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

                                    FORM 10-K/A
                                (AMENDMENT NO. 2)
(Mark  One)
 (    X    )        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
                      OF THE SECURITIES EXCHANGE ACT OF 1934
                  FOR THE FISCAL YEAR ENDED: December 31, 1999

                                       OR

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

                        Commission File Number:  1-11675

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


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

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

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

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



                                               NAME  OF  EACH  EXCHANGE
      TITLE  OF  EACH  CLASS                     ON WHICH REGISTERED
      ----------------------                     -------------------

Ordinary Shares, $.01 par value                  New York Stock Exchange


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

                                       None.


     INDICATE  BY  CHECK  MARK  WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED  TO  BE  FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934  DURING  THE  PRECEDING  12  MONTHS  (OR  FOR  SUCH SHORTER PERIOD THAT THE
REGISTRANT  WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING  REQUIREMENTS  FOR  THE  PAST  90  DAYS.  YES    [   X   ]     NO    [
                                                         --------
]
     INDICATE  BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM
405 OF REGULATION S-K (SECTION 229.405 OF THIS CHAPTER) IS NOT CONTAINED HEREIN,
AND  WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE
PROXY  OR  INFORMATION  STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS
FORM  10-K  OR  ANY  AMENDMENT  TO  THIS  FORM  10-K.  [                  ]
                                                                  ---------
     THE  AGGREGATE  MARKET  VALUE  OF  THE  OUTSTANDING ORDINARY SHARES HELD BY
NON-AFFILIATES  OF  THE REGISTRANT AT MARCH 7, 2000 (FOR SUCH PURPOSES ONLY, ALL
DIRECTORS  AND  EXECUTIVE  OFFICERS  ARE  PRESUMED  TO  BE  AFFILIATES)  WAS
APPROXIMATELY  $1.0  BILLION,  BASED ON THE CLOSING SALES PRICE OF $30.25 ON THE
NEW  YORK  STOCK  EXCHANGE.

     AS  OF  MARCH  7,  2000,  35,944,174 ORDINARY SHARES OF THE REGISTRANT WERE
OUTSTANDING.

                       DOCUMENTS INCORPORATED BY REFERENCE
     PORTIONS  OF  THE  PROXY STATEMENT PERTAINING TO THE 2000 ANNUAL MEETING OF
SHAREHOLDERS  OF  TRITON ENERGY LIMITED  ARE INCORPORATED BY REFERENCE INTO PART
III  HEREOF.






                              TRITON ENERGY LIMITED

                                TABLE OF CONTENTS


<TABLE>
<CAPTION>

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

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

PART I
     ITEMS 1. and 2.  Business and Properties                                            2
     ITEM 3.          Legal Proceedings                                                 20
     ITEM 4.          Submission of Matters to a Vote of Security Holders               22

PART II
     ITEM 5.          Market for Registrant's Common Equity and Related
                      Stockholder Matters                                               23
     ITEM 6.          Selected Financial Data                                           29
     ITEM 7.          Management's Discussion and Analysis of Financial Condition and
                      Results of Operations                                             30
     ITEM 7.A.        Quantitative and Qualitative Disclosures about Market Risk        43
     ITEM 8.          Financial Statements and Supplementary Data                       46
     ITEM 9.          Changes in and Disagreements with Accountants on Accounting and
                      Financial Disclosure                                              46

PART III
     ITEM 10.         Directors and Executive Officers of the Registrant                47
     ITEM 11.         Executive Compensation                                            47
     ITEM 12.         Security Ownership of Certain Beneficial Owners and Management    47
     ITEM 13.         Certain Relationships and Related Transactions                    47

PART IV
     ITEM 14.         Exhibits, Financial Statement Schedules, and Reports on Form 8-K  48

</TABLE>



                                 PART I


ITEMS 1. AND 2.  BUSINESS  AND  PROPERTIES


GENERAL

     Triton  Energy  Limited  is  an  international  oil and gas exploration and
production  company. The Company's principal properties, operations, and oil and
gas  reserves  are located in Colombia, Malaysia-Thailand and Equatorial Guinea.
The  Company is exploring for oil and gas in these areas, as well as in southern
Europe,  Africa  and  the  Middle  East.

     The  Company  conducts  substantially all of its exploration and production
operations  outside  the United States. All of the Company's sales are currently
derived  from  oil  and  gas production in Colombia. For a discussion of certain
political,  economic  and  other  uncertainties  associated  with  operations in
foreign  countries,  particularly  in  the  oil and gas business, see note 19 of
Notes  to  Consolidated  Financial  Statements.

     Triton  Energy  Limited  was  incorporated in the Cayman Islands in 1995 to
become  the  parent  holding company of Triton Energy Corporation, a corporation
formed  in  Texas  in  1962  and  reincorporated  in Delaware in 1995. The terms
"Company"  and  "Triton" when used in this report mean Triton Energy Limited and
its  subsidiaries  and  other  affiliates  through  which  Triton  conducts  its
business,  unless  the  context  otherwise  implies.  The  Company's  principal
executive  offices are located at Caledonian House, Jennett Street, George Town,
Grand  Cayman,  Cayman  Islands,  and  its  telephone  number is (345) 949-0050.
Information  regarding  the  Company can be obtained by contacting the Company's
Investor  Relations  department at Triton Energy, 6688 North Central Expressway,
Suite  1400,  Dallas,  Texas  75206,  telephone number (214) 691-5200, or at the
Company's  web  site,  www.tritonenergy.com.

OIL  AND  GAS  PROPERTIES

     Through  various subsidiaries and affiliates, the Company has participating
interests  in  exploration  licenses  in  Latin America, Southeast Asia, Africa,
Europe  and the Middle East. The following is intended to describe the Company's
interests  in  these  licenses  and  recent  operations  over  these  licenses.

Colombia
--------

Santiago de Las Atalayas, Tauramena and Rio Chitamena Contract Areas

     The  Company holds a 12% interest in the Santiago de Las Atalayas ("SDLA"),
Tauramena  and  Rio  Chitamena  contract  areas,  covering approximately 66,000,
36,300  and  6,700  acres,  respectively, where an active development program is
being  carried  out  in  the  Cusiana  and  Cupiagua fields. The area is located
approximately  160  kilometers  (100  miles)  northeast  of Bogota in the Andean
foothills  of  the  Llanos  Basin area in eastern Colombia. Triton's partners in
these  areas  are  Empresa  Colombiana De Petroleos ("Ecopetrol"), the Colombian
national  oil  company, with a 50% interest, and subsidiaries of BP/Amoco ("BP")
and  TotalFina  SA  ("TOTAL"),  each  with  a  19% interest. BP is the operator.
Triton's  interest  is  12%,  and its net revenue interest is approximately 9.6%
after  governmental  royalties.  Triton's  net revenue is reduced by up to 0.36%
pursuant  to  an agreement with an original co-investor, subject to Triton being
reimbursed  for  a  proportionate  share  of  related  expenditures.

     Contract Terms. The Company and its private partners have secured the right
     ---------------
to  produce  oil  and gas from the SDLA and Tauramena contract areas through the
years  2010  and  2016,  respectively,  and from the Rio Chitamena contract area
through  2015  or  2019,  depending  on  contract  interpretation. In July 1994,
Triton,  BP,  TOTAL  and Ecopetrol entered into an Integral Plan for the Unified
Exploitation  of  the  Cusiana  Oil  Structure  in  the  SDLA, Tauramena and Rio
Chitamena  Association  Contract Areas to develop the Cusiana oil structure in a
technically  efficient  and  cooperative  manner. The plan contemplates that the
parties'  interests  will  be determined over three consecutive periods of time.
Until  the  expiration of the SDLA contract in 2010, petroleum produced from the
unified  area  will be owned by the parties according to their interests in each
contract  area.

     In  the first quarter of 2005, the parties will engage an independent party
to  determine  the  original  barrels  of oil equivalent ("BOE") of petroleum in
place under the unified area and under each contract area. Then a "tract factor"
will be calculated for each contract area.  Each tract factor will be the amount
of  original  BOEs of petroleum in place under the particular contract area as a
percentage  of  the  total  original  BOEs under the unified area.  Each party's
unified  area  interest during the second period (commencing from the expiration
of  the  SDLA contract in 2010) and during the final period (commencing from the
termination of the second contract to termination) will be the aggregate of that
party's  interest in each remaining contract area multiplied by the tract factor
for  each  such  contract  area.

     Recent  Operating  Activity.  In the Cusiana field, during 1999, Triton and
     ---------------------------
its  working  interest  partners completed an additional six wells, bringing the
total  completions  to 43 producing wells, 13 gas injection wells and four water
injection  wells.  The gas injection wells recycle to the Mirador formation most
of  the  gas  that  is  associated  with  the oil production to increase the oil
recoverable  during the life of the field.  The water injection wells inject the
field's  produced water into the Barco and Guadalupe formations for disposal and
pressure  maintenance.  There  are currently four drilling rigs operating in the
Cusiana  field  to drill production, water and gas injection wells.  The Company
expects  that  five  wells  will  be  completed  during  2000.

     During  1999, in the Cupiagua field, including the Cupiagua South extension
of  the  field  discovered  in  January  1998,  Triton  and its working interest
partners completed an additional eight  wells, bringing the total completions to
24  producing  wells  and  seven  gas injection wells. There are currently three
drilling rigs operating in the Cupiagua field on the SDLA contract area to drill
production,  water and gas injection wells.  The Company expects that nine wells
will  be  completed  during  2000.

     Recetor  Contract  Area

     In  1999, the Company acquired a 20% interest in the Recetor contract area,
covering  approximately  70,215 acres. The area is located adjacent to and north
of  the  SDLA  contract  area  and  includes an extension of the Cupiagua field.
Triton's  partners  in  these  areas  are  BP,  with  a  63.3%  interest,  and,
Inaquimicas,  with  a 16.7% interest. BP is the operator. The Company's interest
is subject to certain government royalties and the right of Ecopetrol to acquire
up  to  a  50%  interest  in the contract upon declaration of commerciality. The
contract  provides the Company and its private partners the right to produce oil
and  gas  from  the  Recetor  contract  area  through  the  year  2017.

     In  January  2000,  Triton  and its working interest partners completed the
Liria  YD-2  well on the extension of the Cupiagua field in the Recetor contract
area.  The  well  reached total depth of 16,953 feet and will be tested into the
Cupiagua  Central  Processing Facility (CPF). The Company expects that Ecopetrol
will  grant  commerciality  and  the  well  will  be  put on production into the
Cupiagua  CPF  provided  the  working interest partners reach agreement with the
SDLA working interest partners. There is currently one drilling rig operating in
the Recetor contract area. The Company expects that at least one additional well
will  be  drilled  in  the  Recetor  contract  area  in  2000.

