UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED: December 31, 2000

() TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___________ TO ______________

Commission File Number: 1-11675

TRITON ENERGY LIMITED
(Exact name of registrant as specified in its charter)

CAYMAN ISLANDS NONE
(State of other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

CALEDONIAN HOUSE
JENNETT STREET, P.O. BOX 1043
GEORGE TOWN
GRAND CAYMAN, CAYMAN ISLANDS NONE
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: 345-949-0050

Securities registered pursuant to Section 12(b) of the Act:

NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -------------------
Ordinary Shares, $.01 par value New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None.

INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES [ X ] NO [ ]
--------

INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM
405 OF REGULATION S-K (SECTION 229.405 OF THIS CHAPTER) IS NOT CONTAINED HEREIN,
AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE
PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS
FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. [ ]

THE AGGREGATE MARKET VALUE OF THE OUTSTANDING ORDINARY SHARES HELD BY
NON-AFFILIATES OF THE REGISTRANT AT MARCH 7, 2001 (FOR SUCH PURPOSES ONLY, ALL
DIRECTORS AND EXECUTIVE OFFICERS ARE PRESUMED TO BE AFFILIATES) WAS
APPROXIMATELY $877.7 MILLION, BASED ON THE CLOSING SALES PRICE OF $24.69 ON THE
NEW YORK STOCK EXCHANGE.

AS OF MARCH 7, 2001, 37,451,051 ORDINARY SHARES OF THE
REGISTRANT WERE OUTSTANDING.

DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE PROXY STATEMENT PERTAINING TO THE 2001 ANNUAL MEETING OF
SHAREHOLDERS OF TRITON ENERGY LIMITED ARE INCORPORATED BY REFERENCE INTO PART
III HEREOF.

TRITON ENERGY LIMITED

TABLE OF CONTENTS

Form 10-K Item Page
- -------------- ----

PART I
ITEMS 1. and 2. Business and Properties . . . . . . . . . . . . . . . . . . . . . 2
ITEM 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . 23
ITEM 4. Submission of Matters to a Vote of Security Holders . . . . . . . 25

PART II
ITEM 5. Market for Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . 26
ITEM 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . 31
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations. . . . . . . . . . . . . . . . . . . . . . 32
ITEM 7.A. Quantitative and Qualitative Disclosures about Market Risk. . . . 53
ITEM 8. Financial Statements and Supplementary Data . . . . . . . . . . . 54
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure. . . . . . . . . . . . . . . . . . . . . . 54

PART III
ITEM 10. Directors and Executive Officers of the Registrant. . . . . . . . 55
ITEM 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . . 55
ITEM 12. Security Ownership of Certain Beneficial Owners and Management. . 55
ITEM 13. Certain Relationships and Related Transactions. . . . . . . . . . 55

PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . 56

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

GENERAL

Triton Energy Limited is an international oil and gas exploration and
production company. Our principal properties, operations, and oil and gas
reserves are located in Colombia, Equatorial Guinea and Malaysia-Thailand. We
explore for oil and gas in these areas, as well as in southern Europe, Africa
and the Middle East. Unless this report indicates otherwise or the context
otherwise requires, the terms "we," "our," "us," "Triton" and the "Company" as
used in this report refer to Triton Energy Limited and its subsidiaries and
other affiliates through which Triton conducts its business.

We conduct substantially all of our exploration and production operations
outside the United States. All of our oil and gas sales currently are from
production in Colombia and, commencing with the first quarter of 2001, offshore
Equatorial Guinea. For a discussion of certain political, economic and other
uncertainties associated with operations in foreign countries, particularly in
the oil and gas business, see the "Certain Factors That Could Affect Future
Operations" section in "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations."

Triton Energy Limited was incorporated in the Cayman Islands in 1995 to
become the parent holding company of Triton Energy Corporation, a corporation
formed in Texas in 1962 and reincorporated in Delaware in 1995. Our principal
executive offices are located at Caledonian House, Jennett Street, George Town,
Grand Cayman, Cayman Islands, and our telephone number there is (345) 949-0050.
You can also obtain information regarding Triton by contacting our Investor
Relations department at Triton Energy, 6688 North Central Expressway, Suite
1400, Dallas, Texas 75206, telephone number (214) 691-5200, or at our web site,
www.tritonenergy.com. The information on our web site is not incorporated by
reference into this report and should not be considered to be a part of this
document. Our web site address is included in this report as an inactive textual
reference only.

OIL AND GAS PROPERTIES

Through various subsidiaries and affiliates, we have participating
interests in exploration licenses in Latin America, Southeast Asia, Africa,
Europe and the Middle East. The following is intended to describe our interests
in these licenses and recent operations over these licenses. We have defined
certain technical terms used in this report in the glossary that is included at
the end of this section.

The following description of our properties and activities contains a
number of forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and
the Private Securities Litigation Reform Act of 1995. This information is
subject to the "Safe Harbor" provisions of those statutes. Forward-looking
statements include statements concerning our plans, objectives, expectations,
goals, budgets, strategies and future operations and performance and the
assumptions underlying these forward-looking statements. We use the words
"anticipates," "estimates," "expects," "believes," "intends," "plans,"
"budgets," "may," "will," "should" and similar expressions to identify
forward-looking statements. Please see the "Disclosure Regarding Forward-Looking
Information" and "Certain Factors That Could Affect Future Operations" sections
in "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations" for a description of a number of risks and uncertainties
that could cause actual results and developments to differ materially from those
expressed in or implied by our forward-looking statements.

COLOMBIA

We hold a 12% interest in the Santiago de Las Atalayas ("SDLA") contract
area, covering approximately 66,000 acres, the Tauramena contract area, covering
approximately 36,300 acres, and the Rio Chitamena contract area, covering
approximately 6,700 acres, which include the Cusiana and Cupiagua fields. These
areas are located approximately 160 kilometers (100 miles) northeast of Bogota
in the Andean foothills of the Llanos Basin area in eastern Colombia. Our
partners in these areas are Empresa Colombiana De Petroleos ("Ecopetrol"), the
Colombian national oil company, with a 50% interest, and subsidiaries of BP
Amoco p.l.c. ("BP") and TotalFinaElf SA ("TOTAL"), each with a 19% interest. BP
is the operator. Our net revenue interest is approximately 9.6% after
governmental royalties. We have an agreement with one of our original
co-investors that entitles that party to 3.75% of our net revenue if it pays its
proportionate share of related costs.

The SDLA, Tauramena and Rio Chitamena contracts give BP, TOTAL and us, as
the private contractors, the right to produce oil and gas from the areas subject
to the contracts during their terms. The SDLA contract expires in 2010, the
Tauramena contract in 2016, and the Rio Chitamena contract in 2015 or 2019,
depending on contract interpretation. In July 1994, Triton, BP, TOTAL and
Ecopetrol agreed to a procedure for developing the Cusiana field over the three
contract areas in a unified manner. Until the expiration of the SDLA contract in
2010, oil and gas produced from the three contract areas will be owned by the
parties according to their percentage interests in each contract area.

In the first quarter of 2005, the parties will have an independent party
determine the original BOEs of petroleum in place under the unified area and
under each contract area. Then a "tract factor" will be calculated for each
contract area. Each tract factor will be the amount of original BOEs of
petroleum in place under the particular contract area as a percentage of the
total original BOEs under the three contract areas. After the expiration of the
SDLA contract in 2010, each party's interest in the remaining contract areas,
until their expiration, will be the aggregate of that party's interest in each
remaining contract area multiplied by the tract factor for each such contract
area.

Recent Operating Activity

In the Cusiana field, through the end of 2000, the working interest
partners had completed a total of 49 producing wells, 13 gas injection wells and
three water injection wells. The gas injection wells recycle to the Mirador
formation most of the gas that is associated with the oil production to increase
the oil recoverable during the life of the field. The water injection wells
inject the field's produced water into the Barco and Guadalupe formations for
disposal and pressure maintenance. There are currently two drilling rigs
operating in the Cusiana field, and we expect that three wells will be completed
during 2001.

In the Cupiagua field, through the end of 2000, the working interest
partners had completed a total of 30 producing wells and nine gas injection
wells. There are currently two drilling rigs operating in the Cupiagua field,
and we expect that three wells will be completed during 2001.

Recetor Contract Area

In 1999, we acquired a 20% interest in the Recetor contract area, covering
approximately 70,215 acres, subject to certain government royalties. The area is
located adjacent to and north of the SDLA contract area and includes an
extension of the Cupiagua field. Our partners in these areas are BP, with a
63.3% interest, and Inaquimicas, with a 16.7% interest. BP is the operator. In
June 2000, Ecopetrol granted commerciality over a limited area and exercised its
right to acquire up to a 50% interest in the commercial area, reducing our
interest to 10% and the interests of our partners proportionately. Our interest
is subject to a further royalty of 20%, which reduces our net revenue interest
to 8%. The contract provides BP, Inaquimicas and us, as the private contractors,
the right to produce oil and gas from the Recetor contract area through the year
2017.

In January 2000, the working interest partners completed the Liria YD-2
well on an extension of the Cupiagua field in the Recetor contract area. The
well reached a total depth of 16,991 feet and is producing into the Cupiagua
central processing facility. Currently, one drilling rig is operating in the
Recetor contract area. We expect that at least two additional wells will be
drilled in the Cupiagua field in the Recetor contract area in 2001.

Production

Gross production from the Cusiana and Cupiagua fields has reached over 600
million barrels of oil since production commenced, and averaged approximately
339,000 BOPD during 2000. Although the fields are maturing and are in decline,
the rate of decline in 2000 was greater than the operator, we and our engineers
had expected. This greater rate of decline was primarily due to factors such as
mechanical difficulties in some producing wells, scale buildup in some producing
wells, which inhibits oil production and requires chemical treatment, a decrease
in workovers, delayed drilling of new wells and the disappointing performance of
some of the new wells that were drilled. The operator has devised a plan to
enhance reservoir management by implementing a more aggressive well-maintenance
and workover program. This includes underbalanced drilling in existing and new
wells, modifications to surface facilities, and a chemical treatment to
alleviate the scale problem and improve well production. Based on this plan, we
are estimating that average gross production from the fields will be
approximately 270,000 BOPD to 280,000 BOPD (26,000 to 27,000 net to us) in 2001.
We cannot assure you that these attempts to offset the decline in production
will be successful or that the Colombian fields will not continue to experience
significantly less production than the operator, we and our engineers project.

Production Facilities and Pipelines

We have completed the production facilities in the Cusiana and Cupiagua
fields. The components of the Cusiana central processing facility consist of a
long-term test facility, four early production units, and two 80,000 BOPD
production trains. The production capacity of the Cusiana central processing
facility is approximately 320,000 BOPD. Currently, the production of the Cusiana
field is limited by the gas handling capacity of the Cusiana central processing
facility of about 1,400 million cubic feet of gas per day.

The components of the Cupiagua central processing facility consist of two
100,000 BOPD production trains. The gas handling capacity of the Cupiagua
central processing facility is approximately 1,300 million cubic feet of gas per
day.

We transport the crude oil and condensate produced from the Cusiana and
Cupiagua fields to the Caribbean port of Covenas through the 832-kilometer
(520-mile) pipeline system operated by Oleoducto Central S. A. ("OCENSA").
OCENSA also transports crude oil from other parties in Colombia. OCENSA is a
Colombian company formed in 1994 by Ecopetrol, BP, TOTAL, Triton, IPL
Enterprises (Colombia) Inc. and TCPL International Investments Inc. We own a
9.6% equity interest in OCENSA.

El Pinal Contract Area

During 2000, we completed the sale of our 100% interest in the El Pinal
contract area.

EQUATORIAL GUINEA

We have interests in production sharing contracts covering three blocks
with the Republic of Equatorial Guinea. Our interest in Blocks F and G became
effective in April 1997, and in January 2001, we agreed to acquire an interest
in Block L.

Blocks F and G

We are the operator of Blocks F and G, with an 85% contract interest, and
our partner in these blocks is Energy Africa with a 15% contract interest. The
government has a carried 5% participating interest in any commercial field
discovered on the blocks, which is applied to us and our partner
proportionately. The contracts currently cover a contiguous area of
approximately one million acres located offshore and southwest of the city of
Bata in water depths of up to 5,200 feet.

Recent Operating Activity - the Ceiba Field
-------------------------------------------------

In October 1999, we announced the discovery of the Ceiba oil field, located
on Block G in approximately 2,200 to 2,600 feet of water, approximately 22 miles
off the continental coast.

During 2000, we successfully implemented an accelerated appraisal and
development program for the Ceiba field, drilling the Ceiba-3, -4 and -5 subsea
production wells. We commenced production in November 2000, achieved production
from three wells by the end of 2000, and in February 2001, we commenced
production from a fourth well. The wells are connected through flowlines to a
floating production, storage and offloading vessel ("FPSO"). Based on our
development plan and production history to date, we expect gross production from
the Ceiba field to average approximately 37,000 BOPD to 43,000 BOPD (26,000 to
30,000 net to us) during 2001. We cannot assure you that actual production rates
will meet our expectations. Actual production rates will depend on well and
reservoir performance, our ability to improve pressure support through water
injection, and other factors.

Development Plans. The current plan for development calls for a total of 10
production wells and four water injection wells, including the production wells
that already have been drilled. Our plan is to have the water injection wells
and at least seven production wells drilled and completed in 2001, and the
remaining production wells drilled and completed in 2002.

Currently, the FPSO vessel provides storage for up to two million barrels
of oil and initial processing capacity of up to 60,000 barrels of fluids per
day. In connection with the next phase of development, we are planning to
increase processing capacity to approximately 160,000 barrels of fluids per day
and to install onboard water-injection facilities to inject up to 135,000
barrels per day of water. We expect that the additional wells and production and
water-injection facilities will enable us to increase production in 2002. We are
uncertain as to what the production rate will be in this latter phase of
development. The actual production rate will depend on a number of factors,
including the timing of the completion of the additional production and
water-injection facilities, well performance, the timing of the connection of
the production and water injection wells to the FPSO, reservoir performance, our
ability to improve pressure support through water injection and other factors.
In order to install the necessary equipment to increase the processing capacity
of the facilities, we expect that we will be required to temporarily halt
production from the Ceiba field. Currently, we expect that this production halt
will begin in December 2001 and will last approximately four weeks.

Development and Appraisal Wells. Following the drilling of the Ceiba-1
discovery well and the Ceiba-2 appraisal well in late 1999, we drilled the
Ceiba-3, -4, -5, -6 and -7 wells to develop and appraise the Ceiba field.

The Ceiba-3 development well confirmed the primary reservoir found in the
Ceiba-1 and Ceiba-2 wells and encountered a deeper, similar-quality oil
reservoir. The Ceiba-3 well was drilled to a total depth of 9,695 feet in 2,165
feet of water, and penetrated 256 feet of net oil-bearing pay based on the
analysis of drilling, coring, wireline logging and samples. The well is
approximately one mile northeast and 282 feet downdip of the Ceiba-1 discovery
well and confirmed the extension of the Ceiba field to the north.

The Ceiba-4 development well confirmed the oil pool found in the Ceiba-1,
- -2 and -3 wells. The Ceiba-4 well was drilled to a total depth of 8,957 feet in
2,431 feet of water, and penetrated 269 feet of net oil-bearing pay in three
zone based on the analysis of drilling, coring, wireline logging and samples.
The well is approximately one mile southwest and 207 feet downdip of the Ceiba-2
appraisal well.

The Ceiba-5 appraisal well confirmed the primary oil pool found in the
Ceiba-1, -2, -3 and -4 wells, and encountered a deeper pool with an additional
high-quality reservoir not seen in any of the previous Ceiba wells. The Ceiba-5
well was drilled to a total depth of 9,187 feet in 2,622 feet of water, and
penetrated 243 feet of net oil-bearing pay in three zones based on the analysis
of drilling, wireline logging, downhole pressure measurements and rock/fluid
samples. The new oil pool has an oil-water contact 328 feet below the oil-water
contact of the primary Ceiba pool. The well is approximately 1.75 miles
northwest of the Ceiba-3 development well.

The Ceiba-6 appraisal well was a step-out well located outside and
southeast of the Ceiba field approximately 2.5 miles south of the Ceiba-4 well,
and was drilled to a total depth of 10,388 feet. The well was plugged and
abandoned, having not encountered oil and gas.

The Ceiba-7 development well was completed in February 2001. The well was
side-tracked, and drilled to a total depth of 8,960 feet in 2,352 feet of water.
The well penetrated 102 feet of net oil-bearing pay in two zones based on the
analysis of drilling, wireline logging, downhole pressure measurements and
rock/fluid samples. The well is approximately one-half mile north-northwest of
the Ceiba-2 development well.

Seismic Acquisition. We have acquired a 1,025,000-acre
(4,200-square-kilometer) 3D seismic survey to assist in delineating the extent
of the Ceiba field, identify drilling locations for the appraisal/production
wells, and better define other exploration prospects on the blocks. We have
completed the primary analysis of the data in the Ceiba field, and further
detailed analysis is in process.

Exploration Activity
---------------------

In addition to the development and appraisal wells drilled in the Ceiba
field, we have drilled three exploration wells in Block G and one exploration
well in Block F. While our analysis of the data we have obtained from drilling
and the seismic activity continues, we have identified three main areas for
exploration activity in the blocks - the platform edge closest to the coast of
the country, the slope, or "toe-thrust" zone, that extends west from the
platform edge in Block G and the southern part of Block F, and the basin, which
is in deep water. Our current plans for this year are to drill at least one and
possibly two exploration wells in the toe-thrust zones and possibly one
exploration well in the basin. Our plans for these wells are subject to change
as circumstances warrant. The timing of the exploration wells is uncertain, as
we will need to balance the drilling of exploration wells with our needs for
drilling development wells in the Ceiba field. Also, any exploration well in the
basin area may require a rig suitable for deepwater drilling.

In February 2001, we reported that the F-1 exploration well would be
plugged and abandoned. The well, the first exploration well we have drilled in
Block F, was drilled in about 700 feet of water and reached a total depth of
10,180 feet.

In January 2001, we reported that the G-4 exploration well would be
temporarily abandoned after discovering oil on Block G. During a drill stem
test, 31 degree API oil was flowed to surface, but a sustained flow rate was not
achieved. We will need to perform additional technical work, and, if warranted,
further appraisal drilling, to determine if the field can produce oil at
commercial flow rates. The well was drilled in approximately 800 feet of water
and reached a total depth of 6,610 feet.

In the fourth quarter of 2000, we reported that the G-2 and G-3 exploration
wells would be plugged and abandoned. The G-2 well was drilled in about 2,970
feet of water, and reached a total depth of 15,214 feet. Log analysis indicated
the well encountered three oil-bearing zones, but the reservoir permeability was
inadequate for oil production. The G-3 well was drilled in about 1,900 feet of
water and reached a total depth of 9,065 feet. The well encountered
Ceiba-quality reservoir sands that were water bearing.

Contract Terms
---------------

The production sharing contracts covering Blocks F and G grant to us and
our partner the right to explore for and produce and sell oil and gas from the
blocks. The blocks cover a total of approximately one million acres located
offshore and southwest of the city of Bata. This acreage position takes into
account our relinquishment of approximately 18% of the original areas in 2000.
Under the terms of the contracts, we were required to relinquish 30% of the
original acreage in 2000, and to relinquish an additional 20% of the remaining
contract area by April 2003 if we wanted to extend the exploration period. In
2000, we agreed with the government to relinquish 18% of the acreage in 2000,
with the remainder of the relinquishment requirement to be fulfilled by the end
of the exploration period. In any event, under the contracts, we are not
required to surrender an area that includes a commercial field or a discovery
that has not then been declared commercial. When we are required to relinquish
acreage, we can designate the area or areas to be surrendered, provided that,
where possible, each area must be of sufficient size and convenient shape to
permit petroleum operations.

The initial exploration period in the contracts expires in April 2003. We
can extend the exploration period of each contract for up to three additional
years if we agree to certain operational commitments for those periods, subject
to the relinquishment requirements described in the preceding paragraph.

The contracts provide that if there is a commercial discovery of an oil or
gas field on a block, the contract will remain in existence as to that field for
a period of 30 years, in the case of oil, or 40 years, in the case of gas, from
the date the Ministry of Mines and Energy approves the discovery as commercial.
Any further discoveries of hydrocarbons in formations that underlie or overlie
that field, or other deposits found within the extension of that field, will be
included with that field and will be subject to the original 30- or 40- year
term, as applicable. The Ministry approved the Ceiba field as commercial in
December 1999.

Under the current terms of the production sharing contracts, the
Republic of Equatorial Guinea is entitled to a royalty as to each field. In
the case of an oil field, the royalty is based on average daily production and
is determined as follows:

Rates of Daily Production of an Oil Field Royalty Per Tranche
----------------------------------------- -------------------
(calculated on an incremental basis of crude oil)

From 0 to 30,000 Barrels 11%
Above 30,000 to 60,000 Barrels 12%
Above 60,000 to 80,000 Barrels 14%
Above 80,000 to 100,000 Barrels 15%
More than 100,000 Barrels 16%

In the case of a gas field, the royalty is 10% of the natural gas produced from
the field.

After making the royalty payments, we and Energy Africa will be allocated
up to 70% of the remaining production to recover specified capital and operating
costs. The government of Equatorial Guinea's 5% carried participating interest
does not entitle the government to receive any of the proceeds for cost
recovery.

After the allocation of production toward the payment of the royalty and
cost recovery, the production sharing contracts entitle the Republic of
Equatorial Guinea to receive a share of production based on cumulative
production, determined as follows:

Government Share of Contractors' Share of
Cumulative Production Remaining Production Remaining Production
- ------------------------ --------------------- ----------------------
(in millions of barrels)

From 0 to 200 20% 80%
Above 200 to 350 30% 70%
Above 350 to 450 40% 60%
Above 450 to 550 50% 50%
More than 550 60% 40%

The government of Equatorial Guinea's 5% carried participating interest entitles
it to receive 5% of the production allocated to the contractors in the preceding
table. As a result, we would receive 80.75% of the contractors' share of
remaining production and Energy Africa would receive 14.25%.

In addition, as any new field is discovered, the contractors must make a
non-recoverable production payment to the government in the amount of $750,000
when the Ministry of Mines and Energy approves the discovery as commercial. The
contractors must pay the government certain production bonuses if and when
production from a field, including the Ceiba field, averages certain levels for
a 60-day period for the first time, determined as follows:

Average Production Total
Per Day Production Bonus
------ -----------------
(in barrels)

30,000 $3 million
60,000 $3 million
100,000 $4 million

These production bonuses would be added to the capital costs the contractors are
entitled to recover.

Block L

In January 2001, we agreed to acquire a 25% interest in a production
sharing contract covering Block L in the Republic of Equatorial Guinea. The
contract covers approximately one million acres located offshore Equatorial
Guinea, contiguous to Block F to the north and extending west and south
contiguous Blocks F and G. Block L is in water depths from approximately 1,300
feet to 6,800 feet. Our partners in this area are subsidiaries of Chevron
Corporation, with a 65% interest, and Sasol Limited, a South African company,
with a 10% interest. Chevron is the operator. If there is a discovery in the
block, the government will receive a 7.5% carried interest at such time as it
approves the first development and production plan for the discovery, and the
private partners' interests will be reduced proportionately.

Under the contract, we have the right to explore for oil and gas in the
block for a period that ends in October 2005. If we fulfill our contract
obligations during this initial five-year period, we can extend the exploration
phase of the contract for up to two additional one-year periods. However, if we
desire to extend the contract, we would be required to relinquish 40% of the
acreage at the expiration of the initial exploration period and 25% of the
acreage remaining at the end of each extension year. By October 2003, we will be
required to have acquired and processed at least 2,000 kilometers of 2D seismic
data and at least 800 square kilometers of 3D seismic data, and to have drilled
at least one exploration well. In addition, by October 2005, and subject to our
agreement to do so, we will be required to have drilled a second exploration
well. If we wish to exercise our option to extend the exploration period by one
year, we will be obligated to drill at least one well, which could be an
exploration well or an appraisal well. This would apply to the second one-year
extension as well.

Currently, we are conducting a 3D seismic survey covering 1,500 square
kilometers, and we plan to drill an exploration well by the end of 2002.

MALAYSIA-THAILAND

In Block A-18 of the Malaysia-Thailand Joint Development Area in the Gulf
of Thailand, we and our partners have discovered eight natural gas fields -
known as the Bulan, Bumi, Bumi East, Cakerawala, Samudra, Senja, Suriya, and
Wira fields. We own our interest through a one-half interest in a company that
holds a 50% contract interest in a production sharing contract covering Block
A-18. A subsidiary of BP, which acquired the Atlantic Richfield Company in 2000,
owns the other half of the shares of the company. The operator is
Carigali-Triton Operating Company Sdn. Bhd., a company owned by BP and us,
through our jointly owned company, and Petronas Carigali (JDA) Sdn. Bhd., a
subsidiary of the Malaysian national oil company.

Block A-18 encompasses approximately 731,000 acres. The area had been the
subject of overlapping claims between Malaysia and Thailand. The two countries
established the Malaysia-Thailand Joint Authority to administer the development
of the Joint Development Area. In April 1994, we entered into a production
sharing contract with the Malaysia-Thailand Joint Authority and Petronas
Carigali. We previously held a license from Thailand that covered part of the
Joint Development Area.

Contract Terms

The term of the production sharing contract is 35 years, subject to
possible relinquishment of certain areas and subject to the treaty between
Malaysia and Thailand creating the Malaysia-Thailand Joint Authority remaining
in effect. The contract gives us the right to explore for oil and gas for the
first eight years of the contract, which will expire in April 2002. If we
discover a natural gas field (not associated with crude oil), we must submit to
the Malaysia-Thailand Joint Authority a development plan for the field. If the
Malaysia-Thailand Joint Authority accepts the development plan, we can then hold
that gas field without production for an additional five-year period, but not
beyond the tenth anniversary of the contract. We then have a five-year period
from the Malaysia-Thailand Joint Authority's acceptance of the development plan
to develop the field, and have the right to produce the field for approximately
20 years (or until the termination of the contract, if earlier). We are required
to drill two exploration wells before April 2002.

If we discover an oil field, we would have the right to produce oil from
the field for 25 years (or until the termination of the contract, if earlier).
We would have to relinquish any areas not developed and producing within the
periods provided.

As oil and gas are produced, the Malaysia-Thailand Joint Authority is
entitled to a 10% royalty. A portion of each unit of production is considered
"cost oil" or "cost gas" and will be allocated to the contractors to the extent
of their recoverable costs, with the balance considered "profit oil" or "profit
gas" to be divided 50% to the Malaysia-Thailand Joint Authority and 50% to the
contractors (i.e., 25% to Petronas Carigali and 25% to the company we own
jointly with BP). The portion that will be considered "cost gas" for production
in the first phase of development is a maximum of 60%. The portion that will be
considered "cost gas" following the first phase of development is a maximum of
50%. There is an additional royalty attributable to Triton's and BP's joint
interest equal to 0.75% of Block A-18 production. Tax rates imposed by the
Malaysia-Thailand Joint Authority on behalf of the governments of Malaysia and
Thailand are 0% for the first eight years of production, 10% for the next seven
years of production and 20% for any remaining production.

Our agreements with BP require BP to pay the future exploration and
development costs attributable to our collective interest in Block A-18, up to
$377 million or until first production from a gas field. Once gas production
starts, or once BP has paid $377 million, whichever occurs first, we and BP
would each pay 50% of our share of exploration and development costs. Under our
agreements with BP, once production commences and "cost oil" or "cost gas" is
allocated to the contractors for their recoverable costs under the production
sharing contract, we will recover our investment in recoverable costs in the
project first, and then BP will recover its investment in recoverable costs. We
have estimated our recoverable costs to be approximately $100 million. See "Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations" and note 2 of Notes to Consolidated Financial Statements.

Gas Sales Agreement

In October 1999, we and the other parties to the production sharing
contract for Block A-18 executed a gas sales agreement providing for the sale of
the first phase of gas to Malaysia. The sales agreement provides for gas
deliveries over a term concurrent with the production sharing contract and
contemplates initial deliveries of 195 MMcf per day for up to the first six
months of the agreement, and 390 MMcf per day for a period of twenty years. We
believe that this first phase of the agreement will cover approximately 2.5 Tcf
to 3 Tcf of gas in total. The sales agreement includes a take-or-pay provision
that specifies that the buyers must take a minimum of 90% of the annual daily
contract quantity and the sellers must be able to deliver a maximum of 110% of
the daily contract quantity. Delivery is made at the offshore production
platform.

The agreement provides that the initial delivery date will be a date to be
agreed upon by the sellers and the buyers between April 1, 2002 and June 30,
2002. If the parties do not agree on a date for initial delivery, the agreement
provides that the date will be deemed to be June 30, 2002.

By the first delivery date, we and the other sellers will be required to
have completed the facilities necessary to meet our delivery obligations. The
Malaysia-Thailand Joint Authority had previously approved the field development
plan for the Cakerawala field in December 1997. Carigali-Triton Operating
Company, the operator, has begun field development work and has awarded several
contracts for long lead-time equipment, including carbon dioxide removal,
structural steel, refrigeration, power generation and gas compression. In March
2000, Carigali-Triton Operating Company awarded the contract for engineering,
procurement and construction of three wellhead platforms, a production platform
with living quarters platform, a riser platform and a floating storage and
off-loading vessel for oil and condensate. The initial development plan calls
for 35 development wells. As of February 2001, we believe that the work under
the sellers' engineering, procurement and construction contract was
approximately 50% complete.

The buyers currently do not have in place facilities necessary to transport
and process the gas. While it is not a requirement of the sales agreement, the
buyers anticipate constructing pipeline and processing facilities onshore
Thailand to accept deliveries of the gas. The sales agreement does recognize
that the buyers' downstream facilities will require that certain environmental
approvals be obtained before the buyers' facilities can be constructed. The
agreement provides that, if a delay in obtaining the necessary environmental
approvals results in a delay of the completion of the buyers' downstream
facilities, and the buyers have satisfied other specified conditions precedent,
then this will be treated as a force majeure event and will excuse the buyers
from their take-or-pay obligations for the length of the delay. We cannot give
you any assurance as to when the environmental approvals will be obtained, and a
lengthy approval process or significant opposition to the project could delay
construction and the commencement of gas sales, as could a number of events
unrelated to the environmental approval that are beyond our control. Based on
the delays to date in obtaining the environmental approval, for internal
planning purposes we are assuming that production will begin no earlier than the
fourth quarter of 2002.

The price for gas will be adjusted annually for changes in the U.S.
Consumer Price Index, the Producer Price Index for Oil Field and Gas Field
Machinery and Tools, and medium fuel oil (180 centistokes) in Singapore. The
price is calculated annually based on changes in the factors from the prior year
and will apply to sales over the succeeding twelve months. All calculations and
payments are in U.S. dollars. The base price is $2.30 per MMbtu. Based on the
formula, the price would have been $2.59 per MMbtu for the contract year from
October 1, 2000 to September 30, 2001. To give the buyers incentive to
accelerate the timing of the delivery of the gas, the sales agreement gives the
buyers a discount of 5% after 500 Bcf has been delivered and a discount of 10%
after an aggregate of 1.3 Tcf has been delivered.

