- --- 7,801 156,834
Standardized measure of discounted
future net cash inflows $ 306,044 $ 54,594 $ 3,630 $38,693 $ 48,521 $ 451,482
The Company's proportional equity interest in Crusader's standardized measure
of discounted future net cash inflows follows:
UNITED
AUSTRALIA CANADA STATES TOTAL
December 31, 1995 $ 30,382 $ --- $ --- $30,382
December 31, 1994 $ 32,492 $3,424 $ --- $35,916
May 31, 1994 $ 35,306 $3,997 $ 526 $39,829
May 31, 1993 $ 35,939 $6,016 $1,175 $43,130
Changes in the standardized measure of discounted future net cash inflows
follow:
DECEMBER 31, MAY 31,
1995 1994 1994 1993
Total worldwide, excluding equity share:
Beginning of period $ 499,670 $395,210 $451,482 $ 262,379
Extensions, discoveries and improved recovery 339,413 --- 16,521 276,834
Sales, net of production costs (67,471) (8,249) (14,613) (44,169)
Net change in prices and production costs 42,044 (14,746) (54,143) (4,958)
Purchases of reserves --- 9,573 --- 674
Sales of reserves (144,361) --- (83,462) ---
Revisions of quantity estimates 2,348 43,816 879 (58,019)
Accretion of discount 62,188 31,835 60,831 31,809
Development and facilities costs incurred 28,068 45,152 57,485 62,951
Change in future development costs (102,323) 3,695 (57,459) 19,228
Changes in production rates and other 22,917 (24,205) 11,392 5,882
Net change in income taxes (40,797) 17,589 6,297 (101,129)
End of period $ 641,696 $499,670 $395,210 $ 451,482
At May 31, 1993, $33.4 million of the consolidated standardized measure of
discounted future net cash inflows was attributable to minority interests in
consolidated subsidiaries. The Company's weighted average oil price per
barrel during the year ended December 31, 1995, and at December 31, 1995, was
$16.19 and $18.60, respectively.
SCHEDULE II
TRITON ENERGY CORPORATION 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 May 31, 1993:
Allowance for doubtful
receivables $ 4,778 $ 964 $ --- $ (4,580) $ 1,162
Allowance for deferred
tax asset $ --- $ 21,080 $ 41,709 $ --- $ 62,789
Year ended May 31, 1994:
Allowance for doubtful
receivables, excluding
discontinued operations $ 1,162 $ (149) $ 4 $ (144) $ 873
Allowance for deferred
tax asset $ 62,789 $ 1,027 $ --- $ --- $ 63,816
Period ended Dec 31, 1994: -
Allowance for doubtful
receivables $ 873 $ 19 $ 20 $ (15) $ 897
Allowance for deferred
tax asset $ 63,816 $ 23,702 $ --- $ --- $ 87,518
Year ended Dec 31, 1995:
Allowance for doubtful
receivables $ 897 $ --- $ 41 $ (128) $ 810
Allowance for deferred
tax asset $ 87,518 $ (33,472) $ --- $ --- $ 54,046
___________________
Note - Deductions for the allowance for doubtful receivables in the year
ended May 31, 1993 related primarily to discontinued operations.