     Production  Facilities  and  Pipelines

     The  production  facilities  in  the  Cusiana and Cupiagua fields have been
completed.  The  components  of  the  Cusiana  CPF  consist  of a long term test
facility,  four  early  production  units, and two 80,000 barrels of oil per day
("BOPD") production trains, which brought the production capacity of the Cusiana
CPF  to  approximately  320,000  BOPD.  Currently, the production of the Cusiana
field  is limited by the gas handling capacity of the Cusiana CPF of about 1,400
million  cubic  feet  of  gas  per  day.

     The  components  of the Cupiagua CPF consist of two 100,000 BOPD production
trains,  which  process  the  condensate  and  gas  production from the Cupiagua
producing  wells. The gas handling capacity of the Cupiagua CPF is approximately
1,300  million  cubic  feet  of  gas  per  day.

     Crude  oil and condensate produced from the Cusiana and Cupiagua fields, as
well  as  crude  oil  from other third parties, are transported to the Caribbean
port of Covenas through the 832-kilometer (520-mile) pipeline system operated by
Oleoducto  Central  S.  A.  ("OCENSA").  OCENSA is a Colombian company formed by
Triton  Pipeline  Colombia, Inc., a wholly owned subsidiary of the Company until
its sale in February 1998, Ecopetrol, BP Colombia Pipelines Ltd., Total Pipeline
Colombie,  S.A.,  IPL  Enterprises  (Colombia)  Inc.  and  TCPL  International
Investments  Inc.

     Gross  production from the Cusiana and Cupiagua fields has reached over 500
million  barrels  of  oil since production commenced, and averaged approximately
430,000  BOPD during 1999. Based on estimates of the operator of the Cusiana and
Cupiagua  fields,  the  Company  believes that combined Cusiana and Cupiagua oil
production  will be approximately 8% to 11% lower in 2000 than in 1999, although
there  can  be  no  assurance  that  actual  production  will equal that amount.

     Other  Contract  Areas  in  Colombia

     Triton  owns  a  100%  interest  (before  certain  royalties and government
participation)  in the El Pinal license, which covers approximately 36,000 acres
approximately  330 kilometers (205 miles) north of Bogota.  In the southern part
of  El  Pinal,  Triton discovered and confirmed the Liebre field with two wells
(the  Liebre-1  and  -2). Liebre-1 ceased production in June 1998 while Liebre-2
continues  to  produce  approximately  160  BOPD.
     During  1999,  in  the  Guayabo  A  and  B licenses, the Company drilled an
unsuccessful  exploratory  well  and  conducted  a  surface  geology  program in
satisfaction  of  its  commitments. The Company has relinquished its interest in
these  areas.

     Malaysia-Thailand
     -----------------

     In  Block  A-18 of the Malaysia-Thailand Joint Development Area in the Gulf
of  Thailand,  the  Company  and  its partners have discovered eight natural gas
fields  -  known  as  the  Bulan,  Bumi,  Bumi East, Cakerawala, Samudra, Senja,
Suriya,  and  Wira fields. The Company owns its interest through a company owned
one  half  by  Triton and one half by a subsidiary of Atlantic Richfield Company
("ARCO").  The operator is Carigali-Triton Operating Company Sdn. Bhd. ("CTOC"),
a  company  owned  by  Triton and ARCO, through their jointly owned company, and
Petronas  Carigali  (JDA)  Sdn. Bhd. ("Carigali"), a subsidiary of the Malaysian
national  oil  company.

     Block  A-18  is  located  in  the  Gulf of Thailand in an area known as the
Malaysia-Thailand  Joint  Development  Area.  The  contract  area in the Gulf of
Thailand, which encompasses approximately 731,000 acres, had been the subject of
overlapping  claims between Malaysia and Thailand. The two countries established
the Malaysia-Thailand Joint Authority (the "MTJA") to administer the development
of  the  Joint  Development  Area.  In  April  1994,  Triton  entered  into  a
production-sharing contract with the MTJA and Carigali. Triton previously held a
license  from  Thailand  that  covered  part  of  the  Joint  Development  Area.

     Contract  Terms

     The  term  of  the  production-sharing  contract  is  35  years, subject to
possible  relinquishment  of  certain  areas  and  subject to the treaty between
Malaysia  and  Thailand  creating  the  MTJA remaining in effect. Triton and its
partners  have the right to explore for oil and gas for the first eight years of
the  contract. The contract provides that if there is a discovery of natural gas
(not  associated  with  crude  oil),  the  contractors will submit to the MTJA a
development  plan  for  the field. If the MTJA accepts the plan, the contractors
would have the right to hold that gas field without production for an additional
five-year  period,  but  not  beyond the tenth anniversary of the contract.  The
contractors  would  then  have a five-year period to develop the field, and have
the  right  to  produce  gas  from the field for 20 years plus a number of years
equal  to  the  number  of years, if any, prior to the end of the holding period
that  gas  production  commenced  (or  until the termination of the contract, if
earlier).  The  contract requires the contractors to drill two exploratory wells
before  April  2002.

     For  a  discovery of an oil field, the contract grants to the operators the
right  to  produce  oil from the field for 25 years (or until the termination of
the  contract,  if  earlier).  Any  areas not developed and producing within the
periods  provided  will  be  relinquished.

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

     The  Company's  agreements  with  ARCO  require  ARCO  to  pay  the  future
exploration  and  development  costs  attributable  to  the Company's and ARCO's
collective  interest in Block A-18, up to $377 million or until first production
from  a  gas  field, after which the Company and ARCO would each pay 50% of such
costs.  The  agreements  provide that the Company will recover its investment in
recoverable costs in the project, approximately $100 million, and that ARCO will
recover its investment in recoverable costs, on a first-in, first-out basis from
the  cost  recovery  portion  of  future  production.  See "Item 7. Management's
Discussion  and  Analysis  of Financial Condition and Results of Operations" and
note  2  of  Notes  to  Consolidated  Financial  Statements.

     Gas  Sales  Agreement

     In  October  1999,  the  Company  and  the  other  parties  to  the
production-sharing  contract  for  Block  A-18  executed  a  gas sales agreement
providing  for  the sale of the first phase of gas. The sales agreement provides
for  gas  deliveries over a term concurrent with the production-sharing contract
and  contemplates initial deliveries of 195 million cubic feet of gas (MMCF) per
day for the first six months of the agreement, and 390 MMCF per day for a period
of  twenty  years.  The  sales  agreement  includes a take-or-pay provision that
specifies  that  the  buyers  must  take  a  minimum  of 90% of the annual daily
contract  quantity  and the sellers must be able to deliver a maximum of 110% of
the  daily  contract  quantity.  Delivery  is  made  at  the offshore production
platform.

     The  price for gas will be adjusted annually for changes in the US Consumer
Price  Index, the Producer Price Index for Oil Field and Gas Field Machinery and
Tools,  and  medium  fuel  oil  (180  CST) in Singapore. The price is calculated
annually  and  will  apply  to  sales  over  the  succeeding  twelve months. All
calculations  and  payments  are  in  U.S.  dollars. The base price is $2.30 per
mmbtu.  To give the buyers incentive to accelerate the timing of the delivery of
the gas, the sales agreement gives the buyers a discount of 5% after 500 billion
cubic  feet  has  been delivered and a discount of 10% after an aggregate of 1.3
trillion  cubic  feet  has  been  delivered.

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

     By  the first delivery date, the sellers will be required to have completed
the  facilities  necessary  to  meet  its  delivery  obligations.  The  MTJA had
previously  approved  the  field  development  plan  for the Cakerawala field in
December  1997.  CTOC  has  begun field development work and has awarded several
contracts for long lead-time equipment, including CO2 removal, structural steel,
refrigeration,  power  generation  and  gas  compression.  In  March  2000, CTOC
awarded  the  contract  for  engineering,  procurement and construction (EPC) of
three wellhead platforms, a production platform with living quarters platform, a
riser  platform  and  a  floating  storage  and  off-loading  vessel for oil and
condensate.  The  initial  development  plan  calls  for  35  development wells.

     The buyers currently do not have in place facilities necessary to transport
and  process  the gas. While it is not a requirement of the sales agreement, the
buyers  anticipate  constructing  pipeline  and  processing  facilities  onshore
Thailand  to  accept  deliveries  of the gas. The sales agreement does recognize
that  the  buyers' downstream facilities will require that certain environmental
approvals  be  obtained  before  the  buyers' facilities can be constructed. The
agreement  provides  that,  if  a delay in obtaining the necessary environmental
approvals  results  in  a  delay  of  the  completion  of the buyers' downstream
facilities,  this  will  be treated as a force majeure event and will excuse the
buyers  from  their  take  or  pay  obligations for the length of the delay. The
Company  can  give  no  assurance as to when the environmental approvals will be
obtained,  and  a  lengthy  approval  process,  or significant opposition to the
project,  could  delay  construction  and  the  commencement  of  gas  sales.

     Notwithstanding  a  possible  future  delay  in  the  buyers' environmental
approvals  process, in order to meet the June 30, 2002 deadline, the sellers are
committed  to,  or  will  be  required  to  commit to, significant expenditures,
including  the  EPC  contract. Although ARCO is committed to pay all development
costs  associated  with Block A-18 up to $377 million, the Company has agreed to
provide  some  compensation  to  ARCO in the event that gas sales are delayed by
agreeing  to  pay to ARCO $1.25 million per month for each month, if applicable,
that  first  gas  sales are delayed beyond 30 months following commitment to the
EPC contract. The Company's obligation is capped at 24 months of these payments.

     Equatorial  Guinea
     ------------------

     The  Company signed production-sharing contracts in March 1997 covering two
contiguous  blocks  (Blocks F and G) with the Republic of Equatorial Guinea. The
contracts  became effective in April 1997. During 1999, the Company announced an
oil  discovery,  the  Ceiba field, in Block G, and confirmed the significance of
the  discovery  with  the  Ceiba-2  appraisal  well.

     The  contracts  give  the  Company the right to explore and develop an area
covering  approximately  1.3 million acres located offshore and southwest of the
town  of  Bata  in water depths of up to 5,200 feet. The Company is the operator
and Energy Africa Equatorial Guinea Limited is the Company's partner. Currently,
the  Company's contract interest is 85% and Energy Africa's contract interest is
15%,  but  these  interests are subject to the renegotiation of the contracts as
discussed  below.