When we sold one half of our interest in Block A-18 to BP in 1998, BP
agreed to pay the future exploration and development costs attributable to our
collective interest in Block A-18, up to $377 million or until first production
from a gas field. BP also agreed to pay us specified incentive payments if the
requisite criteria were met. The first $65 million in incentive payments is
conditioned upon having the production facilities for the sale of gas from Block
A-18 completed by June 30, 2002. If the facilities are completed after June 30,
2002 but before June 30, 2003, the incentive payment would be reduced to $40
million. A lengthy environmental approval process, or delays in construction of
the facilities, could result in our receiving a reduced incentive payment or
possibly the complete loss of the first incentive payment. For purposes of
estimating our discounted net cash inflows from our proved reserves in Block
A-18, we have assumed that we would be entitled to a $40 million incentive
payment.

Notwithstanding a possible future delay in the buyers' environmental
approvals process, in order to meet the June 30, 2002 deadline, the sellers are
committed to, or will be required to commit to, significant expenditures,
including the engineering, procurement and construction contract. Although BP is
committed to pay all development costs associated with Block A-18 up to $377
million, we have agreed to share some of the costs of development with BP in the
event that the environmental approval process delays production by agreeing to
pay BP $1.25 million per month for each month, if applicable, that first gas
sales are delayed beyond 30 months following the award of the engineering,
procurement and construction contract for the project in March 2000. Our
obligation is capped at 24 months of these payments, or $30 million.

GABON

In 2000, we acquired a 38% interest in the Tolo and Otiti blocks offshore
Gabon. Our partners in the two blocks are Australia-based Broken Hill
Proprietary Company Limited, the operator, and Sasol Limited. The Tolo block
covers approximately 836,000 acres located offshore and west of Libreville in
water depths from 1,600 to 8,200 feet. The contract for the Tolo block provides
an exploration term expiring in July 2003 with a commitment of one exploration
well. We expect to drill this well in second half of 2001, subject to rig
availability.

The Otiti block covers approximately 815,000 acres located offshore and
southwest of Libreville in water depths from 1,600 to 6,600 feet. The contract
for the Otiti block provides an exploration term expiring in July 2003, with a
commitment of 750 kilometers of 2D seismic and 250 square kilometers of 3D
seismic.

GREECE

We have an 88% interest in the Gulf of Patraikos contract area. Hellenic
Petroleum, the national oil company of Greece, has the remaining 12% interest.
The Gulf of Patraikos contract area covers approximately 402,000 acres located
offshore between the western coast of Greece and the offshore Ionian islands of
Lefkas, Kefalonia and Zakynthos in water depths of up to 920 feet. The contract
provides a primary exploration term expiring in September 2001. We have
remaining a commitment to drill one exploration well.

We had an interest in the Aitoloakarnania onshore contract area. During
2000, we completed our commitments for this area, including the drilling of two
commitment wells, which were dry holes. In September 2000, we surrendered our
interest in the area.

ITALY

We hold interests in three licenses in Italy comprising three offshore
blocks in the Adriatic Sea.

We have a 47% interest in each of the DR71 and DR72 licenses covering
approximately 369,400 acres. The license areas are located in the Adriatic Sea
located 45 kilometers (28 miles) offshore the city of Brindisi. Our partner is
Enterprise Oil Italiana, S.p.A., the operator, with a 53% interest. During 1998,
we drilled the Giove-1 well. The well was drilled to a total depth of 3,458 feet
but was prematurely abandoned due to a gas blowout and mechanical failure. We
drilled a replacement well, Giove-2, to a total depth of 4,285 feet and
encountered oil and gas, although additional work is required to evaluate the
commercial potential of the licenses.

We have a 20% interest in the FR33AG offshore license. The license covers
approximately 71,600 acres and is adjacent to the DR71 and DR72 licenses. Eni
S.p.A. is operator, with a 50% interest, and Enterprise holds the remaining 30%
interest. The license provides a primary exploration term expiring in September
2004 with a commitment of 250 kilometers (156 miles) of new 2D seismic and the
drilling of one exploration well.

In January 2001, we and our partner applied to relinquish our interest in
the Fosso del Lupo, Valsinni and Masseria de Sole onshore licenses in the Matera
province.

MADAGASCAR

We are a party to a production sharing contract with the Office of National
Mines and Strategic Industries in Madagascar for the Ambilobe Block, covering
approximately 4.3 million acres. The block is located directly offshore from
Ambilobe in water depths of up to 11,500 feet. We have acquired approximately
3,000 kilometers (1,875 miles) of 2D seismic. The contract provides that it will
expire in November 2001, unless we elect to extend the contract, which would
require us to commit to drill one exploration well.

OMAN

We are a party to a production sharing contract for Block 40, covering
approximately 1.3 million acres located offshore in the Straits of Hormuz. The
contract provides an exploration term expiring in July 2002 with a commitment of
the drilling of one exploration well. We are the operator with a 50% contract
interest and Atlantis Holding Norway AS is our partner with a 50% interest.

We have completed the reprocessing and interpretation of 4,083 kilometers
(2,546 miles) of existing 2D seismic, and the processing and interpretation of a
620-square-kilometer 3D seismic survey acquired in January 2000. We are
processing the information from a recently completed site survey in preparation
for drilling an exploration well in late 2001 or early 2002.

RESERVES

The following table sets forth a summary of our estimated proved oil and
gas reserves at December 31, 2000, and is based on separate estimates of our net
proved reserves prepared by:

- the independent petroleum engineers, DeGolyer and MacNaughton, with
respect to the proved reserves in the Cusiana and Cupiagua fields in Colombia,

- the independent petroleum engineers, Netherland, Sewell & Associates,
Inc., with respect to the proved reserves in the Ceiba field in Equatorial
Guinea, and

- the internal petroleum engineers of the operating company, Carigali-Triton
Operating Company, with respect to the proved reserves in Malaysia-Thailand on
Block A-18 in the Gulf of Thailand.

For additional information regarding our reserves, including the
standardized measure of future net cash flows, see note 21 of Notes to
Consolidated Financial Statements. Oil reserves data include natural gas liquids
and condensate.

Net proved reserves at December 31, 2000, were:

PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
------------------- ---------------------- ------------------
OIL GAS OIL GAS OIL GAS
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
---------- ------- ------------ -------- -------- --------

Colombia (1) 81,101 10,865 25,303 --- 106,404 10,865
Equatorial Guinea 24,663 --- 50,504 --- 75,167 ---
Malaysia-Thailand (2) --- --- 13,124 581,708 13,124 581,708
---------- ------- ------------ -------- -------- --------

Total 105,764 10,865 88,931 581,708 194,695 592,573
========== ======= ============ ======== ======== ========

____________________
(1) Includes liquids to be recovered from Ecopetrol as reimbursement for
precommerciality expenditures.
(2) As of December 31, 2000, gas sales had not yet commenced. The proved gas
reserves are calculated using the base price in the gas sales agreement of
$2.30. The base price is subject to annual adjustments based on various indices.
We cannot assure you that the actual price when gas sales commence will be the
same as the price we used in our assumptions. Because of the cost-recovery
feature of the production sharing contract, a higher price would result in lower
volumes of reserves, but a higher measure of discounted net cash inflows. See
"Items 1. and 2. Business and Properties - Malaysia-Thailand."

Reserve quantities are estimates and there are a number of uncertainties.

Reserve estimates are approximate and may be expected to change as
additional information becomes available. In addition, there are inherent
uncertainties in making reserve estimates, such as the following:

- reservoir engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact way;

- the accuracy of reserve estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment;

- we, and if applicable our independent engineers, must make certain
assumptions and projections based on engineering data;

- there are uncertainties inherent in interpreting engineering data; and

- we, and if applicable our independent engineers, must project future rates
of production and the timing of development expenditures.

Accordingly, we cannot assure you that we will ultimately produce the
quantity of reserves set forth in the table, and we cannot assure you that the
proved undeveloped reserves will be developed within the periods anticipated.

We do not file estimates of total proved net oil or gas reserves with, or
included estimates of total proved net oil or gas reserves in any report to, any
United States authority or agency.

OIL AND GAS OPERATIONS

PRODUCTION AND SALES

The following table sets forth the net quantities of oil and gas we
produced during 2000, 1999 and 1998. If during these three years we acquired or
sold a property or a subsidiary, the information in the table includes
production and sales information relating to the property or subsidiary only
during the times we owned it. The table does not reflect production from our
interest in the Ceiba field in Equatorial Guinea because we did not make our
first sale until January 2001. Approximately 1.25 million barrels of oil (one
million net to us) were produced in the fourth quarter of 2000 and stored in the
FPSO. More details regarding our revenues, assets and other data by geographical
area is contained in note 19 of Notes to Consolidated Financial Statements.

OIL PRODUCTION (1) GAS PRODUCTION
------------------------ -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ -----------------------
2000 1999 1998 2000 1999 1998
------ ------ ------ ------ ------ -----
(MBBLS) (MMCF)

Colombia (2) 11,167 12,469 9,979 470 459 503

____________________
(1) Includes natural gas liquids and condensate.
(2) Includes Ecopetrol reimbursement barrels, and excludes oil produced and
delivered over the past three years to satisfy our obligations under a forward
oil sale we entered into in May 1995. We delivered 0.8 million barrels in 2000,
3.1 million barrels in 1999 and 3.1 million barrels in 1998 in connection with
the forward oil sale.

The following tables summarize for 2000, 1999 and 1998: (i) the average
sales price per barrel of oil and per Mcf of natural gas; (ii) the average sales
price per equivalent barrel of production; (iii) the depletion cost per
equivalent barrel of production; and (iv) the production cost per equivalent
barrel of production:

AVERAGE SALES PRICE AVERAGE SALES PRICE
PER BARREL OF OIL (1) PER MCF OF GAS
------------------------- ------------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------- ------------------------
2000 1999 1998 2000 1999 1998
------ ------ ------ ------ ------ ------

Colombia (4) $27.48 $ 15.95 $12.31 $ 1.34 $ 0.88 $ 0.99

PER EQUIVALENT BARREL (2)
----------------------------------------------------------------------------
AVERAGE SALES PRICE DEPLETION (3) PRODUCTION COST
------------------------- ------------------------ -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------- ------------------------ -----------------------

2000 1999 1998 2000 1999 1998 2000 1999 1998
------- ------ ------ ------ ------ ------ ------ ----- ------
Colombia (4) $ 27.36 $15.89 $12.27 $ 4.37 $ 3.80 $ 4.07 $ 4.64 $ 4.50 $ 5.97

____________________________
(1) Includes natural gas liquids and condensate.
(2) Natural gas has been converted into equivalent barrels of oil based on six
Mcf of natural gas per barrel of oil.
(3) Includes depreciation calculated on the unit of production method for
support equipment and facilities. Excludes the full cost ceiling limitation
writedown in 1998 totaling $241 million.
(4) Includes barrels delivered under the forward oil sale which are recorded
at $11.56 per barrel upon delivery.

COMPETITION

We encounter 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 we operate 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. We believe that the principal
means of competition in the sale of oil and gas are product availability, price,
quality and logistics.

MARKETS

We generally sell our crude oil, natural gas, condensate and other oil and
gas products to other oil and gas companies, government agencies and other
industries. We do not believe that the loss of any single customer or sales
contract would have a long-term material, adverse effect on our revenues or oil
and gas operations.

In Colombia, our oil production is exported through the Caribbean port of
Covenas where it is sold at prices based on United States prices, adjusted for
quality and transportation. The oil produced from the Cusiana and Cupiagua
fields is transported to the export terminal by pipeline.

In Equatorial Guinea, our oil production is sold upon transfer from the
FPSO to a buyer's vessel. We expect to be able to market our crude oil to
refiners throughout the world. The price of the Ceiba crude is based on a
benchmark crude oil, such as Dated Brent, adjusted for quality and
transportation. Initially, for operational reasons, we have limited sales to
relatively smaller cargo vessels capable of loading quantities of 1,000,000
barrels or less. We believe this has somewhat limited the number of potential
purchasers due to the relatively higher transportation costs per barrel. In
addition, Ceiba crude is a relatively new crude oil previously unknown to
refiners, with an acid quality that certain refiners will not readily be able to
process, which could discourage those refiners from purchasing the crude without
a price discount.

We believe that, as our operational efficiency improves to permit us to
market the crude to larger vessels, and therefore to a greater number of
refiners, the price of Ceiba crude in relation to applicable benchmarks should
improve. We cannot assure you that this price differential will improve or if it
does, that it will improve by a material amount.

For a discussion of certain factors regarding our markets and potential
markets that could affect future operations, see the "Certain Factors That Could
Affect Future Operations" section in "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations."

ACREAGE

The following table shows the total gross and net developed and undeveloped
oil and gas acreage we held at December 31, 2000. "Gross" refers to the total
number of acres in an area in which we hold an interest without adjustment to
reflect the actual percentage interest we hold. "Net" acreage is adjusted for
working interests owned by other parties.

"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(2) GROSS NET(2)
-------- -------- -------- --------
(In thousands)

Colombia 29 3 150 17
Equatorial Guinea 1 1 2,127 1,177
Malaysia-Thailand --- --- 731 183
Gabon --- --- 1,651 628
Greece --- --- 402 354
Italy(3) --- --- 441 188
Madagascar --- --- 4,300 4,300
Oman --- --- 1,322 661
-------- -------- -------- --------

Total 30 4 11,124 7,508
======== ======== ======== ========

____________________

(1) Our interest in certain of this acreage may expire if not developed at
various times in the future pursuant to the terms of the leases, licenses,
concessions, contracts, permits or other agreements under which it was acquired.
(2) The net acreage position does not take into account royalties, net
revenue interests, carried interests or similar interests held by third parties
that reduce our net revenue interest but not our working interest.
(3) Excludes approximately 58,000 gross acres (29,000 net acres)
attributable to onshore licenses that we relinquished in January 2001.

PRODUCTIVE WELLS AND DRILLING ACTIVITY

In this section, when we refer to "gross" wells, we mean every well drilled
in an area in which we hold any interest. When we refer to "net" wells, we mean
the gross number of wells drilled adjusted for our percentage interest in the
area.

The following table summarizes the approximate total gross and net working
interests we held in productive wells at December 31, 2000:

PRODUCTIVE WELLS(1)
GROSS NET
-------------- --------------
OIL GAS OIL GAS
------ ------ ------ ------

Colombia 105 --- 12.58 ---
Equatorial Guinea(2) 5 --- 4.25 ---
------ ------ ------ ------

Total 110 --- 16.83 ---
====== ====== ====== ======

___________________

The following tables set forth the results of the oil and gas well drilling
activity on a gross basis for wells in which we held an interest during 2000,
1999 and 1998. If during these three years we acquired or sold a property or a
subsidiary, the information in the tables includes production and sales
information relating to the property or subsidiary only during the times we
owned it. For purposes of the following tables, the Ceiba-5 and -6 wells are
counted as exploration wells because they were drilled outside the area that
included proved reserves at the time they were drilled. The Ceiba-3 and -4 wells
are counted as development wells.

GROSS EXPLORATION WELLS

PRODUCTIVE (1) DRY TOTAL
------------------------ ----------------------- -----------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ ----------------------- -----------------------
2000 1999 1998 2000 1999 1998 2000 1999 1998
------ ------ ------ ------ ------ ----- ------- ------ ------

Colombia --- --- 1 --- 1 --- --- 1 1
Equatorial Guinea 1 2 --- 3 --- --- 4 2 ---
Malaysia-Thailand --- --- 2 --- --- --- --- --- 2
Italy --- --- --- --- --- 2 --- --- 2
China --- --- --- --- --- 1 --- --- 1
Greece --- --- --- 2 --- --- 2 --- ---
Tunisia --- --- --- --- --- 1 --- --- 1
------ ------ ------ ------ ------ ----- ------- ------ ------

Total 1 2 3 5 1 4 6 3 7
====== ====== ====== ====== ====== ===== ======= ====== ======

GROSS DEVELOPMENT WELLS

Colombia 14 14 13 --- --- --- 14 14 13
Equatorial Guinea 2 --- --- --- --- --- 2 --- ---
Malaysia-Thailand --- --- --- --- --- --- --- --- ---
------ ------ ------ ------ ------ ----- ------- ------ ------

Total 16 14 13 --- --- --- 16 14 13
====== ====== ====== ====== ====== ===== ======= ====== ======

___________________
(1) A productive well is producing or capable of producing oil and/or gas in
commercial quantities. Multiple completions have been counted as one well. Any
well in which one of the multiple completions is an oil completion is classified
as an oil well.

The following tables set forth the results of drilling activity on a net
basis for wells in which we held an interest during 2000, 1999 and 1998. If
during these three years we acquired or sold a property or a
subsidiary, the information in the tables includes production and sales
information relating to the property or subsidiary only during the times
we owned it.

NET EXPLORATION WELLS

Colombia (2) --- --- 0.12 --- 0.50 --- --- 0.50 0.12
Equatorial Guinea(3) .85 1.70 --- 2.55 --- --- 3.40 1.70 ---
Malaysia-Thailand (4) --- --- 1.00 --- --- --- --- --- 1.00
Italy --- --- --- --- --- 0.80 --- --- 0.80
China --- --- --- --- --- 0.50 --- --- 0.50
Greece --- --- --- 2.00 --- --- 2.00 --- ---
Tunisia --- --- --- --- --- 0.50 --- --- 0.50
------ ------ ------ ------ ------ ----- ------- ------ ------

Total .85 1.70 1.12 4.55 0.50 1.80 5.40 2.20 2.92
====== ====== ====== ====== ====== ===== ======= ====== ======

NET DEVELOPMENT WELLS

Colombia (2) 1.66 1.68 1.56 --- --- --- 1.66 1.68 1.56
Equatorial Guinea(3) 1.70 --- --- --- --- --- 1.70 --- ---
Malaysia-Thailand --- --- --- --- --- --- --- --- ---
------ ------ ------ ------ ------ ----- ------- ------ ------

Total 3.36 1.68 1.56 --- --- --- 3.36 1.68 1.56
====== ====== ====== ====== ====== ===== ======= ====== ======

__________________

(1) A productive well is producing or capable of producing oil and/or gas in
commercial quantities. Multiple completions have been counted as one well. Any
well in which one of the multiple completions is an oil completion is classified
as an oil well.
(2) Adjusted to reflect the national oil company participation at commerciality
for the Cusiana and Cupiagua fields.
(3) The well data does not take into account the government of Equatorial
Guinea's 5% carried interest.
(4) The interest in the wells drilled in 1998 was not reduced to take into
account the sale of our interest in Block A-18 to BP because the sale occurred
after the drilling of the wells.

OTHER PROPERTIES

We lease office space, other facilities and equipment under various
operating leases expiring through 2005. Total rental expense was $1.3 million in
2000, $1.3 million in 1999 and $2.1 million in 1998. These figures exclude the
charter payments during 2000 for the FPSO, which totaled $3.2 million and were
capitalized in inventory at December 31, 2000. We have chartered the FPSO
through November 2002, with options to extend the charter for five additional
one-year periods. At December 31, 2000, the minimum payments required under
terms of the leases, including the FPSO charter, were as follows: 2001 -- $31.4
million; 2002 -- $28.9 million; 2003 -- $1.9 million; 2004 -- $1.7 million; and
2005 -- $1.0 million.

For additional information on our leases, including our office leases, see
note 18 of Notes to Consolidated Financial Statements.

EMPLOYEES

At March 6, 2001, we employed approximately 195 full-time employees.

EXECUTIVE OFFICERS

The following table sets forth certain information regarding our executive
officers at March 6, 2001:

SERVED WITH
-----------
TRITON
-----------
NAME AGE POSITION WITH TRITON SINCE
- ------------------ --- ---------------------------------- -----------
James C. Musselman 53 President and Chief Executive
Officer 1998
A.E. Turner, III 52 Senior Vice President and
Chief Operating Officer 1994
W. Greg Dunlevy 45 Senior Vice President, Chief
Financial Officer and Treasurer 1993
Brian Maxted 43 Senior Vice President, Exploration 1994
Marvin Garrett 45 Vice President, Production 1994

Mr. Musselman was elected as a director in May 1998, and was elected Chief
Executive Officer in October 1998. Mr. Musselman has served as Chairman,
President and Chief Executive Officer of Avia Energy Development, LLC, a private
company engaged in gas processing and drilling, since September 1994. From June
1991 to September 1994, Mr. Musselman was the President and Chief Executive
Officer of Lone Star Jockey Club, LLC, a company formed to organize a horse
racetrack facility in Texas.

Mr. Turner was elected Senior Vice President and Chief Operating Officer in
March 1999, and prior to that served as Senior Vice President, Operations, since
March 1994. From 1988 to February 1994, Mr. Turner served in various positions
with British Gas Exploration & Production, Inc., including Vice President and
General Manager of operations in Africa and the Western Hemisphere from October
1993.

Mr. Dunlevy has served as Senior Vice President and Chief Financial Officer
since September 2000. Mr. Dunlevy joined Triton in 1993 as Vice President,
Investor Relations and became Treasurer in July 1998. He became Vice President,
Finance in March 2000.

Mr. Maxted has served as Senior Vice President, Exploration since September
2000. He served as Vice President, Exploration, since January 1998, and prior to
that served as Exploration Manager of Carigali-Triton Operating Company where he
led exploration activities in the Gulf of Thailand from 1994 to 1998. From 1979
to 1994, Mr. Maxted was employed by British Petroleum in various capacities,
including Exploration Manager, Colombia from 1990 to 1992 and License Manager,
Norway from 1992 to 1994.

Mr. Garrett has served as Vice President, Production, since December 1999,
and prior to that served in various capacities within our Operations Department
since August 1994, including most recently as Director, Operations. Prior to
joining Triton in August 1994, Mr. Garrett served in various positions with
British Gas Exploration and Production, Inc., including General Manager and
Managing Director of Zaafarana Joint Operating Company in Cairo, Egypt.

Our executive officers are elected annually by the Board of Directors to
serve until removed or their successors are duly elected and qualified. There
are no family relationships among our executive officers.

CERTAIN DEFINITIONS

As used in this report:

- "Bbl" means barrel;

- "Bcf" means billion cubic feet;

- "BOPD" means barrels of crude oil per day;

- "BOE" means barrels of oil equivalent;

- "Mcf" means thousand cubic feet;

- "MMcf means million cubic feet;

- "Mbbls" means thousand barrels;

- "MMbtu" means million British thermal unit; and

- "Tcf" means trillion cubic feet; and

- "WTI" means the West Texas Intermediate price index.

ITEM 3. LEGAL PROCEEDINGS

In July through October 1998, eight lawsuits were filed against Triton and
Thomas G. Finck and Peter Rugg, in their capacities as former officers of
Triton. The lawsuits were filed in the United States District Court for the
Eastern District of Texas, Texarkana Division, and have been consolidated and
are styled In re: Triton Energy Limited Securities Litigation. The consolidated
complaint alleges violations of Sections 10(b) and 20(a) of the Securities
Exchange Act of 1934, and Rule 10b-5 promulgated thereunder, in connection with
disclosures concerning our properties, operations, and value relating to a
prospective sale in 1998 of Triton or of all or a part of our assets. The
lawsuits seek recovery of an unspecified amount of compensatory damages, fees
and costs. We have filed a motion to dismiss the claims, which is pending.

We believe our disclosures were accurate and intend to vigorously defend
these actions. We cannot assure you that the litigation will be resolved in our
favor. An adverse result could have a material adverse effect on our financial
position or results of operations.

In November 1999, a lawsuit was filed against us, one of our subsidiaries
and Thomas G. Finck and Peter Rugg, in their capacities as former officers of
Triton, in the District Court of the State of Texas for Dallas County. The
lawsuit is styled Aaron Sherman, et al. vs. Triton Energy Corporation et al.
and, as amended, alleges as causes of action fraud, negligent misrepresentation
and violations of the Texas securities fraud statutes in connection with our
1996 reorganization as a Cayman Islands corporation and disclosures concerning
our prospective sale of all or a substantial part of our assets announced in
March 1998. In their most recent filling, the plaintiffs asserted actual damages
of up to $10 million and sought punitive damages of up to $50 million. We have
filed various motions to dispose of the lawsuit on the grounds that the
plaintiffs do not have standing and have not plead causes of action cognizable
in law. The court has dismissed all claims of certain plaintiffs and some claims
of the remaining plaintiffs for failure to plead viable causes of action. The
Court has entered an order for proceedings in connection with further
examination of plaintiffs' claims.

In August 1997, we were sued in the Superior Court of the State of
California for the County of Los Angeles, by David A. Hite, Nordell
International Resources Ltd., and International Veronex Resources, Ltd. The
action was removed to the United States District Court for the Central District
of California. We and the plaintiffs were adversaries in a 1990 arbitration
proceeding in which the interest of Nordell International Resources Ltd. in the
Enim oil field in Indonesia was awarded to us (subject to a 5% net profits
interest for Nordell) and Nordell was ordered to pay us nearly $1 million. The
arbitration award was followed by a series of legal actions by the parties in
which the validity of the award and its enforcement were at issue. As a result
of these proceedings, the award was ultimately upheld and enforced. The current
suit alleges that the plaintiffs were damaged in amounts aggregating $13 million
primarily because of our prosecution of various claims against the plaintiffs,
as well as our alleged misrepresentations, infliction of emotional distress, and
improper accounting practices. The suit seeks specific performance of the
arbitration award, damages for alleged fraud and misrepresentation in accounting
for Enim field operating results, an accounting for Nordell's 5% net profit
interest, and damages for emotional distress and various other alleged torts.
The suit seeks interest, punitive damages and attorneys fees in addition to the
alleged actual damages. In August 1998, the district court dismissed all claims
asserted by the plaintiffs other than claims for malicious prosecution and abuse
of the legal process, which the court held could not be subject to a motion to
dismiss. The abuse of process claim was later withdrawn, and the damages sought
were reduced to approximately $700,000 (not including punitive damages). The
lawsuit was tried and the jury found in favor of the plaintiffs and assessed
compensatory damages against us in the amount of approximately $700,000 and
punitive damages in the amount of approximately $11 million. We believe we have
acted appropriately, and we have appealed the verdict. Nordell has
cross-appealed from the dismissal of its claims for an audit and an accounting
related to the 5% net profits interest. Enforcement of the judgment was stayed
without a bond pending the outcome of the appeal.

During the quarter ended September 30, 1995, the United States
Environmental Protection Agency ("EPA") and Justice Department advised us that
one of our 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. Our
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, our subsidiary declined
to accept the offer. In October 1997, the EPA advised us that the estimated cost
of the clean-up of the site would be approximately $217 million to be allocated
among the 280 known operators. Our subsidiary's share would be approximately $1
million based upon a volumetric allocation, but there can be no assurance that
any allocation of liability to the subsidiary would be made on a volumetric
basis. No proceeding has been brought in any court against us or our subsidiary
in this matter.

In addition to the matters described above, we are also subject to
litigation that is incidental to our business.

Certain Factors Relating to Litigation Matters

We do not expect that the legal matters described above will have a
material adverse effect on our consolidated financial position, results of
operations and cash flows. However, this is a forward-looking statement that is
dependent on certain events and uncertainties that may be outside of our
control. Actual results and developments could differ materially from our
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 we may elect to settle claims at amounts that exceed our
expected liability for the 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

We did not submit any matter to our security holders, through the
solicitation of proxies or otherwise, during the fourth quarter of 2000.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS

ORDINARY SHARES

Our ordinary shares are listed on the New York Stock Exchange and are
traded under the symbol "OIL." The following table sets forth the high and low
sales prices of our ordinary shares as reported on the New York Stock Exchange
Composite Tape for the periods indicated:

CALENDAR PERIODS HIGH LOW
- -------------------------------- ----- -----
2001:
First Quarter* 30.75 19.24
2000:
Fourth Quarter 39.75 22.81
Third Quarter 50.88 34.13
Second Quarter 41.00 29.06
First Quarter 38.06 19.19
1999:
Fourth Quarter 27.50 13.50
Third Quarter 14.69 10.00
Second Quarter 16.00 6.94
First Quarter 8.88 5.19

________________________________
*Through March 6, 2001.

The holders of ordinary shares are only entitled to receive such dividends
as are declared by our Board of Directors. Under applicable corporate law, the
Board of Directors may declare dividends or make other distributions to our
shareholders in such amounts as appear to the directors to be justified by our
profits or out of our share premium account if we have the ability to pay our
debts as they come due.

Our current intent is to retain earnings for use in our business and the
financing of our capital requirements. The payment of any future cash dividends
on the ordinary shares is necessarily dependent upon our earnings and financial
needs, along with applicable legal and contractual restrictions.

We are prohibited from paying cash dividends on the ordinary shares under
both our revolving credit facility and our shareholders agreement with HM4
Triton, L.P. unless we get those parties' consents, and we are limited in the
amount of dividends we could pay by the indenture governing the terms of our 8
7/8% Senior Notes due 2007. In addition, under the terms of our 8% Convertible
Preference Shares, we may not pay a dividend or other distribution on the
ordinary shares unless all dividends on the 8% Convertible Preference Shares
have been paid in full or set aside for payment. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
note 9 of Notes to Consolidated Financial Statements.

There is no tax treaty between the United States and the Cayman Islands.

At March 6, 2001, there were 3,808 record holders of our ordinary shares.

8% CONVERTIBLE PREFERENCE SHARES

We have one series of preference shares outstanding, the 8% Convertible
Preference Shares. As of March 6, 2001, there were outstanding 5,180,761 8%
Convertible Preference Shares. The following summary of certain provisions of
the resolutions establishing the terms of the 8% Convertible Preference Shares
is not complete. You should refer to the resolutions, a copy of which was filed
as an exhibit to our Quarterly Report on Form 10-Q for the quarter ended
September 30, 1998.

Dividends. We are required to pay dividends on the 8% Convertible
---------
Preference Shares semiannually at the rate of 8% per year of the stated value of
$70 per share for each semiannual dividend period ending on June 30 and December
31 of each year. Dividends on the 8% Convertible Preference Shares are
cumulative.

We can choose to pay dividends in cash or in additional 8% Convertible
Preference Shares. If we pay a dividend in additional shares, the number of
additional shares we would issue is determined by dividing the amount of the
dividend by $70, with amounts in respect of any fractional shares to be paid in
cash. If we were to fail to pay an accumulated dividend on the 8% Convertible
Preference Shares, the unpaid dividends would be added to the stated value of
the 8% Convertible Preference Shares, and thereafter dividends would accumulate
and be paid based on the adjusted stated value. We are limited in the amount of
dividends we may pay in cash by the terms of the indenture under which our 8
7/8% Senior Notes due 2007 were issued as well as by our revolving credit
facility. In the event that, at a time a dividend is required to be paid under
the terms of the 8% Convertible Preference Shares, the dividend would exceed the
applicable limits, we may be required to pay the dividend in additional 8%
Convertible Preference Shares.

