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

                                       OR

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

                        Commission File Number:  1-11675

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

     CAYMAN ISLANDS                                                NONE
  (State 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


<TABLE>
<CAPTION>


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

<S>     <C>              <C>                                                              <C>



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



</TABLE>


                                      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.



<PAGE>
     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.



<PAGE>
     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%.



<PAGE>
     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.



<PAGE>

     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.


<PAGE>

     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.



<PAGE>

Net  proved  reserves  at  December  31,  2000,  were:


<TABLE>
<CAPTION>

                                 PROVED                PROVED                 TOTAL
                               DEVELOPED             UNDEVELOPED              PROVED
                           -------------------  ----------------------  ------------------
                              OIL        GAS        OIL         GAS       OIL       GAS
                            (MBBLS)    (MMCF)     (MBBLS)      (MMCF)   (MBBLS)    (MMCF)
                           ----------  -------  ------------  --------  --------  --------
<C>                    <S>
  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
                           ==========  =======  ============  ========  ========  ========



</TABLE>
____________________
(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.


<PAGE>

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.


<TABLE>
<CAPTION>

                           OIL PRODUCTION (1)                        GAS PRODUCTION
                        ------------------------                 -----------------------
                         YEAR ENDED DECEMBER 31,                 YEAR ENDED DECEMBER 31,
                        ------------------------                 -----------------------
                         2000     1999     1998                   2000     1999     1998
                        ------   ------   ------                 ------   ------   -----
                                (MBBLS)                                   (MMCF)
     <S>                <C>      <C>      <C>                    <C>      <C>      <C>
     Colombia (2)       11,167   12,469    9,979                   470      459      503


</TABLE>

____________________
(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



<TABLE>
<CAPTION>

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

</TABLE>

____________________________
(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.


<TABLE>
<CAPTION>


                            DEVELOPED         UNDEVELOPED
                             ACREAGE           ACREAGE (1)
                       ------------------  ------------------
                         GROSS     NET(2)   GROSS      NET(2)
                       --------  --------  --------  --------
                                    (In thousands)
<S>                    <C>       <C>       <C>       <C>
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
                       ========  ========  ========  ========


</TABLE>

____________________

(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:



<TABLE>
<CAPTION>

                               PRODUCTIVE WELLS(1)
                           GROSS            NET
                      --------------  --------------
                        OIL     GAS     OIL    GAS
                      ------  ------  ------  ------
<S>                   <C>     <C>     <C>     <C>
Colombia                 105     ---   12.58     ---
Equatorial Guinea(2)       5     ---    4.25     ---
                      ------  ------  ------  ------

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


</TABLE>

___________________

(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)     Our net interest does not take into account the 5% carried interest held
by  the  government  of  Equatorial  Guinea.

     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.


<TABLE>
<CAPTION>

                                             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
                   ------   ------   ------  ------   ------   -----  -------  ------  ------
<S>                <C>      <C>      <C>     <C>      <C>      <C>    <C>      <C>     <C>
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
                   ======   ======   ======  ======   ======   =====  =======  ======  ======


</TABLE>



<TABLE>
<CAPTION>

                                               GROSS DEVELOPMENT 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
                     ------   ------   ------  ------   ------   -----  -------  ------  ------
<S>                  <C>      <C>      <C>     <C>      <C>      <C>    <C>      <C>     <C>
Colombia                14       14       13     ---      ---     ---       14      14      13
Equatorial Guinea        2      ---      ---     ---      ---     ---        2     ---     ---
Malaysia-Thailand      ---      ---      ---     ---      ---     ---      ---     ---     ---
                     ------   ------   ------  ------   ------   -----  -------  ------  ------

            Total       16       14       13     ---      ---     ---       16      14      13
                     ======   ======   ======  ======   ======   =====  =======  ======  ======
 </TABLE>
___________________
(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.



<PAGE>
     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.



<TABLE>
<CAPTION>

                                                  NET 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
                       ------   ------   ------  ------   ------   -----  -------  ------  ------

<S>                    <C>      <C>      <C>     <C>      <C>      <C>    <C>      <C>      <C>
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
                       ======   ======   ======  ======   ======   =====  =======  ======  ======


</TABLE>

<TABLE>
<CAPTION>



                                                 NET DEVELOPMENT 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
                      ------   ------   ------  ------   ------   -----  -------  ------  ------
<S>                   <C>      <C>      <C>     <C>      <C>      <C>    <C>      <C>     <C>
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
                      ======   ======   ======  ======   ======   =====  =======  ======  ======



</TABLE>
__________________

(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.