     Contract  Terms

     Currently, the Company's commitments under the production-sharing contracts
for  the  contract  year ending April 2001 are to drill at least one exploration
well,  and  a second exploration well contingent upon the Company identifying an
additional structure it believes is a drillable prospect. The Company can extend
the exploration period of each contract for three additional one-year periods if
it  agrees  to  certain operational commitments for those periods, including the
drilling  of  at  least  one  exploration  well,  and  a second exploration well
contingent upon the Company identifying an additional structure it believes is a
drillable prospect. The Company is required to relinquish 30% of each contract's
original  area  by  April  2000, and an additional 20% of the remaining contract
area  by  the  end  of  April 2002, provided that the Company will not be
required to surrender  an  area that includes a commercial field or a discovery
that has not then  been  declared  commercial.   The area or areas to be
surrendered is to be designated  by  the  Company,  provided  that,  where
possible, each area is of sufficient  size  and  convenient  shape  to  permit
petroleum  operations.

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

     Under  the current terms of the Company's production-sharing contracts, the
Republic  of  Equatorial  Guinea  is entitled to a royalty as to each field. The
royalty  is  10%  for up to the first 100 million barrels of oil produced, 12.5%
for  greater  than  100  million barrels of oil up to 300 million barrels of oil
produced,  and  15%  for greater than 300 million barrels of oil produced. After
making  the  royalty payments, the Company is entitled to receive the production
until  it recovers its costs, such capital costs to be depreciated and recovered
over  a  four year period. After the Company recovers its costs, the Republic of
Equatorial Guinea is entitled to receive a share of production based on the rate
of return realized by the Company under the contract. The contracts provide that
the government's share of production will vary from 0%, where the Company's rate
of return is less than 18%, to 55% where the Company's rate of return is greater
than  or  equal  to  40%.

     At  the  request  of the Republic of Equatorial Guinea, the Company and its
partner  are  negotiating  amendments to certain terms of the contracts with the
government. The parties have signed a memorandum of understanding reflecting the
revised  terms,  and  negotiations  of definitive amendments are continuing. The
memorandum  of  understanding  provides  that  the government would receive a 5%
carried  participating  interest,  and  its  royalty would vary based on average
daily  production,  ranging  from 11% to 16%. After making the royalty payments,
the  contractors  would be entitled to receive up to 70% of the production until
they  recover  their costs. Production not allocated to the contractors for cost
recovery  would be allocated between the contractors and the government based on
cumulative  production,  with the government's share ranging from 20% to 60%, to
the  extent  production  exceeds  certain levels. This share of production is in
addition  to  the  share  the  government  would  receive through its 5% carried
participating interest.  The implementation of the revised terms of the contract
is  subject to the negotiation and execution of definitive amendments, but there
can  be  no assurance as to whether, or when, such definitive amendments will be
executed.

     Recent  Operating  Activity

     During  1999,  the  Company announced an oil discovery, the Ceiba field, in
Block  G,  and  confirmed  the  significance  of  the discovery with the Ceiba-2
appraisal  well.  On test, the Ceiba-1 well flowed 12,401 barrels of oil per day
(BOPD)  of  30  degree  oil  from  one  zone over an interval of 160 feet with a
flowing  tubing  pressure  of  897  pounds  per  square  inch. Test results were
constrained  by  the capacity of surface testing equipment. Analysis of wireline
logs and core data indicates a gross oil column of 742 feet in the well with net
oil-bearing  pay  of  314  feet in four zones. The Ceiba-1 well was drilled to a
total  depth  of  approximately 9,700 feet in approximately 2,200 feet of water,
located  22  miles  off  the  continental  coast.

     The  Ceiba-2  well  was drilled approximately one mile to the southwest and
342  feet  down-dip  of  the  Ceiba-1  discovery  well. The well encountered net
oil-bearing  pay  of  300 feet in a single, continuous column.  In addition, the
well  confirmed the oil-water contact found in Ceiba-1, and demonstrated lateral
reservoir  continuity  and  connectivity.  The  well is located 22 miles off the
continental  coast  and was drilled to a total depth of 8,744 feet in 2,347 feet
of  water. The Company elected not to flow test the well based on wireline logs,
extensive  coring  and  pressure  data,  as  well  as Ceiba-1 flow-test results.

     The  Company  intends  to  maintain  both  the Ceiba-1 and Ceiba-2 wells as
potential  future  producers.

     The  Company  has  acquired  a  1,025,000-acre  (4,200 square kilometer) 3D
seismic survey, out of the total 1.3 million acres, to assist in delineating the
extent  of  the  Ceiba  field,  identify  drilling  locations  for  the
appraisal/production wells, and better define other exploration prospects on the
blocks.      The  Company  is  in  the  process  of  evaluating  the  data.

     The  Company  intends  to  accelerate  its  exploration,  appraisal  and
development  drilling  activities  through  implementation of a two-rig drilling
program.  The  drilling  program  provides  for  up to ten wells: four firm well
commitments  and  six  optional  wells.  The  rigs  will  be  used  to:

- Complete the Ceiba-1 and -2 wells as oil producers.
- Drill and complete two Ceiba field appraisal/production wells, Ceiba-3 and
  Ceiba-4.
- Drill two exploration wells, one each on Blocks F and G.
- At  the  option  of  the  Company, drill a combination of up to six additional
  development,  appraisal  and/or  exploration  wells.

     Plan  of  Development

     In January 2000, the Company received notice from the Ministry of Mines and
Energy  of  the  Republic  of  Equatorial  Guinea that the Ministry had approved
Triton's  plan  of  development  for  the  Ceiba  field. The plan of development
provides for initial or phase one production of 52,000 BOPD utilizing a floating
production  storage  and  offloading  (FPSO)  system,  although  there can be no
assurance  that  actual  production  will  be  at  this  level.  Selection  of a
FPSO-based development concept was designed to allow for accelerated development
of  the Ceiba field.  Specifications call for the FPSO vessel to provide storage
for  two  million barrels of oil and initial processing capacity of up to 60,000
barrels  of  oil  per day. The FPSO vessel can also be expanded cost effectively
through  the  addition  of incremental processing capacity, to accommodate up to
240,000  barrels  of  oil  per  day.

     As part of this initial phase of development, four sub-sea production wells
are  scheduled  to  be  completed  and connected through flow lines to the FPSO,
including  the  Ceiba-1  and  Ceiba-2  wells.

     Based on discussions held to date with development contractors, the Company
is targeting first oil production to occur by year end, although the Company can
give  no assurance that it will meet this target.  The Company believes that due
to  transportation  and  preliminary assays of the quality of the crude oil, the
oil  from  the  Ceiba  field  will  sell  at  a  discount  to  Brent  crude.

     Greece
     ------

     The Company has signed two leases with Hellenic Petroleum, the national oil
company  of  Greece,  with  the Company having an 88% interest in each lease and
Hellenic  Petroleum  the  remaining 12% interest. The Gulf of Patraikos contract
area  covers  approximately  402,000  acres  (after  a  contractually-required
relinquishment in 1999) located offshore between the western coast of Greece and
the  offshore  Ionian islands of Lefkas, Kefalonia and Zakynthos in water depths
of  up  to 1,700 feet. The lease provides a primary exploration term expiring in
September  2001  with  a  commitment  of  1,000 kilometers (625 miles) of new 2D
seismic  and the drilling of one exploratory well for a total expenditure of not
less  than  $13.5  million.  The  Company  has  reprocessed  approximately 3,000
kilometers (1,900 miles) of existing 2D seismic and acquired approximately 1,000
kilometers  (625  miles)  of  2D  seismic  and  gravity  in  January  2000.

     The Aitoloakarnania contract area covers approximately 658,000 acres (after
a  contractually-required  relinquishment  in  1999)  located onshore in western
Greece. The lease provides a primary exploration term expiring in June 2000 with
a commitment of 200 kilometers of 2D seismic and the drilling of two exploratory
wells  for  a total expenditure of not less than $13.25 million. The Company has
reprocessed  approximately 660 kilometers (410 miles) of existing 2D seismic and
acquired approximately 200 kilometers (125 miles) of new 2D seismic. The Company
plans  to  drill the commitment wells this year although the Company may attempt
to  negotiate  amendments  to  these  commitments.

     Italy
     -----

     The  Company  holds  interests  in  six  licenses in Italy comprising three
offshore  blocks  in  the  Adriatic Sea and three onshore blocks in the Southern
Apennines.

     The  Company  has  a  47%  interest in each of the contiguous DR71 and DR72
licenses  covering  approximately  369,400 acres (after a contractually required
relinquishment  in  1999)  in  the Adriatic Sea located 45 kilometers (28 miles)
offshore  the city of Brindisi. Triton's partner in these licenses is Enterprise
Oil  Italiana,  S.p.A. ("Enterprise"), the operator, with a 53% interest. During
1998,  the  Company  and its working interest partners drilled the Giove-1 well.
The  well  was  drilled  to  a  total  depth  of  3,458 feet but was prematurely
abandoned  due  to  a  gas  blowout  and mechanical failure. A replacement well,
Giove-2, was drilled to a total depth of 4,285 feet and encountered oil and gas.
Additional  work  is  required  to  evaluate  the  commercial  potential  of the
licenses.  During 1999, a subsidiary of ExxonMobil withdrew from its interest in
the  licenses  and  the  Company  and Enterprise each received its proportionate
share  of  ExxonMobil's  interest.
     In 1998, Triton acquired a 20% interest in the FR33AG offshore license. The
license  covers  approximately 71,600 acres and is adjacent to the DR71 and DR72
licenses.  Eni S.p.A. is operator, with a 50% interest, and Enterprise holds the
remaining 30% interest. The license provides a primary exploration term expiring
in  September  2004  with  a  commitment of 250 kilometers (156 miles) of new 2D
seismic  and  the  drilling  of  one  exploratory  well.

     In  the  southern  Apennine Mountains, the Company has an interest in three
contiguous  licenses,  Fosso  del  Lupo, Valsinni and Masseria de Sole, covering
approximately  58,000 acres in the Matera province. The Company is the operator,
with  a 50% interest, and a subsidiary of ARCO holds the remaining 50% interest.
The  licenses  provide  a  primary  exploration term expiring in August 2002 and
were  amended  in 1999 to provide a combined work commitment of approximately 50
kilometers  (31  miles)  of  new  2D seismic and the drilling of one exploratory
well.  In  connection with the amendment, the Company relinquished approximately
40%  of the acreage. The Company acquired the 50 kilometers of seismic data over
the  license  area  in  1999.