Conversion. Holders of 8% Convertible Preference Shares generally have the
----------
right to convert their 8% Convertible Preference Shares into ordinary shares at
any time before redemption at the conversion price in effect at the time of
conversion. The current conversion price is $17.50 per ordinary share so that
each 8% Convertible Preference Share is convertible into four ordinary shares.
The conversion price is subject to adjustment under certain circumstances. Upon
the conversion of 8% Convertible Preference Shares, the holder is also entitled
to receive an amount in cash equal to all accumulated and unpaid dividends on
the 8% Convertible Preference Shares converted through the effective date of
conversion.

Redemption. We cannot redeem the 8% Convertible Preference Shares before
----------
September 30, 2001. Beginning September 30, 2001, we can redeem all, but not
less than all, of the outstanding 8% Convertible Preference Shares if the
average market value of the ordinary shares as calculated below is above certain
market values. The redemption price is equal to $70 per share, plus an amount
equal to all accumulated but unpaid dividends, and is payable in cash.

The average market value is determined by averaging the closing price of
the ordinary shares for the 20 trading days preceding the notice of redemption.
We may only redeem the 8% Convertible Preference Shares if this average market
value exceeds the average market value corresponding to the six-month period set
forth below:

REDEMPTION NOTICE GIVEN IN THE SIX-MONTH PERIOD: AVERAGE MARKET VALUE
- ------------------------------------------------ ---------------------
September 30, 2001 through March 31, 2002 $ 28.54
April 1, 2002 through September 30, 2002 31.14
October 1, 2002 through March 31, 2003 34.20
April 1, 2003 through September 30, 2003 37.58
October 1, 2003 through March 31, 2004 32.57
April 1, 2004 through September 30, 2004 34.97
October 1, 2004 through March 31, 2005 37.60

Beginning April 1, 2005, the minimum average market value will be increased
every six months to reflect an internal rate of return of 20% assuming a holder
purchased 8% Convertible Preference Shares on September 30, 1998. The minimum
average prices set forth above will be adjusted in the event of any combination,
subdivision or reclassification of ordinary shares, or any similar event.

Liquidation Rights. The liquidation preference of the 8% Convertible
-------------------
Preference Shares is $70 per share, plus accumulated and unpaid dividends. In
the event we undergo a liquidation, dissolution or winding up, before any
payment or distribution can be made to the holders of our ordinary shares or any
other class or series of our shares ranking junior to the 8% Convertible
Preference Shares as to both dividends and liquidation rights, the holders of
the 8% Convertible Preference Shares will be entitled to receive their
liquidation preference and any accumulated and unpaid dividends.

Voting Rights. The holders of the 8% Convertible Preference Shares
--------------
generally vote with the holders of the ordinary shares on all matters brought
before our shareholders. When voting with the holders of the ordinary shares,
the holders of the 8% Convertible Preference Shares have the number of votes for
each share that they would have if they had converted their shares into ordinary
shares on the related record date. In addition, the holders of the 8%
Convertible Preference Shares will be entitled to elect two directors of Triton
if we do not pay dividends on the 8% Convertible Preference Shares under certain
circumstances. When voting as a class, the holders of the 8% Convertible
Preference Shares have one vote per share.

The rights of the 8% Convertible Preference Shares may not be varied
without the consent of the holders of at least two-thirds of the 8% Convertible
Preference Shares. We cannot create a class of equity securities ranking senior
to the 8% Convertible Preference Shares as to dividend or liquidation rights,
other than out of our existing authorized shares of "blank check" preference
shares, or adopt charter amendments materially adversely affecting the rights of
the 8% Convertible Preference Shares, without the consent of the holders of at
least two-thirds of the outstanding 8% Convertible Preference Shares. In
addition, we cannot increase the authorized number of 8% Convertible Preference
Shares, or create a class of equity securities ranking equal to the 8%
Convertible Preference Shares as to dividend or liquidation rights, other than
out of our existing authorized shares of "blank check" preference shares,
without the consent of the holders of at least a majority of the outstanding 8%
Convertible Preference Shares.

Shareholders Agreement with HM4 Triton, L.P. We have entered into a
-------------------------------------------------
shareholders agreement with HM4 Triton, L.P. The shareholders agreement provides
that, in general, for so long as the entire board of directors consists of 10
members, HM4 Triton, L.P. may designate four nominees for election to the board
of directors, with any fractional directorship rounded up to the next whole
number. If HM4 Triton, L.P. transfers its 8% Convertible Preference Shares, it
may also assign its right to designate Triton directors for nomination. The
number of designees HM4 Triton, L.P. may designate will increase or decrease
proportionately with any change in the total number of members of the board of
directors. The right of HM4 Triton, L.P. and its designated transferees to
designate nominees for election to the board of directors will be reduced if the
number of ordinary shares held by HM4 Triton, L.P. and its affiliates represents
less than certain specified percentages of the number of shares HM4 Triton, L.P.
purchased from us under the stock purchase agreement between HM4 Triton, L.P.
and us. These percentages are calculated assuming HM4 Triton, L.P. converts all
of its 8% Convertible Preference Shares into ordinary shares.

In the shareholders agreement, we also agreed that we would not take
specified fundamental corporate actions without the consent of HM4 Triton, L.P.
Some of the actions that would require HM4 Triton, L.P.'s consent are listed
below:

- - amending our Articles of Association or the terms of the 8% Convertible
Preference Shares with respect to the voting powers, rights or preferences of
the holders of 8% Convertible Preference Shares,

- - entering into a merger or similar business combination transaction, or
effecting a reorganization, recapitalization or other transaction pursuant to
which a majority of the outstanding ordinary shares or any 8% Convertible
Preference Shares are exchanged for securities, cash or other property;

- - authorizing, creating or modifying the terms of any securities that would
rank equal to or senior to the 8% Convertible Preference Shares;

- - selling assets comprising more than 50% of our market value;

- - paying dividends on our ordinary shares or other shares ranking junior to
the 8% Convertible Preference Shares;

- - incurring debt over a specified amount; and

- - commencing a tender offer or exchange offer for any of our ordinary
shares.

SHAREHOLDER RIGHTS PLAN

We have adopted a shareholder rights plan. Under this plan, preference
share rights attach to all ordinary shares at the rate of one right for each
ordinary share. Each right entitles the holder of our ordinary shares to
purchase one one-thousandth of our Series A Junior Participating Preference
Shares at a price of $120 per one one-thousandth of a Series A Junior Preference
Share, subject to adjustment. Generally, these rights would only become
distributable 10 days following a public announcement that a person has acquired
beneficial ownership of 15% or more of our ordinary shares or 10 business days
following commencement of a tender offer or exchange offer for 15% or more of
our outstanding ordinary shares. If, among other events, any person becomes the
beneficial owner of 15% or more of our ordinary shares, each right not owned by
that person generally becomes the right to purchase a number of ordinary shares
equal to the number obtained by dividing the right's exercise price, currently
$120, by 50% of the market price of the ordinary shares on the date of the first
occurrence. In addition, if we are subsequently merged or certain other
extraordinary business transactions are consummated, each right generally
becomes a right to purchase a number of shares of common stock of the acquiring
person equal to the number obtained by dividing the right's exercise price by
50% of the market price of the common stock on the date of the first occurrence.
Pursuant to the terms of the plan, any acquisition of Triton shares by HM4
Triton, L.P. or its affiliates will not result in the distribution of rights
unless and until HM4 Triton, L.P.'s ownership of Triton shares is reduced below
certain levels.

Under certain circumstances, our board of directors may determine that a
tender offer or merger is fair to all our shareholders and prevent the rights
from being exercised. At any time after a person or group acquires 15% or more
of the ordinary shares outstanding and prior to the acquisition by that person
or group of 50% or more of the outstanding ordinary shares, our board of
directors may exchange the rights, in whole or in part, at an exchange ratio of
one ordinary share, or one one-thousandth of a Junior Preference Share, per
right, subject to adjustment. The board of directors may not exchange the rights
owned by the person or group who acquired 50% or more of the outstanding
ordinary shares. Their rights will become void.

We can amend the rights, except the redemption price, in any manner prior
to the public announcement that a 15% position has been acquired or a tender
offer has been commenced. We can redeem the rights at $0.01 per right at any
time prior to the time that a 15% position has been acquired. The rights will
expire on May 22, 2005, unless we redeem the rights before then.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth certain financial and oil and gas data on a
historical basis. We adopted Securities and Exchange Commission Staff Accounting
Bulletin (SAB) 101, Revenue Recognition in Financial Statements, effective
January 1, 2000, which requires us to record oil revenue on each sale, or tanker
lifting, and our oil inventories at cost, rather than at market value as in the
past. The cumulative effect of this change for periods prior to January 1, 2000
is a reduction in net earnings of $1.3 million, or $0.03 per diluted share and
is shown as the cumulative effect of accounting change in the Consolidated
Statements of Operations. Pro forma net earnings, adjusted for the new
accounting principle, would have decreased by $.1 million for 1999 and increased
by $.1 million for 1998.

AS OF OR FOR YEAR ENDED DECEMBER 31,
-------------------------------------------------------
2000 1999 1998 1997 1996
---------- --------- --------- ---------- ---------

OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA):
Oil and gas sales $ 328,467 $ 247,878 $ 160,881 $ 145,419 $ 129,795
Sales and other operating revenues 328,467 247,878 228,618 149,496 133,977
Earnings (loss) before extraordinary item and cumulative
effect of accounting change 75,680 47,557 (187,504) 5,595 23,805
Net earnings (loss) 67,373 47,557 (187,504) (8,896) 22,609
Average ordinary shares outstanding 36,551 36,135 36,609 36,471 35,929
Basic earnings (loss) per ordinary share:
Earnings (loss) before extraordinary item and
cumulative effect of accounting change $ 1.27 $ 0.52 $ (5.21) $ 0.14 $ 0.64
Net earnings (loss) 1.04 0.52 (5.21) (0.26) 0.61
Diluted earnings (loss) per ordinary share:
Earnings (loss) before extraordinary item and
cumulative effect of accounting change $ 1.20 $ 0.52 $ (5.21) $ 0.14 $ 0.62
Net earnings (loss) 0.99 0.52 (5.21) (0.25) 0.59

BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment $ 687,511 $ 524,152 $ 470,907 $ 835,506 $ 676,833
Total assets 1,194,280 974,475 754,280 1,098,039 914,524
Long-term debt, including current maturities (1) 504,696 413,487 427,492 573,687 416,630
Shareholders' equity 525,016 463,052 223,807 296,620 300,644

CERTAIN OIL AND GAS DATA (2) :
Production
Sales volumes (Mbbls) (3) 11,167 12,469 9,979 5,776 5,987
Forward oil sale deliveries (Mbbls) 762 3,050 3,050 2,462 701
---------- --------- ---------- ---------- ---------
Total revenue barrels (Mbbls) 11,929 15,519 13,029 8,238 6,688
========== ========= ========== =========== ========

Gas (MMcf) 470 459 503 802 2,517
Average sales price
Oil (per Bbl) (4) $ 27.48 $ 15.95 $ 12.31 $ 17.54 $ 19.61
Gas (per Mcf) $ 1.34 $ 0.88 $ 0.99 $ 1.15 $ 1.69

_________________________

(1) Includes current maturities totaling $4.6 million for 2000, $9.0 million
for 1999, $14.0 million for 1998, $130.4 million for 1997 and $199.6 million for
1996.
(2) Information presented includes the 49.9% equity investment in Crusader
Limited until its sale in 1996.
(3) Includes natural gas liquids and condensate.
(4) Includes barrels delivered under the forward oil sale, which are recognized
in oil and gas sales at $11.56 per barrel upon delivery.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

You should read the following discussion and analysis in conjunction with
our financial information and our consolidated financial statements and notes to
those statements included in this report. The following information contains
forward-looking statements. For a discussion of limitations inherent in
forward-looking statements, see "Disclosure Regarding Forward-Looking
Information" and "Certain Factors That Could Affect Future Operations" below.

LIQUIDITY AND CAPITAL REQUIREMENTS

Cash and equivalents totaled $136.4 million at December 31, 2000, and
$186.3 million at December 31, 1999. Working capital was $63.3 million at
December 31, 2000, and $161.3 million at December 31, 1999.

The following summary table reflects our cash flows for the years ended
December 31, 2000, 1999 and 1998 (in thousands):

2000 1999 1998
--------- --------- --------

Net cash provided (used) by operating activities $ 187,224 $ 116,522 $ 1,466
Net cash provided (used) by investing activities $(321,733) $(118,530) $ 84,191
Net cash provided (used) by financing activities $ 84,710 $ 170,143 $(80,071)

Net Cash Provided (Used) by Operating Activities
------------------------------------------------

Our production from the Cusiana and Cupiagua fields in Colombia was
responsible for all of our cash flows provided by operating activities in 2000.
Our cash flows benefited from a higher average realized oil price, but this
benefit was partially offset by a decrease in production in 2000 compared with
1999. Our average realized oil price per barrel was $27.48 in 2000, compared
with $15.95 in 1999 and $12.31 in 1998. Gross production from the Cusiana and
Cupiagua fields averaged 339,000 barrels of oil per day ("BOPD") (32,500 net to
our interest) during 2000, 430,000 BOPD (41,300 net to our interest) during 1999
and 350,000 BOPD (33,600 net to our interest) during 1998. See "Results of
Operations - Oil and Gas Sales" below.

Cash flows from operating activities in 2000 relative to 1999 also
benefited from the expiration of our crude oil delivery requirement under a
forward oil sale we entered into in 1995. In May 1995, we sold oil forward to a
third party for a lump sum payment, which required us to deliver to the
purchaser a fixed amount of production each month until the contract's
expiration in March 2000. We recognized as revenue $11.56 per barrel delivered
under the forward oil sale. We completed the deliveries at the end of the first
quarter of 2000, at which time we were delivering 254,136 barrels per month.
Because of the expiration of the forward oil sale, during the second, third and
fourth quarters of 2000, we were able to sell all of our production at the
higher market price, although we did hedge the price of some of our production.
During 1999, we received substantially all of the remaining proceeds,
approximately $31.9 million, from this forward oil sale.

For 2001, our cash flows from operating activities will benefit from the
sale of Ceiba field production in Equatorial Guinea. Production from the
Ceiba field began in November 2000, but the first sale did not occur until
January 2001. We expect gross production from the Ceiba field to average
approximately 37,000 BOPD to 43,000 BOPD (26,000 to 30,000 net to us)
during 2001. Based on a production forecast from the operator of the
Cusiana and Cupiagua fields in Colombia, we are estimating that average gross
production from these fields will be approximately 270,000 BOPD to 280,000
BOPD (26,000 to 27,000 net to us) in 2001. Our actual production rates in 2001
will depend on a number of factors and are subject to a number of
uncertainties, and thus we cannot assure you that actual production rates
will meet our expectations.

Prices for our production in Colombia historically are based off of West
Texas Intermediate ("WTI") prices. With regard to sales of our Ceiba production,
through March 2001 there were only three sales, and they have been based off of
the price of Dated Brent, adjusted for quality and location. The differential on
our most recent sale was negative $4.60 per barrel. We believe that the
discounts to date reflect the fact that, for operational reasons, we have
limited sales to relatively smaller cargo vessels capable of loading quantities
of 1,000,000 barrels or less. In addition, the Ceiba crude is a relatively new
crude oil previously unknown to refiners, with an acid quality that certain
refiners will not readily be able to process, which could discourage refiners
from purchasing the crude without a price discount. We believe that, as our
operational efficiency improves to permit us to market the crude to larger
vessels, and therefore to a greater number of refiners, the price of Ceiba crude
in relation to applicable benchmarks should improve. We cannot assure you that
this price differential will improve or if it does, that it will improve by a
material amount.

Net Cash Provided (Used) by Investing Activities
------------------------------------------------------

Our capital expenditures and other capital investments, excluding
acquisitions, were $232.7 million in 2000, $121.5 million in 1999 and $180.2
million in 1998. Capital expenditures in 2000 were primarily for development of
the Ceiba field and exploration activities in Equatorial Guinea ($157.4 million)
and for development of the Cusiana and Cupiagua fields in Colombia ($41.5
million). Restructuring activities undertaken in 1998 contributed to lower
capital spending in 1999. Proceeds from asset sales were $2.4 million during
1999 and $267 million during 1998. See "Results of Operations" below and note 2
of Notes to Consolidated Financial Statements.

In May 2000, we acquired from an unrelated third party, for $88.7 million
in cash 100% of the shares of Triton Pipeline Colombia, Inc., whose sole asset
is its 9.6% equity interest in Oleoducto Central S.A. ("OCENSA"). OCENSA is the
Colombian pipeline company formed in 1994 by Empresa Colombiana De Petroleos
("Ecopetrol"), the Colombian national oil company, BP Amoco p.l.c. ("BP"),
TotalFinaElf SA ("TOTAL"), Triton Pipeline Colombia, IPL Enterprises (Colombia)
Inc. and TCPL International Investments Inc. to own and operate the pipeline and
port facilities that handle and transport crude oil from the Cusiana and
Cupiagua fields to the Caribbean port of Covenas. We had sold Triton Pipeline
Colombia in February 1998.

Net Cash Provided (Used) by Financing Activities
------------------------------------------------------

In February 2000, we entered into an unsecured two-year revolving credit
facility with a group of banks, which matures in February 2002. The credit
facility gives us the right to borrow from time to time up to the amount of the
borrowing base determined by the banks, not to exceed $150 million. As a result
of the issuance of the 8 7/8% Senior Notes and the redemption of the 8 3/4%
Senior Notes, the borrowing base was adjusted to $50 million, subject to any
future redetermination of the borrowing base as provided in the agreement. The
credit facility contains various restrictive covenants, including covenants that
require us to maintain a ratio of earnings before interest, depreciation,
depletion, amortization and income taxes to net interest expense of at least 2.5
to 1 on a trailing-four-quarters basis. The restrictive covenants also prohibit
us from permitting net debt to exceed the product of 3.75 times our earnings
before interest, depreciation, depletion, amortization and income taxes on a
trailing-four-quarters basis. As of March 6, 2001, we had no borrowings
outstanding under the facility.

In October 2000, we issued $300 million face value of 8 7/8% Senior Notes
due 2007 for proceeds of $300 million before deducting transaction costs of
approximately $6 million. Interest is payable semiannually on April 1 and
October 1, commencing April 1, 2001. We have the option to redeem the 8 7/8%
Senior Notes, in whole or in part, at any time on or after October 1, 2004. In
addition, we can redeem up to $105 million of the 8 7/8% Senior Notes using
proceeds of any equity offerings we may complete before October 1, 2003. The
indenture governing the 8 7/8% Senior Notes contains various restrictive
covenants that limit our ability to borrow money or guarantee other debt, create
liens, make investments, use assets as security in other transactions, pay
dividends on stock, enter into sale/leaseback transactions, sell assets, and
merge or consolidate. The indenture provides that we may not incur additional
debt unless at the time of the incurrence the ratio of our consolidated earnings
before interest, income taxes, depreciation, depletion, amortization and
writedowns to the sum of interest expense and capitalized interest is at least
2.5 to 1. Notwithstanding this limit, the indenture does permit us to incur
certain indebtedness even if we do not meet this limitation. For example, we can
incur indebtedness to financial institutions, such as our unsecured revolving
credit facility described above, in an amount up to $250 million or the amount
obtained by adding $100 million to 20% of our adjusted net tangible assets,
whichever is greater.

In September 2000, we called for redemption all of our outstanding 5%
Convertible Preference Shares. Each 5% Convertible Preference Share was
convertible into one ordinary share. A total of 107,075 shares were converted
into ordinary shares, and the remaining 78,201 shares were redeemed for cash at
the redemption price of $34.56 per share totaling $2.7 million. The redemption
price represented the stated value of $34.41 plus the amount of dividends that
accrued per share from September 30, 2000, through the redemption date of
October 31, 2000.

During 2000, we repaid borrowings of $9 million under a term credit
facility and paid cash preference-share dividends totaling $14.9 million.
Proceeds from issuances of ordinary shares under our stock compensation plans
totaled $26.5 million for 2000.

During 1999, we repaid borrowings totaling $19 million, including $10
million under unsecured credit facilities that were outstanding at December 31,
1998. By December 31, 1999, all of our unsecured revolving credit facilities
that were outstanding at December 31, 1998, had expired. In addition, we paid
cash preference-share dividends totaling $17.6 million and a dividend in
additional 8% Convertible Preference Shares totaling $13.7 million.

In April 1999, our Board of Directors authorized a share repurchase program
enabling us to repurchase up to 10% of our then-outstanding 36.7 million
ordinary shares. We purchased 948,300 ordinary shares in 1999 under this program
for $11.3 million. Because of our capital needs in Equatorial Guinea, we did not
repurchase any shares under the program in 2000. In addition, our revolving
credit facility, entered into in February 2000, generally does not permit us to
repurchase our ordinary shares without the banks' consent.

In two stages, in late 1998 and early 1999, we issued $350 million of 8%
Convertible Preference Shares. At the closing of the first stage in September
1998, we issued 1,822,500 shares of 8% Convertible Preference Shares for $70 per
share (for proceeds of $116.8 million, net of transaction costs), all of which
were purchased by HM4 Triton, L.P. At the closing of the second stage in January
1999, which was effected through a rights offering, we issued an additional
3,177,500 8% Convertible Preference Shares for proceeds totaling $217.8 million,
net of closing costs, of which HM4 Triton L.P. purchased 3,114,863 shares. Each
8% Convertible Preference Share is convertible into four ordinary shares,
subject to adjustment upon the occurrence of specified events.

During 1998, we borrowed $162.5 million and repaid $360.1 million under
revolving lines of credit, notes payable and long-term debt. We terminated a
$125 million revolving credit facility during 1998 upon the repayment of the
amounts then outstanding.

Future Capital Needs
----------------------

Our capital spending program for the year ending December 31, 2001, is
approximately $320 million, excluding capitalized interest and acquisitions, of
which approximately $253 million relates to exploration and development
activities in Equatorial Guinea, $39 million relates to exploration and
development activities in Colombia and $28 million relates to our exploration
activities in other parts of the world.

In Equatorial Guinea, during 2000, we successfully implemented an
accelerated appraisal and development program for the Ceiba field, drilling the
Ceiba-3, -4 and -5 subsea production wells. We commenced production in November
2000, achieved production from three wells by the end of 2000, and, in February
2001, we completed and commenced production from the fourth production well. The
wells are connected through flowlines to a floating production, storage and
offloading vessel ("FPSO") that we lease. Based on our development plan and
production history to date, we expect gross production from the Ceiba field to
average approximately 37,000 BOPD to 43,000 BOPD (26,000 to 30,000 net to us)
during 2001. We cannot assure you that actual production rates from this field
will meet our expectations. Actual production rates will depend on well and
reservoir performance, our ability to improve pressure support through water
injection and other factors.

The current plan for development calls for a total of 10 production wells
and four water injection wells, including the production wells that already have
been drilled. Our plan is to have the water injection wells and at least seven
production wells drilled and completed in 2001, and the remaining production
wells drilled and completed in 2002. In connection with the next phase of
development, we are planning to increase the processing capacity of the FPSO
from 60,000 barrels of fluids per day to approximately 160,000 barrels of fluids
per day and to install onboard water-injection facilities to inject up to
135,000 barrels per day of water. We expect that the additional wells and
production and water-injection facilities will enable us to increase production
in 2002. We are uncertain as to what the production rate will be in this latter
phase of development. The actual production rate will depend on a number of
factors, including the timing of the completion of the additional production and
water-injection facilities, well performance, the timing of the connection of
the production and water injection wells to the FPSO, reservoir performance, our
ability to improve pressure support through water injection and other factors.
In order to install the necessary equipment to increase the processing capacity
of the facilities, we expect that we will be required to temporarily halt
production from the Ceiba field. Currently, we expect that this production halt
will begin in December 2001 and will last approximately four weeks.

We expect to fund 2001 capital spending with a combination of some or all
of the following: cash flow from operations, cash, our unsecured revolving bank
credit facility, and the issuance of debt or equity securities. To facilitate a
possible future securities issuance or issuances, we have on file with the
Securities and Exchange Commission a shelf registration statement under which we
could issue up to an aggregate of $250 million debt or equity securities.

At December 31, 2000, we had guaranteed the performance of a total of $7.3
million in future exploration expenditures to be incurred through 2001 in
Greece. This commitment is backed primarily by an unsecured letter of credit
In addition, at December 31, 2000, we were committed to make lease payments,
including under the FPSO charter, totaling $31.4 million in 2001 and $28.9
million in 2002.

RESULTS OF OPERATIONS

During the three-year period ended December 31, 2000, all of our oil and
gas sales were derived from our operations in Colombia, as follows:

YEAR ENDED DECEMBER 31,
-------------------------
2000 1999 1998
------- ------- -------
Sales volumes:
Oil (Mbbls), excluding forward oil sale 11,167 12,469 9,979
Forward oil sale (Mbbls delivered) 762 3,050 3,050
------- ------- -------

Total 11,929 15,519 13,029
======= ======= =======

Gas (MMcf) 470 459 503

Weighted average price realized:
Oil (per Bbl)(1) $ 27.48 $ 15.95 $ 12.31
Gas (per Mcf) $ 1.34 $ 0.88 $ 0.99

__________________________

(1) Includes the effect of barrels delivered under the forward oil
sale, if applicable, that were recognized at $11.56 per barrel.

2000 COMPARED WITH 1999

Oil and Gas Sales
--------------------

Oil and gas sales for 2000 totaled $328.5 million, a 33% increase from
1999. The average realized oil price increased $11.53 per barrel, or 72%,
resulting in an increase in revenues of $137.6 million, compared with 1999. This
increase was partially offset by lower production in Colombia. Sales volumes,
including barrels delivered under the forward oil sale, decreased 23% in 2000,
compared with the prior year, resulting in a revenue decrease of $57.2 million.
Gross production from the Cusiana and Cupiagua fields averaged 339,000 BOPD
(32,500 net to us) for 2000, compared with 430,000 BOPD (41,300 net to us) for
the prior year. Although the fields are maturing and are in decline, the rate of
decline in 2000 was greater than the operator, we and our engineers had
expected. This greater rate of decline was primarily due to factors such as
mechanical difficulties in some producing wells, scale buildup in some producing
wells, which inhibits oil production and requires chemical treatment, a decrease
in workovers, delayed drilling of new wells and the disappointing performance of
some of the new wells that were drilled. The operator has devised a plan to
enhance reservoir management by implementing a more aggressive well-maintenance
and workover program. Based on this plan we are estimating that average gross
production from the fields will be approximately 270,000 BOPD to 280,000 BOPD
(26,000 to 27,000 net to us) in 2001. We cannot assure you that these attempts
to offset the decline in production will be successful or that the Colombian
fields will not continue to experience significantly less production than the
operator, we and our engineers project.

Production from the Ceiba field began in November 2000. We achieved our
first tanker loading, or lifting, of Ceiba crude in January 2001. We expect
2001 revenues will increase as a result of production from the Ceiba field, with
gross production expected to average approximately 37,000 BOPD to 43,000 BOPD
(26,000 to 30,000 net to us) during 2001. We cannot assure you that actual
production rates from this field will meet our expectations.

We adopted Securities and Exchange Commission Staff Accounting Bulletin
(SAB) 101, Revenue Recognition in Financial Statements, effective January 1,
2000, which requires us to record oil revenue on each sale, or tanker lifting,
and our oil inventories at cost, rather than at market value as in the past.
Sales of our crude oil in both Colombia and Equatorial Guinea are made when the
crude oil is "lifted," or transferred to the buyer's tanker. The number of
liftings occurring on a quarter-to-quarter basis may fluctuate based upon tanker
availability and lifting schedules. In addition, while we will be marketing our
crude oil in Equatorial Guinea collectively with that of our partner, currently
the government expects to market its crude oil separately on a periodic basis as
its share of production accumulates to a marketable quantity. As a result, we
expect that our revenues on a quarter-to-quarter basis will be subject to
variation depending on the timing of liftings of our production. In addition,
our 2001 revenues will be subject to fluctuations in the market price for oil,
as well as the discounts for quality and transportation discussed above and in
"Items 1. and 2. Business and Properties - Oil and Gas Operations - Markets."

We have entered into financial and commodity market transactions intended
primarily to reduce risk associated with changing oil prices. Our oil sales were
approximately $17.6 million less in 2000 and approximately $19.8 million less in
1999 than if we had not entered into those transactions. Looking forward, we
have hedged the WTI and Dated Brent price components on a portion of our 2001
production. See "Item 7.A. Quantitative and Qualitative Disclosures About
Market Risk" below.

Operating Expenses
-------------------

Operating expenses totaled $55.2 million in 2000, compared with $68.1
million in 1999. On an oil-equivalent barrel basis, operating expenses were
$4.64 in 2000 and $4.50 in 1999. The decrease in operating expenses during 2000
was primarily due to lower pipeline tariffs in Colombia. One component of
operating expenses is the tariff OCENSA charges us to transport our oil through
its pipeline in Colombia. OCENSA pipeline tariffs totaled $29.6 million in 2000
and $42.1 million in 1999. After we acquired Triton Pipeline Colombia in 2000,
we elected to cancel the dividend we would receive as an owner of OCENSA shares
to reduce our tariff. The tariff OCENSA charges us, as well as the other owners
of OCENSA, is the amount OCENSA estimates it needs to recoup the total capital
cost of the project, amortized over a 15-year period; its operating expenses for
the year, which include all Colombian taxes; its interest expense; and the
dividend it must pay to any shareholder who has elected to receive a dividend.
OCENSA charges other shippers of crude oil a tariff on a per-barrel basis, and
OCENSA uses the revenues from those tariffs to reduce the tariff it charges us
and its other shareholders.

Depreciation, Depletion and Amortization
-------------------------------------------

Depreciation, depletion and amortization decreased $6.3 million, primarily
due to lower production volumes, which was partially offset by a higher
depletion rate per barrel. Depletion per equivalent barrel of production was
$4.37 in 2000 compared with $3.80 in 1999 as calculated using the
unit-of-production method. We expect operating expenses and depreciation,
depletion and amortization expense will increase in 2001 as a result of
production from the Ceiba field in Equatorial Guinea, which began November 2000.

General and Administrative Expenses
--------------------------------------

General and administrative expenses before capitalization increased $4.6
million to $35.2 million in 2000, primarily due to increased activities
associated with the development of the Ceiba field. Capitalized general and
administrative costs were $11.1 million in 2000 and $6.9 million in 1999.

Writedown of Assets
---------------------

Following the acquisition of new acreage, reviews of our capital
expenditure requirements and exploration portfolio during 2000, and other
information management deemed relevant, we recorded a writedown of $36.7 million
($34.8 million after-tax) related to our operations onshore Italy, offshore
Madagascar and offshore Greece. We also surrendered our interest in the
Aitoloakarnania lease onshore Greece after drilling two dry holes and recorded a
writedown of $18.7 million ($17.2 million after-tax) during 2000.