<PAGE>
                                     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.


<TABLE>
<CAPTION>

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

<S>                                                        <C>         <C>        <C>        <C>         <C>
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

</TABLE>


_________________________

(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.

<PAGE>

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):

<TABLE>
<CAPTION>

                                                     2000        1999       1998
                                                  ---------   ---------   --------
<S>                                               <C>         <C>         <C>
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)

</TABLE>

     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.



<PAGE>

     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  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.

     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.



<PAGE>

     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
     ------------------------------------------

     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.

     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.



<PAGE>

     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.


<PAGE>

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.


<PAGE>

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.


<PAGE>

     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.


<PAGE>

                                    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.)


<TABLE>
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<S>   <C>

 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)



</TABLE>
_____________________
*  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



<TABLE>
<CAPTION>

                                                                                 PAGE
                                                                                 ----

<S>                                                                              <C>

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
</TABLE>



<TABLE>
<CAPTION>

<C>  <C>                                                                          <S>
SCHEDULE:
II  -  Valuation and Qualifying Accounts - Years ended December 31, 2000,
        1999 and 1998  . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  F-46
</TABLE>






  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)







<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                                              --------------------------------
                                                                2000       1999        1998
                                                              ---------  ---------  ----------
<S>                                                           <C>        <C>        <C>
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)
                                                              =========  =========  ==========


</TABLE>

                 See accompanying Notes to Consolidated Financial Statements.



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






<TABLE>
<CAPTION>

                        ASSETS                                           DECEMBER 31,
                                                                    ------------------------
                                                                        2000         1999
                                                                    -----------  -----------
<S>                                                                 <C>          <C>
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
                                                                    ===========  ===========
</TABLE>





  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)



<TABLE>
<CAPTION>


                                                                     YEAR ENDED DECEMBER 31,
                                                              ----------------------------------
                                                                 2000        1999        1998
                                                              ----------  ----------  ----------
<S>                                                           <C>         <C>         <C>
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
                                                              ==========  ==========  ==========


</TABLE>


                  See accompanying Notes to Consolidated Financial Statements.



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


<TABLE>
<CAPTION>

                                                                         YEAR ENDED DECEMBER 31,
                                                     ---------------------------------------------------------------
                                                            2000                 1999                  1998
                                                     -------------------  -------------------   --------------------
<S>                                                  <C>         <C>      <C>         <C>       <C>         <C>
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
                                                     ==========           ==========            ==========
</TABLE>






     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.


<PAGE>
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.


<PAGE>

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.


<PAGE>

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.


<PAGE>

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:



<TABLE>
<CAPTION>

                                                        YEAR ENDED DECEMBER 31,
                                                      --------------------------
                                                       2000      1999     1998
                                                      -------  -------   -------
<S>                                                   <C>      <C>       <C>
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 %
                                                      =======  =======   =======
</TABLE>





<PAGE>

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


<TABLE>
<CAPTION>
                                                   DECEMBER 31, 2000                DECEMBER 31, 1999
                                             ------------------------------  -------------------------------
<S>                                          <C>        <C>       <C>        <C>        <C>       <C>
                                                                    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)
                                             =========  ========  =========  ==========  ========  =========
</TABLE>



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
                     =========

<PAGE>
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.


<PAGE>
The  funding  status  of  the  plans  follows:


<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                 ----------------------------------------
<S>           <C>
                                                         2000                1999
                                                 -------------------  -------------------
                                                  DEFINED              DEFINED
                                                  BENEFIT     SERP     BENEFIT     SERP
                                                   PLAN       PLAN      PLAN       PLAN
                                                 ---------  --------  ---------  --------
<S>                                              <C>        <C>       <C>        <C>
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)
                                                 =========  ========  =========  ========
</TABLE>



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:



<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31,
                                                 -------------------------------------
                                                   2000           1999           1998
                                                 -------        -------        -------
Components of net periodic pension cost:
<S>                                              <C>            <C>            <C>
 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
                                                 =======        =======        =======

</TABLE>

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:


<TABLE>
<CAPTION>


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

<S>                                  <C>         <C>          <C>
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
                                     ==========  ===========  ===========


</TABLE>

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:



<TABLE>
<CAPTION>

                                           DECEMBER 31, 2000    DECEMBER 31, 1999    DECEMBER 31, 1998
                                         --------------------- -------------------- --------------------
                                                      WEIGHTED             WEIGHTED             WEIGHTED
                                                      AVERAGE              AVERAGE              AVERAGE
                                                      EXERCISE             EXERCISE             EXERCISE
                                            SHARES     PRICE     SHARES     PRICE     SHARES      PRICE
<S>                                      <C>           <C>     <C>          <C>     <C>           <C>
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


</TABLE>

<PAGE>

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


<TABLE>
<CAPTION>

                         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
--------------  --------------  -----------  ---------  --------------  ---------
<S>             <C>             <C>          <C>        <C>             <C>
 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
                ==============                          ==============

</TABLE>

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:


<TABLE>
<CAPTION>

                                                       YEAR ENDED DECEMBER 31,
                                                    ----------------------------
                                                     2000     1999       1998
                                                    -------  -------  ----------
<S>                                                 <C>      <C>      <C>
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)

</TABLE>

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.


<TABLE>
<CAPTION>

12.  WRITEDOWN OF ASSETS

                                                            YEAR ENDED DECEMBER 31,
                                                         ----------------------------
<S>                                                      <C>       <C>       <C>
                                                           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
                                                         ========  ========  ========
</TABLE>



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


<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                              ----------------------------
    <S>                                                       <C>       <C>       <C>
                                                                 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
                                                              ========  ========  ========
</TABLE>



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.


<TABLE>
<CAPTION>

                                                    INCOME        SHARES      PER-SHARE
                                                  (NUMERATOR)  (DENOMINATOR)    AMOUNT
                                                  -----------  -------------  ---------
                                                  <S>          <C>            <C>
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
                                                               =============  =========
</TABLE>



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:


<TABLE>
<CAPTION>

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

</TABLE>

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.


<PAGE>

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:


<TABLE>
<CAPTION>
                                                                                          CORPORATE
                                                      MALAYSIA-  EQUATORIAL                  AND
                                            COLOMBIA  THAILAND     GUINEA    EXPLORATION    OTHER       TOTAL
                                            --------  ---------  ----------  -----------  ---------  -----------
<S>                                        <C>        <C>        <C>         <C>          <C>        <C>
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

</TABLE>

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.


<TABLE>
<CAPTION>
                                                                     QUARTER
                                                      ----------------------------------
                                                       FIRST   SECOND    THIRD    FOURTH
                                                      -------  -------  -------  -------

<S>                                                  <C>       <C>      <C>      <C>
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


<PAGE>

                                                                    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


</TABLE>



<TABLE>
<CAPTION>
                                                             QUARTER
                                            -----------------------------------------------
                                                                                 PRO FORMA
                                             FIRST    SECOND    THIRD   FOURTH     FOURTH
                                            --------  -------  -------  -------  ----------

<S>                                         <C>       <C>      <C>      <C>      <C>
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
</TABLE>



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:


<TABLE>
<CAPTION>

                                                            TOTAL
                                     COLOMBIA    OTHER    WORLDWIDE
                                     --------  ---------  ---------
<S>                                  <C>       <C>        <C>
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
                                     ========  =========  =========
</TABLE>



<TABLE>
<CAPTION>
                                 COLOMBIA
                                 --------
<S>                              <C>
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
                                 ========
</TABLE>




<TABLE>
<CAPTION>

                                             MALAYSIA-             TOTAL
                                  COLOMBIA   THAILAND    OTHER    WORLDWIDE
                                 ----------  --------  ---------  ----------
<S>                              <C>         <C>       <C>        <C>
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)
                                 ==========  ========  =========  ==========
</TABLE>




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:


<TABLE>
<CAPTION>

                                           EQUATORIAL            TOTAL
                                 COLOMBIA    GUINEA     OTHER   WORLDWIDE
                                 --------  ----------  -------  ---------
<S>                              <C>       <C>         <C>      <C>
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
                                 ========  ==========  =======  =========
</TABLE>




<TABLE>
<CAPTION>

                                           EQUATORIAL             TOTAL
                                 COLOMBIA    GUINEA     OTHER   WORLDWIDE
                                 --------  ----------  -------  ---------
<S>                              <C>       <C>         <C>      <C>
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
                                 ========  ==========  =======  =========
</TABLE>