     Oman
     ----

     In  1998,  the  Company  signed a production-sharing contract for Block 40,
covering  approximately  1.3  million  acres  located offshore in the Straits of
Hormuz.  The  contract provides an exploration term expiring in June 2001 with a
commitment  of the drilling of one exploratory well. The Company is the operator
with  a  50%  contract  interest and Atlantis Holding Norway AS is the Company's
partner  with  a  50%  interest.

     Triton  has  completed  the  reprocessing  and  interpretation  of  4,083
kilometers  (2,546  miles) of existing 2D seismic, and completed the acquisition
of a 620 square kilometer 3D seismic survey in January 2000. The Company expects
that  it  will  process  and  interpret  this  data  during  2000  and  drill an
exploratory  well  in  early  2001.

     Madagascar
     ----------

     The  Company  has  signed  a production-sharing contract with the Office of
National  Mines  and  Strategic Industries in Madagascar for the Ambilobe Block,
covering approximately 4.3 million acres. The block is located directly offshore
from  Ambilobe  in  water  depths of up to 11,500 feet. The Company has acquired
approximately  3,000  kilometers  (1,875  miles)  of  2D  seismic.

     Ecuador
     -------

     In  1999,  the Company assigned its 55% interest in Block 19 in the Oriente
Basin  to Vintage Petroleum Ecuador, Inc.  The assignment is subject to approval
of  the  Ministry  of  Energy  and  Mines.

<PAGE>
RESERVES

     The  following table sets forth a summary of the Company's estimated proved
oil and gas reserves at December 31, 1999, and is based on separate estimates of
the  Company's  net  proved  reserves  prepared  by:

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

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

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

- the  Company's  internal  petroleum  engineers  with  respect to the proved
  reserves  in  the  Liebre  field  in  Colombia.

     For  additional information regarding the Company's reserves, including the
standardized  measure  of  future  net  cash  flows,  see  note  23  of Notes to
Consolidated Financial Statements. Oil reserves data include natural gas liquids
and  condensate.

     Net  proved  reserves  at  December  31,  1999,  were:





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

Colombia (1)                          91,859    11,566      33,712       ---     125,571    11,566
Malaysia-Thailand (2)                  ---        ---       13,223     553,862    13,223   553,862
Equatorial Guinea                      ---        ---       32,033       ---      32,033     ---
                                    ----------  -------  ------------  --------  --------  --------

        Total                         91,859    11,566      78,968     553,862   170,827   565,428
                                    ==========  =======  ============  ========  ========  ========

</TABLE>
____________________

(1)  Includes liquids to be recovered from Ecopetrol as reimbursement for
precommerciality expenditures.
(2)  As of December 31, 1999, gas sales had not yet commenced. The proved gas
reserves  are  calculated  using  the  base  price in the gas sales agreement of
$2.30. The base price is subject to annual adjustments based on various indices.
There  can  be  no  assurance as to what the actual price will be when gas sales
commence.  See  "Item  1.  Business  and  Properties  -  Malaysia-Thailand."


<PAGE>
     Reserve  quantities  are estimates and there are a number of uncertainties.

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

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

- there  are  uncertainties  inherent  in  interpreting  engineering  data;

- the  Company,  and  if  applicable  the independent engineers, must project
  future  rates of production and the  timing of  development  expenditures;

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

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

     Accordingly,  the  Company  cannot give any assurance that the Company will
ultimately  produce  the  quantity  of  reserves set forth in the table, and the
Company  cannot  give any assurance that the proved undeveloped reserves will be
developed  within  the  periods  anticipated.

     The  Company  has  not  filed  any estimates of total proved net oil or gas
reserves  with, or included estimates of total proved net oil or gas reserves in
any  report to, any United States authority or agency since the beginning of the
Company's  last  fiscal  year.

OIL  AND  GAS  OPERATIONS

          Production  and  Sales
          ----------------------

     During  1999, 1998 and 1997, the Company produced and sold oil and gas only
from  its  property  in Colombia. More details regarding the Company's revenues,
assets  and  certain  other data by geographical area is contained in note 21 of
Notes  to  Consolidated  Financial  Statements.

The following table sets forth the net quantities of oil and gas the Company
produced during 1999, 1998 and 1997.

<TABLE>
<CAPTION>
<S>                       <C>       <C>       <C>        <C>      <C>       <C>
                              OIL PRODUCTION (1)               GAS PRODUCTION
                          ---------------------------    --------------------------
                            YEAR ENDED DECEMBER 31,        YEAR ENDED DECEMBER 31,
,                         ---------------------------    --------------------------
                           1999       1998      1997      1999      1998      1997
                          ------     ------    ------    ------    ------    ------
                                   (Mbbls)                         (MMcf)

    Colombia (2)          12,469     9,979     5,776       459       503       802

</TABLE>


____________________
(1)     Includes  natural  gas  liquids  and  condensate.
(2)     Includes  Ecopetrol  reimbursement barrels and excludes 3.1 million, 3.1
million  and  2.5  million  barrels  of oil produced and delivered for the years
ended  December  31,  1999,  1998 and 1997, respectively, in connection with the
Company's forward oil sale in May 1995. See "Item 7. Management's Discussion and
Analysis  of  Financial  Condition  and  Results  of  Operations  -  Results  of
Operations"  and  note  8  of  Notes  to  Consolidated  Financial  Statements.

     The  following  tables  summarize  for 1999, 1998 and 1997: (i) the average
sales price per barrel of oil and per Mcf of natural gas; (ii) the average sales
price  per  equivalent  barrel  of  production;  (iii)  the  depletion  cost per
equivalent  barrel  of  production;  and (iv) the production cost per equivalent
barrel  of  production:



<TABLE>
<CAPTION>
<S>           <C>        <C>     <C>     <C>       <C>    <C>

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

                1999     1998   1997      1999     1998     1997
              -------  ------  ------    -----    -----    -----

Colombia (4)  $ 15.95  $12.31  $17.54    $0.88    $0.99    $1.15
</TABLE>




<TABLE>
<CAPTION>

                                             PER EQUIVALENT BARREL (2)
                   ----------------------------------------------------------------------------
<S>                        <C>                       <C>
                      AVERAGE SALES PRICE          DEPLETION (3)             PRODUCTION COST
                   -------------------------  ------------------------  -----------------------
                    YEAR ENDED DECEMBER 31,    YEAR ENDED DECEMBER 31,  YEAR ENDED DECEMBER 31,
                   -------------------------  ------------------------  -----------------------
                     1999    1998     1997     1999     1998    1997     1999     1998    1997
                   ------   ------   ------   ------   ------   ------  ------   ------  ------
 Colombia (4)      $15.89   $12.27   $17.37   $ 3.80   $ 4.07   $ 3.67  $ 4.77   $ 5.97  $ 6.47

 </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.
(4) Includes barrels delivered under the forward oil sale which are recorded
at  $11.56  per barrel upon delivery.  Excludes the full cost ceiling
limitation writedown  in  1998  totaling  $241  million.

     Competition
     -----------

     The  Company  encounters  strong  competition  from  major  oil  companies
(including  government-owned  companies),  independent  operators  and  other
companies  for  favorable  oil and gas concessions, licenses, production-sharing
contracts and leases, drilling rights and markets. Additionally, the governments
of  certain countries in which the Company operates may, from time to time, give
preferential  treatment  to their nationals. The oil and gas industry as a whole
also  competes  with  other  industries  in  supplying  the  energy  and  fuel
requirements  of  industrial,  commercial  and individual consumers. The Company
believes  that the principal means of competition in the sale of oil and gas are
product  availability,  price  and  quality.

     Markets
     -------

     Crude oil, natural gas, condensate and other oil and gas products generally
are  sold  to  other  oil  and  gas  companies,  government  agencies  and other
industries. The Company does not believe that the loss of any single customer or
contract pursuant to which oil and gas are sold would have a long-term material,
adverse  effect  on  the  revenues  from  the  Company's oil and gas operations.

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

     For  a  discussion  of  certain factors regarding the Company's markets and
potential  markets  that could affect future operations, see note 19 of Notes to
Consolidated  Financial  Statements.

ACREAGE

     The following table shows the total gross and net developed and undeveloped
oil  and gas acreage held by Triton at December 31, 1999.  "Gross" refers to the
total  number of acres in an area in which the Company holds an interest without
adjustment  to  reflect  the  actual  percentage  interest  held  therein by the
Company.  "Net"  refers  to  the gross acreage as adjusted for working interests
owned  by  parties  other  than  the  Company.

     "Developed"  acreage  is  acreage spaced or assignable to productive wells.
"Undeveloped"  acreage  is  acreage  on  which  wells  have  not been drilled or
completed  to  a point that would permit the production of commercial quantities
of  oil  and  gas,  regardless of whether such acreage contains proved reserves.



<TABLE>
<CAPTION>
<S>        <C>             <C>           <C>


                        DEVELOPED    UNDEVELOPED
                         ACREAGE     ACREAGE (1)
                      -----------  --------------
                      GROSS  NET    GROSS     NET
                      ----- -----  -------  -----
                            (In thousands)
Colombia               109    13      106      50
Malaysia-Thailand      ---   ---      731     183
Greece                 ---   ---    1,060     933
Italy                  ---   ---      499     217
Oman                   ---   ---    1,322     661
Equatorial Guinea (2)  ---   ---    1,306   1,110
Madagascar             ---   ---    4,300   4,300
                      ----- -----  -------  -----

Total                  109    13   9,324    7,454
                      ===== =====  =======  =====

____________________
</TABLE>

(1)     Triton's  interests  in  certain  of  this  acreage  may  expire  if not
developed at various times in the future pursuant to the terms and provisions of
the  leases, licenses, concessions, contracts, permits or other agreements under
which  it  was  acquired.
(2)     The  acreage  listed  does  not  take  into  account  the  5%  carried
participating  interest  the  Company  expects  to  assign  to the government of
Equatorial Guinea in connection with the renegotiation of the production-sharing
contract.

PRODUCTIVE  WELLS  AND  DRILLING  ACTIVITY

     In  this section, "gross" wells refers to the total number of wells drilled
in an area in which the Company holds any interest without adjustment to reflect
the  actual  ownership interest held.  "Net" refers to the gross number of wells
drilled  adjusted for working interests owned by parties other than the Company.