Interest Expense, Net
-----------------------

Gross interest expense totaled $41 million for 2000 and $37.2 million for
1999, while capitalized interest for 2000 increased $9.6 million to $24.1
million. We expect that gross interest expense will increase in future periods
as a result of higher outstanding debt balances following the issuance of the
8 7/8% Senior Notes due 2007. We expect that the amount of gross interest
expense that is capitalized will decrease in 2001, as capitalized oil and
gas assets from the Ceiba field in Equatorial Guinea are placed in
service.

Income Taxes
-------------

Statement of Financial Accounting Standards No. 109 ("SFAS 109"),
"Accounting for Income Taxes," requires that we make projections about the
timing and scope of certain future business transactions in order to estimate
recoverability of deferred tax assets primarily resulting from the expected
utilization of net operating loss carryforwards ("NOLs"). Changes in the timing
or nature of actual or anticipated business transactions, projections and income
tax laws can give rise to significant adjustments to our deferred tax expense or
benefit that may be reported from time to time. For these and other reasons,
compliance with SFAS 109 may result in significant differences between tax
expense for income statement purposes and taxes actually paid.

Current taxes increased to $39.9 million in 2000 from $20.8 million in 1999
due to higher pretax income from Colombian operations. The income tax provisions
included deferred tax expense of $21.2 million for 2000 and $7.8 million for
1999. During 2000, our tax expense was approximately $21 million lower due to
anticipated utilization of NOLs from entities that were acquired during 1999 and
2000.

At December 31, 2000, we had U.S. NOLs of approximately $383 million,
compared with NOLs of approximately $450.2 million at December 31, 1999. The
NOLs expire from 2001 to 2021. See note 7 of Notes to Consolidated Financial
Statements. At December 31, 2000, we had NOLs in Equatorial Guinea totaling $176
million with an unlimited carryforward. In other countries outside the U.S., we
had NOLs and other credit carryforwards totaling $30.1 million that will expire
between 2001 and 2010.

We recorded a U.S. deferred tax asset of $89 million, net of a valuation
allowance of $48.7 million, at December 31, 2000. The valuation allowance was
primarily attributable to our assessment of the utilization of NOLs in the U.S.,
the expectation that other tax credits will expire without being utilized, and
the expectation that certain temporary differences will reverse without a
benefit to us. The minimum amount of future taxable income necessary to realize
the U.S. net deferred tax asset is approximately $254 million. Although we
cannot assure you that we will achieve these levels of income, we believe the
deferred tax asset will be realized through income from our operations or asset
sales.

Extraordinary Item - Extinguishment of Debt
------------------------------------------------

In November 2000, we used approximately $207 million of the net proceeds
from the sale of the 8 7/8% Senior Notes to redeem all of our outstanding 8 3/4%
Senior Notes due 2002 at a price, including accrued interest, of $1,038.40 for
each $1,000 note outstanding. The extinguishment of the 8 3/4% Senior Notes due
2002 resulted in an extraordinary expense of approximately $7 million.

Cumulative Effect of Accounting Change
------------------------------------------

1999 COMPARED WITH 1998

Oil and Gas Sales
--------------------

Oil and gas sales in 1999 totaled $247.9 million, a 54% increase from 1998,
due to higher average realized oil prices and higher production. The average
realized oil price per barrel was $15.95 in 1999 and $12.31 in 1998, an increase
of 30%, resulting in higher revenues of $56.4 million compared with 1998. Total
revenue barrels, including production related to barrels delivered under the
forward oil sale, totaled 15.5 million barrels in 1999, an increase of 19%,
compared with the prior year, resulting in an increase in revenues of $30.7
million. The increased production was due primarily to the start-up during the
second half of 1998 of two new 100,000 BOPD oil-production units at the Cupiagua
central processing facility.

We entered into financial and commodity market transactions intended
primarily to reduce risk associated with changing oil prices for our production
in 1999. During 1999, our oil sales were approximately $19.8 million less than
if we had not entered into those transactions.

Gain on Sale of Oil and Gas Assets
-----------------------------------------

In August 1998, we sold to a subsidiary of BP (formerly The Atlantic
Richfield Company, or ARCO) for $150 million, one-half of the shares of the
subsidiary through which we owned our 50% share of Block A-18 in the
Malaysia-Thailand Joint Development Area. The sale resulted in a gain of $63.2
million. In December 1998, we sold our Bangladesh subsidiary for $4.5 million
and recorded a gain of the same amount.

Operating Expenses
-------------------

Operating expenses decreased $5.4 million in 1999. On an oil
equivalent-barrel basis, operating expenses were $4.50 in 1999 and $5.97 in
1998. We paid lifting costs, production taxes and transportation costs to the
Colombian port of Covenas for barrels to be delivered under the forward oil
sale. Operating expenses on an oil equivalent-barrel basis were lower primarily
due to higher production volumes. OCENSA pipeline tariffs totaled $42.1 million
in 1999 and $49.9 million in 1998. Pipeline tariffs for 1999 were lower
primarily due to a nonrecurring credit issued by OCENSA in February 2000
totaling $4.2 million. The credit resulted from OCENSA's compliance with a
Colombian government decree in December 1999 that reduced its 1999 noncash
expenses.

Depreciation, Depletion and Amortization
-------------------------------------------

Depreciation, depletion and amortization increased $2.5 million, primarily
due to higher production volumes, including barrels delivered under the forward
oil sale. Offsetting the effect of higher production, full cost ceiling test
writedowns taken during 1998 reduced the per barrel depletion rate in 1999.

General and Administrative Expenses
--------------------------------------

General and administrative expenses before capitalization decreased $16.6
million from $47.2 million in 1998 to $30.6 million in 1999, while capitalized
general and administrative costs were $6.9 million in 1999 and $20.6 million in
1998. General and administrative expenses, and the portion capitalized,
decreased as a result of restructuring activities undertaken during the second
half of 1998 and in March 1999.

Writedown of Assets
---------------------

We wrote down the carrying amount of our evaluated oil and gas properties
in Colombia by $105.4 million ($68.5 million, net of tax) in June 1998 and
$135.6 million ($115.9 million, net of tax) in December 1998, through
application of the full cost ceiling limitation as prescribed by the Securities
and Exchange Commission, principally as a result of a decline in oil prices. To
calculate the limitation, at June 30, 1998, we used the WTI oil price of $14.18
per barrel, or approximately $13 per barrel after taking into account the
differential for Cusiana crude delivered at the port of Covenas in Colombia, and
at December 31, 1998, we used the WTI oil price of $12.05 per barrel, or
approximately $11 per barrel after taking into account the differential.

During 1998, we evaluated the recoverability of our approximate 6.6%
investment in a Colombian pipeline company, Oleoducto de Colombia S.A. ("ODC"),
which was accounted for under the cost method. Based on an analysis of the
future cash flows expected to be received from ODC, we expensed the carrying
value of our investment totaling $10.3 million.

In July 1998, we commenced a plan to restructure our operations, reduce
overhead costs and substantially scale back exploration-related expenditures.
The plan contemplated the closing of foreign offices in four countries, the
elimination of approximately 105 positions, or 41% of the worldwide workforce,
and the relinquishment or other disposal of several exploration licenses.

In conjunction with the plan to restructure operations and scale back
exploration-related expenditures in 1998, we assessed our investments in
exploration licenses and determined that certain investments were impaired. As a
result, unevaluated oil and gas properties and other assets totaling $77.3
million ($72.6 million, net of tax) were expensed. The writedown included
exploration-related activities totaling $27.2 million in Guatemala and $22.5
million in China. The remaining writedowns related to our exploration projects
in certain other areas of the world.

Special Charges
----------------

As a result of the restructuring, we recognized special charges of $15
million during the third quarter of 1998 and $3.3 million during the fourth
quarter of 1998 for a total of $18.3 million. Of the $18.3 million in special
charges, $14.5 million related to the reduction in workforce, and represented
the estimated costs for severance, benefit continuation and outplacement costs,
which were paid over a period of up to two years according to the severance
formula. From July 1998 through December 31, 1999, we paid $13.1 million in
severance, benefit continuation and outplacement costs. A total of $2.1 million
of special charges related to the closing of foreign offices, and represented
the estimated costs of terminating office leases and the write-off of related
assets. The remaining special charges of $1.7 million primarily related to the
write-off of other surplus fixed assets resulting from the reduction in
workforce. At December 31, 1999, all of the positions had been eliminated, all
designated foreign offices had been closed and all licenses had been
relinquished or sold, or their commitments renegotiated. During the fourth
quarter of 1999, we reversed $.7 million of the accrual associated with the
substantial completion of restructuring activities.

In March 1999, we accrued special charges of $1.2 million related to an
additional 15% reduction in the number of employees resulting from our
continuing efforts to reduce costs. The special charges consisted of $1 million
for severance, benefit continuation and outplacement costs and $.2 million
related to the write-off of surplus fixed assets. From March 1999 through
December 31, 1999, we paid $.9 million in severance, benefit continuation and
outplacement costs.

In September 1999, we recognized special charges totaling $2.4 million
related to the transfer of our working interest in Ecuador to a third party.

Gain on Sale of Triton Pipeline Colombia
----------------------------------------------

In February 1998, we sold Triton Pipeline Colombia to an unrelated third
party for $100 million. Net proceeds were approximately $97.7 million. The sale
resulted in a gain of $50.2 million.

Interest Expense, Net
-----------------------

Gross interest expense totaled $37.2 million for 1999 and $46.4 million for
1998, while capitalized interest for 1999 decreased $8.7 million to $14.5
million. The decrease in capitalized interest is due primarily to the writedown
of unevaluated oil and gas properties in June 1998 and a sale of 50% of our
Block A-18 project in August 1998.

Other Income (Expense), Net
------------------------------

Other income (expense), net, included a foreign exchange loss of $2.7
million in 1999 and a foreign exchange gain of $2.1 million in 1998. We recorded
gains of $6.2 million in 1999 and $.4 million in 1998, representing the changes
in the fair value of the call options we purchased in anticipation of the 1995
forward oil sale. In addition, we recorded an expense of $6.9 million in 1999
and $3.3 million in 1998 in other income (expense), net, related to the net
payments made under and the change in the fair value of the equity swap entered
into in conjunction with the sale of Triton Pipeline Colombia. We recorded loss
provisions of $2.3 million in 1999 and $.8 million in 1998 for certain legal
matters. In 1998, we recognized gains of $7.6 million on the sale of corporate
assets in addition to the ARCO and Triton Pipeline Colombia transactions.

RECENT ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board issued Statement No.
133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging
Activities." This Statement was amended in June 2000 by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities --
an Amendment of SFAS No. 133." The new statements establish accounting and
reporting standards for derivative instruments and for hedging activities. The
standards require us to recognize all derivatives as either assets or
liabilities in our balance sheet and measure those instruments at fair value.
The requisite accounting for changes in the fair value of a derivative will
depend on the intended use of the derivative and the resulting designation. We
have adopted the statements effective January 1, 2001, and thus the new
accounting and reporting standards will be reflected for the first time in our
financial statements for the first quarter of 2001.

For financial and commodity market transactions in which we are hedging the
variability of cash flows associated with our forecasted crude oil sales, the
effective portion of changes in the fair value of the derivative instrument will
be reported in comprehensive income in the period changes in fair value occur.
These gains and losses will be recognized in earnings in the periods in which
the related hedged sale of crude oil occurs. All changes in the value of
derivative instruments not designated as hedges and the ineffective portion of
changes in fair value of hedging transactions will be recognized in earnings in
the period changes in fair value occur.

In January 2001, we expect to record a net-of-tax cumulative effect
adjustment of $1.2 million gain to earnings and $2.9 million gain to
comprehensive income to recognize the fair value of all derivative instruments
as a result of adopting SFAS 133. We believe the recognition of unrecognized
gains and losses from the changes in fair value of all derivative instruments in
accordance with SFAS 133 will increase the volatility of our future results of
operations and shareholders equity. The amount of volatility will depend on
several factors, including the volume and type of derivative transactions we
enter into and the volatility of crude oil prices.

DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION

Some statements in this report and the documents we refer you to, as well
as written and oral statements made from time to time by us and our
representatives in other reports, filings with the Securities and Exchange
Commission, news releases, conferences, teleconferences, World Wide Web postings
or otherwise, may be deemed to be "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, Section 21E of the
Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act
of 1995. This information is subject to the "Safe Harbor" provisions of those
statutes. Forward-looking statements include statements concerning Triton's and
management's plans, objectives, expectations, goals, budgets, strategies and
future operations and performance and the assumptions underlying these
forward-looking statements. We use the words "anticipates," "estimates,"
"expects," "believes," "intends," "plans," "budgets," "may," "will," "should"
and similar expressions to identify forward-looking statements. These statements
include information regarding:

- drilling schedules;

- expected or planned production capacity;

- our interpretation of seismic data;

- future production from the Cusiana and Cupiagua fields in Colombia,
including the Recetor license;

- future production from the Ceiba field in Equatorial Guinea, including
volumes and future phases of development;

- our exploration, appraisal and development activities in Equatorial
Guinea;

- the completion of development and commencement of production offshore
Malaysia-Thailand and the realization of future incentive payments;

- our capital budget, future capital requirements and ability to meet our
future capital needs;

- commodity prices and future revenues, costs and expenses;

- our ability to realize our deferred tax asset;

- the level of future expenditures for environmental costs;

- the outcome of regulatory and litigation matters;

- the fair value of derivative instruments; and

- estimates of oil and gas reserves and discounted future net cash
flows from reserves.

We base these statements on our current expectations. These statements
involve a number of risks and uncertainties, including those described in the
context of the forward-looking statements, as well as those presented in
"Certain Factors That Could Affect Future Operations" below. Actual results and
developments could differ materially from those expressed in or implied by these
statements. We do not undertake to update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise.

CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS

Our business is subject to a number of risks and uncertainties, many of
which could affect whether our forward-looking statements become inaccurate.
These risks are summarized below.

CERTAIN FACTORS RELATING TO THE INTERNATIONAL OIL AND GAS INDUSTRY

Oil prices significantly impact our operating results.

Currently, we derive substantially all of our revenues and operating cash
flow from the sale of oil. In general, we sell our oil production at prices
based on the market price of oil on the date of sale, although from time to time
we may sell production in advance at contractually fixed prices, and we may
enter into hedging transactions. The market prices for oil and natural gas
historically have been volatile and are likely to continue to be volatile in the
future. Oil and natural gas prices may fluctuate in response to relatively minor
changes in the supply of and demand for oil and natural gas, market uncertainty
and a variety of additional factors that are beyond our control. It is
impossible to predict future oil and gas price movements with any certainty.
Decreases in oil and natural gas prices will adversely affect our revenues,
results of operations and cash flows.

Changes in the price of oil also may impact our results of operations as a
result of the potential impact on the value of derivatives we may have in place
from time to time. Changes in the price of oil may change the fair value of
derivatives we may enter into from time to time, and these changes may increase
or decrease our earnings from period to period. We adopted SFAS 133, as amended
by SFAS No. 138, effective January 1, 2001, which requires us to recognize all
derivatives as either assets or liabilities in our balance sheet and measure
those instruments at fair value. The requisite accounting for changes in the
fair value of a derivative will depend on the intended use of the derivative and
the resulting designation. For financial and commodity market transactions in
which we are hedging the variability of cash flows associated with our
forecasted crude oil sales, the effective portion of changes in the fair value
of the derivative instrument will be reported in comprehensive income in the
period changes in fair value occur. These gains and losses will be recognized in
earnings in the periods in which the related hedged sale of crude oil occurs.
All changes in the value of derivative instruments not designated as hedges and
the ineffective portion of changes in fair value of hedging transactions will be
recognized in earnings in the period changes in fair value occur.

Substantially all of our operations are conducted in foreign countries,
and we are subject to political, economic and other uncertainties.

We conduct substantially all of our exploration and production operations
and derive substantially all our revenues outside the United States in countries
including Colombia, Equatorial Guinea, Malaysia-Thailand, Gabon, Greece, Italy,
Madagascar and Oman. International operations, particularly in the oil and gas
business, are subject to political, economic and other uncertainties, which
include:

- the risk of expropriation, nationalization, war, revolution, border
disputes, renegotiation or modification of existing contracts, and import,
export and transportation regulations and tariffs;

- taxation policies, including royalty and tax increases and retroactive tax
claims;

- exchange controls, currency fluctuations and other uncertainties arising
out of foreign government sovereignty over our international operations;

- laws and policies of the United States affecting foreign trade, taxation
and investment; and

- the possibility of being subjected to the exclusive jurisdiction of
foreign courts in connection with legal disputes and the possible inability to
subject foreign persons to the jurisdiction of courts in the United States.

Operating risks normally associated with the exploration for and
production of oil and gas include blowouts and other operating
hazards, as well as environmental risks and other regulatory risks.

Our activities are subject to all of the operating hazards normally
associated with the exploration for and production of oil and gas, including
blowouts, explosions, uncontrollable flows of oil, gas or well fluids,
pollution, earthquakes, formations with abnormal pressures, labor disruptions
and fires, each of which could result in substantial losses due to injury or
loss of life and damage to or destruction of oil and gas wells, formations,
production facilities or other properties.

Our activities also are subject to environmental hazards, such as oil
spills, gas leaks and ruptures and discharges of toxic substances or gases.
These environmental hazards could expose us to material liabilities for property
damages, personal injuries or other environmental harm, including costs of
investigating and remediating contaminated properties.

We are subject to extensive environmental laws and regulations regarding
the discharge of oil, gas or other materials into the environment, which may
require us to remove or mitigate the environmental effects of the disposal or
release of such materials at various sites. In addition, we could be held liable
for environmental damages caused by previous owners of our properties or our
predecessors. We do not believe that our environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, we cannot assure you that environmental laws and regulations will
not, in the future, adversely affect our results of operations, cash flows or
financial position.

Our activities are also subject to laws, rules and regulations in the
countries where we operate, which generally pertain to production control,
taxation, environmental and pricing concerns, and other matters relating to the
petroleum industry. Many jurisdictions have at various times imposed limitations
on the production of natural gas and oil by restricting the rate of flow for oil
and natural gas wells below their actual capacity. We cannot assure you that
present or future regulation will not adversely affect our results of
operations, cash flows or financial position.

In accordance with customary industry practices, we maintain insurance
against some, but not all, of these risks and losses. Pollution and similar
environmental risks generally are not fully insurable. If an event occurs that
is not fully covered by insurance, it could result in a financial loss and
reduce our resources for capital expenditures. In addition, we cannot be sure
that insurance will continue to be available, or that insurance will continue to
be available at premium levels that justify its purchase.

Our drilling operations are subject to certain other risks that could
cause us to delay or cease the drilling of wells.

Numerous risks affect drilling activities, including the risk of drilling
nonproductive wells or dry holes. The cost of drilling, completing and operating
wells and of installing production facilities and pipelines is often uncertain.
Also, our drilling could be delayed or cease because of any of the following:

- title problems;

- weather conditions;

- noncompliance with or changes in governmental requirements or regulations;

- shortages or delays in the delivery or availability of equipment; and

- failure to obtain permits for operations in a timely manner.

Estimates of oil and gas reserves and future net revenues are based on
numerous assumptions and may be determined to be inaccurate.

Numerous uncertainties exist in estimating quantities of proved reserves
and future net revenues from those reserves. Estimates of proved reserves and
related future net revenues are based on various assumptions, which may be
determined to be inaccurate. Actual future production, oil and gas prices,
revenues, taxes, capital expenditures, operating expenses, geologic success and
quantities of recoverable oil and gas reserves may vary substantially from those
assumed in the estimates and could materially affect the estimated quantities
and future net revenues of our proved reserves. In addition, reserve estimates
may be subject to downward or upward revisions based on production performance,
purchases or sales of properties, results of future development, prevailing oil
and gas prices and other factors. Therefore, the estimated future net revenues
should not be construed as estimates of the current market value of our proved
reserves.

If we determine that exploration results on one or more properties
do not justify continuing to carry their capitalized costs, we may
write down the properties' carrying value and incur a charge to
earnings and a reduction in shareholders' equity.

We follow the full cost method of accounting for exploration and
development of oil and gas reserves. Under this method of accounting, all of our
costs related to acquisition, holding and initial exploration of licenses in
countries where we do not have any proved reserves are initially capitalized. We
then periodically make assessments of these licenses for impairment on a
country-by-country basis. Based on our evaluation of drilling results, seismic
data and other information we deem relevant, we may write down the carrying
value of the oil and gas licenses in a particular country. A writedown
constitutes a charge to earnings that does not impact our cash flow from
operating activities, but does reduce our shareholders' equity. For example, in
the fourth quarter of 2000, following the acquisition of new acreage, reviews of
our capital expenditure requirements and exploration portfolio and other
information management deemed relevant, we recorded a writedown of $36.7 million
($34.8 million after-tax) related to our operations onshore Italy, offshore
Madagascar and offshore Greece, and in the third quarter of 2000, we surrendered
our interest in the Aitoloakarnania lease onshore Greece after drilling two dry
holes and recorded a writedown of $18.7 million ($17.2 million after-tax), and
recorded corresponding reductions in shareholders' equity. In addition, in the
second quarter of 1998, we recorded a $77.3 million ($72.6 million, net of tax)
writedown of unevaluated oil and gas properties and other assets relating to our
operations in China, Ecuador, Guatemala and other countries, and a corresponding
reduction in shareholders' equity. Subject to the possible extension or
modification of our commitments, we expect to complete our contractual
obligations in Italy and Oman over the next 12 to 18 months. If, in the course
of our exploration activities in a particular country, we determine that
continuing to explore for hydrocarbons there is not justified, we may record a
writedown during that period for the cost pool related to that country. Due to
the unpredictable nature of exploration activities, we cannot predict the amount
and timing of impairment writedowns. Financial information concerning our assets
at December 31, 2000, including capitalized costs by geographic area, is in note
19 of Notes to Consolidated Financial Statements.

If oil and gas prices decrease below specified levels, we may write
down the carrying values of properties with proved reserves and
incur a charge to earnings and a reduction in shareholders' equity.

We also may be required to write down the carrying value of properties
where we have proved reserves as a result of the "full cost ceiling limitation"
prescribed by the Securities and Exchange Commission. Under the full cost
ceiling limitation, we must write down the carrying value of properties in any
country where we have proved reserves to the extent that the net capitalized
costs of the properties, less related deferred income taxes, exceeds the amount
given by the following formula:

(1) the estimated future net revenues from the properties, discounted at 10%;
plus

(2) unevaluated costs not being amortized; plus

(3) the lower of cost or estimated fair value of unproved properties being
amortized; minus

(4) income tax effects related to differences between the financial statement
basis and tax basis of oil and gas properties.

The discounted future net revenues from a property are determined based on
the selling price of oil or gas at the end of the accounting period, or when
results of operations for that period are determined. For example, as a result
of a decline in oil prices in 1998, we wrote down the carrying value of our
evaluated oil and gas properties in Colombia by $105.4 million ($68.5 million,
net of tax) in June 1998, and $135.6 million ($115.9 million, net of tax) in
December 1998, because of the full cost ceiling limitation.

CERTAIN FACTORS RELATING TO OUR ASSETS AND OPERATIONS

Guerrilla activity in Colombia could disrupt our operations.

We derive a substantial part of our revenues and operating cash flow from
our interest in the Cusiana and Cupiagua fields, located approximately 160
kilometers (100 miles) northeast of Bogota, Colombia. The operator of the fields
is BP. Pipelines connect the major producing fields in Colombia to export
facilities and refineries.

From time to time, guerrilla activity in Colombia has disrupted the
operation of oil and gas projects. The guerrilla activity has increased over the
last few years and appears to be increasing as political negotiations among
government and various rebel groups proceed. In addition, the government of the
United States has enacted a program to assist the government of Colombia in its
efforts to halt the flow of illegal drugs, which may intensify the guerrillas'
efforts to disrupt oil operations. Guerrilla activity has caused delays in the
development of the fields in Colombia and from time to time has slowed the
operator's ability to put workers in the field. For example, in one case, a bomb
planted near the pipeline caused OCENSA to halt shipments, which, in turn,
caused the operator of the fields to curtail production for approximately two
days. The partners in the fields, together with the Colombian government, have
taken steps to maintain security and favorable relations with the local
population, including hiring security to patrol the facilities, and providing
programs to local communities for health and educational assistance. We expect
these steps will be required throughout the term of our interest there. We
cannot assure you that these attempts to reduce or prevent guerrilla activity
will be successful or that guerrilla activity will not disrupt our operations
and cash flow in the future.

We have experienced greater than expected production declines
in Colombia.

Gross production from the Cusiana and Cupiagua fields averaged
approximately 430,000 BOPD during 1999 and approximately 339,000 BOPD during
2000. The declines in gross production rates have been greater than the
operator, we and our engineers had expected. The operator has devised a plan to
enhance reservoir management by implementing a more aggressive well-maintenance
and workover program. This includes underbalanced drilling in existing and new
wells, modifications to surface facilities, and a chemical treatment to
alleviate the scale problem and improve well production. Based on this plan, we
are estimating that average gross production from the fields will be
approximately 270,000 BOPD to 280,000 BOPD in 2001. We cannot assure you that
these attempts to offset the decline in production will be successful or that
the Colombian fields will not continue to experience significantly less
production than the operator, we and our engineers project. Because our
contracts in Colombia give us a limited time to produce the oil, if in the
future we determine that rates of production will be lower than we had
previously assumed in determining proved reserves, we may be required to reduce
the quantity of our proved reserves by an amount greater than production.

Our property in Equatorial Guinea is in the development stage, and we may
not be able to meet our targets for production levels, or for
increased levels of production in future phases of development.

We are a participant in a significant oil discovery, the Ceiba field,
located in Block G offshore the Republic of Equatorial Guinea. The current plan
for development calls for a total of 10 production wells and four water
injection wells, including the production wells that already have been drilled.
Based on our development plans and production history to date, we expect gross
production from the Ceiba field to average approximately 37,000 BOPD to 43,000
BOPD (26,000 to 30,000 net to us) during 2001. Actual production rates will
depend on well and reservoir performance, our ability to improve pressure
support through water injection and other factors. In connection with the next
phase of development, we are planning to increase the processing capacity of the
FPSO from 60,000 barrels of fluids per day to approximately 160,000 barrels of
fluids per day and to install onboard water-injection facilities to inject up to
135,000 barrels per day of water. We expect that the additional wells and
production and water injection facilities will enable us to increase production
in 2002. We are uncertain as to what the production rate will be in this latter
phase of development. The actual production rate will depend on a number of
factors, including the timing of the completion of the additional production and
water-injection facilities, well performance, the timing of the connection of
the production and water injection wells to the FPSO, reservoir performance, our
ability to improve pressure support through water injection and other factors.

Our development plans will require significant capital expenditures, the
drilling and completion of additional wells, the connection of the wells to the
FPSO and the installation of additional processing and water-injection
facilities. We are highly dependent on third-party contractors, including the
firm that owns and is maintaining and operating the FPSO vessel. Our ability to
meet our targets is subject to the timely drilling and completion of development
wells and the timely performance by the development contractors of their
commitments, and is subject to the risks associated with oil and gas operations
and international operations as discussed previously. We cannot assure you that
we will meet our targets. Any phases of production beyond the initial or
phase-one production level from the Ceiba field will depend on a successful
delineation and appraisal program, including interpretation of seismic data and
the drilling of successful appraisal wells.

Our growth in Equatorial Guinea is dependent on our ability to
discover additional oil or gas fields, and we have a limited time in
which to explore.

Under the terms of the production sharing contracts, we have the right to
continue to explore the remaining acreage on our Blocks F and G through April
2003. We can extend the exploration period of each contract for up to three
additional years if we agree to certain operational commitments for those
periods. If we do elect to extend the exploration period beyond April 2003, we
would be required to relinquish a portion of the contract area, provided that we
would not be required to surrender an area that includes a commercial field or a
discovery that has not then been declared commercial. We can designate the area
or areas to be surrendered, provided that, where possible, each area must be of
sufficient size and convenient shape to permit petroleum operations. We cannot
assure you that we will be successful in future exploration efforts on the
blocks.

Sales of gas from our property in Malaysia-Thailand could be delayed
by an environmental impact assessment, we may have to share some of
the costs of development with BP, and we may not receive incentive
payments from BP if delays occur.

We are a partner in a significant gas exploration project located in the
Gulf of Thailand approximately 450 kilometers (280 miles) northeast of Kuala
Lumpur and 750 kilometers (470 miles) south of Bangkok as a contractor under a
production sharing contract covering Block A-18 of the Malaysia-Thailand Joint
Development Area. In October 1999, we and the other parties to the production
sharing contract for Block A-18 executed a gas sales agreement providing for the
sale of the first phase of gas. Under terms of the gas sales agreement, delivery
of gas is scheduled to begin by the end of the second quarter of 2002, following
timely completion and approval of an environmental impact assessment associated
with the buyers' pipeline and processing facilities. The buyers may delay their
obligation to purchase the gas if they do not receive approval of the
environmental impact assessment for the pipeline and processing facilities they
plan to construct and if they satisfy other specified conditions precedent. A
lengthy approval process, or significant opposition to the project, as well as a
number of events unrelated to the environmental approval that are beyond our
control, could delay construction and the commencement of gas sales. We cannot
assure you that the buyers will receive approval of the environmental impact
assessment or, if they do receive approval, when that approval will occur. It is
possible that if the environmental impact assessment process does result in a
significant delay, the buyers could seek an alternate route for the delivery of
the gas. We cannot assure you as to when any such alternate route could be
completed or when gas sales could commence. Based on the delays to date in
obtaining the environmental approval, for internal planning purposes we are
assuming that production will begin no earlier than the fourth quarter of 2002.

In connection with the sale to BP of one-half of the shares through which
we owned our interest in Block A-18, BP agreed to pay the future exploration and
development costs attributable to our collective interest in Block A-18, up to
$377 million or until first production from a gas field, after which we and BP
would each pay 50% of such costs. We cannot assure you that our and BP's
collective share of the cost of developing the project through first production
will not exceed $377 million.

BP also agreed to pay us specified incentive payments if the requisite
criteria were met. The first $65 million in incentive payments is conditioned
upon having the production facilities for the sale of gas from Block A-18
completed by June 30, 2002. If the facilities are completed after June 30, 2002,
but before June 30, 2003, the incentive payment would be reduced to $40 million.
A lengthy environmental approval process, or delays in construction of the
facilities, could result in our receiving a reduced incentive payment or
possibly the complete loss of the first incentive payment. For purposes of
estimating our discounted net cash inflows from our proved reserves in Block
A-18, we have assumed that we would be entitled to a $40 million incentive
payment. In addition, we have agreed to share some of the costs of development
with BP in the event that the environmental approval process delays production
by agreeing to pay BP $1.25 million per month for each month, if applicable,
that first gas sales are delayed beyond 30 months following the award of an
engineering, procurement and construction contract for the project in March
2000. Our obligation is capped at 24 months of these payments, or $30 million.