<PAGE>


<TABLE>
<CAPTION>

                                           MALAYSIA-  EQUATORIAL             TOTAL
                                 COLOMBIA  THAILAND     GUINEA     OTHER   WORLDWIDE
                                 --------  ---------  ----------  -------  ---------
<S>                              <C>       <C>        <C>         <C>      <C>
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
                                 ========  =========  ==========  =======  =========
</TABLE>



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:


<TABLE>
<CAPTION>

                                         DECEMBER 31,
                      --------------------------------------------------
                       TOTAL     2000    1999     1998    1997 AND PRIOR
                      -------  -------  -------  -------  --------------
<S>                   <C>      <C>      <C>      <C>      <C>
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
                      =======  =======  =======  =======  ==============
</TABLE>



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.


<TABLE>
<CAPTION>
                                                                                                    EQUITY INVESTMENT
                                       COLOMBIA        EQUATORIAL GUINEA       TOTAL WORLDWIDE      MALAYSIA-THAILAND
                                --------------------  --------------------  --------------------  --------------------
                                   OIL        GAS       OIL         GAS        OIL       GAS         OIL        GAS
                                ---------  ---------  ---------  ---------  ---------  ---------  ---------  ---------
<S>                             <C>        <C>        <C>        <C>        <C>        <C>        <C>        <C>
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        ---        ---
                                =========  ========  ==========  =========  =========  =========  =========  =========


</TABLE>




<TABLE>
<CAPTION>

                                                                                             EQUITY INVESTMENT
                                     COLOMBIA         EQUATORIAL GUINEA    TOTAL WORLDWIDE   MALAYSIA-THAILAND
                                 ------------------  ------------------  ------------------  ------------------
                                   OIL        GAS       OIL       GAS       OIL       GAS       OIL      GAS
                                 --------  --------  --------  --------  --------  --------  --------  --------
<S>                              <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>
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       ---       ---
                                 ========  ========  ========  ========  ========  ========  ========  ========
</TABLE>





<TABLE>
<CAPTION>

                                                                                                EQUITY INVESTMENT
                                     COLOMBIA        EQUATORIAL GUINEA      TOTAL WORLDWIDE     MALAYSIA-THAILAND
                                -----------------  --------------------  --------------------  ------------------
                                   OIL      GAS       OIL        GAS        OIL        GAS        OIL       GAS
                                --------  -------  --------  ----------  --------  ----------  --------  --------
<S>                             <C>       <C>      <C>       <C>         <C>       <C>         <C>       <C>
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       ---       ---
                                ========  =======  ========  ==========  ========  ==========  ========  ========
</TABLE>






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.


<TABLE>
<CAPTION>

                                                                                EQUITY
                                                                              INVESTMENT
                                                       EQUATORIAL     TOTAL    MALAYSIA-
                                            COLOMBIA     GUINEA     WORLDWIDE  THAILAND
                                           ----------  ----------  ----------  ----------
DECEMBER  31,  2000:
<S>                                        <C>         <C>         <C>         <C>
      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
                                           ==========  ==========  ==========  ==========
</TABLE>




<PAGE>


<TABLE>
<CAPTION>

                                                                                EQUITY
                                                                              INVESTMENT
                                                       EQUATORIAL    TOTAL     MALAYSIA-
                                            COLOMBIA     GUINEA    WORLDWIDE   THAILAND
                                           ----------  ----------  ----------  ----------
DECEMBER  31,  1999:
<S>                                        <C>         <C>         <C>         <C>
      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
                                           ==========  ==========  ==========  ==========
</TABLE>





<TABLE>
<CAPTION>

                                                         EQUITY
                                                       INVESTMENT
                                                        MALAYSIA-
                                            COLOMBIA    THAILAND
                                           ----------  ----------
DECEMBER  31,  1998:
<S>                                        <C>         <C>
      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
                                           ==========  ==========
</TABLE>




<PAGE>

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

<TABLE>
<CAPTION>
                                                              DECEMBER 31,
                                                 -------------------------------------
                                                    2000         1999         1998
                                                 -----------  -----------  -----------
<S>                                              <C>          <C>          <C>
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
                                                 ===========  ===========  ===========
</TABLE>





                                                                     SCHEDULE II

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



<TABLE>
<CAPTION>

                                              ADDITIONS
                                        -------------------------
<S>                        <C>          <C>           <C>          <C>           <C>
                            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
                           ===========  ============  ===========  ============  =========
</TABLE>