     At  December  31,  1999,  in  Colombia,  Triton  held gross and net working
interests in 93 and 12.92 productive wells, respectively, which include 20 gross
(2.4  net)  gas-injection  wells and four gross (.48 net) water-injection wells.

     The following tables set forth the results of the oil and gas well drilling
activity on a gross basis for wells in which the Company held an interest during
1999,  1998  and  1997.


<TABLE>
<CAPTION>
                                            GROSS EXPLORATORY WELLS


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

                        PRODUCTIVE (1)                DRY                      TOTAL
                   ------------------------  -----------------------  -----------------------
                    YEAR ENDED DECEMBER 31,  YEAR ENDED DECEMBER 31,  YEAR ENDED DECEMBER 31,
                   ------------------------  -----------------------  -----------------------
                    1999     1998     1997    1999     1998    1997     1999    1998    1997
                   ------   ------   ------  ------   ------  ------  ------   ------  ------

Colombia             ---        1        1       1      ---       1       1        1       2
Malaysia-Thailand    ---        2        5     ---      ---     ---     ---        2       5
Equatorial Guinea      2      ---      ---     ---      ---     ---       2      ---     ---
Italy                ---      ---      ---     ---        2     ---     ---        2     ---
Guatemala            ---      ---      ---     ---      ---       1     ---      ---       1
China                ---      ---      ---     ---        1     ---     ---        1     ---
Ecuador              ---      ---      ---     ---      ---       1     ---      ---       1
Tunisia              ---      ---      ---     ---        1     ---     ---        1     ---
                   ------   ------   ------  ------   ------  ------  ------   ------  ------

            Total      2        3        6       1        4       3       3        7       9
                   ======   ======   ======  ======   ======  ======  ======   ======  ======

</TABLE>

<TABLE>
<CAPTION>


                                             GROSS DEVELOPMENT WELLS


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

                        PRODUCTIVE (1)                DRY                      TOTAL
                   ------------------------  -----------------------  -----------------------
                    YEAR ENDED DECEMBER 31,  YEAR ENDED DECEMBER 31,  YEAR ENDED DECEMBER 31,
                   ------------------------  -----------------------  -----------------------
                    1999     1998     1997    1999     1998    1997     1999    1998    1997
                   ------   ------   ------  ------   ------  ------  ------   ------  ------

Colombia              14       13       18     ---      ---     ---      14       13      18
Malaysia-Thailand    ---      ---      ---     ---      ---     ---     ---      ---     ---
Equatorial Guinea    ---      ---      ---     ---      ---     ---     ---      ---     ---
                   ------   ------   ------  ------   ------  ------  ------   ------  ------

            Total     14       13       18     ---      ---     ---      14       13      18
                   ======   ======   ======  ======   ======  ======  ======   ======  ======


</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.

     The  following  tables  set forth the results of drilling activity on a net
basis for wells in which the Company held an interest during 1999, 1998 and 1997
(those wells acquired or disposed of since January 1, 1997, are reflected in the
following tables only since or up to the effective dates of their respective
acquisitions or sales, as the case may be):


                                                 NET EXPLORATORY WELLS


<TABLE>
<CAPTION>

<S>                    <C>      <C>   <C>        <C>    <C>    <C>         <C>    <C>     <C>
                            PRODUCTIVE (1)               DRY                       TOTAL
                       ------------------------  -----------------------   -----------------------
                       YEAR ENDED DECEMBER 31,   YEAR ENDED DECEMBER 31,    YEAR ENDED DECEMBER 31,
                       ------------------------  -----------------------   -----------------------
                        1999      1998     1997   1999     1998    1997     1999     1998     1997
                       -----     -----    -----  -----    -----    -----   -----    -----    -----

Colombia (2)             ---      0.12     0.12   0.50      ---     0.50    0.50     0.12     0.62
Malaysia-Thailand (3)    ---      1.00     2.50    ---      ---      ---     ---     1.00     2.50
Equatorial Guinea       1.70       ---      ---    ---      ---      ---    1.70      ---      ---
Italy                    ---       ---      ---    ---     0.80      ---     ---     0.80      ---
Guatemala                ---       ---      ---    ---      ---     0.60     ---      ---     0.60
China                    ---       ---      ---    ---     0.50      ---     ---     0.50      ---
Ecuador                  ---       ---      ---    ---      ---     0.55     ---      ---     0.55
Tunisia                  ---       ---      ---    ---     0.50      ---     ---     0.50      ---
                       -----     -----    -----  -----    -----    -----   -----    -----    -----

            Total       1.70      1.12     2.62   0.50     1.80     1.65    2.20     2.92     4.27
                       =====     =====    =====  =====    =====    =====   =====    =====    =====


</TABLE>
                                                  NET DEVELOPMENT WELLS


<TABLE>
<CAPTION>

<S>                    <C>      <C>   <C>        <C>    <C>    <C>         <C>    <C>     <C>
                            PRODUCTIVE (1)               DRY                       TOTAL
                       ------------------------  -----------------------   -----------------------
                       YEAR ENDED DECEMBER 31,   YEAR ENDED DECEMBER 31,    YEAR ENDED DECEMBER 31,
                       ------------------------  -----------------------   -----------------------
                        1999      1998     1997   1999     1998    1997     1999     1998     1997
                       -----     -----    -----  -----    -----    -----   -----    -----    -----

Colombia (2)            1.68      1.56     2.16    ---      ---      ---    1.68     1.56     2.16
Malaysia-Thailand        ---       ---      ---    ---      ---      ---     ---      ---      ---
Equatorial Guinea        ---       ---      ---    ---      ---      ---     ---      ---      ---
                       -----     -----    -----  -----    -----    -----   -----    -----    -----

            Total       1.68      1.56     2.16    ---      ---      ---    1.68     1.56     2.16
                       =====     =====    =====  =====    =====    =====   =====    =====    =====

</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  interest  in the wells drilled in 1998 was not reduced to take into
account  the  sale  of the Company's interest in Block A-18 to ARCO because such
sale  occurred  after  the  drilling  of  the  wells.

OTHER  PROPERTIES

     The  Company  leases  or  owns  office  space  and other properties for its
operations  in  various  parts  of the world.  For additional information on the
Company's  leases,  including  its  office  leases,  see  note  20  of  Notes to
Consolidated  Financial  Statements.

FORWARD-LOOKING  INFORMATION

     Certain  information  contained in this report, as well as written and oral
statements  made  or  incorporated by reference from time to time by the Company
and  its  representatives  in  other  reports,  filings  with the Securities and
Exchange  Commission, press releases, conferences, teleconferences or otherwise,
may  be  deemed to be "forward-looking statements" within the meaning of Section
21E of the Securities Exchange Act of 1934  and are subject to the "Safe Harbor"
provisions  of  that  section.  Forward-looking  statements  include  statements
concerning  the  Company's and management's plans, objectives, goals, strategies
and  future  operations  and  performance  and  the  assumptions underlying such
forward-looking statements. When used in this document, the words "anticipates,"
"estimates,"  "expects,"  "believes," "intends," "plans" and similar expressions
are  intended  to  identify  such  forward-looking  statements. These statements
include  information  regarding:

-  drilling schedules;

-  expected or planned production capacity;

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

-  the completion of development and commencement of production in
   Malaysia-Thailand;

-  future production of the Ceiba field in Equatorial Guinea, including volumes
   and timing of first production;

-  the acceleration of the Company's exploration, appraisal and development
   activities in Equatorial Guinea;

-  the Company's capital budget and future capital requirements;

-  the Company's meeting its future capital needs;

-  the Company's utilization of net operating loss carryforwards and realization
   of its deferred tax asset;

-  the level of future expenditures for environmental costs;

-  the outcome of regulatory and litigation matters;

-  the estimated fair value of derivative instruments, including the equity
   swap; and

-  proven oil and gas reserves and discounted future net cash flows therefrom.


     These  statements are based on current expectations and involve a number of
risks  and  uncertainties,  including  those  described  in  the context of such
forward-looking  statements  and  in  notes  19  and 20 of Notes to Consolidated
Financial  Statements.  Actual  results and developments could differ materially
from  those  expressed  in  or implied by such statements due to these and other
factors.

EMPLOYEES

     At  March  6,  2000,  the  Company  employed  approximately  126  full-time
employees.

EXECUTIVE  OFFICERS  OF  THE  COMPANY



The following table sets forth certain information regarding the executive
officers of the Company at March 6, 2000:


<TABLE>
<CAPTION>
<S>                   <C>  <C>                                  <C>

                                                                SERVED WITH
                                                                -----------
                                                                THE COMPANY
                                                                -----------
      NAME             AGE     POSITION WITH THE COMPANY           SINCE
------------------     ---  ----------------------------------  -----------

James C. Musselman      52  President and Chief Executive
                             Officer                                  1998
A.E. Turner, III        51  Senior Vice President and
                             Chief Operating Officer                  1994
W. Greg Dunlevy         44  Vice President, Investor Relations
                             and Treasurer                            1993
Marvin Garrett          44  Vice President, Production                1994
Brian Maxted            42  Vice President, Exploration               1994

</TABLE>


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

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

     Mr.  Dunlevy  has  served  as  Vice  President,  Investor Relations, of the
Company  since  April  1993  and  was  elected  Treasurer  in  July  1998.

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

     Mr.  Maxted has served as Vice President, Exploration, of the Company since
January 1998, and prior to that served as Exploration Manager of CTOC since June
1994. From 1979 to 1994, Mr. Maxted was employed by British Petroleum in various
capacities,  including  Exploration  Manager,  Colombia  from  1990  to 1992 and
License  Manager,  Norway  from  1992  to  1994.

     All  executive officers of the Company are elected annually by the Board of
Directors  of  the  Company  to  serve in such capacities until removed or their
successors  are  duly  elected and qualified.  There are no family relationships
among  the  executive  officers  of  the  Company.


ITEM  3.  LEGAL  PROCEEDINGS

LITIGATION

     In July through October 1998, eight lawsuits were filed against the Company
and  Thomas  G.  Finck and Peter Rugg, in their capacities as Chairman and Chief
Executive  Officer  and Chief Financial Officer, respectively. The lawsuits were
filed  in  the  United  States District Court for the Eastern District of Texas,
Texarkana  Division,  and  have  been  consolidated and are styled In re: Triton
Energy  Limited  Securities Litigation. In November 1999, the plaintiffs filed a
consolidated complaint. It alleges violations of Sections 10(b) and 20(a) of the
Securities  Exchange  Act  of  1934,  as  amended,  and  Rule  10b-5 promulgated
thereunder,  in connection with disclosures concerning the Company's properties,
operations, and value relating to a prospective sale of the Company or of all or
a  part  of  its  assets. The lawsuits seek recovery of an unspecified amount of
compensatory  damages,  fees  and  costs.  In  the  consolidated  complaint, the
plaintiffs  abandoned  a  claim  for  negligent  misrepresentation  and punitive
damages  that had previously been asserted in one of the eight individual suits.