INFLUENCE OF HICKS, MUSE, TATE & FURST INCORPORATED

In connection with the issuance of the 8% Convertible Preference Shares to
HM4 Triton, L.P., we entered into a shareholders agreement with HM4 Triton, L.P.
pursuant to which, among other things, HM4 Triton, L.P. was granted the right to
designate four out of 10 of the directors on our board. In addition, the
shareholders agreement provides that, for so long as HM4 Triton, L.P. and its
affiliates continue to hold at least a specified number of our shares, we may
not take certain actions without the consent of HM4 Triton, L.P., including
those described in "Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters - 8% Convertible Preference Shares." HM4 Triton, L.P. is a
limited partnership controlled by Hicks, Muse, Tate & Furst Incorporated, a
private investment firm specializing in acquisitions, recapitalizations and
other principal investing activities. Thomas O. Hicks, Triton's Chairman of the
Board, is the Chairman of the Board and Chief Executive Officer of Hicks, Muse,
Tate & Furst Incorporated. Jack D. Furst, a director of Triton, is a partner of
Hicks, Muse, Tate & Furst Incorporated.

As a result of HM4 Triton, L.P.'s ownership of 8% Convertible Preference
Shares and ordinary shares and the rights conferred upon HM4 Triton, L.P. and
its designees pursuant to the shareholders agreement, HM4 Triton, L.P. and
Hicks, Muse, Tate & Furst Incorporated have significant influence over our
business, policies and affairs. The interests of HM4 Triton, L.P. and Hicks,
Muse, Tate & Furst Incorporated may differ from those of our other shareholders,
and the influence they have may have the effect of discouraging selected
transactions involving an actual or potential change of control of Triton.

POSSIBLE FUTURE ACQUISITIONS

Our strategy includes the possible acquisition of additional reserves,
including through possible future business combination transactions. We cannot
assure you as to the terms upon which any such acquisitions would be consummated
or as to the effect any such transactions would have on our financial condition
or results of operations. An acquisition could involve the use of our cash, or
the issuance of debt or equity securities, which could have a dilutive effect on
our current shareholders.

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 we might
discover and the prices we might obtain for the oil and gas depend on many
factors beyond our 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.

ITEM 7. A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY RISK

Our oil sales are normally priced with reference to a defined benchmark,
such as WTI spot and Dated Brent. The price we actually receive will vary from
the benchmark depending on quality and location differentials. As a matter of
policy, from time to time we use financial market transactions with creditworthy
counterparties to reduce risk associated with the pricing of our oil sales. The
policy is structured to underpin our planned revenues and results of operations.
We cannot assure you that our use of financial market transactions will not
result in losses. We do not enter into financial market transactions for trading
purposes.

The markets for crude oil historically have been volatile and are likely to
continue to be volatile in the future. During the three-year period ended
December 31, 2000, WTI oil prices fluctuated between a low price of $10.72 per
barrel and a high price of $37.20 per barrel. During the year ended December 31,
1998, we did not have any outstanding financial market transactions to hedge
against oil price fluctuations. As a result of financial and commodity market
transactions settled during the years ended December 31, 2000 and 1999, our risk
management program resulted in an average net realization of approximately $1.59
per barrel in 2000 and $1.65 per barrel in 1999 lower than if we had not entered
into such transactions. Realized gains or losses from our price risk management
activities are recognized in oil and gas sales at the time of settlement of the
underlying hedged transaction.

As of March 1, 2001, we had entered into derivative contracts for 3.9
million barrels of 2001 production using WTI-based oil-price collars to
establish a weighted average floor price of $28.11 per barrel and a ceiling
price of $31.13 per barrel. We have also entered into contracts associated with
2001 production for 450,000 barrels using WTI-based oil-price swaps and 600,000
barrels using Dated Brent-based oil-price swaps to establish weighted average
fixed prices of $26.89 per barrel for WTI and $24.31 for Dated Brent. We used a
sensitivity analysis technique to evaluate the hypothetical effect that changes
in WTI oil prices may have on the fair value of these contracts. At December 31,
2000, the potential decrease in future earnings, assuming a 10% movement in WTI
oil prices, would not have a material adverse effect on our consolidated
financial position or results of operations.

INDEBTEDNESS OF THE COMPANY

We believe our interest rate exposure on debt is not significant since only
$4.5 million out of total debt of $504.7 million at December 31, 2000, has
floating interest rate obligations.

FOREIGN CURRENCY RISK

We derive substantially all of our revenues from international operations.
A risk inherent in international operations is the possibility of realizing
economic currency-exchange losses when transactions are completed in currencies
other than U.S. dollars. Our risk of realizing currency-exchange losses
currently is largely mitigated because we receive U.S. dollars for our oil
sales. With respect to expenditures denominated in currencies other than the
U.S. dollar, we generally convert U.S. dollars to the local currency near the
applicable payment dates to minimize exposure to losses caused by holding
foreign currency deposits. During the three-year period ended December 31, 2000,
we did not realize any material foreign exchange losses from our international
operations.

We have evaluated the potential effect that reasonably possible near-term
changes in foreign exchange rates may have on the fair value of our assets that
are denominated in a foreign currency. Based on our analysis utilizing the
actual foreign currency exchange rates at December 31, 2000, and assuming a 10%
adverse movement in exchange rates, the potential decrease in fair value of
foreign currency denominated assets does not have a material adverse effect on
our consolidated financial position or results of operations.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements required by this item begin at page F-1
hereof.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL
DISCLOSURE

Not applicable.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information relating to our directors and nominees for election as
directors is incorporated in this report by reference from the Proxy Statement
for our 2001 Annual Meeting of Shareholders, specifically the discussion under
the heading "Election of Directors." We expect that the 2001 proxy statement
will be publicly available and mailed in April 2001. Certain information
regarding our executive officers is included earlier in this report under Items
1 and 2, "Business and Properties - Executive Officers." The discussion under
"Section 16(a) Beneficial Ownership Reporting Compliance" in the 2001 proxy
statement is incorporated in this report by reference.

ITEM 11. EXECUTIVE COMPENSATION

The discussion under "Management Compensation" in the 2001 proxy statement
is incorporated in this report by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The discussion under "Security Ownership of Management and Certain
Shareholders" in the 2001 proxy statement is incorporated in this report by
reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The discussion under "Management Compensation - Compensation Committee
Interlocks and Insider Participation and Certain Transactions" in the 2001 proxy
statement is incorporated in this report by reference.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) The following documents are filed as part of this Annual Report on
Form 10-K:

1. Financial Statements: The financial statements filed as part of
this report are listed in the "Index to Financial Statements and Schedules" on
page F-1 hereof.

2. Financial Statement Schedules: The financial statement schedules
filed as part of this report are listed in the "Index to Financial Statements
and Schedules" on page F-1 hereof.

3. Exhibits required to be filed by Item 601 of Regulation S-K. (Where
the amount of securities authorized to be issued under any of Triton Energy
Limited's and any of its subsidiaries' long-term debt agreements does not exceed
10% of the Company's assets, pursuant to paragraph (b)(4) of Item 601 of
Regulation S-K, in lieu of filing such as exhibits, the Company hereby agrees to
furnish to the Commission upon request a copy of any agreement with respect to
such long-term debt.)

3.1 Memorandum of Association (previously filed as an exhibit to the Company's
Registration Statement on Form S-3 (No 333-08005) and incorporated herein by
reference)
3.2 Articles of Association (previously filed as an exhibit to the Company's
Registration Statement on Form S-3 (No 333-08005) and incorporated herein by
reference)
4.1 Specimen Share Certificate of Ordinary Shares, $.01 par value, of the Company
(previously filed as an exhibit to the Company's Registration Statement on Form 8-A
dated March 25, 1996, and incorporated herein by reference)
4.2 Unanimous Written Consent of the Board of Directors authorizing the Company's 8%
Convertible Preference Shares (previously filed as an exhibit to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and
incorporated herein by reference.)
4.3 Rights Agreement dated as of March 25, 1996, between Triton and The Chase
Manhattan Bank, as Rights Agent, including, as Exhibit A thereto, Resolutions
establishing the Junior Preference Shares (previously filed as an exhibit to the
Company's Registration Statement on Form S-3 (No 333-08005) and incorporated herein
by reference)
4.4 Amendment No. 1 to Rights Agreement dated as of August 2, 1996, between Triton
Energy Limited and The Chase Manhattan Bank, as Rights Agent (previously filed as an
exhibit to the Company's Registration Statement on Form 8-A/A (Amendment No. 1)
dated August 14, 1996, and incorporated herein by reference)
4.5 Amendment No. 2 to Rights Agreement dated as of August 30, 1998, between Triton
Energy Limited and The Chase Manhattan Bank, as Rights Agent (previously filed
as an exhibit to the Company's Registration Statement on Form 8-A/A (Amendment No.
2) dated October 2, 1998, and incorporated herein by reference)
4.6 Amendment No. 3 to Rights Agreement dated as of January 5, 1999, between Triton
Energy Limited and The Chase Manhattan Bank, as Rights Agent (previously filed
as an exhibit to the Company's Registration Statement on Form 8-A/A (Amendment No.
3) dated January 31, 1999, and incorporated herein by reference)
10.1 Amended and Restated Retirement Income Plan (previously filed as an exhibit
to Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended
November 30, 1993, and incorporated by reference) (1)
10.2 Amendment to the Retirement Income Plan dated August 1, 1998. (previously filed
as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1998, and incorporated herein by reference.) (1)
10.3 Amendment to Amended and Restated Retirement Income Plan dated
December 31, 1996 (previously filed as an exhibit to the Company's Quarterly Report
on Form 10-Q for the quarter ended March 31, 1998, and incorporated herein by
reference) (1)
10.4 Amended and Restated Supplemental Executive Retirement Income Plan. (previously
filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1997, and incorporated herein by reference.) (1)
10.5 Second Amended and Restated 1992 Stock Option Plan.(previously filed as an
exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March
31, 1996, and incorporated herein by reference.) (1)
10.6 Form of Amended and Restated Employment Agreement with Triton Energy Limited
and certain officers, including Messrs. Dunlevy, Garrett and Maxted, as amended and
restated June 28, 2000 (previously filed as an exhibit to the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30, 2000, and incorporated
herein by reference.) (1)
10.7 Amended and Restated Employment Agreement among Triton Energy Limited, Triton
Exploration Services, Inc. and A. E. Turner III (previously filed as an exhibit to T
Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
1998, and incorporated herein by reference.) (1)
10.8 Amended and Restated 1985 Restricted Stock Plan. (previously filed as an exhibit
to Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended
November 30, 1993, and incorporated herein by reference.) (1)
10.9 First Amendment to Amended and Restated 1985 Restricted Stock Plan. (previously
filed as an exhibit to Triton Energy Corporation's Annual Report on Form 10-K for the
fiscal year ended December 31, 1995, and incorporated herein by reference.) (1)
10.10 Second Amendment to Amended and Restated 1985 Restricted Stock Plan. (previously
filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1996, and incorporated herein by reference.) (1)
10.11 Executive Life Insurance Plan. (previously filed as an exhibit to Triton Energy
Corporation's Annual Report on Form 10-K for the fiscal year ended May 31, 1991,
and incorporated herein by reference.) (1)
10.12 Long-Term Disability Income Plan. (previously filed as an exhibit to Triton Energy
Corporation's Annual Report on Form 10-K for the fiscal year ended May 31, 1991,
and incorporated herein by reference.) (1)
10.13 Amended and Restated Retirement Plan for Directors. (previously filed as an exhibit
to Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended
May 31, 1990, and incorporated herein by reference.) (1)
10.14 Contract for Exploration and Exploitation for Santiago de Atalayas I with an effective
date of July 1, 1982, between Triton Colombia, Inc., and Empresa Colombiana
De Petroleos. (previously filed as an exhibit to Triton Energy Corporation's Annual
Report on Form 10-K for the fiscal year ended May 31, 1990, and incorporated
herein by reference.)
10.15 Contract for Exploration and Exploitation for Tauramena with an effective date of July
4, 1988, between Triton Colombia, Inc., and Empresa Colombiana De Petroleos.
(previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended May 31, 1990, and incorporated herein by reference.)
10.16 Summary of Assignment legalized by Public Instrument No. 1255 dated September 15,
1987 (Assignment is in Spanish language). (previously filed as an exhibit to Triton
Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31,
1993, and incorporated herein by reference.)
10.17 Summary of Assignment legalized by Public Instrument No. 1602 dated June 11, 1990
(Assignment is in Spanish language). (previously filed as an exhibit to Triton
Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31,
1993, and incorporated herein by reference.)
10.18 Summary of Assignment legalized by Public Instrument No. 2586 dated September 9,
1992 (Assignment is in Spanish language). (previously filed as an exhibit to Triton
Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31,
1993, and incorporated herein by reference.)
10.19 Triton Exploration Services, Inc. 401(K) Savings Plan, as amended and restated
June 1, 2000. (previously filed as an exhibit to the Company's Quarterly Report
on Form 10-Q for the quarter ended June 30, 2000, and incorporated herein by
reference.) (1)
10.20 Contract between Malaysia-Thailand Joint Authority and Petronas Carigali
SDN.BHD. and Triton Oil Company of Thailand relating to Exploration and Production
of Petroleum for Malaysia-Thailand Joint Development Area Block A-18. (previously
filed as an exhibit to Triton Energy Corporation's Current Report on Form 8-K dated
April 21, 1994, and incorporated herein by reference.)
10.21 Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation,
NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States
(previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
10-K for the fiscal year ended December 31, 1995, and incorporated herein by
reference.)
10.22 Amendment No. 1 to Credit Agreement among Triton Colombia, Inc., Triton Energy
Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
States. (previously filed as an exhibit to Triton Energy Corporation's Annual Report
on Form 10-K for the fiscal year ended December 31, 1995, and incorporated herein
by reference.)
10.23 Amendment No. 2 to Credit Agreement among Triton Colombia, Inc., Triton Energy
Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
States. (previously filed as an exhibit to the Company's Quarterly Report on Form
10-Q for the quarter ended March 31, 1996, and incorporated herein by reference)
10.24 Amendment No. 3 to Credit Agreement among Triton Colombia, Inc., Triton Energy
Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
States. (previously filed as an exhibit to the Company's Quarterly Report on Form
10-Q for the quarter ended March 31, 1998, and incorporated herein by reference)
10.25 Form of Indemnity Agreement entered into with each director and officer of the
Company. (previously filed as an exhibit to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1998, and incorporated herein by reference)
10.26 Description of Performance Goals for Executive Bonus Compensation. (previously
filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1996, and incorporated herein by reference) (1)
10.27 Amended and Restated 1997 Share Compensation Plan. (previously filed as an
exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1998, and incorporated herein by reference) (1)
10.28 First Amendment to Amended and Restated Retirement Plan for Directors. (previously
filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1997, and incorporated herein by reference) (1)
10.29 First Amendment to Second Amended and Restated 1992 Stock Option Plan. (previously
filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1997, and incorporated herein by reference) (1)
10.30 Second Amendment to Second Amended and Restated 1992 Stock Option Plan.
(previously filed as an exhibit to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1997, and incorporated herein by reference) (1)
10.31 Amended and Restated Indenture dated July 25, 1997, between Triton Energy
Limited and The Chase Manhattan Bank. (previously filed as an exhibit to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, and
incorporated herein by reference)
10.32 Amended and Restated Second Supplemental Indenture dated July 25, 1997,
between Triton Energy Limited and The Chase Manhattan Bank relating
to the 9 1/4% Senior Notes due 2005. (previously filed as an exhibit to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, and
incorporated herein by reference)
10.33 Indenture, dated October 4, 2000, between the Company and The Chase Manhattan
Bank, governing the Company's outstanding 8 7/8% Senior Notes Due 2007 (previously
filed as an exhibit to the Company's Registration Statement on Form S-4 (No. 333-
48584), and incorporated herein by reference.)
10.34 Shareholders Agreement dated August 3, 1998, among Triton Energy Limited, Triton
Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA Limited.
(previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1998, and incorporated herein by reference)
10.35 Stock Purchase Agreement dated as of August 31, 1998, between Triton Energy
Limited and HM4 Triton, L.P. (previously filed as an exhibit to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and
incorporated herein by reference)
10.36 Shareholders Agreement dated as of September 30, 1998, between Triton Energy
Limited and HM4 Triton, L.P. (previously filed as an exhibit to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and
incorporated herein by reference)
10.37 Financial Advisory Agreement dated as of September 30, 1998, between Triton Energy
Limited and Hicks, Muse & Co. Partners, L.P. (previously filed as an exhibit to the
Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998,
and incorporated herein by reference)
10.38 Monitoring and Oversight Agreement dated as of September 30, 1998, between Triton
Energy Limited and Hicks, Muse & Co. Partners, L.P. (previously filed as an exhibit to
the Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
1998, and incorporated herein by reference)
10.39 Severance Agreement dated April 9, 1999, made and entered into by and among Triton
Energy Limited, Triton Exploration Services, Inc. and Peter Rugg. (previously filed as
an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1999, and incorporated herein by reference) (1)
10.40 Consulting and Non-Compete Agreement dated April 9, 1999, made and entered into
by and between Triton Exploration Services, Inc. and Peter Rugg. (previously filed as
an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 1999, and incorporated herein by reference) (1)
10.41 Third Amendment to Amended and Restated 1985 Restricted Stock Plan (previously
filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter
ended March 31, 1999, and incorporated herein by reference) (1)
10.42 Amendment to Triton Exploration Services, Inc. Retirement Income Plan. (previously
filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1999, and incorporated herein by reference) (1)
10.43 Amendment to the Triton Exploration Services, Inc. Supplemental Executive
Retirement Plan. (previously filed as an exhibit to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by
reference) (1)
10.44 Third Amendment to the Second Amended and Restated 1992 Stock Option Plan
(previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999, and incorporated herein by reference) (1)
10.45 First Amendment to the Amended and Restated 1997 Share Compensation Plan
(previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999, and incorporated herein by reference) (1)
10.46 Amendment dated May 11, 1999, to Amended and Restated Employment Agreement
dated July 15, 1998 among Triton Exploration Services, Inc., Triton Energy Limited
and A.E. Turner, III (previously filed as an exhibit to the Company's Quarterly Report
on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by
reference) (1)
10.47 Second Amendment to Retirement Plan for Directors. (previously filed as an exhibit to
the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999,
and incorporated herein by reference) (1)
10.48 Amendment to Triton Exploration Services, Inc. 401 (k) Savings Plan. (previously filed
as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1999, and incorporated herein by reference) (1)
10.49 Aendment No. 1 to Shareholders Agreement between Triton Energy Limited
and HM4 Triton, L.P. (previously filed as an exhibit to the Company's Quarterly Report
on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by
reference)
10.50 Supplemental Letter Agreement dated October 28, 1999, among Triton Energy
Limited, Triton Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA
Limited (previously filed as an exhibit to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1999, and incorporated herein by reference)
10.51 Gas Sales Agreement dated October 30, 1999 among the Malaysia-Thailand Joint
Authority, and Petronas Carigali (JDA) SDN.BHD., Triton Oil Company of Thailand,
Triton Oil Company of Thailand (JDA) Limited, as Sellers, and with Petroleum
Authority of Thailand and Petroliam Nasional Berhad, as Buyers. (previously filed
as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1999, and incorporated herein by reference)
10.52 Form of Stock Option Agreement between Triton Energy Limited and its
non-employee directors (previously filed as an exhibit to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1999, and
incorporated herein by reference) (1)
10.53 Form of Stock Option Agreement between Triton Energy Limited and its employees,
including its executive officers (previously filed as an exhibit to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and
incorpoted herein by reference) (1)
10.54 Amendment to Stock Options dated as of January 3, 2000, between Triton Energy
Limited and A.E. Turner. (previously filed as an exhibit to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and
incorporated herein by reference.) (1)
10.55 Form of Amendment to Stock Options dated as of January 3, 2000, between Triton
Energy Limited and its non-employee directors. (previously filed as an exhibit to
the Company's Annual Report on Form 10-K for the fiscal year ended December
31, 1999, and incorporated herein by reference.) (1)
10.56 Production Sharing Contract between the Republic of Equatorial Guinea
and Triton Equatorial Guinea, Inc. for Block F. (previously filed as an exhibit to the
Company's Annual Report on Form 10-K for the fiscal year ended December 31,
1999, and incorporated herein by reference.)
10.57 Production Sharing Contract between the Republic of Equatorial Guinea and Triton
Equatorial Guinea, Inc. for Block G. (previously filed as an exhibit to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and
incorporated herein by reference.)
10.58 Supplementary Contract (No. 1) to the Production Sharing Contract for Block A-18
dated 21 April 1994 between Malaysia-Thailand Joint Authority and Petronas
Carigali (JDA) SDN.BHD., Triton Oil Company of Thailand and Triton Oil Company
of Thailand (JDA) Limited. (previously filed as an exhibit to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and
incorporated herein by reference.)
10.59 Supplementary Contract (No. 2) to the Production Sharing Contract for Block A-18
dated 21 April 1994 between Malaysia-Thailand Joint Authority and Petronas Carigali
(JDA) SDN.BHD., Triton Oil Company of Thailand and Triton Oil Company of
Thailand (JDA) Limited. (previously filed as an exhibit to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31, 1999, and
incorporated herein by reference.)
10.60 Credit Agreement dated as of February 29, 2000, among Triton Energy Limited,
the Lenders party thereto and The Chase Manhattan bank, as Administrative Agent
(previously filed as an exhibit to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1999, and incorporated herein by
reference)
10.61 Share Purchase Agreement dated as of May 8, 2000 between Triton International
Petroleum, Inc. and The Strategic Transaction Company. (previously filed as an
exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2000, and incorporated herein by reference.)
10.62 Amendment Agreement to Credit Agreement dated as of September 25, 2000, among
Triton Energy Limited, the Lenders party thereto and The Chase Manhattan Bank, as
Administrative Agent. (previously filed as an exhibit to the Company's Registration
Statement on Form S-4 (No. 333-48584), and incorporated herein by reference.)
10.63 Triton Energy Limited 2000 Broad Based Share Compensation Plan. (previously filed
as an exhibit to the Company's Registration Statement on Form S-4 (No. 333-48584),
and incorporated herein by reference.)
10.64 First Amendment to the Production Sharing Contract between the Republic of Equatorial
Guinea and Triton Equatorial Guinea, Inc. for Block F. (previously filed as an exhibit to
the Company's Registration Statement on Form S-4 (No. 333-48584), and incorporated
herein by reference.)
10.65 Assignment of State Participating Interest in the Production Sharing Contract for Block
F, Offshore Republic of Republic of Equatorial Guinea. (previously filed as an exhibit
to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
2000, and incorporated herein by reference.)
10.66 First Amendment to the Production Sharing Contract between the Republic of Equatorial
Guinea and Triton Equatorial Guinea, Inc. for Block G. (previously filed as an exhibit to
the Company's Registration Statement on Form S-4 (No. 333-48584), and incorporated
herein by reference.)
10.67 Assignment of State Participating Interest in the Production Sharing Contract for Block
G, Offshore Republic of Republic of Equatorial Guinea. (previously filed as an exhibit
to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
2000, and incorporated herein by reference.)
10.68 Second Amendment to the Amended and Restated 1997 Share Compensation Plan.
(previously filed as an exhibit to the Company's Registration Statement on Form S-4
(No. 333-48584), and incorporated herein by reference.) (1)
10.69* Form of Amendment dated December 19, 2000 to Amended and Restated Employment
with Triton Energy Limited and Messrs. Dunlevy and Maxted (1)
10.70* Employment Agreement among Triton Energy Limited, Triton Exploration Services, Inc.
and James C. Musselman (1)
12.1* Computation of Ratio of Earnings to Fixed Charges.
12.2* Computation of Ratio of Earnings to Combined Fixed Charges and Preference
Dividends.
21.1* Subsidiaries of the Company.
23.1* Consent of PricewaterhouseCoopers LLP.
23.2* Consent of DeGolyer and MacNaughton.
23.3* Consent of Netherland, Sewell & Associates, Inc.
24.1* The power of attorney of officers and directors of the Company (set forth on the
signature page hereof).
99.1 Rio Chitamena Association Contract. (previously filed as an exhibit to Triton Energy
Corporation's Current Report on Form 8-K/A dated July 15, 1994, and incorporated
herein by reference)
99.2 Rio Chitamena Purchase and Sale Agreement. (previously filed as an exhibit to Triton
Energy Corporation's Current Report on Form 8-K/A dated July 15, 1994, and
incorporated herein by reference)
99.3 Integral Plan - Cusiana Oil Structure. (previously filed as an exhibit to Triton Energy
Corporation's Current Report on Form 8-K/A dated July 15, 1994, and incorporated
herein by reference)
99.4 Letter Agreements with co-investor in Colombia. (previously filed as an exhibit to
Triton Energy Corporation's Current Report on Form 8-K/A dated July 15, 1994, and
incorporated herein by reference)
99.5 Amended and Restated Oleoducto Central S.A. Agreement dated as of March 31,
1995. (previously filed as an exhibit to Triton Energy Corporation's Quarterly Report
on Form 10-Q for the quarter ended June 30, 1995, and incorporated herein by
reference)

_____________________
* Filed herewith.

(1) Management contract or compensatory plan or arrangement.

(b) Reports on Form 8-K.

Form 8-K filed October 6, 2000 reporting under Item 5 the closing of the
offering of 8 7/8% Senior Notes due 2007.

Form 8-K filed November 9, 2000 furnishing under Item 9 information regarding
the posting of a presentation on the Company's web site.

Form 8-K filed November 14, 2000 furnishing under Item 9 information regarding
the posting of a presentation on the Company's web site.

Form 8-K filed December 5, 2000 furnishing under Item 9 information regarding
the posting of a presentation on the Company's web site.

Form 8-K filed December 11, 2000 furnishing under Item 9 information regarding
the posting of a presentation on the Company's web site.

Form 8-K filed December 20, 2000 furnishing under Item 9 information regarding
the posting of a presentation on the Company's web site.

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 14th day
of March, 2001.

TRITON ENERGY LIMITED

By: /s/James C. Musselman
-------------------------------------
James. C. Musselman
President and Chief Executive Officer

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and
directors of Triton Energy Limited (the "Company") hereby constitutes and
appoints James C. Musselman, A. E. Turner, III, and W. Greg Dunlevy, 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, 2000, 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 14th day of
March, 2001.

Signatures Title
---------- -----

/s/W. Greg Dunlevy Senior Vice President and Chief Financial
- ------------------ Officer
W. Greg Dunlevy (Principal Financial and Accounting Officer)

/s/Thomas O. Hicks Chairman of the Board
- ------------------
Thomas O. Hicks

/s/James C. Musselman Director, President and Chief Executive Officer
- --------------------- (Principal Executive Officer)
James C. Musselman

/s/Fitzgerald Hudson Director
- --------------------
Fitzgerald Hudson

/s/Sheldon R. Erikson Director
- ---------------------
Sheldon R. Erikson

/s/Jack D. Furst Director
- ----------------
Jack D. Furst

/s/John R. Huff Director
- ---------------
John R. Huff

/s/Michael E. McMahon Director
- ---------------------
Michael E. McMahon

- --------------------- Director
C. Lamar Norsworthy

/s/C. Richard Vermillion, Jr. Director
- -----------------------------
C. Richard Vermillion, Jr.

/s/J. Otis Winters Director
- ------------------
J. Otis Winters

TRITON ENERGY LIMITED AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES

PAGE
----

TRITON ENERGY LIMITED AND SUBSIDIARIES:

Report of Independent Accountants. . . . . . . . . . . . . . . . . . . . . . . . F-2
Consolidated Statements of Operations - Years ended December 31, 2000, 1999
and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-3
Consolidated Balance Sheets - December 31, 2000 and 1999 . . . . . . . . . . . . F-4
Consolidated Statements of Cash Flows - Years ended December 31, 2000, 1999
and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5
Consolidated Statements of Shareholders' Equity - Years ended December 31, 2000,
1999 and 1998. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-6
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . F-7

SCHEDULE:
II - Valuation and Qualifying Accounts - Years ended December 31, 2000,
1999 and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-46

All other schedules are omitted as the required information is inapplicable or
presented in the consolidated financial statements or related notes.

REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------

To the Board of Directors and Shareholders of
Triton Energy Limited

In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Triton
Energy Limited and its subsidiaries at December 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States of America. In addition, in our
opinion, the financial statement schedule listed in the accompanying index
presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements.
These financial statements and financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America 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 our opinion expressed above.

As discussed in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for its crude oil inventories in connection
with its adoption of Staff Accounting Bulletin 101, "Revenue Recognition in
Financial Statements" effective January 1, 2000.

PricewaterhouseCoopers LLP
Dallas, Texas
January 30, 2001

TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

YEAR ENDED DECEMBER 31,
--------------------------------
2000 1999 1998
--------- --------- ----------

SALES AND OTHER OPERATING REVENUES:
Oil and gas sales $328,467 $247,878 $ 160,881
Gain on sale of oil and gas assets --- --- 67,737
--------- --------- ----------
328,467 247,878 228,618
--------- --------- ----------
COSTS AND EXPENSES:
Operating 55,237 68,130 73,546
General and administrative 24,099 23,636 26,653
Depreciation, depletion and amortization 55,073 61,343 58,811
Writedown of assets 55,369 --- 328,630
Special charges --- 2,909 18,324
--------- --------- ----------
189,778 156,018 505,964
--------- --------- ----------

OPERATING INCOME (LOSS) 138,689 91,860 (277,346)

Gain on sale of Triton Pipeline Colombia --- --- 50,227
Interest income 9,673 10,579 3,258
Interest expense, net (16,880) (22,648) (23,228)
Other income (expense), net 5,244 (3,614) 8,480
--------- --------- ----------

(1,963) (15,683) 38,737
--------- --------- ----------

EARNINGS (LOSS) BEFORE INCOME TAXES,
EXTRAORDINARY ITEM AND CUMULATIVE EFFECT
OF ACCOUNTING CHANGE 136,726 76,177 (238,609)
Income tax expense (benefit) 61,046 28,620 (51,105)
--------- --------- ----------

EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 75,680 47,557 (187,504)
Extraordinary item - extinguishment of debt (6,962) --- ---
Cumulative effect of accounting change (1,345) --- ---
--------- --------- ----------

NET EARNINGS (LOSS) 67,373 47,557 (187,504)
ACCUMULATED DIVIDENDS ON PREFERENCE SHARES 29,278 28,671 3,061
--------- --------- ----------

EARNINGS (LOSS) APPLICABLE TO ORDINARY SHARES $ 38,095 $ 18,886 $(190,565)
========= ========= ==========

Average ordinary shares outstanding 36,551 36,135 36,609
========= ========= ==========

BASIC EARNINGS (LOSS) PER ORDINARY SHARE:
Earnings (loss) before extraordinary item and cumulative
effect of accounting change $ 1.27 $ 0.52 $ (5.21)
Extraordinary item - extinguishment of debt (0.19) --- ---
Cumulative effect of accounting change (0.04) --- ---
--------- --------- ----------

BASIC EARNINGS (LOSS) $ 1.04 $ 0.52 $ (5.21)
========= ========= ==========

Average diluted shares outstanding 38,604 36,197 36,609
========= ========= ==========

DILUTED EARNINGS (LOSS) PER ORDINARY SHARE:
Earnings (loss) before extraordinary item and cumulative
effect of accounting change $ 1.20 $ 0.52 $ (5.21)
Extraordinary item - extinguishment of debt (0.18) --- ---
Cumulative effect of accounting change (0.03) --- ---
--------- --------- ----------

DILUTED EARNINGS (LOSS) $ 0.99 $ 0.52 $ (5.21)
========= ========= ==========

See accompanying Notes to Consolidated Financial Statements.

TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)

ASSETS DECEMBER 31,
------------------------
2000 1999
----------- -----------

CURRENT ASSETS:
Cash and equivalents $ 136,361 $ 186,323
Trade receivables 25,616 17,246
Advances to third parties and other receivables 27,823 23,814
Deferred income taxes --- 20,090
Inventories, prepaid expenses and other 18,811 7,806
----------- -----------

TOTAL CURRENT ASSETS 208,611 255,279

Property and equipment, at cost, net 687,511 524,152
Investment in affiliates 190,430 93,188
Deferred income taxes 88,973 88,228
Other assets 18,755 13,628
----------- -----------

$1,194,280 $ 974,475
=========== ===========

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
Current maturities of long-term debt $ 4,648 $ 9,027
Accounts payable and accrued liabilities 140,700 62,576
Deferred income and other --- 22,347
----------- -----------

TOTAL CURRENT LIABILITIES 145,348 93,950

Long-term debt, excluding current maturities 500,048 404,460
Deferred income taxes 17,108 6,677
Other liabilities 6,760 6,336

SHAREHOLDERS' EQUITY:
5% preference shares, par value $.01; issued nil and 209,639
shares at December 31, 2000 and 1999, respectively,
stated value $34.41 --- 7,214
8% preference shares, par value $.01; authorized 11,000,000
shares; issued 5,181,033 and 5,193,643 shares at
December 31, 2000 and 1999, respectively, stated value $70 362,672 363,555
Ordinary shares, par value $.01; authorized 200,000,000
shares; issued 37,426,404 and 35,763,728 shares at
December 31, 2000 and 1999, respectively 374 358
Additional paid-in capital 534,480 531,904
Accumulated deficit (370,155) (437,528)
Accumulated other nonowner changes in shareholders' equity (2,355) (2,451)
----------- -----------

TOTAL SHAREHOLDERS' EQUITY 525,016 463,052
Commitments and contingencies (note 18) --- ---
----------- -----------

$1,194,280 $ 974,475
=========== ===========

The Company uses the full cost method to account for its oil-and gas-producing
activities.
See accompanying Notes to Consolidated Financial Statements.

TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

YEAR ENDED DECEMBER 31,
----------------------------------
2000 1999 1998
---------- ---------- ----------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ 67,373 $ 47,557 $(187,504)
Adjustments to reconcile net earnings to net cash provided
by operating activities:
Writedown of assets 55,369 --- 328,630
Depreciation, depletion and amortization 55,073 61,343 58,811
Deferred income taxes 21,187 7,827 (55,592)
Extraordinary loss on extinguishment of debt, net of tax 6,962 --- ---
Cumulative effect of accounting change 1,345 --- ---
Gain on sale of other assets 656 (677) (7,590)
Amortization of deferred income (8,814) (35,254) (35,254)
Proceeds from forward oil sale --- 31,932 1,770
Gain on sale of oil and gas assets --- --- (67,737)
Gain on sale of Triton Pipeline Colombia --- --- (50,227)
Other, net (2,296) 8,921 3,962
Changes in working capital:
Trade and other receivables (6,245) (16,131) 6,300
Inventories, prepaid expenses and other (15,052) (3,577) 918
Accounts payable and accrued liabilities 11,666 14,581 4,979
---------- ---------- ----------

Net cash provided by operating activities 187,224 116,522 1,466
---------- ---------- ----------

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures and investments (232,711) (121,483) (180,215)
Investment in affiliate (88,656) --- ---
Proceeds from sale of oil and gas assets --- --- 147,027
Proceeds from sale of Triton Pipeline Colombia --- --- 97,656
Proceeds from sales of other assets 1,398 2,353 22,353
Other (1,764) 600 (2,630)
---------- ---------- ----------

Net cash provided (used) by investing activities (321,733) (118,530) 84,191
---------- ---------- ----------

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving lines of credit and
long-term debt 293,351 --- 162,530
Payments on revolving lines of credit and long-term debt (215,909) (19,028) (350,511)
Short-term notes payable, net --- --- (9,600)
Issuance of 8% preference shares, net --- 217,805 115,329
Issuances of ordinary shares under stock compensation
plans 26,546 419 2,544
Repurchase of ordinary shares --- (11,285) ---
Redemption of 5% preference shares (2,691) --- ---
Dividends paid on preference shares (14,853) (17,617) (368)
Other (1,734) (151) 5
---------- ---------- ----------

Net cash provided (used) by financing activities 84,710 170,143 (80,071)
---------- ---------- ----------

Effect of exchange rate changes on cash and equivalents (163) (569) (280)
---------- ---------- ----------

Net increase (decrease) in cash and equivalents (49,962) 167,566 5,306
CASH AND EQUIVALENTS AT BEGINNING OF YEAR 186,323 18,757 13,451
---------- ---------- ----------

CASH AND EQUIVALENTS AT END OF YEAR $ 136,361 $ 186,323 $ 18,757
========== ========== ==========

See accompanying Notes to Consolidated Financial Statements.

TRITON ENERGY LIMITED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS)

YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
2000 1999 1998
------------------- ------------------- --------------------

OWNER SOURCES OF SHAREHOLDERS' EQUITY:
5% PREFERENCE SHARES:
Balance at beginning of period $ 7,214 $ 7,214 $ 7,511
Conversion of 5% preference shares (4,523) --- (297)
Redemption of 5% preference shares (2,691) --- ---
---------- ---------- ----------
Balance at end of period --- 7,214 7,214
---------- ---------- ----------
8% PREFERENCE SHARES:
Balance at beginning of period 363,555 127,575 ---
Issuances of 8% preference shares at $70 per share --- 222,425 127,575
Conversion of 8% preference shares (883) (192) ---
Stock dividends, 8% preference shares --- 13,747 ---
---------- ---------- ----------

Balance at end of period 362,672 363,555 127,575
---------- ---------- ----------
ORDINARY SHARES:
Balance at beginning of period 358 366 365
Conversion of preference shares 2 --- ---
Repurchase of ordinary shares --- (9) ---
Issuances under stock compensation plans 14 1 1
---------- ---------- ----------
Balance at end of period 374 358 366
---------- ---------- ----------
ADDITIONAL PAID-IN CAPITAL:
Balance at beginning of period 531,904 575,863 588,454
Dividends, 5% preference shares (334) (361) (368)
Dividends, 8% preference shares (29,026) (28,310) (2,693)
Issuances under stock compensation plans 26,532 418 2,548
Conversion of 5% preference shares 4,522 --- 297
Conversion of 8% preference shares 882 192 ---
Transaction costs for issuance of
8% preference shares --- (4,620) (12,370)
Repurchase of ordinary shares --- (11,276) ---
Other, net --- (2) (5)
---------- ---------- ----------
Balance at end of period 534,480 531,904 575,863
---------- ---------- ----------

TOTAL OWNER SOURCES OF SHAREHOLDERS' EQUITY 897,526 903,031 711,018
---------- ---------- ----------

NONOWNER SOURCES OF SHAREHOLDERS' EQUITY:
ACCUMULATED DEFICIT:
Balance at beginning of period (437,528) (485,085) (297,581)
Net earnings (loss) 67,373 $ 67,373 47,557 $47,557 (187,504) $(187,504)
---------- ---------- ----------
Balance at end of period (370,155) (437,528) (485,085)
---------- ---------- ----------
ACCUMULATED OTHER NONOWNER CHANGES IN
SHAREHOLDERS' EQUITY:
Balance at beginning of period (2,451) (2,126) (2,126)

Adjustment for minimum pension liability 96 96 (325) (325) --- ---
---------- -------- ---------- -------- ---------- ---------

Comprehensive income (loss) $ 67,469 $47,232 $(187,504)
======== ======== =========

Balance at end of period (2,355) (2,451) (2,126)
---------- ---------- ----------

TOTAL NONOWNER SOURCES OF
SHAREHOLDERS' EQUITY (372,510) (439,979) (487,211)
---------- ---------- ----------

TOTAL SHAREHOLDERS' EQUITY $525,016 $ 463,052 $ 223,807
========== ========== ==========

See accompanying Notes to Consolidated Financial Statements.

TRITON ENERGY LIMITED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(AMOUNTS IN TABLES IN THOUSANDS, EXCEPT FOR SHARE, PER SHARE AND PER BARREL
DATA)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

GENERAL

Triton Energy Limited ("Triton") is an international oil and gas exploration and
production company. The term "Company" in this report means Triton and its
subsidiaries and other affiliates through which the Company conducts its
business. The Company's principal properties, operations, and oil and gas
reserves are located in Colombia, offshore Malaysia-Thailand and offshore
Equatorial Guinea. The Company is exploring for oil and gas in these areas, as
well as in southern Europe, Africa and the Middle East. All sales for the
three-year period ended December 31, 2000, were derived from oil and gas
production in Colombia. First sales from oil production in Equatorial Guinea
occurred in January 2001.

Triton, a Cayman Islands company, was incorporated in 1995 to become the parent
holding company of Triton Energy Corporation, a Delaware corporation ("TEC").
On March 25, 1996, the stockholders of TEC approved the merger of a wholly owned
subsidiary of Triton with and into TEC (the "Reorganization"). Pursuant to the
Reorganization, Triton became the parent holding company of TEC and each share
of common stock, par value $1.00, and 5% preferred stock of TEC outstanding on
March 25, 1996, was converted into one Triton ordinary share, par value $.01,
and one 5% Triton preference share, respectively. The Reorganization was
accounted for as a combination of entities under common control.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of Triton and its
majority-owned subsidiaries. All intercompany balances and transactions have
been eliminated in consolidation. Investments in 20%- to 50%-owned affiliates
whose operating and financial polices the Company exercises significant
influence over are accounted for using the equity method. Investments in less
than 20%-owned affiliates are accounted for using the cost method.

CASH EQUIVALENTS

Cash equivalents are highly liquid investments purchased with an original
maturity of three months or less.

INVENTORIES

The Company adopted Securities and Exchange Commission ("SEC") Staff Accounting
Bulletin (SAB) 101, "Revenue Recognition in Financial Statements," effective
January 1, 2000, which requires the Company to record oil revenue on each sale,
or tanker lifting, and oil inventories at cost, rather than at market value as
in the past. The cumulative effect of the change for periods prior to January
1, 2000, is a reduction in net earnings of $1.3 million, or $0.03 per diluted
share, and is shown as the cumulative effect of accounting change in the
Consolidated Statement of Operations. Pro forma unaudited net earnings for the
years ended December 31, 1999 and 1998, assuming the new accounting principle is
applied retroactively, would have increased (decreased) by ($.1 million) and $.1
million, respectively.

Inventories related to materials and supplies are stated at the lower of cost or
market. Crude oil and materials and supplies inventories totaled $12.6 million
at December 31, 2000, and $3.9 million at December 31, 1999.

PROPERTY AND EQUIPMENT

The Company follows the full cost method of accounting for exploration and
development of oil and gas reserves, whereby all acquisition, exploration and
development costs are capitalized. Individual countries are designated as
separate cost centers. All capitalized costs plus the undiscounted estimated
future development costs of proved reserves are depleted using the
unit-of-production method based on total proved reserves applicable to each
country. A gain or loss is recognized on sales of oil and gas properties only
when the sale would significantly alter the relationship between capitalized
costs and proved oil and gas reserves.

Costs related to acquisition, holding and initial exploration of licenses in
countries with no proved reserves are initially capitalized, including internal
costs directly identified with acquisition, exploration and development
activities. Costs related to production, general overhead or similar activities
are expensed. The Company's exploration licenses are periodically assessed for
impairment on a country-by-country basis. If the Company's investment in
exploration licenses within a country where no proved reserves are assigned is
deemed to be impaired, the licenses are written down to estimated recoverable
value. If the Company abandons all exploration efforts in a country where no
proved reserves are assigned, all acquisition and exploration costs associated
with the country are expensed. Due to the unpredictable nature of exploration
drilling activities, the amount and timing of impairment expense are difficult
to predict with any certainty.

The net capitalized costs of oil and gas properties for each cost center, less
related deferred income taxes, cannot exceed the sum of (i) the estimated future
net revenues from the properties, discounted at 10%; (ii) unevaluated costs not
being amortized; and (iii) the lower of cost or estimated fair value of unproved
properties being amortized; less (iv) income tax effects related to differences
between the financial statement basis and tax basis of oil and gas properties.

The estimated costs, net of salvage value, of dismantling facilities or projects
with limited lives or facilities that are required to be dismantled by contract,
regulation or law, and the estimated costs of restoration and reclamation
associated with oil and gas operations, are included in estimated future
development costs as part of the amortizable base.

Support equipment and facilities are depreciated using the unit-of-production
method based on total reserves of the field related to the support equipment and
facilities. Other property and equipment and leasehold improvements are
depreciated principally on a straight-line basis over estimated useful lives
ranging from 3 to 10 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 are deemed probable, and the costs
can be reasonably estimated. Costs of future expenditures for environmental
remediation obligations are not discounted to their present value.

INCOME TAXES

Deferred tax liabilities or assets are recognized for the anticipated future tax
effects of temporary differences between the financial statement basis and the
tax basis of the Company's assets and liabilities using the enacted tax rates in
effect at year-end. A valuation allowance for deferred tax assets is recorded
when it is more likely than not that the benefit from the deferred tax asset
will not be realized.

REVENUE RECOGNITION

Cost reimbursements arising from carried interests granted by the Company are
revenues to the extent the reimbursements are contingent upon and derived from
production. Obligations arising from net profit interest conveyances are
recorded as operating expenses when the obligation is incurred.

FOREIGN CURRENCY TRANSLATION

The U.S. dollar is the designated functional currency for all of the Company's
foreign operations. The cumulative translation adjustment represents the
cumulative effect of translating the balance sheet accounts of Triton Colombia,
Inc. from the functional currency into U.S. dollars during the period when the
Colombian peso was the functional currency. Accumulated other nonowner changes
in shareholders' equity included a cumulative translation adjustment of ($2.1
million) at December 31, 2000, 1999 and 1998.

RISK MANAGEMENT

Oil sold by the Company is normally priced with reference to a defined
benchmark, such as West Texas Intermediate spot ("WTI") and Dated Brent. Actual
prices received vary from the benchmark depending on quality and location
differentials. From time to time, it is the Company's policy to use financial
market transactions, including swaps, collars and options, or combinations of
these, with creditworthy counterparties to reduce risk associated with the
pricing of the oil that it sells. The Company does not enter into financial
market transactions for trading purposes.

Gains or losses on financial market transactions that qualify for hedge
accounting are recognized in oil and gas sales at the time of settlement of the
underlying hedged transactions. Premiums paid for financial market contracts
are capitalized and amortized as operating expenses over the contract period.
Changes in the fair market value of financial market transactions that do not
qualify for hedge accounting are reflected as noncash adjustments to other
income (expense), net in the period the change occurs. Realized gains or losses
on financial market transactions that do not qualify for hedge accounting are
recorded in oil and gas sales.

STOCK-BASED COMPENSATION

The Company applies the provisions of Accounting Principles Board Opinion No. 25
("Opinion 25"), "Accounting for Stock Issued to Employees," and related
interpretations, in accounting for its stock-based compensation plans. Under
Opinion 25, compensation cost is measured as the excess, if any, of the quoted
market price of the Company's stock at the date of the grant above the amount an
employee must pay to acquire the stock.

EARNINGS PER ORDINARY SHARE

Basic earnings (loss) per ordinary share amounts were computed by dividing net
earnings (loss) after deduction of dividends on preference shares by the
weighted average number of ordinary shares outstanding during the period.
Diluted earnings (loss) per ordinary share assumes the conversion of all
securities that are exercisable or convertible into ordinary shares that would
dilute the basic earnings per ordinary share during the period.

COMPREHENSIVE INCOME

Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive
Income," established standards for the reporting and display of comprehensive
income and its components, specifically net income and all other changes in
shareholders' equity except those resulting from investments by and
distributions to shareholders. The Company has elected to display comprehensive
income in the Consolidated Statement of Shareholders' Equity.

RECENT ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board issued Statement No. 133
("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities."
This Statement was amended in June 2000 by SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities -- an Amendment of SFAS
No. 133." The new statements establish accounting and reporting standards for
derivative instruments and for hedging activities. The standards require the
Company to recognize all derivatives as either assets or liabilities in its
balance sheet and measure those instruments at fair value. The requisite
accounting for changes in the fair value of a derivative will depend on the
intended use of the derivative and the resulting designation. The Company
adopted the statements effective January 1, 2001, and thus the new accounting
and reporting standards will be reflected for the first time in its financial
statements for the first quarter of 2001.

For financial and commodity market transactions in which the Company hedges the
variability of cash flows associated with its forecasted crude oil sales, the
effective portion of changes in the fair value of the derivative instrument will
be reported in comprehensive income in the period changes in fair value occur.
These gains and losses will be recognized in earnings in the periods in which
the related hedged sale of crude oil occurs. All changes in the value of
derivative instruments not designated as hedges and the ineffective portion of
changes in fair value of hedging transactions will be recognized in earnings in
the period changes in fair value occur.

In January 2001, the Company expects to record a net-of-tax cumulative effect
adjustment of $1.2 million gain to earnings and $2.9 million gain to
comprehensive income to recognize the fair value of all derivative instruments
as a result of adopting SFAS 133.

THE USE OF ESTIMATES IN PREPARING FINANCIAL STATEMENTS

The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, disclosure of contingent
assets and liabilities at the date of the financial statements, and reported
amounts of revenues and expenses during the reporting period. Actual results
could differ from these estimates.

RECLASSIFICATIONS

Certain previously reported financial information has been reclassified to
conform to the current period's presentation.

2. ASSET ACQUISITION AND DISPOSITIONS

In May 2000, the Company acquired from an unrelated third party for $88.7
million in cash 100% of the shares of Triton Pipeline Colombia, Inc. ("TPC"), a
formerly wholly owned subsidiary up to its disposal on February 2, 1998. TPC's
sole asset is its 9.6% equity interest in the Colombian pipeline company,
Oleoducto Central S.A. ("OCENSA"). OCENSA owns and operates the pipeline and
port facilities that handle and transport crude oil from the Cusiana and
Cupiagua fields to the Caribbean port of Covenas. The investment in OCENSA
totaling $88.7 million at December 31, 2000, is accounted for under the cost
method and is presented in the Consolidated Balance Sheets as investment in
affiliates.

In December 1998, the Company sold its Bangladesh subsidiary for cash proceeds
of $4.5 million and recognized a gain of $4.5 million in gain on sale of oil and
gas assets.

In July 1998, the Company and Atlantic Richfield Company, now BP Amoco p.l.c.
("BP"), signed an agreement providing financing for the development of the
Company's gas reserves on Block A-18 of the Malaysia-Thailand Joint Development
Area. Under terms of the agreement, consummated in August 1998, the Company
sold to BP for $150 million one-half of the shares of the subsidiary through
which the Company owned its then 50% share of Block A-18. The Company received
net proceeds of $142 million and recorded a gain of $63.2 million in gain on the
sale of oil and gas assets. After the sale, the Company's remaining 50%
ownership of the entity is accounted for using the equity method. This
investment in Block A-18, totaling $101.7 million and $93.2 million at December
31, 2000 and 1999, respectively, is presented in the Consolidated Balance Sheets
as investment in affiliates.

In February 1998, the Company sold TPC, a wholly owned subsidiary that held the
Company's 9.6% equity interest in OCENSA, to an unrelated third party for $100
million. Net proceeds were approximately $97.7 million. The sale resulted in a
gain of $50.2 million.

In conjunction with the sale of TPC, the Company entered into an equity swap
with a creditworthy financial institution (the "Counterparty"). The equity swap
had a notional amount of $97 million and required the Company to make quarterly
floating LIBOR-based payments on the notional amount to the Counterparty. In
exchange, the Counterparty was required to make payments to the Company
equivalent to 97% of the dividends TPC received in respect of its equity
interest in OCENSA. The equity swap was carried in the Company's financial
statements at fair value during its term, which, as amended, expired in May
2000. The value of the equity swap in the Company's financial statements was
equal to 97% of the estimated fair value of the shares of OCENSA owned by TPC.
Because there was no public market for the shares of OCENSA, the Company
estimated their value using a discounted cash flow model applied to the
distributions expected to be paid in respect of the OCENSA shares. The discount
rate applied to the estimated cash flows from the OCENSA shares was based on a
combination of current market rates of interest, a credit spread for OCENSA's
debt, and a spread to reflect the preferred stock nature of the OCENSA shares.
During the years ended December 31, 2000, 1999 and 1998, the Company recorded an
expense of $2.1 million, $6.9 million and $3.3 million, respectively, in other
income (expense), net, related to the net payments made under the equity swap
and its change in fair value. Upon expiration of the equity swap, the Company
paid the counterparty $12 million in accordance with the terms of the agreement.

3. ADVANCES TO THIRD PARTIES AND OTHER RECEIVABLES

DECEMBER 31,
----------------
2000 1999
------- -------

Advance to third party for equipment $16,791 $ ---
Receivables from and advances to partners 7,053 10,684
Receivable from insurance 1,190 2,300
Receivable from financial and commodity market transactions 173 4,861
Other 2,616 5,969
------- -------

$27,823 $23,814
======= =======

A director of the Company is the chief executive officer of a company that is
providing certain subsea equipment for the Company's offshore development in
Equatorial Guinea. At December 31, 2000, the Company had advanced $16.8 million
to the third party under its current contract. See note 17 - Related Party
Transactions.

4. PROPERTY AND EQUIPMENT

DECEMBER 31,
--------------------
2000 1999
---------- --------
Oil and gas properties, full cost method:
Evaluated $ 829,188 $560,949
Unevaluated 67,893 78,527
Support equipment and facilities 311,632 303,244
Other 21,574 17,535
---------- --------

1,230,287 960,255
Less accumulated depreciation and depletion 542,776 436,103
---------- --------

$ 687,511 $524,152
========== ========

The Company capitalized general and administrative expenses related to
exploration and development activities of $11.1 million, $6.9 million and $20.6
million during the years ended December 31, 2000, 1999 and 1998, respectively.

5. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

DECEMBER 31,
-----------------
2000 1999
-------- -------
Accrued exploration and development $ 58,655 $ 9,762
Colombian income taxes 29,877 14,471
Dividends payable 14,507 ---
Taxes other than income 10,761 7,713
Accrued interest payable 10,498 7,864
Accounts payable, principally trade 5,402 1,242
Litigation and environmental matters 3,694 3,872
Equity swap --- 8,435
Other 7,306 9,217
-------- -------

$140,700 $62,576
======== =======

6. DEBT

DECEMBER 31,
-------------------
2000 1999
-------- --------

Senior Notes due 2007 $300,000 $ ---
Senior Notes due 2005 200,000 200,000
Senior Notes due 2002 --- 199,947
Term credit facility maturing 2001 4,513 13,540
Capitalized lease obligations 183 ---
-------- --------

504,696 413,487
Less current maturities 4,648 9,027
-------- --------

$500,048 $404,460
======== ========

In October 2000, the Company issued $300 million face value of 8 7/8% Senior
Notes due 2007 ( the "2007 Notes") for proceeds of $300 million before deducting
transaction costs of approximately $6 million. Interest is payable semiannually
on April 1 and October 1, commencing April 1, 2001. The 2007 Notes are
redeemable, in whole or in part, at any time on or after October 1, 2004, at the
option of the Company. Up to $105 million may be redeemed using proceeds of
future equity offerings completed before October 1, 2003. The 2007 Notes
contain various restrictive covenants that limit the Company's ability to borrow
money or guarantee other indebtedness, create liens, make investments, use
assets as security in other transactions, pay dividends on stock, enter into
sale/leaseback transactions, sell assets, and merge or consolidate.

Subject to certain exceptions, the indenture governing the 2007 Notes provides
that the Company may not incur additional indebtedness unless, at the time of
the incurrence, the ratio of consolidated earnings before interest, income
taxes, depreciation, depletion, amortization and writedowns to the sum of
interest expense and capitalized interest, as those terms are defined in the
indenture, is at least 2.5 to 1. One of the exceptions would permit the Company
to incur additional indebtedness under certain credit arrangements with
financial institutions, so long as the total amount of indebtedness outstanding
under this exception does not exceed the greater of (i) $250 million or (ii) an
amount equal to the sum of $100 million plus 20% of the adjusted net tangible
assets as defined in the indenture, on the date of such incurrence.

In April 1997, the Company issued $400 million aggregate face value of senior
indebtedness to refinance other indebtedness. The senior indebtedness consisted
of $200 million face amount of 8 3/4% Senior Notes due April 15, 2002 (the "2002
Notes") at 99.942% of the principal amount (resulting in $199.9 million
aggregate net proceeds) and $200 million face amount of 9 1/4% Senior Notes due
April 15, 2005 (the "2005 Notes") at 100% of the principal amount for total
aggregate net proceeds of $399.9 million before deducting transaction costs of
approximately $1 million.

The Company used approximately $207 million of the net proceeds from the sale of
the 2007 Notes to redeem all of the Company's outstanding 2002 Notes at a price,
including accrued interest, of $1,038.40 for each $1,000 note outstanding which
resulted in an extraordinary extinguishment expense for the quarter ended
December 31, 2000, of approximately $7 million.

Interest on the 2005 Notes is payable semiannually on April 15 and October 15.
The 2005 Notes are redeemable at any time at the option of the Company, in whole
or in part, and contain certain covenants limiting the incurrence of certain
liens, sale/leaseback transactions, and mergers and consolidations.

In November 1995, a subsidiary signed an unsecured term credit facility with a
bank supported by a guarantee issued by the Export-Import Bank of the United
States ("EXIM") for $45 million, which matured and was fully paid in January
2001. Principal and interest payments were due semiannually on January 15 and
July 15, and borrowings bore interest at LIBOR plus .25%, adjusted on a
semiannual basis. At December 31, 2000, the Company had outstanding borrowings
of $4.5 million under the facility.

In February 2000, the Company entered into an unsecured two-year revolving
credit facility with a group of banks, which matures in February 2002. The
credit facility gives the Company the right to borrow from time to time up to
the amount of the borrowing base determined by the banks, not to exceed $150
million. As a result of the issuance of the 2007 Notes and the redemption of
the 2002 Notes, the borrowing base was adjusted to $50 million, subject to any
future redetermination of the borrowing base as provided in the agreement. The
credit facility contains various restrictive covenants, including covenants that
require the Company to maintain a ratio of earnings before interest,
depreciation, depletion, amortization and income taxes to net interest expense
of at least 2.5 to 1, and that prohibit the Company from permitting net debt to
exceed the product of 3.75 times the Company's earnings before interest,
depreciation, depletion, amortization and income taxes, in each case, on a
trailing-four-quarters basis. At December 31, 2000, the Company had no
outstanding borrowings under the facility.

The Company capitalizes interest on qualifying assets, principally unevaluated
oil and gas properties, major development projects in progress and investments
accounted for by the equity method, while the investee has activities in
progress necessary to commence its principal operations. Capitalized interest
amounted to $24.1 million, $14.5 million and $23.2 million in the years ended
December 31, 2000, 1999 and 1998, respectively.

The Company amortizes debt issue costs over the life of the borrowing using the
interest method. Amortization related to the Company's debt issue costs was
$1.2 million, $.5 million and $2.9 million in the years ended December 31, 2000,
1999 and 1998, respectively. The aggregate maturities of long-term debt for the
five years during the period ending December 31, 2005, are as follows: 2001 --
$4.6 million; 2002 -- nil; 2003 -- nil; 2004 -- nil; and 2005 -- $200 million.

7. INCOME TAXES

The components of earnings (loss) from continuing operations before income
taxes, extraordinary item and cumulative effect of accounting change were as
follows:

YEAR ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
--------- --------- ----------
Cayman Islands $(30,712) $(35,907) $ 82,995
United States (12,720) (7,810) (24,003)
Foreign - other 180,158 119,894 (297,601)
--------- --------- ----------

$136,726 $ 76,177 $(238,609)
========= ========= ==========

Pursuant to the Reorganization in March 1996, Triton, a Cayman Islands company,
became the parent holding company of TEC, a Delaware corporation. As a result,
the Company's corporate domicile became the Cayman Islands, a 0% taxing
jurisdiction.

The components of the provision for income taxes on continuing operations were
as follows:

YEAR ENDED DECEMBER 31,
-----------------------------
2000 1999 1998
-------- -------- ---------
Current:
Cayman Islands $ --- $ --- $ ---
United States --- --- ---
Foreign - other 39,859 20,793 4,487
-------- -------- ---------

Total current 39,859 20,793 4,487
-------- -------- ---------
Deferred:
Cayman Islands --- --- ---
United States (826) (1,410) 1,457
Foreign - other 22,013 9,237 (57,049)
-------- -------- ---------

Total deferred 21,187 7,827 (55,592)
-------- -------- ---------

Total $61,046 $28,620 $(51,105)
======== ======== =========

A reconciliation of the differences between the Company's applicable statutory
tax rate and the Company's effective income tax rate follows:

YEAR ENDED DECEMBER 31,
--------------------------
2000 1999 1998
------- ------- -------

Tax provision at statutory tax rate 0.0 % 0.0 % 0.0 %
Increase (decrease) resulting from:
Net change in valuation allowance (7.5)% (15.7)% 3.9 %
Foreign items without tax benefit 21.8 % 18.9 % (34.9)%
Income subject to tax in excess of statutory rate 38.9 % 36.6 % 32.6 %
Current year change in NOL/credit carryforwards (17.1)% (7.6)% (4.8)%
Temporary differences:
Oil and gas basis adjustments 7.6 % 3.3 % 25.7 %
Reimbursement of pre-commerciality costs 0.7 % 2.3 % (1.1)%
Other 0.2 % (0.2)% --- %
------- ------- -------

44.6 % 37.6 % 21.4 %
======= ======= =======

The components of the net deferred tax asset and liability were as follows:

DECEMBER 31, 2000 DECEMBER 31, 1999
------------------------------ -------------------------------

OTHER OTHER
U.S. COLOMBIA FOREIGN U.S. COLOMBIA FOREIGN
--------- -------- --------- ---------- -------- ---------
Deferred tax asset:
Net operating loss carryforwards $134,046 $ --- $ 50,355 $ 157,558 $20,090 $ 9,832
Depreciable/depletable property 1,527 --- --- 1,748 8,778 ---
Credit carryforwards 1,851 --- --- 2,048 --- ---
Other 813 --- --- 995 --- ---
--------- -------- --------- ---------- -------- ---------

Gross deferred tax asset 138,237 --- 50,355 162,349 28,868 9,832
Valuation allowances (48,695) --- --- (72,908) (8,778) ---
--------- -------- --------- ---------- -------- ---------

Net deferred tax asset 89,542 --- 50,355 89,441 20,090 9,832
--------- -------- --------- ---------- -------- ---------

Deferred tax liability:
Depreciable/depletable property --- (9,956) (57,507) --- --- (16,509)
Other (569) --- --- (1,213) --- ---
--------- -------- --------- ---------- -------- ---------

Net deferred tax asset (liability) 88,973 (9,956) (7,152) 88,228 20,090 (6,677)
Less current deferred tax asset (liability) --- --- --- --- 20,090 ---
--------- -------- --------- ---------- -------- ---------

Noncurrent deferred tax asset (liability) $ 88,973 $(9,956) $ (7,152) $ 88,228 $ --- $ (6,677)
========= ======== ========= ========== ======== =========

At December 31, 2000, the Company had net operating losses ("NOLs") and
depletion carryforwards for U.S. tax purposes of $383 million and $20.3 million,
respectively. The U.S. NOLs expire from 2001 through 2021 as follows:

NOLS
EXPIRING
BY YEAR
---------
May 2001 $ 21,417
May 2002 22,702
May 2003 20,569
May 2004 8,552
May 2005 6,858
May 2006 - May 2021 302,895
---------

$ 382,993
=========

The Company's Equatorial Guinea operations had NOLs totaling $176 million with
an unlimited carryforward. In other countries outside the U.S., the Company had
NOLs and other credit carryforwards totaling $30.1 million, which expire from
2001 through 2010.