     In September 1999, the court granted the plaintiffs' motion for appointment
as  lead  plaintiffs  and  for approval of selection of lead counsel. In October
1999,  the  defendants filed a motion to dismiss the claims alleged in the eight
individual  suits,  and  in  December 1999, the defendants filed a supplement to
their  motion  to dismiss to address the plaintiffs' consolidated complaint. The
Company's  motion,  as  supplemented,  is  currently  pending.

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

          In  November 1999, a lawsuit was filed against the Company, one of its
subsidiaries  and  Thomas  G.  Finck,  Peter Rugg and Robert B. Holland, III, in
their  capacities as officers of the Company, in the District Court of the State
of  Texas  for  Dallas  County.  The lawsuit is styled Aaron Sherman, et al. vs.
Triton Energy Corporation et al. and seeks an unspecified amount of compensatory
and punitive damages and interest. The lawsuit alleges as causes of action fraud
and  negligent  misrepresentation  in connection with disclosures concerning the
prospective  sale  by  the  Company  of  all or a substantial part of its assets
announced  in  March  1998.  The  Company's date to answer has not yet run.  Its
subsidiary  has  filed  various motions to dispose of the lawsuit on the grounds
that  the plaintiffs do not have standing.  The Court has ordered the plaintiffs
to  replead  and  has  stayed  discovery    pending  its  further  orders.

     In  August 1997, the Company was sued in the Superior Court of the State of
California  for  the  County  of  Los  Angeles,  by  David  A.  Hite,  Nordell
International  Resources  Ltd.,  and  International  Veronex Resources, Ltd. The
action  has  since  been  removed  to  the  United States District Court for the
Central  District of California. The Company and the plaintiffs were adversaries
in  a 1990 arbitration proceeding in which the interest of Nordell International
Resources  Ltd.  in  the  Enim oil field in Indonesia was awarded to the Company
(subject  to  a  5% net profits interest for Nordell) and Nordell was ordered to
pay  the  Company  nearly  $1  million.  The arbitration award was followed by a
series  of  legal  actions by the parties in which the validity of the award and
its  enforcement were at issue.  As a result of these proceedings, the award was
ultimately  upheld  and  enforced.  The current suit alleges that the plaintiffs
were  damaged  in  amounts  aggregating  $13  million  primarily  because of the
Company's  prosecution  of  various claims against the plaintiffs as well as its
alleged  misrepresentations,  infliction  of  emotional  distress,  and improper
accounting  practices.  The  suit  seeks specific performance of the arbitration
award,  damages  for  alleged fraud and misrepresentation in accounting for Enim
field operating results, an accounting for Nordell's 5% net profit interest, and
damages  for emotional distress and various other alleged torts.  The suit seeks
interest,  punitive damages and attorneys fees in addition to the alleged actual
damages. In August 1998, the district court dismissed all claims asserted by the
plaintiffs  other  than  claims for malicious prosecution and abuse of the legal
process,  which the court held could not be subject to a motion to dismiss.  The
abuse  of process claim was later withdrawn, and the damages sought were reduced
to  approximately  $700,000  (not  including  punitive damages). The lawsuit was
tried  and  the  jury found in favor of the plaintiffs and assessed compensatory
damages against the Company in the amount of approximately $700,000 and punitive
damages  in the amount of approximately $11 million. The Company believes it has
acted  appropriately  and  intends  to  appeal  the  verdict.

     During  the  quarter  ended  September  30,  1995,  the  United  States
Environmental  Protection  Agency (the "EPA") and Justice Department advised the
Company  that  one  of  its  domestic oil and gas subsidiaries, as a potentially
responsible  party  for the clean-up of the Monterey Park, California, Superfund
site  operated  by  Operating  Industries,  Inc.,  could  agree  to  contribute
approximately  $2.8 million to settle its alleged liability for certain remedial
tasks  at the site. The offer did not address responsibility for any groundwater
remediation. The subsidiary was advised that if it did not accept the settlement
offer,  it,  together with other potentially responsible parties, may be ordered
to  perform  or  pay  for  various remedial tasks. After considering the cost of
possible  remedial tasks, its legal position relative to potentially responsible
parties  and insurers, possible legal defenses and other factors, the subsidiary
declined to accept the offer. In  October 1997, the EPA advised the Company that
the  estimated  cost  of  the  clean-up  of the site would be approximately $217
million  to  be  allocated among the 280 known operators. The subsidiary's share
would  be approximately $1 million based upon a volumetric allocation, but there
can  be no assurance that any allocation of liability to the subsidiary would be
made  on a volumetric basis. No proceeding has been brought in any court against
the  Company  or  the  subsidiary  in  this  matter.

     The  Company  is  also  subject  to  litigation  that  is incidental to its
business.

CERTAIN  FACTORS

     None  of  the  legal matters described above is expected to have a material
adverse  effect  on the Company's consolidated financial position. However, this
statement  of  the  Company's expectation is a forward-looking statement that is
dependent  on  certain  events  and  uncertainties  that  may  be outside of the
Company's  control. Actual results and developments could differ materially from
the  Company's  expectation,  for  example,  due  to  such uncertainties as jury
verdicts,  the  application  of  laws to various factual situations, the actions
that may or may not be taken by other parties and the availability of insurance.
In  addition, in certain situations, such as environmental claims, one defendant
may be responsible for the liabilities of other parties. Moreover, circumstances
could  arise  under which the Company may elect to settle claims at amounts that
exceed  the  Company's expected liability for such claims in an attempt to avoid
costly  litigation.  Judgments  or  settlements  could,  therefore,  exceed  any
reserves.


ITEM  4.  SUBMISSION  OF  MATTERS  TO  A  VOTE  OF  SECURITY  HOLDERS

     No  matter  was  submitted  by the Company during the fourth quarter of the
year  ended  December 31, 1999, to security holders, through the solicitation of
proxies  or  otherwise.

<PAGE>
                                     PART II

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

Ordinary  Shares
----------------

     Triton's  ordinary shares are listed on the New York Stock Exchange and are
traded  under the symbol OIL.  Set forth below are the high and low sales prices
of Triton's ordinary shares as reported on the New York Stock Exchange Composite
Tape  for  the  periods  indicated:



<TABLE>
<CAPTION>

<S>                   <C>    <C>

CALENDAR PERIODS      HIGH    LOW
--------------------  -----  -----
2000:
 First Quarter*       29.56  19.19
1999:
Fourth Quarter        27.50  13.50
Third Quarter         14.69  10.00
Second Quarter        16.00   6.94
First Quarter          8.88   5.19
1998:
Fourth Quarter        12.63   7.13
Third Quarter         37.75   9.75
Second Quarter        43.38  32.44
First Quarter         38.13  25.56
_____________
*Through March 6, 2000.

</TABLE>

     Triton  has  not  declared  any cash dividends on its ordinary shares since
fiscal  1990.  The  holders  of  ordinary  shares  are  entitled to receive such
dividends  as are declared by the Board of Directors. Under applicable corporate
law,  the  Company  may  pay  dividends  or  make  other  distributions  to  its
shareholders  in  such amounts as appear to the directors to be justified by the
profits  of  the  Company  or  out of the Company's share premium account if the
Company  has  the  ability  to  pay  its  debts  as  they  come  due.

     The Company's current intent is to retain earnings for use in the Company's
business  and  the  financing  of  its  capital requirements. The payment of any
future  cash  dividends on the ordinary shares is necessarily dependent upon the
earnings  and  financial  needs  of the Company, along with applicable legal and
contractual restrictions. Triton is prohibited from paying cash dividends on the
ordinary  shares  under  its  revolving  credit  facility.  In  addition,  the
Shareholders  Agreement  between  the Company and HM4 Triton, L.P. provides that
for  so  long  as  HM4  Triton,  L.P. and its affiliates own a certain number of
shares,  Triton cannot pay a dividend on the ordinary shares without HM4 Triton,
L.P.'s  consent.  See "Item 7. Management's Discussion and Analysis of Financial
Condition  and  Results  of  Operations"  and  note  12 of Notes to Consolidated
Financial  Statements.  Finally,  the  terms  of  the  8% Convertible Preference
Shares  and  the  5%  Convertible  Preference  Shares  prohibit  the  payment of
dividends  on  the  ordinary shares unless full cumulative dividends on all such
outstanding  preference  shares have been paid in full or set aside for payment.

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

At March 6, 2000, there were 4,061 record holders of the Company's ordinary
shares.

Preference Shares
-----------------

     The  Company  has  two  series  of  preference  shares  outstanding, the 8%
Convertible  Preference  Shares  and  the  5% Convertible Preference Shares. The
following  summary  of  certain  provisions  of the resolutions establishing the
terms  of  the  outstanding  preference  shares  is  not complete. Copies of the
resolutions  are  filed  as  exhibits  to  this  report.

8% Convertible Preference Shares

As of March 6, 2000, the Company had outstanding 5,189,758 8% Convertible
Preference Shares.

     Dividends.  The  Company is required to pay dividends on the 8% Convertible
     ---------
Preference  Shares  semi-annually at the rate of 8% per year of the stated value
per share (initially $70) for each semi-annual dividend period ending on June 30
and  December 31 of each year. Dividends on the 8% Convertible Preference Shares
are cumulative. The Company can choose to pay dividends in cash or in additional
8%  Convertible  Preference Shares. If the Company pays a dividend in additional
shares,  the  number  of  additional  shares  to be issued will be determined by
dividing  the  amount  of  the  dividend  by $70, with amounts in respect of any
fractional  shares  to  be  paid  in  cash.

     The  Company  may  not pay a dividend or other distribution on any ordinary
shares  or other shares ranking equal or junior to the 8% Convertible Preference
Shares  unless  all  dividends on the 8% Convertible Preference Shares have been
paid.  The  Company may pay a partial dividend on shares ranking equal to the 8%
Convertible  Preference  Shares as to dividends if the Company pays a partial to
the  holders of both the 8% Convertible Preference Shares and the equally-ranked
shares  in  proportion  to  the  accrued  and  unpaid  dividends  on each share.