During 2000, the Company's tax expense was approximately $21 million lower due
to anticipated utilization of NOLs from entities that were acquired during 1999
and 2000.

The deferred tax valuation allowance of $48.7 million at December 31, 2000, is
primarily attributable to management's assessment of the utilization of NOLs in
the U.S., the expectation that other tax credits will expire without being
utilized, and the expectation that certain temporary differences will reverse
without a benefit to the Company. The minimum amount of future taxable income
necessary to realize the U.S. net deferred tax asset is approximately $254
million. Although there can be no assurance the Company will achieve such
levels of income, management believes the deferred tax asset will be realized
through income from its operations or sales of assets.

If certain changes in the Company's ownership should occur, there would be an
annual limitation on the amount of U.S. NOLs that can be utilized. To the
extent a change in ownership does occur, the limitation is not expected to
materially impact the utilization of such carryforwards.

8. EMPLOYEE BENEFITS

PENSION PLANS

The Company has a defined benefit pension plan covering substantially all of its
employees in the U.S. Plan benefits are based on years of service and the
employee's final average monthly compensation. Contributions are intended to
provide for benefits attributed to past and future services. The Company also
has a Supplemental Executive Retirement Plan ("SERP") that is unfunded and
provides supplemental pension benefits to a select group of management and key
employees.

The funding status of the plans follows:

DECEMBER 31,
----------------------------------------

2000 1999
------------------- -------------------
DEFINED DEFINED
BENEFIT SERP BENEFIT SERP
PLAN PLAN PLAN PLAN
--------- -------- --------- --------

Change in benefit obligation:
Benefit obligation at beginning of year $ 5,967 $ 7,631 $ 6,435 $ 6,579
Service cost 295 496 392 537
Interest cost 447 575 421 435
Actuarial loss/(gain) 179 155 (750) 1,465
Benefits paid (379) (410) (531) (1,385)
--------- -------- --------- --------

Benefit obligation at end of year 6,509 8,447 5,967 7,631
--------- -------- --------- --------

Change in plan assets:
Fair value of plan assets at beginning of year 8,988 --- 7,068 ---
Actual return on plan assets (238) --- 1,971 ---
Company contribution --- 410 480 1,385
Benefits paid (379) (410) (531) (1,385)
--------- -------- --------- --------

Fair value of plan assets at end of year 8,371 --- 8,988 ---
--------- -------- --------- --------

Reconciliation:
Funded status 1,862 (8,447) 3,021 (7,631)
Unrecognized actuarial (gain)/loss (1,660) 2,012 (2,999) 1,945
Unrecognized transition (asset)/obligation (4) 359 (6) 527
Unrecognized prior service cost 260 199 317 226
--------- -------- --------- --------

Prepaid/(accrued) pension cost 458 (5,877) 333 (4,933)
--------- -------- --------- --------

Adjustment for minimum liability --- (912) --- (1,255)
--------- -------- --------- --------

Adjusted prepaid/(accrued) pension cost $ 458 $(6,789) $ 333 $(6,188)
========= ======== ========= ========

The adjustment required to recognize the minimum liability for the SERP plan at
December 31, 2000, resulted in the recognition of $.6 million as an intangible
asset and $.4 million ($.2 million net of tax) as a charge against comprehensive
income.

A summary of the components of pension expense follows:

YEAR ENDED DECEMBER 31,
-------------------------------------
2000 1999 1998
------- ------- -------
Components of net periodic pension cost:

Service cost $ 792 $ 929 $1,359
Interest cost 1,022 856 1,045
Expected return on plan assets (791) (618) (481)
Recognized net actuarial loss/(gain) (43) (12) ---
Amortization of transition obligation 166 166 591
Amortization of prior service cost 83 83 538
------- ------- -------

Net periodic pension cost $1,229 $1,404 $3,052
======= ======= =======

The projected benefit obligations at both December 31, 2000 and 1999, assume a
discount rate of 7.75%, and a rate of increase in compensation expense of 5%.
The expected long-term rate of return on assets is 9% for the defined benefit
plan.

EMPLOYEE STOCK OWNERSHIP PLAN

Effective January 1, 1994, the Company amended and restated the employee stock
ownership plan to form a 401(k) plan (the "Plan"). The Company recognizes
expense based on actual amounts contributed to the Plan. The cost recognized
for the Plan was $.5 million, $.2 million and $.6 million for the years ended
December 31, 2000, 1999 and 1998, respectively.

9. SHAREHOLDERS' EQUITY

5% CONVERTIBLE PREFERENCE SHARES

On September 8, 2000, the Company called all of the outstanding 5% Convertible
Preference Shares for redemption. Each 5% Convertible Preference Share was
convertible into one ordinary share of the Company. A total of 107,075 shares
were converted into ordinary shares, and the remaining 78,201 shares were
redeemed for cash at the redemption price of $34.56 per share totaling $2.7
million. The redemption price represented the stated value of $34.41 plus the
amount of dividends that accrued per share from September 30, 2000, through the
redemption date of October 31, 2000. The 5% Convertible Preference Shares were
canceled and returned to the status of authorized but unissued preference
shares.

8% CONVERTIBLE PREFERENCE SHARES

In August 1998, the Company and HM4 Triton, L.P., an affiliate of Hicks, Muse,
Tate & Furst Incorporated ("Hicks Muse"), entered into a stock purchase
agreement (the "Stock Purchase Agreement") that provided for a $350 million
equity investment in the Company. The investment was effected in two stages. At
the closing of the first stage in September 1998 (the "First Closing"), the
Company issued to HM4 Triton, L.P. 1,822,500 shares of 8% Convertible Preference
Shares for $70 per share (for proceeds of $116.8 million, net of transaction
costs). Pursuant to the Stock Purchase Agreement, the second stage was effected
through a rights offering for 3,177,500 shares of 8% Convertible Preference
Shares at $70 per share, with HM4 Triton, L.P. being obligated to purchase any
shares not subscribed. At the closing of the second stage, which occurred on
January 4, 1999 (the "Second Closing"), the Company issued an additional
3,177,500 8% Convertible Preference Shares for proceeds totaling $217.8 million,
net of closing costs (of which, HM4 Triton, L.P. purchased 3,114,863 shares).

Each 8% Convertible Preference Share is convertible at any time at the option of
the holder into four ordinary shares of the Company (subject to certain
antidilution protections). Holders of 8% Convertible Preference Shares are
entitled to receive, when and if declared by the Board of Directors, cumulative
dividends at a rate per annum equal to 8% of the liquidation preference of $70
per share, payable for each semiannual period ending June 30 and December 30 of
each year. At the Company's option, dividends may be paid in cash or by the
issuance of additional whole shares of 8% Convertible Preference Shares. If a
dividend is to be paid in additional shares, the number of additional shares to
be issued in payment of the dividend will be determined by dividing the amount
of the dividend by $70, with amounts in respect of any fractional shares to be
paid in cash. The first dividend period was from January 4, 1999, to June 30,
1999. The Company's Board of Directors elected to pay the dividend for that
period in additional shares resulting in the issuance of 196,388 8% Convertible
Preference Shares. Dividends for periods subsequent to June 30, 1999, have been
paid in cash. The declaration of a dividend in cash or additional shares for
any period should not be considered an indication as to whether the Board will
declare dividends in cash or additional shares in future periods. Holders of 8%
Convertible Preference Shares are entitled to vote with the holders of ordinary
shares on all matters submitted to the shareholders of the Company for a vote,
with each 8% Convertible Preference Share entitling its holder to a number of
votes equal to the number of ordinary shares into which it could be converted at
that time. At December 31, 2000 and 1999, 5,181,033 and 5,193,643 8%
Convertible Preference Shares were outstanding, respectively.

Beginning September 30, 2001, the Company can redeem all, but not less than all,
of the outstanding 8% Convertible Preference Shares if the average market value
of the ordinary shares is above certain market values. The redemption price is
equal to $70 per share, plus an amount equal to all accumulated but unpaid
dividends, and is payable in cash.

ORDINARY SHARES

Changes in issued ordinary shares were as follows:

YEAR ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
---------- ----------- -----------

Balance at beginning of year 35,763,728 36,643,478 36,541,064
Exercise of employee stock options 1,427,462 8,213 47,238
Conversion of 5% preference shares 131,438 --- 8,646
Issuances under stock purchase plan 53,336 49,367 46,648
Conversion of 8% preference shares 50,440 10,980 ---
Repurchase of shares --- (948,300) ---
Other, net --- (10) (118)
---------- ----------- -----------

Balance at end of year 37,426,404 35,763,728 36,643,478
========== =========== ===========

SHARE REPURCHASE

In April 1999, the Company's Board of Directors authorized a share repurchase
program enabling the Company to repurchase up to 10% of the Company's
then-outstanding 36.7 million ordinary shares. During 1999, the Company
purchased 948,300 ordinary shares for $11.3 million. The Company canceled and
returned the repurchased ordinary shares to the status of authorized but
unissued shares. The Company's revolving credit facility entered into in
February 2000 generally does not permit the Company to repurchase its ordinary
shares without the banks' consent.

SHAREHOLDER RIGHTS PLAN

The Company has adopted a Shareholder Rights Plan pursuant to which preference
share rights attach to all ordinary shares at the rate of one right for each
ordinary share. Each right entitles the registered holder to purchase from the
Company one one-thousandth of a Series A Junior Participating Preference Share,
par value $.01 per share ("Junior Preference Shares"), of the Company at a price
of $120 per one one-thousandth of a share of such Junior Preference Shares,
subject to adjustment. Generally, the rights only become distributable 10 days
following a public announcement that a person has acquired beneficial ownership
of 15% or more of Triton's ordinary shares or 10 business days following
commencement of a tender offer or exchange offer for 15% or more of the
outstanding ordinary shares; provided that, pursuant to the terms of the plan,
any acquisition of Triton shares by HM4 Triton, L.P. or its affiliates,
including Hicks Muse will not result in the distribution of rights unless and
until HM4 Triton, L.P.'s ownership of Triton shares is reduced below certain
levels.

If, among other events, any person becomes the beneficial owner of 15% or more
of Triton's ordinary shares (except as provided with respect to HM4 Triton,
L.P.), each right not owned by such person generally becomes the right to
purchase a number of ordinary shares of the Company equal to the number obtained
by dividing the right's exercise price (currently $120) by 50% of the market
price of the ordinary shares on the date of the first occurrence. In addition,
if the Company is subsequently merged or certain other extraordinary business
transactions are consummated, each right generally becomes a right to purchase a
number of shares of common stock of the acquiring person equal to the number
obtained by dividing the right's exercise price by 50% of the market price of
the common stock on the date of the first occurrence.

Under certain circumstances, the Company's directors may determine that a tender
offer or merger is fair to all shareholders and prevent the rights from being
exercised. At any time after a person or group acquires 15% or more of the
ordinary shares outstanding (other than with respect to HM4 Triton, L.P.) and
prior to the acquisition by such person or group of 50% or more of the
outstanding ordinary shares or the occurrence of an event described in the prior
paragraph, the Board of Directors of the Company may exchange the rights (other
than rights owned by such person or group which will become void), in whole or
in part, at an exchange ratio of one ordinary share, or one one-thousandth of a
Junior Preference Share, per right (subject to adjustment). The Company has the
ability to amend the rights (except the redemption price) in any manner prior to
the public announcement that a 15% position has been acquired or a tender offer
has been commenced. The Company will be entitled to redeem the rights at $0.01 a
right at any time prior to the time that a 15% position has been acquired. The
rights will expire on May 22, 2005, unless earlier redeemed by the Company.

10. STOCK COMPENSATION PLANS

STOCK OPTION PLANS

Options to purchase ordinary shares of the Company may be granted to directors,
officers and employees under various stock option plans. The exercise price of
each option is equal to or greater than the market price of the Company's
ordinary shares on the date of grant. Grants generally become exercisable in 25%
or 33% cumulative annual increments beginning one year from the date of issuance
and generally expire during a period from 5 to 10 years after the date of grant,
depending on terms of the grant. In addition, each nonemployee director
receives an option to purchase 15,000 shares each year. These grants become
exercisable at the date of the grant and expire at the end of 10 years. At
December 31, 2000 and 1999, options to purchase ordinary shares available for
grant were 650,521 and 1,019,021, respectively.

A summary of the status of the Company's stock option plans is presented below:

DECEMBER 31, 2000 DECEMBER 31, 1999 DECEMBER 31, 1998
--------------------- -------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE

Outstanding at beginning of year 5,847,856 $21.78 4,057,207 $26.51 4,449,435 $39.05
Granted 1,750,500 37.28 2,150,000 14.03 2,894,603 20.56
Exercised (1,427,462) 18.16 (8,213) 10.57 (47,238) 29.30
Canceled (252,448) 39.36 (351,138) 29.24 (3,239,593) 38.39
------------ ----------- ------------

Outstanding at end of year 5,918,446 26.48 5,847,856 21.78 4,057,207 26.51
============ =========== ============

Options exercisable at year-end 2,751,439 3,121,601 2,804,584

Weighted average fair value of options:
Granted at market prices $ 12.35 $ 2.71 $ 6.12
Granted at greater than market prices 15.26 4.93 2.84

The following table summarizes information about stock options outstanding at
December 31, 2000:

OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------- -------------------------
WEIGHTED
RANGE AVERAGE WEIGHTED WEIGHTED
OF NUMBER REMAINING AVERAGE NUMBER AVERAGE
EXERCISE OUTSTANDING AT CONTRACTUAL EXERCISE EXERCISABLE AT EXERCISE
PRICES DEC. 31, 2000 LIFE PRICE DEC. 31, 2000 PRICE
- -------------- -------------- ----------- --------- -------------- ---------

6.94 - 14.50 2,363,437 4.0 years $ 14.19 1,049,271 $ 13.81
14.51 - 25.00 512,553 3.8 years 17.85 279,212 17.97
25.01 - 35.00 839,404 3.4 years 29.47 772,404 29.51
35.01 - 40.00 1,702,500 4.5 years 38.94 150,000 37.90
40.01 - 52.00 500,552 3.9 years 46.00 500,552 46.00
-------------- --------------

5,918,446 2,751,439
============== ==============

EMPLOYEE STOCK PURCHASE PLAN

The Company has an employee stock purchase plan that provides for the award of
ordinary shares to employees. Under the terms of the plan, employees can choose
each semiannual period to have up to 15% of their annual gross or base
compensation withheld to purchase the Company's ordinary shares. The purchase
price of the stock is 85% of the lower of its beginning-of-period or
end-of-period market price. Under the plan, the Company sold 53,336 shares and
49,367 shares to employees for the years ended December 31, 2000 and 1999,
respectively.

FAIR VALUE OF STOCK COMPENSATION

The Company applies Opinion 25 in accounting for its plans. Accordingly, no
compensation cost has been recognized for its fixed stock option plans and stock
purchase plan. Had the Company elected to recognize compensation expense
consistent with the fair value-based methodology in Statement of Financial
Accounting Standards No. 123, the Company's net earnings (loss) applicable to
ordinary shares and earnings (loss) per ordinary share would have been as
follows:

YEAR ENDED DECEMBER 31,
----------------------------
2000 1999 1998
------- ------- ----------

Net earnings (loss) applicable to ordinary shares:
As reported $38,095 $18,886 $(190,565)
Pro forma 27,888 12,579 (200,147)

Basic earnings (loss) per ordinary share:
As reported $ 1.04 $ 0.52 $ (5.21)
Pro forma 0.73 0.35 (5.47)

Diluted earnings (loss) per ordinary share:
As reported $ 0.99 $ 0.52 $ (5.21)
Pro forma 0.70 0.35 (5.47)

The fair value of each option granted was estimated on the date of grant using
the Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 2000, 1999 and 1998: dividend yield of 0%;
expected volatility of approximately 64%, 54% and 40%, respectively; risk-free
interest rates of approximately 6%, 6% and 5%, respectively; and an expected
life of approximately three to four years.

11. FAIR VALUE OF FINANCIAL INSTRUMENTS, RISK MANAGEMENT
AND CREDIT RISK CONCENTRATIONS

FAIR VALUE OF FINANCIAL INSTRUMENTS

At December 31, 2000 and 1999, the Company's financial instruments included cash
and equivalents, short-term receivables, long-term receivables, short-term and
long-term debt, and financial market transactions. The fair value of cash, cash
equivalents, short-term receivables and short-term debt approximated carrying
values because of the short maturities of these instruments. The fair values of
the Company's long-term receivables and financial market transactions, based on
broker quotes and discounted cash flows, approximated the carrying values. The
estimated fair value of long-term debt, based on quoted market prices and market
data for similar instruments, was $514 million (carrying value - $505 million)
and $416 million (carrying value - $413 million) at December 31, 2000 and 1999,
respectively.

RISK MANAGEMENT

Oil sold by the Company is normally priced with reference to a defined
benchmark, such as WTI spot and Dated Brent. Actual prices received vary from
the benchmark depending on quality and location differentials. From time to
time, it is the Company's policy to use financial market transactions, including
swaps, collars and options, or combinations of these, with creditworthy
counterparties to reduce risk associated with the pricing of the oil that it
sells. The policy is structured to underpin the Company's planned revenues and
results of operations. The Company does not enter into financial market
transactions for trading purposes. There can be no assurance that the use of
financial market transactions will not result in losses. As a result of
financial and commodity market transactions settled during the years ended
December 31, 2000 and 1999, the Company's oil sales were approximately $17.6
million and $19.8 million, respectively, lower than if the Company had not
entered into such transactions.

CONCENTRATION OF CREDIT RISK

Financial instruments potentially subject to concentrations of credit risk
consist of cash equivalents, receivables and financial market transactions. The
Company places its cash equivalents and financial market transactions with high
credit-quality financial institutions. The Company believes the risk of
incurring losses related to credit risk is remote.

The Company sells its crude oil production from the Cusiana and Cupiagua fields
in Colombia through an agreement with a third party to approximately 10 to 15
buyers located primarily in the United States. The Company does not believe
that the loss of any single customer or a termination of the agreement with the
third party would have a long-term material, adverse effect on its operations.

12. WRITEDOWN OF ASSETS

YEAR ENDED DECEMBER 31,
----------------------------

2000 1999 1998
-------- -------- --------

Evaluated oil and gas properties $ --- $ --- $241,005
Unevaluated oil and gas properties 54,186 --- 73,890
Other assets 1,183 --- 13,735
-------- -------- --------

$ 55,369 $ --- $ 328,630
======== ======== ========

Following the acquisition of new acreage, reviews of the Company's capital
expenditure requirements and exploration portfolio during 2000, and other
information management deemed relevant, the Company recorded a writedown of
$36.7 million ($34.8 million after-tax) related to its operations onshore Italy,
offshore Madagascar and offshore Greece. The Company also surrendered its
interest in the Aitoloakarnania lease onshore Greece after drilling two dry
holes and recorded a writedown of $18.7 million ($17.2 million after-tax) during
2000.

In June and December 1998, the carrying amount of the Company's evaluated oil
and gas properties in Colombia was written down by $105.4 million ($68.5
million, net of tax) and $135.6 million ($115.9 million, net of tax),
respectively, through application of the full cost ceiling limitation as
prescribed by the SEC, principally as a result of a decline in oil prices. The
SEC ceiling test was calculated using the June 30, and December 31, 1998, WTI
oil prices of $14.18 per barrel and $12.05 per barrel, respectively, that, after
a differential for Cusiana crude delivered at the port of Covenas in Colombia,
resulted in a net price of approximately $13 per barrel and $11 per barrel,
respectively.

In conjunction with the plan to restructure operations and scale back
exploration-related expenditures in 1998, the Company assessed its investments
in exploration licenses and determined that certain investments were impaired.
As a result, unevaluated oil and gas properties and other assets totaling $77.3
million ($72.6 million, net of tax) were expensed in June 1998. The writedown
included $27.2 million and $22.5 million related to exploration activity in
Guatemala and China, respectively. The remaining writedowns related to the
Company's exploration projects in certain other areas of the world.

During 1998, the Company evaluated the recoverability of its approximate 6.6%
investment in a Colombian pipeline company, Oleoducto de Colombia S.A. ("ODC"),
which was accounted for under the cost method. Based on an analysis of the
future cash flows expected to be received from ODC, the Company expensed the
carrying value of its investment totaling $10.3 million.

13. SPECIAL CHARGES

In September 1999, the Company recognized special charges totaling $2.4 million
related to the transfer of its working interest in Ecuador to a third party.

In July 1998, the Company commenced a plan to restructure the Company's
operations, reduce overhead costs and substantially scale back
exploration-related expenditures. The plan contemplated the closing of foreign
offices in four countries, the elimination of approximately 105 positions, or
41% of the worldwide workforce, and the relinquishment or other disposal of
several exploration licenses. As a result of the restructuring, the Company
recognized special charges of $15 million during the third quarter of 1998 and
$3.3 million during the fourth quarter of 1998 for a total of $18.3 million. Of
the $18.3 million in special charges, $14.5 million related to the reduction in
workforce, and represented the estimated costs for severance, benefit
continuation and outplacement costs, which were paid over a period of up to two
years according to the severance formula. During the fourth quarter of 1999, the
Company reversed $.7 million of the accrual through special charges in the
Consolidated Statement of Operations associated with the substantial completion
of restructuring activities. During 2000, all amounts outstanding were paid,
therefore at December 31, 2000, there is no liability remaining related to the
restructuring activities undertaken in 1998.

In March 1999, the Company accrued special charges of $1.2 million related to an
additional 15% reduction in the number of employees resulting from the
Company's continuing efforts to reduce costs. The special charges consisted of
$1 million for severance, benefit continuation and outplacement costs and $.2
million related to the write-off of surplus fixed assets. During 2000, all
amounts outstanding were paid, therefore at December 31, 2000, there is no
liability remaining related to the restructuring activities undertaken in 1999.

14. OTHER INCOME (EXPENSE), NET

YEAR ENDED DECEMBER 31,
----------------------------

2000 1999 1998
-------- -------- --------
Foreign exchange gain (loss) $ 4,685 $(2,674) $ 2,113
Change in fair market value of financial and commodity
market transactions 2,374 6,150 366
Equity swap (2,147) (6,858) (3,283)
Loss provisions --- (2,250) (750)
Gain on sale of corporate assets --- 443 7,593
Other 332 1,575 2,441
-------- -------- --------

$ 5,244 $(3,614) $ 8,480
======== ======== ========

The net foreign exchange gain (loss) consists primarily of noncash adjustments
related to deferred taxes in Colombia associated with valuation of the Colombian
peso versus the U.S. dollar.

15. EARNINGS PER ORDINARY SHARE

The following table reconciles the numerators and denominators of the basic and
diluted earnings per ordinary share computation for earnings from continuing
operations for the years ended December 31, 2000 and 1999.

INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------

YEAR ENDED DECEMBER 31, 2000:

Net earnings before extraordinary item and
cumulative effect of accounting change $ 75,680
Less: Accumulated dividends on preference shares (29,278)
-----------

Earnings available to ordinary shareholders 46,402
Basic earnings per ordinary share 36,551 $ 1.27
=========
Effect of dilutive securities
Stock options --- 2,053
----------- -------------
Earnings available to ordinary shareholders and
assumed conversions $ 46,402
===========
Diluted earnings per ordinary share 38,604 $1.20
============= =========

YEAR ENDED DECEMBER 31, 1999:

Net earnings $ 47,557
Less: Accumulated dividends on preference shares (28,671)
-----------

Earnings available to ordinary shareholders 18,886
Basic earnings per ordinary share 36,135 $ 0.52
=========
Effect of dilutive securities
Stock options --- 62
----------- -------------
Earnings available to ordinary shareholders and
assumed conversions $ 18,886
===========
Diluted earnings per ordinary share 36,197 $ 0.52
============= =========

For the year ended December 31, 1998, the computation of diluted net loss per
ordinary share was antidilutive, and therefore, the amounts reported for basic
and diluted net loss per ordinary share were the same.

At December 31, 2000 and 1999, 5,181,033 shares and 5,193,643 shares of 8%
Convertible Preference Shares, respectively, were outstanding. Each 8%
Convertible Preference Share is convertible any time into four ordinary shares,
subject to adjustment in certain events. The 8% Convertible Preference Shares
were not included in the computation of diluted earnings per ordinary share
because the effect of assuming conversion was antidilutive.

16. STATEMENTS OF CASH FLOWS

Supplemental disclosures of cash payments and noncash investing and financing
activities follow:

YEAR ENDED DECEMBER 31,
-------------------------
2000 1999 1998
------- ------- -------
Cash paid during the year for:

Interest (net of amounts capitalized) $14,158 $22,810 $24,517
Income taxes 19,004 5,564 4,339

Noncash financing activities:
8% Convertible Preference Shares issued
in lieu of cash dividend $ --- $13,747 $ ---
Conversion of preference shares into
ordinary shares 5,406 192 297

At December 31, 2000, the Company had an accrual of $14.5 million for dividends
declared with respect to the 8% Convertible Preference Shares which was paid in
2001.

17. RELATED PARTY TRANSACTIONS

Pursuant to a financial advisory agreement (the "Financial Advisory Agreement")
between Triton and Hicks, Muse & Co. Partners L.P. ("Hicks Muse Partners"), an
affiliate of Hicks Muse, the Company paid Hicks Muse Partners transaction fees
aggregating approximately $9.6 million and $4.4 million for services as
financial advisor to the Company in connection with the First Closing and Second
Closing, respectively, contemplated by the Stock Purchase Agreement. In
accordance with the terms of the Financial Advisory Agreement, the Company has
retained Hicks Muse Partners as its exclusive financial advisor in connection
with any Sale Transaction (defined below) unless Hicks Muse Partners and the
Company agree to retain an additional financial advisor in connection with any
particular Sale Transaction. The Financial Advisory Agreement requires the
Company to pay a fee to Hicks Muse Partners in connection with any Sale
Transaction (unless the Chief Executive Officer of the Company elects not to
retain a financial advisor) in an amount equal to the lesser of (i) the amount
of fees then charged by first-tier investment banking firms for similar advisory
services rendered in similar transactions or (ii) 1.5% of the Transaction Value
(as defined in the Financial Advisory Agreement); provided that such fee will be
divided equally between Hicks Muse Partners and any additional financial advisor
which the Company and Hicks Muse Partners agree will be retained by the Company
with respect to any such transaction. A "Sale Transaction" is defined as any
merger, sale of securities representing a majority of the combined voting power
of the Company, sale of assets of the Company representing more than 50% of the
total market value of the assets of the Company and its subsidiaries or other
similar transaction. The Company is also required to reimburse Hicks Muse
Partners for reasonable disbursements and out-of-pocket expenses of Hicks Muse
Partners incurred in connection with its advisory services.

Pursuant to a monitoring agreement (the "Monitoring Agreement") between Triton
and Hicks Muse Partners, Hicks Muse Partners will provide financial oversight
and monitoring services as requested by the Company and the Company will pay to
Hicks Muse Partners an annual fee of $.5 million. In addition, the Company will
reimburse Hicks Muse Partners for reasonable disbursements and out-of-pocket
expenses incurred by Hicks Muse Partners or its affiliates for the account of
the Company or in connection with the performance of its services. During the
years ended December 31, 2000 and 1999, the Company paid Hicks Muse Partners $.5
million and $.6 million, respectively, under the terms of the Monitoring
Agreement.

The Financial Advisory Agreement and the Monitoring Agreement will remain in
effect until the earlier of (i) September 30, 2008, or (ii) the date on which
HM4 Triton, L.P. and its affiliates cease to own beneficially, directly or
indirectly, at least 5% of the Company's outstanding ordinary shares (determined
after giving effect to the conversion of all 8% Convertible Preference Shares
held by HM4 Triton, L.P. and its affiliates). The Company has agreed to
indemnify Hicks Muse Partners with respect to liabilities incurred as a result
of Hicks Muse Partners' performance of services for the Company pursuant to the
Financial Advisory Agreement and the Monitoring Agreement.

In 1999, the Company sold its hunting lease and related facilities to HMTF
Operating, L.P., an affiliate of Hicks Muse, for proceeds of $.9 million and
recognized a gain of $.4 million in other income (expense), net. From time to
time HMTF Operating, L.P. permits the Company to use this facility for business
purposes for a fee. During 2000, the Company paid approximately $.1 million to
HMTF Operating, L.P. in connection with the use of this facility.

Both Cooper Cameron Corporation ("Cooper Cameron") and Oceaneering
International, Inc. ("Oceaneering") were winning bidders to provide services as
subcontractors for the Company's offshore development program in Equatorial
Guinea. Cooper Cameron has provided, and is continuing to provide, certain
subsea equipment and related services. During 2000, the Company paid Cooper
Cameron approximately $44 million. The Company expects the amounts to be paid
under Cooper Cameron's current contracts will amount to approximately $40
million during 2001. Oceaneering also has provided, and is continuing to
provide, certain subsea equipment and related services. During 2000, the Company
paid Oceaneering approximately $2.6 million. The Company expects the amounts to
be paid under Oceaneering's current contracts will amount to approximately $7
million during 2001. Mr. Erikson, a director of Triton, is the Chairman,
President and Chief Executive Officer of Cooper Cameron Corporation, and Mr.
Huff, a director of Triton, is the Chairman and Chief Executive Officer of
Oceaneering International.

In November 2000, the Company purchased from a subsidiary of Holly Corporation a
one-half interest in a business aircraft for a purchase price of approximately
$1.1 million, which was based on an independent appraisal of the aircraft. In
addition, the Company agreed to reimburse that entity for its pro rata share of
the costs of maintaining and operating the aircraft. Mr. Norsworthy, a director
of Triton, is the Chairman and Chief Executive Officer of Holly Corporation.

18. COMMITMENTS AND CONTINGENCIES

For internal planning purposes, the Company's capital spending program for the
year ending December 31, 2001, is approximately $320 million, excluding
capitalized interest and acquisitions, of which approximately $253 million
relates to exploration and development activities in Equatorial Guinea, $39
million relates to exploration and development activities in Colombia and $28
million relates to the Company's exploration activities in other parts of the
world.

During the normal course of business, the Company is subject to the terms of
various operating agreements and capital commitments associated with the
exploration and development of its oil and gas properties. Management believes
that such commitments, including the capital requirements in Colombia,
Equatorial Guinea and other parts of the world, as discussed previously, will be
met without any material adverse effect on the Company's operations or
consolidated financial condition. See Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Requirements.

The Company leases office space, other facilities and equipment under various
operating leases that expire through 2005. Total rental expense was $1.3
million, $1.3 million and $2.1 million for the years ended December 31, 2000,
1999 and 1998, respectively.

At year-end 2000, the Company leased a floating production, storage and
offloading vessel ("FPSO") as the cornerstone of the first phase of development
in the Ceiba field. The FPSO lease has a two-year minimum lease period. At the
completion of the minimum lease period, the Company can purchase the FPSO at a
fixed price negotiated at inception of the lease that is not considered a
bargain purchase option, terminate the lease, or elect to extend the lease for
one or more one-year secondary terms up to a maximum of five additional years.
At December 31, 2000, the minimum payments required under terms of the leases
are as follows: 2001 -- $31.4 million; 2002 -- $28.9 million; 2003 -- $1.9
million; 2004 -- $1.7 million; and 2005 -- $1 million.

GUARANTEES

At December 31, 2000, the Company had guaranteed the performance of a total of
$7.3 million in future exploration expenditures to be incurred through 2001 in
Greece. This commitment is backed primarily by an unsecured letter of credit.

ENVIRONMENTAL MATTERS

The Company is subject to extensive environmental laws and regulations. These
laws regulate the discharge of oil, gas or other materials into the environment
and may require the Company to remove or mitigate the environmental effects of
the disposal or release of such materials at various sites. The Company believes
that the level of future expenditures for environmental matters, including
cleanup obligations, is impracticable to determine with a precise and reliable
degree of accuracy. Management believes that such costs, when finally
determined, will not have a material adverse effect on the Company's operations
or consolidated financial condition.

LITIGATION

During July through October 1998, eight lawsuits were filed against the Company
and Thomas G. Finck and Peter Rugg, in their capacities as officers of the
Company. The lawsuits were filed in the United States District Court for the
Eastern District of Texas, Texarkana Division, and have been consolidated and
are styled In re: Triton Energy Limited Securities Litigation. The consolidated
complaint alleges violations of Sections 10(b) and 20(a) of the Exchange Act,
and Rule 10b-5 promulgated thereunder, in connection with disclosures concerning
the Company's properties, operations and value relating to a prospective sale in
1998 of the Company or of all or a part of its assets. The lawsuits seek
recovery of an unspecified amount of compensatory damages, fees and costs. The
Company has filed a motion to dismiss the claims, which is pending.

The Company believes its disclosures have been accurate and intends to
vigorously defend these actions. There can be no assurance that the litigation
will be resolved in the Company's favor. An adverse result could have a material
adverse effect on the Company's financial position or results of operations.

In November 1999, a lawsuit was filed against the Company, one of its
subsidiaries and Thomas G. Finck and Peter Rugg, in their capacities as former
officers of the Company, in the District Court of the State of Texas for Dallas
County. The lawsuit is styled Aaron Sherman, et al. vs. Triton Energy
Corporation et al. and, as amended, alleges as causes of action fraud, negligent
misrepresentation and violations of the Texas Securities fraud statutes in
connection with the Company's 1996 reorganization as a Cayman Islands
corporation and disclosures concerning the prospective sale by the Company of
all or a substantial part of its assets announced in March 1998. In their most
recent filing, the plaintiffs asserted actual damages of up to $10 million and
sought punitive damages of up to $50 million. The Company has filed various
motions to dispose of the lawsuit on the grounds that the plaintiffs do not have
standing and have not plead causes of action cognizable in law. The Court has
dismissed all claims of certain plaintiffs and some claims of the remaining
plaintiffs for failure to plead viable causes of action. The Court entered an
order for proceedings in connection with further examination of plaintiffs'
claims.

In August 1997, the Company was sued in the Superior Court of the State of
California for the County of Los Angeles, by David A. Hite, Nordell
International Resources Ltd., and International Veronex Resources, Ltd. The
action was removed to the United States District Court for the Central District
of California. The Company and the plaintiffs were adversaries in a 1990
arbitration proceeding in which the interest of Nordell International Resources
Ltd. in the Enim oil field in Indonesia was awarded to the Company (subject to a
5% net profits interest for Nordell), and Nordell was ordered to pay the Company
nearly $1 million. The arbitration award was followed by a series of legal
actions by the parties in which the validity of the award and its enforcement
were at issue. As a result of these proceedings, the award was ultimately
upheld and enforced. The current suit alleges that the plaintiffs were damaged
in amounts aggregating $13 million primarily because of the Company's
prosecution of various claims against the plaintiffs, as well as alleged
misrepresentations, infliction of emotional distress and improper accounting
practices. The suit seeks specific performance of the arbitration award,
damages for alleged fraud and misrepresentation in accounting for Enim field
operating results, an accounting for Nordell's 5% net profit interest, and
damages for emotional distress and various other alleged torts. The suit seeks
interest, punitive damages and attorneys fees in addition to the alleged actual
damages. In August 1998, the district court dismissed all claims asserted by the
plaintiffs other than claims for malicious prosecution and abuse of the legal
process, which the court held could not be subject to a motion to dismiss. The
abuse of process claim was later withdrawn, and the damages sought were reduced
to approximately $700,000 (not including punitive damages). The lawsuit was
tried and the jury found in favor of the plaintiffs and assessed compensatory
damages against the Company in the amount of approximately $700,000 and punitive
damages in the amount of approximately $11 million. The Company believes it has
acted appropriately and has appealed the verdict. Nordell has cross-appealed
from the dismissal of its claims for an audit and an accounting related to the
5% net profits interest. Enforcement of the judgment has been stayed without a
bond pending the outcome of the appeal.

The Company is subject to certain other litigation matters, none of which is
expected to have a material adverse effect on the Company's operations or
consolidated financial condition.

19. GEOGRAPHIC INFORMATION

Triton's operations are primarily related to crude oil and natural gas
exploration and production. The Company's principal properties, operations and
oil and gas reserves are located in Colombia, Malaysia-Thailand and Equatorial
Guinea. The Company is exploring for oil and gas in these areas, as well as in
southern Europe, Africa and the Middle East. During the three-year period ended
December 31, 2000, all sales were derived from oil and gas production in
Colombia. Financial information about the Company's operations by geographic
area is presented below:

CORPORATE
MALAYSIA- EQUATORIAL AND
COLOMBIA THAILAND GUINEA EXPLORATION OTHER TOTAL
-------- --------- ---------- ----------- --------- -----------

YEAR ENDED DECEMBER 31, 2000:
Sales and other operating revenues $328,467 $ --- $ --- $ --- $ --- $ 328,467
Operating income (loss) 216,574 --- (2,418) (57,512) (17,955) 138,689
Depreciation, depletion and amortization 52,774 --- 266 72 1,961 55,073
Writedown of assets --- --- --- 55,369 --- 55,369
Capital expenditures and investments 41,454 8,577 157,388 23,461 1,831 232,711
Assets 526,908 101,765 270,885 53,024 241,698 1,194,280

YEAR ENDED DECEMBER 31, 1999:
Sales and other operating revenues $ 247,878 $ --- $ --- $ --- $ --- $ 247,878
Operating income (loss) 115,877 --- (469) (7,214) (16,334) 91,860
Depreciation, depletion and amortization 59,728 --- 16 144 1,455 61,343
Capital expenditures and investments 79,889 8,453 19,968 12,419 754 121,483
Assets 476,543 93,188 37,229 85,250 282,265 974,475

YEAR ENDED DECEMBER 31, 1998:
Sales and other operating revenues $ 160,881 $ 63,237 $ --- $ 4,500 $ --- $ 228,618
Operating income (loss) (220,697) 62,538 (124) (79,703) (39,360) (277,346)
Depreciation, depletion and amortization 53,641 49 1 175 4,945 58,811
Writedown of assets 251,312 --- --- 76,664 654 328,630
Capital expenditures and investments 106,624 25,319 5,913 41,603 756 180,215
Assets 468,533 84,735 10,766 78,086 112,160 754,280

During 1998, the Company sold one-half of the shares of the subsidiary through
which the Company owned its 50% share of Block A-18 resulting in a gain of $63.2
million which is included in Malaysia-Thailand sales and other operating
revenues and operating income (loss). See note 2 - Asset Acquisition and
Dispositions. After the sale, which resulted in a 50% ownership in the
previously wholly owned subsidiary, the Company's remaining ownership is
accounted for using the equity method. This investment in Block A-18 is
presented in Malaysia-Thailand assets.

Exploration operating income (loss) included writedowns of oil and gas
properties and other assets totaling $55.4 million for the year ended December
31, 2000. Colombia operating income (loss) for the year ended December 31,
1998, included an SEC full cost ceiling limitation writedown of $241 million.
Additionally, exploration operating income (loss) included writedowns of oil and
gas properties and other assets totaling $76.7 million for the year ended
December 31, 1998.

At December 31, 2000, corporate assets were principally cash and equivalents and
the U.S. deferred tax asset. Exploration assets included $32.2 million, $14.1
million and $6.4 million in Italy, Oman and Gabon, respectively.

20. QUARTERLY FINANCIAL DATA (UNAUDITED)

The Company adopted SEC Staff Accounting Bulletin (SAB)101, "Revenue Recognition
in Financial Statements," effective January 1, 2000, which requires the Company
to record oil revenue on each sale, or tanker lifting, and oil inventories at
cost, rather than at market value as in the past. The schedule below includes
quarterly information as previously reported on Form 10-Q during 2000 and
revised to reflect the change in accounting policy. Additionally, the pro forma
effect of this change in accounting principle on the quarter ended December 31,
1999, is presented below.

QUARTER
----------------------------------
FIRST SECOND THIRD FOURTH
------- ------- ------- -------

YEAR ENDED DECEMBER 31, 2000:
Sales and other operating revenues
As reported $ 74,505 $79,496 $89,096 $89,784
Revised 74,334 69,790 94,559
Gross profit
As reported 44,665 50,634 44,682 26,091
Revised 44,617 43,350 48,730
Net earnings before extraordinary item and
cumulative effect of accounting change
As reported 26,524 28,793 17,649 4,679
Revised 26,367 22,706 21,928
Net earnings (loss)
As reported 26,524 28,793 17,649 (2,283)
Revised 25,022 22,706 21,928

QUARTER
----------------------------------
FIRST SECOND THIRD FOURTH
------- ------- ------- -------
Basic earnings (loss) per ordinary share
Before extraordinary item and
cumulative effect of accounting change
As reported 0.53 0.59 0.28 (0.07)
Revised 0.53 0.42 0.40
Net earnings (loss)
As reported 0.53 0.59 0.28 (0.26)
Revised 0.49 0.42 0.40
Diluted earnings (loss) per ordinary share
Before extraordinary item and
cumulative effect of accounting change
As reported 0.45 0.48 0.26 (0.07)
Revised 0.45 0.38 0.36
Net earnings (loss)
As reported 0.45 0.48 0.26 (0.26)
Revised 0.43 0.38 0.36

QUARTER
-----------------------------------------------
PRO FORMA
FIRST SECOND THIRD FOURTH FOURTH
-------- ------- ------- ------- ----------

YEAR ENDED DECEMBER 31, 1999:
Sales and other operating revenues $49,170 $59,622 $67,295 $71,791 $ 74,082
Gross profit 14,823 25,151 32,349 46,082 47,443
Net earnings 1,887 10,883 11,762 23,025 24,676
Basic earnings (loss) per ordinary share (0.14) 0.11 0.12 0.44 0.48
Diluted earnings (loss) per ordinary share (0.14) 0.11 0.12 0.40 0.43

Gross profit comprises sales and other operating revenues less operating
expenses, depreciation, depletion and amortization, and writedowns pertaining to
operating assets. Gross profit for the third and fourth quarter of 2000
included writedowns totaling $18.7 million and $36.7 million, respectively. See
note 12 - Writedown of Assets. Net earnings (loss) for the fourth quarter of
2000 included an approximate $7 million extraordinary charge for the early
extinguishment of the 2002 Notes. Gross profit for the fourth quarter of 1999
included a nonrecurring credit issued by OCENSA in February 2000 totaling $4.2
million. The credit to pipeline tariffs resulted from OCENSA's compliance with
a Colombian government decree in December 1999 that reduced its 1999 noncash
expenses.

21. OIL AND GAS DATA (UNAUDITED)

The following tables provide additional information about the Company's oil and
gas exploration and production activities. The oil and gas data reflect the
Company's proportionate interest in Block A-18 on an equity investment basis
since the sale of one-half of the subsidiary through which the Company owned its
50% share of Block A-18 in August 1998.

RESULTS OF OPERATIONS

The results of operations for oil and gas producing activities, considering
direct costs only, follow:

TOTAL
COLOMBIA OTHER WORLDWIDE
-------- --------- ---------

YEAR ENDED DECEMBER 31, 2000:
Revenues $328,467 $ --- $ 328,467
Costs:
Production costs 55,237 --- 55,237
General operating expenses 4,035 --- 4,035
Depletion 52,679 --- 52,679
Writedown of assets --- 54,186 54,186
Income tax expense (benefit) 63,288 (3,386) 59,902
-------- --------- ---------

Results of operations $153,228 $(50,800) $ 102,428
======== ========= =========

COLOMBIA
--------

YEAR ENDED DECEMBER 31, 1999:
Revenues $247,878
Costs:
Production costs 68,130
General operating expenses 3,954
Depletion 59,512
Income tax expense 42,083
--------

Results of operations $ 74,199
========

MALAYSIA- TOTAL
COLOMBIA THAILAND OTHER WORLDWIDE
---------- -------- --------- ----------

YEAR ENDED DECEMBER 31, 1998:
Revenues $ 160,881 $63,237 $ 4,500 $ 228,618
Costs:
Production costs 73,546 --- --- 73,546
General operating expenses 2,460 --- --- 2,460
Depletion 53,304 --- --- 53,304
Writedown of assets 251,312 --- 76,664 327,976
Income tax benefit (76,048) --- (22,527) (98,575)
---------- -------- --------- ----------

Results of operations $(143,693) $63,237 $(49,637) $(130,093)
========== ======== ========= ==========

Production from the Ceiba field in Equatorial Guinea began in November 2000, but
the first sale did not occur until January 2001. Malaysia-Thailand revenues for
the year ended December 31, 1998, included a gain of $63.2 million from the sale
of one-half of the shares of the subsidiary through which the Company owned its
50% share of Block A-18. Other revenues for the year ended December 31, 1998,
included a gain of $4.5 million from the sale of the Company's Bangladesh
subsidiary.

Depletion includes depreciation on support equipment and facilities calculated
on the unit-of-production method.

COSTS INCURRED AND CAPITALIZED COSTS

The costs incurred in oil and gas acquisition, exploration and development
activities and related capitalized costs follow:

EQUATORIAL TOTAL
COLOMBIA GUINEA OTHER WORLDWIDE
-------- ---------- ------- ---------

DECEMBER 31, 2000:
Costs incurred:
Property acquisition $ --- $ --- $ 4,750 $ 4,750
Exploration --- 25,643 26,776 52,419
Development 52,326 169,899 --- 222,225
Depletion per equivalent
barrel of production 4.37 --- --- 4.37

Cost of properties at year-end:
Unevaluated $ --- $ 18,207 $49,686 $ 67,893
======== ========== ======= =========

Evaluated $562,598 $ 212,428 $54,162 $ 829,188
======== ========== ======= =========

Support equipment and
facilities $311,632 $ --- $ --- $ 311,632
======== ========== ======= =========
Accumulated depletion and
depreciation at year-end $471,563 $ --- $54,162 $ 525,725
======== ========== ======= =========

EQUATORIAL TOTAL
COLOMBIA GUINEA OTHER WORLDWIDE
-------- ---------- ------- ---------

DECEMBER 31, 1999:
Costs incurred:
Property acquisition $ 6,400 $ --- $ 20 $ 6,420
Exploration 155 23,631 13,051 36,837
Development 80,782 --- --- 80,782
Depletion per equivalent
barrel of production 3.80 --- --- 3.80

Cost of properties at year-end:
Unevaluated $ --- $ 5,772 $72,755 $ 78,527
======== ========== ======= =========

Evaluated $530,947 $ 29,322 $ 680 $ 560,949
======== ========== ======= =========

Support equipment and
facilities $303,244 $ --- $ --- $ 303,244
======== ========== ======= =========
Accumulated depletion and
depreciation at year-end $419,651 $ --- $ 680 $ 420,331
======== ========== ======= =========

MALAYSIA- EQUATORIAL TOTAL
COLOMBIA THAILAND GUINEA OTHER WORLDWIDE
-------- --------- ---------- ------- ---------

DECEMBER 31, 1998:
Costs incurred:
Property acquisition $ --- $ --- $ --- $ 500 $ 500
Exploration 2,886 17,739 5,913 43,153 69,691
Development 83,088 1,026 --- --- 84,114
Depletion per equivalent
barrel of production 4.07 --- --- --- 4.07

Cost of properties at year-end:
Unevaluated $ --- $ --- $ 10,754 $60,082 $ 70,836
======== ========= ========== ======= =========

Evaluated $467,147 $ --- $ --- $76,367 $ 543,514
======== ========= ========== ======= =========

Support equipment and
facilities $289,659 $ --- $ --- $ --- $ 289,659
======== ========= ========== ======= =========
Accumulated depletion and
depreciation at year-end $360,324 $ --- $ --- $76,367 $ 436,691
======== ========= ========== ======= =========

Development costs include additions to production facilities and equipment,
additions to development wells, including those in progress, and depreciation of
support equipment and related facilities.

A summary of costs excluded from depletion at December 31, 2000, by year
incurred follows:

DECEMBER 31,
--------------------------------------------------
TOTAL 2000 1999 1998 1997 AND PRIOR
------- ------- ------- ------- --------------

Property acquisition $ 1,850 $ --- $ --- $ 500 $ 1,350
Exploration 51,519 15,766 8,194 15,475 12,084
Capitalized interest 14,524 10,744 2,763 718 299
------- ------- ------- ------- --------------

Total worldwide $67,893 $26,510 $10,957 $16,693 $ 13,733
======= ======= ======= ======= ==============

The Company excludes from its depletion computation property acquisition and
exploration costs of unevaluated properties and major development projects in
progress. Excluded costs include exploration costs of $28.1 million, $13.6
million and $6.4 million in Italy, Oman and Gabon, respectively, where there are
no proved reserves at December 31, 2000. Subject to the possible extension or
modification of the Company's commitments, the Company expects to complete its
contractual obligations in Italy and Oman over the next 12 to 18 months. With
respect to the remaining excluded costs, the Company is unable to predict either
the timing of the inclusion of these costs and any related oil and gas reserves
in its depletion computation or their potential future impact on depletion
rates. Drilling or other exploration activities are being conducted in each of
these cost centers.

The Company's share of costs incurred for Block A-18 were $8.6 million and $8.2
million for the years ended December 31, 2000 and 1999, respectively. Net
capitalized costs were $101.8 million and $90.2 million at December 31, 2000
and 1999, respectively.

OIL AND GAS RESERVE DATA (OIL RESERVES ARE STATED IN THOUSANDS OF BARRELS AND
GAS RESERVES ARE STATED IN MILLIONS OF CUBIC FEET.)

The following tables present the Company's estimates of its proved oil and gas
reserves. The estimates for the proved reserves in the Cusiana and Cupiagua
fields in Colombia and the Ceiba field in Equatorial Guinea were prepared by the
Company's independent petroleum engineers, DeGolyer and MacNaughton and
Netherland, Sewell & Associates, Inc., respectively. The estimates for proved
reserves in Malaysia-Thailand were prepared by the internal petroleum engineers
of the operating company, Carigali-Triton Operating Company (CTOC). The Company
emphasizes that reserve estimates are approximate and are expected to change as
additional information becomes available. Reservoir engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
measured in an exact way, and the accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. Accordingly, there can be no assurance that the
reserves set forth herein will ultimately be produced, and there can be no
assurance that the proved undeveloped reserves will be developed within the
periods anticipated.

Production from the Ceiba field in Equatorial Guinea began in November 2000, but
the first sale did not occur until January 2001. As of December 31, 2000, gas
sales had not yet commenced from the Company's interest in the Malaysia-Thailand
Joint Development Area. In estimating its reserves attributable to such
interest, the Company assumed that production from the interest would be sold at
the base price in the gas sales agreement of $2.30. The base price is subject
to annual adjustments based on various indices. There can be no assurance as to
what the actual price will be when gas sales commence.

EQUITY INVESTMENT
COLOMBIA EQUATORIAL GUINEA TOTAL WORLDWIDE MALAYSIA-THAILAND
-------------------- -------------------- -------------------- --------------------
OIL GAS OIL GAS OIL GAS OIL GAS
--------- --------- --------- --------- --------- --------- --------- ---------

PROVED DEVELOPED AND
UNDEVELOPED RESERVES AS OF
DECEMBER 31, 1999 125,571 11,566 32,033 --- 157,604 11,566 13,223 553,862
Revisions (8,000) (231) --- --- (8,000) (231) (99) 27,846
Purchases --- --- --- --- --- --- --- ---
Extensions and discoveries --- --- 43,134 --- 43,134 --- --- ---
Production (11,167) (470) --- --- (11,167) (470) --- ---
--------- -------- ---------- --------- --------- --------- --------- ---------

AS OF DECEMBER 31, 2000 106,404 10,865 75,167 --- 181,571 10,865 13,124 581,708
========= ======== ========== ========= ========= ========= ========= =========

PROVED DEVELOPED RESERVES AT
DECEMBER 31, 2000 81,101 10,865 24,663 --- 105,764 10,865 --- ---
========= ======== ========== ========= ========= ========= ========= =========

EQUITY INVESTMENT
COLOMBIA EQUATORIAL GUINEA TOTAL WORLDWIDE MALAYSIA-THAILAND
------------------ ------------------ ------------------ ------------------
OIL GAS OIL GAS OIL GAS OIL GAS
-------- -------- -------- -------- -------- -------- -------- --------

PROVED DEVELOPED AND
UNDEVELOPED RESERVES AS OF
DECEMBER 31, 199 135,327 12,284 --- --- 135,327 12,284 8,017 570,312
Revisions (567) (259) --- --- (567) (259) 5,206 (16,450)
Purchases 3,280 --- --- --- 3,280 --- --- ---
Extensions and discoveries --- --- 32,033 --- 32,033 --- --- ---
Production (12,469) (459) --- --- (12,469) (459) --- ---
-------- -------- -------- -------- -------- -------- -------- --------

AS OF DECEMBER 31, 1999 125,571 11,566 32,033 --- 157,604 11,566 13,223 553,862
======== ======== ======== ======== ======== ======== ======== ========

PROVED DEVELOPED RESERVES AT
DECEMBER 31, 1999 91,859 11,566 --- --- 91,859 11,566 --- ---
======== ======== ======== ======== ======== ======== ======== ========

EQUITY INVESTMENT
COLOMBIA EQUATORIAL GUINEA TOTAL WORLDWIDE MALAYSIA-THAILAND
----------------- -------------------- -------------------- ------------------
OIL GAS OIL GAS OIL GAS OIL GAS
-------- ------- -------- ---------- -------- ---------- -------- --------

PROVED DEVELOPED AND
UNDEVELOPED RESERVES AS OF
DECEMBER 31, 1997 145,999 14,619 29,800 1,223,800 175,799 1,238,419 --- ---
Revisions (693) (1,832) (6,583) (41,588) (7,276) (43,420) --- ---
Sales --- --- (15,200) (625,400) (15,200) (625,400) --- ---
Equity investment --- --- (8,017) (570,312) (8,017) (570,312) 8,017 570,312
Extensions and discoveries --- --- --- 13,500 --- 13,500 --- ---
Production (9,979) (503) --- --- (9,979) (503) --- ---
-------- ------- -------- ---------- -------- ---------- -------- --------

AS OF DECEMBER 31, 1998 135,327 12,284 --- --- 135,327 12,284 8,017 570,312
======== ======= ======== ========== ======== ========== ======== ========

PROVED DEVELOPED RESERVES AT
DECEMBER 31, 1998 86,039 12,284 --- --- 86,039 12,284 --- ---
======== ======= ======== ========== ======== ========== ======== ========

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH INFLOWS AND CHANGES THEREIN

The following table presents for the net quantities of proved oil and gas
reserves a standardized measure of future net cash inflows discounted at an
annual rate of 10%. The future net cash inflows were calculated in accordance
with SEC guidelines. Future cash inflows were computed by applying year-end
prices of oil and gas relating to the Company's proved reserves to the estimated
year-end quantities of those reserves. The future cash inflow estimates for
2000 attributable to oil reserves were based on the year-end WTI crude oil price
of $26.80 per barrel for the Company's reserves in Colombia and
Malaysia-Thailand, and the year-end Dated Brent crude oil price of $22.54 per
barrel for the Company's reserves in Equatorial Guinea, in each case before
adjustments for oil quality and transportation costs.

In 1999, the Company and the other parties to the production-sharing contract
for Block A-18 executed a gas sales agreement providing for the sale of the
first phase of gas. In estimating discounted future net cash inflows
attributable to such interest, the Company assumed that production from the
interest would be sold at the base price in the gas sales agreement of $2.30.
The base price is subject to annual adjustments based on various indices. There
can be no assurance as to what the actual price will be when gas sales commence.

Future production and development costs were computed by estimating those
expenditures expected to occur in developing and producing the proved oil and
gas reserves at the end of the year, based on year-end costs. The Company
emphasizes that the future net cash inflows should not be construed as
representative of the fair market value of the Company's proved reserves. The
meaningfulness of the estimates is highly dependent upon the accuracy of the
assumptions upon which they were based. Actual future cash inflows may vary
materially.

In connection with the sale to BP of one-half of the shares through which the
Company owned its interest in Block A-18, BP agreed to pay the Company an
additional $65 million each at July 1, 2002, and July 1, 2005, if certain
specific development objectives are met by such dates, or $40 million each if
the objectives are met within one year thereafter. For purposes of calculating
future cash inflows for Malaysia-Thailand at December 31, 2000, the Company
assumed that it would receive an incentive payment of $40 million. There can be
no assurances that the Company will receive any incentive payments.

EQUITY
INVESTMENT
EQUATORIAL TOTAL MALAYSIA-
COLOMBIA GUINEA WORLDWIDE THAILAND
---------- ---------- ---------- ----------
DECEMBER 31, 2000:

Future cash inflows $2,683,051 $1,356,027 $4,039,078 $1,686,677
Future production and
development costs 646,930 573,511 1,220,441 634,547
---------- ---------- ---------- ----------
Future net cash inflows before
income taxes $2,036,121 $ 782,516 $2,818,637 $1,052,130
========== ========== ========== ==========

Future net cash inflows before
income taxes discounted at 10%
per annum $1,261,684 $ 594,589 $1,856,273 $ 283,694
Future income taxes discounted at
10% per annum 382,699 98,903 481,602 17,521
---------- ---------- ---------- ----------
Standardized measure of discounted
future net cash inflows $ 878,985 $ 495,686 $1,374,671 $ 266,173
========== ========== ========== ==========

EQUITY
INVESTMENT
EQUATORIAL TOTAL MALAYSIA-
COLOMBIA GUINEA WORLDWIDE THAILAND
---------- ---------- ---------- ----------
DECEMBER 31, 1999:

Future cash inflows $3,152,352 $ 765,275 $3,917,627 $1,649,881
Future production and
development costs 817,065 399,365 1,216,430 703,419
---------- ---------- ---------- ----------
Future net cash inflows before
income taxes $2,335,287 $ 365,910 $2,701,197 $ 946,462
========== ========== ========== ==========

Future net cash inflows before
income taxes discounted at 10%
per annum $1,414,433 $ 263,849 $1,678,282 $ 266,631
Future income taxes discounted at
10% per annum 391,796 57,589 449,385 15,845
---------- ---------- ---------- ----------
Standardized measure of discounted
future net cash inflows $1,022,637 $ 206,260 $1,228,897 $ 250,786
========== ========== ========== ==========

EQUITY
INVESTMENT
MALAYSIA-
COLOMBIA THAILAND
---------- ----------
DECEMBER 31, 1998:

Future cash inflows $1,481,065 $1,555,929
Future production and
development costs 734,025 695,575
---------- ----------
Future net cash inflows before
income taxes $ 747,040 $ 860,354
========== ==========

Future net cash inflows before
income taxes discounted at 10%
per annum $ 415,127 $ 253,535
Future income taxes discounted at
10% per annum 3,909 8,917
---------- ----------
Standardized measure of discounted
future net cash inflows $ 411,218 $ 244,618
========== ==========

Changes in the standardized measure of discounted future net cash inflows
follow:

DECEMBER 31,
-------------------------------------
2000 1999 1998
----------- ----------- -----------

Total worldwide:
Beginning of year $1,228,897 $ 411,218 $1,069,343
Sales, net of production costs (273,230) (179,748) (87,335)
Sales of reserves --- --- (70,543)
Equity investment --- --- (244,618)
Revisions of quantity estimates (129,433) (6,546) (29,321)
Net change in prices and production costs (98,228) 1,105,963 (579,212)
Extensions, discoveries and improved recovery 414,829 206,260 6,516
Change in future development costs (175,430) (61,728) (46,633)
Purchases of reserves --- 6,400 ---
Development and facilities costs incurred 209,658 70,828 105,808
Accretion of discount 270,120 74,704 120,270
Changes in production rates and other (40,295) (10,567) (30,772)
Net change in income taxes (32,217) (387,887) 197,715
----------- ----------- -----------

End of year $1,374,671 $1,228,897 $ 411,218
=========== =========== ===========

SCHEDULE II

TRITON ENERGY LIMITED AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)

ADDITIONS
-------------------------

BALANCE AT CHARGED TO BALANCE
BEGINNING CHARGED TO OTHER AT CLOSE
CLASSIFICATIONS OF YEAR EARNINGS ACCOUNTS DEDUCTIONS OF YEAR
- ------------------------- ----------- ------------ ----------- ------------ ---------

Year ended Dec. 31, 1998:
Allowance for doubtful
receivables $ 41 $ --- $ --- $ (41) $ ---
=========== ============ =========== ============ =========

Allowance for deferred
tax asset $ 75,092 $ 18,519 $ --- $ --- $ 93,611
=========== ============ =========== ============ =========

Year ended Dec. 31, 1999:
Allowance for deferred
tax asset $ 93,611 $ (11,925) $ --- $ --- $ 81,686
=========== ============ =========== ============ =========

Year ended Dec. 31, 2000:
Allowance for doubtful
receivables $ --- $ 1,183 $ --- $ --- $ 1,183
=========== ============ =========== ============ =========

Allowance for deferred
tax asset $ 81,686 $ (32,991) $ --- $ --- $ 48,695
=========== ============ =========== ============ =========