     So  long  as  the  8%  Convertible  Preference  Shares are outstanding, the
Company  may  not  redeem  or  purchase any ordinary shares or any Triton shares
ranking  junior  as  to dividends to the 8% Convertible Preference Shares or any
other Triton shares ranking junior to the 8% Convertible Preference Shares as to
liquidation  rights  unless (1) full dividends on all outstanding 8% Convertible
Preference  Shares  and any other shares ranking equal as to dividends to the 8%
Convertible  Preference Shares have been, or contemporaneously are, paid and (2)
the  Company  pays  or  sets  aside cash (or additional shares of 8% Convertible
Preference  Shares)  in  amounts  sufficient to pay the dividend for the current
dividend  period.  In any event, the Company may purchase or acquire such junior
shares either (1) pursuant to any employee or director incentive or benefit plan
or  arrangement  or  (2)  in  exchange  solely  for  junior  shares.

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

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

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


<TABLE>
<CAPTION>

<S>                                                <C>

REDEMPTION NOTICE GIVEN ON THE SIX MONTHS ENDING:  AVERAGE PRICE
-------------------------------------------------  --------------
March 31, 2002                                     $ 28.54
September 30, 2002                                   31.14
March 31, 2003                                       34.20
September 30, 2003                                   37.58
March 31, 2004                                       32.57
September 30, 2004                                   34.97
March 31, 2005                                       37.60

</TABLE>

     Beginning  April 1, 2005, the minimum average price will be increased every
six  months to reflect an internal rate of return of 20% for a holder purchasing
8%  Convertible  Preference  Shares  as  of  the  date  the first 8% Convertible
Preference  Share was issued. The minimum average prices set forth above will be
adjusted  in  the  event  of any combination, subdivision or reclassification of
ordinary  shares,  or  any  similar  event.

     Liquidation  Rights.  The  liquidation  preference  of  the  8% Convertible
     -------------------
Preference  Shares  is  $70  per  share,  plus accumulated and unpaid dividends.

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

     The  Shareholders  Agreement  between  the  Company  and  HM4  Triton, L.P.
provides that, in general, for so long as the entire Board of Directors consists
of  ten members, HM4 Triton, L.P. (and its designated transferees, collectively)
may designate four nominees for election to the Board of Directors. The right of
HM4  Triton,  L.P.  (and  its  designated transferees) to designate nominees for
election  to  the  Board  of Directors will be reduced if the number of ordinary
shares  held  by  HM4 Triton, L.P. and its affiliates (assuming conversion of 8%
Convertible Preference Shares into ordinary shares) represents less than certain
specified  percentages  of the number of ordinary shares (assuming conversion of
8%  Convertible Preference Shares into ordinary shares) purchased by HM4 Triton,
L.P.  under  the  Stock  Purchase  Agreement between Triton and HM4 Triton, L.P.

     In  the  Shareholders  Agreement, the Company also agreed that it would not
take  certain  fundamental  corporate actions without the consent of HM4 Triton,
L.P.  Some  of  the  actions  that  would require HM4 Triton, L.P.'s consent are
listed  below:

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

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

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

-  paying dividends on the Company's ordinary shares;

-  incurring certain levels of debt; and

-  commencing a tender offer or exchange offer for any of the Company's ordinary
shares.

   5% Convertible Preference Shares

As of March 6, 2000, the Company had outstanding 209,558 5% Convertible
Preference Shares.

     Dividends.  The  Company is required to pay dividends on the 5% Convertible
     ---------
Preference  Shares  semi-annually  at  the rate of 5% per year of the redemption
price  per  share  (initially  $34.41)  for  each semi-annual dividend period on
September  30  and  March  30  of  each  year.  Dividends  on the 5% Convertible
Preference  Shares  are  cumulative.

     The  Company may not pay a dividend (other than dividends payable solely in
shares  ranking  junior  to  the  5%  Convertible  Preference  Shares)  or other
distribution  on  any  ordinary  shares or other shares ranking junior to the 5%
Convertible  Preference  Shares  unless  all  dividends  on  the  5% Convertible
Preference Shares have been paid. The Company may not pay dividends on any class
or series of shares ranking equal to the 5% Convertible Preference Shares unless
the Company has paid, or concurrently pays, all accrued and unpaid dividends for
all  prior  periods  on  the  5%  Convertible  Preference Shares. If any accrued
dividends  are  not paid in full on the 5% Convertible Preference Shares and any
shares  ranking  equal  to the 5% Convertible Preference Shares as to dividends,
the  Company  must pay any dividends on the 5% Convertible Preference Shares and
such equally-ranked shares so that the amount of dividends declared per share on
the  5%  Convertible  Preference Shares and such equally-ranked shares will bear
the same ratio that accrued and unpaid dividends per share on the 5% Convertible
Preference  Shares  and  such  equally-ranked  shares  bear  to  each  other.

     Conversion. Holders of  5% Convertible Preference Shares generally have the
     ----------
right  to convert their 5% Convertible Preference Shares into ordinary shares at
any  time  before redemption. Currently, each 5% Convertible Preference Share is
convertible  into  one  ordinary  share.  The  conversion  price  is  subject to
adjustment under certain circumstances. No payment or adjustment will be made in
respect  of  accrued or unpaid dividends on the 5% Convertible Preference Shares
upon  conversion  of 5% Convertible Preference Shares except as set forth below.

     Redemption.  The Company can redeem the 5% Convertible Preference Shares at
     ----------
any  time in whole or in part. The redemption price is $34.41 per share, plus an
amount  equal  to  all accumulated but unpaid dividends, and is payable in cash.

     If  any 5% Convertible Preference Shares are outstanding on March 30, 2004,
the  Company is required to redeem the 5% Convertible Preference Shares. In this
event,  the  Company  may  redeem  the  5%  Convertible  Preference  Shares  by

     (1)  paying cash at the $34.41 redemption price plus any accrued and unpaid
dividends  to  the  redemption  date;

     (2)  issuing  to the holder a number of ordinary shares with a market value
equal  to  the  $34.41 redemption price plus any accrued and unpaid dividends to
the  redemption  date;  or

     (3) a combination of cash or ordinary shares equal to the $34.41 redemption
price  plus  any  accrued  and  unpaid  dividends  to  the  redemption  date.

     Liquidation  Rights.  The  liquidation  preference  of  the  5% Convertible
     -------------------
Preference  Shares  is  $34.41 per share, plus accumulated and unpaid dividends.

     Voting  Rights.  The  holders  of  the  5%  Convertible  Preference  Shares
     --------------
generally  have no voting rights except as required under Cayman Islands law. So
long as any 5% Convertible Preference Shares are outstanding, the consent of the
holders  of  at  least  two-thirds  of the outstanding 5% Convertible Preference
Shares  is  required  if  the  Company  issues,  other  than  wholly  for  cash
consideration,  any  shares of any class of shares that would rank senior to the
5%  Convertible  Preference  Shares in dividend or liquidation rights, or if the
Company  proposes  to  amend  its  articles of association in a manner adversely
affecting the rights of the holders of the 5% Convertible Preference Shares. The
Company's  articles  of  association  may  be  amended to increase the number of
authorized  preference shares without the vote of the holders of the outstanding
5%  Convertible Preference Shares. When voting as a class, the holders of the 5%
Convertible  Preference  Shares  have  one  vote  per  share.

Shareholder  Rights  Plan
-------------------------

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

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

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

ITEM  6.  SELECTED  FINANCIAL  DATA

     The  following table sets forth certain financial and oil and gas data on a
historical  basis.


<TABLE>
<CAPTION>


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

                                                                  AS OF OR FOR YEAR ENDED
                                                                        DECEMBER 31,
                                                  -----------------------------------------------------
                                                   1999        1998         1997       1996      1995
                                                  --------  ----------  -----------  --------  --------
OPERATING DATA (IN THOUSANDS, EXCEPT PER
  SHARE  DATA):
Oil and gas sales                                 $247,878  $ 160,881   $  145,419   $129,795  $106,844
Sales and other operating revenues                 247,878    228,618      149,496    133,977   107,472
Earnings (loss) from continuing operations          47,557   (187,504)       5,595     23,805     6,541
Earnings (loss) before extraordinary items          47,557   (187,504)       5,595     23,805     2,720
Net earnings (loss)                                 47,557   (187,504)      (8,896)    22,609     2,720
Average ordinary shares outstanding                 36,135     36,609       36,471     35,929    35,147
Basic earnings (loss) per ordinary share:
   Continuing operations                          $   0.52  $   (5.21)  $     0.14   $   0.64  $   0.16
   Before extraordinary item                          0.52      (5.21)        0.14       0.64      0.05
   Net earnings (loss)                                0.52      (5.21)       (0.26)      0.61      0.05
Diluted earnings (loss) per ordinary share:
   Continuing operations                          $   0.52  $   (5.21)  $     0.14   $   0.62  $   0.16
   Before extraordinary item                          0.52      (5.21)        0.14       0.62      0.05
   Net earnings (loss)                                0.52      (5.21)       (0.25)      0.59      0.05

BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment                        $524,152  $ 470,907   $  835,506   $676,833  $524,381
Total assets                                       974,475    754,280    1,098,039    914,524   824,167
Long-term debt, including current maturities (1)   413,487    427,492      573,687    416,630   402,503
Shareholders' equity                               463,052    223,807      296,620    300,644   246,025

CERTAIN OIL AND GAS DATA  (2) :
Production
   Sales volumes (Mbbls) (3)                        12,469      9,979        5,776      5,987     6,303
   Forward oil sale deliveries (Mbbls)               3,050      3,050        2,462        701       409
                                                  --------  ----------  -----------  --------  --------

        Total revenue barrels (Mbbls)               15,519     13,029        8,238      6,688     6,712
                                                  ========  ==========  ===========  ========  ========

   Gas (MMcf)                                          459        503          802      2,517     5,312
Average sales price
   Oil (per bbl) (4)                              $  15.95  $   12.31   $    17.54   $  19.61  $  16.60
   Gas (per Mcf)                                  $   0.88  $    0.99   $     1.15   $   1.69  $   1.64
</TABLE>



__________________________

(1)  Includes current maturities totaling $9.0 million, $14.0 million, $130.4
million,  $199.6  million,  and  $1.3  million at December 31, 1999, 1998, 1997,
1996,  and  1995,  respectively.
(2)  Information presented includes the 49.9% equity investment in Crusader
Limited until its sale in 1996.
(3)  Includes natural gas liquids and condensate.
(4)  Includes barrels delivered under the forward oil sale, which are recognized
in oil and gas sales at $11.56  per  barrel  upon  delivery.




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


                       LIQUIDITY AND CAPITAL REQUIREMENTS
                       ----------------------------------

     Cash  and  equivalents totaled $186.3 million and $18.8 million at December
31,  1999  and  1998,  respectively,  and  working  capital (deficit) was $161.3
million  and  ($21.6  million)  at  December  31,  1999  and 1998, respectively.

     The  following  summary  table  reflects  cash flows of the Company for the
years  ended  December  31,  1999,  1998  and  1997  (in  thousands):



<TABLE>
<CAPTION>

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

                                                     1999       1998         1997
                                                  ----------  ---------  ----------
Net cash provided (used) by operating activities  $ 116,522   $  1,466   $ (97,416)
Net cash provided (used) by investing activities  $(118,530)  $ 84,191   $(212,700)
Net cash provided (used) by financing activities  $ 170,143   $(80,071)  $ 313,368


</TABLE>

Operating Activities
--------------------


               Cash  flows  provided  by operating activities for the year ended
December  31,  1999,  benefited  from  increased production from the Cusiana and
Cupiagua  fields  in Colombia, and higher oil prices.  Gross production from the
Cusiana  and  Cupiagua  fields  averaged  approximately 430,000 BOPD during 1999
compared  with  350,000  BOPD  during 1998 and 220,000 BOPD during 1997.  During
1999, 1998 and 1997, the Company's average realized oil price was $15.95, $12.31
and  $17.54,  respectively.  See  "Results  of  Operations  - Oil and Gas Sales"
below.  Based  on  estimates of the operator of the Cusiana and Cupiagua fields,
the  Company  believes that combined Cusiana and Cupiagua oil production will be
approximately  8%  to  11%  lower in 2000 than in 1999, although there can be no
assurance  that  actual  production  will  equal  that  amount.

               During  1999,  the  Company  received  substantially  all  of the
remaining  proceeds (approximately $31.9 million) from a forward oil sale in May
1995.  Starting  with the second quarter of 2000, 254,136 barrels per month, the
amount currently delivered under the forward oil sale, will become available for
sale.

               The  Company's  reported cash flows from operating activities for
the  year  ended  December  31,  1997, were reduced by $124.8 million, which was
attributable  to  interest  accreted  with  respect  to  the  Company's  Senior
Subordinated  Discount  Notes due November 1, 1997 (the "1997 Notes"), and the
9 3/4%  Senior  Subordinated Discount Notes due December 31, 2000
(the "9 3/4% Notes"), through  the  dates  of  retirement  in  the  second
quarter  of  1997.

Investing  Activities
---------------------

          The  Company's capital expenditures and other capital investments were
$121.5  million,  $180.2  million  and  $219.2  million  during  the years ended
December  31,  1999,  1998 and 1997, respectively, primarily for exploration and
development  of the Cusiana and Cupiagua fields in Colombia, and for exploration
within  the Company's licenses in Equatorial Guinea, the Malaysia-Thailand Joint
Development  Area  in  the  Gulf  of Thailand and in other areas.  Restructuring
activities  undertaken  in  1998  contributed to lower capital spending in 1999.
Proceeds  from  asset  sales  were  $2.4 million, $267 million and  $5.9 million
during 1999, 1998 and 1997, respectively.  See "Results of Operations" below and
note  2  of  Notes  to  Consolidated  Financial  Statements.

Financing  Activities
---------------------

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

          In  April  1999,  the  Company's Board of Directors authorized a share
repurchase  program  enabling the Company to repurchase up to ten percent of the
Company's  then outstanding 36.7 million ordinary shares.  Purchases of ordinary
shares  by  the  Company began in April and may be made from time to time in the
open  market  or  through privately negotiated transactions at prevailing market
prices  depending  on  market  conditions.  The  Company  has  no  obligation to
repurchase  any  of  its  outstanding  shares  and  may  discontinue  the  share
repurchase  program  at  management's  discretion.  As of December 31, 1999, the
Company  had  purchased  948,300  ordinary shares for $11.3 million.  Because of
anticipated  capital  needs in Equatorial Guinea, the Company did not include in
its capital budget for 2000 any amounts for share repurchases under the program.
In  addition,  the Company's revolving credit facility, entered into in February
2000,  generally  does  not permit the Company to repurchase its ordinary shares
without  the  banks'  consent.

          During  1999,  the  Company  repaid  borrowings  totaling $19 million,
including $10 million under unsecured credit facilities that were outstanding at
December  31,  1998.  By  December  31,  1999,  all  of  the Company's unsecured
revolving  credit  facilities  that  were  outstanding  at December 31, 1998 had
expired.  In addition, the Company paid cash preference dividends totaling $17.6
million  in  1999.

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

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

     In  May  and  June  1997,  the  Company  offered  to  purchase  all  of its
outstanding  1997  Notes and 9 3/4% Notes, which resulted in the retirement of
the 1997  Notes  and substantially all of the 9 3/4% Notes.  The remainder of
the 9 3/4% Notes  were  retired  in  1998.  During  the  year  ended December
31, 1997, the Company borrowed $630 million and repaid $321.5 million under
revolving lines of credit,  notes  payable  and  long-term  debt  (including
the  Senior  Notes).

FUTURE  CAPITAL  NEEDS

          The  Company  intends  to  implement  an  accelerated  appraisal  and
development  program  to  enable  early  production from the Ceiba field, with a
target of first production by the end of 2000, and has contracted for a floating
production  storage  and  offloading  (FPSO)  system that is expected to provide
storage  for two million barrels of oil and initial processing capacity of up to
60,000  barrels  of  oil per day from a single production unit.  Capacity can be
cost-effectively  increased  through  the addition of up to three similar units.
In  addition,  the  Company intends to accelerate its exploration, appraisal and
development  drilling  activities  through  implementation of a two-rig drilling
program  that  is  intended to enable the Company to complete the Ceiba-1 and -2
wells  as  production  wells,  to  drill  and  complete  two  additional
appraisal/production  wells  in  the Ceiba field, to drill two exploration wells
and  to  provide  the  Company  the  option to drill up to six additional wells.

          The  Company  expects  that  its accelerated appraisal and development
program  for  Equatorial  Guinea  will  require  significant  capital  outlays
commencing  in  the  year  2000.  For  internal planning purposes, the Company's
capital spending program for the year ending December 31, 2000, is approximately
$191  million,  excluding  capitalized  interest  and  acquisitions,  of  which
approximately  $122 million relates to exploration and development activities in
Equatorial  Guinea,  $58  million  relates to the Cusiana and Cupiagua fields in
Colombia,  and  $11  million  relates to the Company's exploration activities in
other  parts  of  the world.  The 2000 capital spending program does not include
the  six  optional  wells  in  Equatorial  Guinea.

          In conjunction with the sale of Triton Pipeline Colombia, Inc. ("TPC")
to  an  unrelated  third  party  (the "Purchaser") in February 1998, the Company
entered  into  a five year equity swap with a creditworthy financial institution
(the  "Counterparty").  The  issuance  to HM4 Triton, L.P. of the 8% Convertible
Preference  Shares  resulted  in  the right of the Counterparty to terminate the
equity  swap  prior  to  the  end  of  its  five year term. In January 1999, the
Counterparty  exercised  its  right and designated April 2000 as the termination
date  of  the equity swap. Upon the expiration of the equity swap in April 2000,
the Company expects that the Purchaser will sell the TPC shares. Under the terms
of  the equity swap with the Counterparty, upon any sale by the Purchaser of the
TPC  shares,  the  Company  will  receive  from  the Counterparty, or pay to the
Counterparty, an amount equal to the excess or deficiency, as applicable, of the
difference  between 97% of the net proceeds from the Purchaser's sale of the TPC
shares  and  the  notional  amount of $97 million. For example, if the Purchaser
sold  the  TPC shares for an amount equal to the value the Company has estimated
for purposes of preparing its balance sheet as of December 31, 1999, the Company
would  have  to  make  a  payment  to  the Counterparty under the equity swap of
approximately  $8.4  million.  There  can  be  no  assurance  that the value the
Purchaser  may realize in any sale of the TPC shares will equal the value of the
shares  estimated  by  the  Company for purposes of valuing the equity swap. The
Company has no right or obligation to repurchase the TPC shares at any time, but
the  Company  is  not  prohibited  from  offering  to purchase the shares if the
Purchaser  offers  to  sell  them.  The  Company  expects  to make a bid for the
acquisition  of  the  TPC  shares  because the Company's pipeline tariffs can be
lowered  by  electing to cancel the dividend to the holder of the OCENSA shares.
See  "Results  of Operations - Other Income and Expenses" below, note 2 of Notes
to  Consolidated  Financial  Statements,  and  "Quantitative  and  Qualitative
Disclosures  about  Market  Risk"  below.

          In  February  2000,  the  Company  entered  into an unsecured two-year
revolving credit facility with a group of banks, which matures in February 2002.
The  credit  facility gives the Company the right to borrow from time to time up
to  the amount of the borrowing base determined by the banks, not to exceed $150
million.  As  of February 2000, the borrowing base was $150 million.  The credit
facility  contains  various  restrictive  covenants,  including  covenants  that
require  the  Company  to  maintain  a  ratio  of  earnings  before  interest,
depreciation,  depletion,  amortization and income taxes to net interest expense
of  at least 2.5 to 1, and that prohibit the Company from permitting net debt to
exceed  the  product  of  3.75  times  the  Company's  earnings before interest,
depreciation,  depletion,  amortization  and  income  taxes,  in each case, on a
trailing  four  quarters basis.  As of March 6, 2000, the Company had not made a
borrowing  under  the  facility.

     The  Company  expects  to  fund 2000 capital spending with a combination of
some  or  all  of  the following: cash flow from operations, cash, the Company's
committed  bank  credit facility, and the issuance of debt or equity securities.
To  facilitate  a  possible future securities issuance or issuances, the Company
has  on  file  with  the  Securities  and  Exchange  Commission  ("SEC") a shelf
registration statement under which the Company could issue up to an aggregate of
$250  million  debt  or  equity  securities.

     At December 31, 1999, the Company had guaranteed the performance of a total
of  $16.4  million  in  future  exploration  expenditures to be incurred through
September 2001 in various countries.  A total of approximately $6 million of the
exploration  expenditures  are  included  in  the  2000 capital spending program
related  to  a  commitment  for  two onshore exploratory wells in Greece.  These
commitments  are  backed  primarily by unsecured letters of credit.  The Company
also  had guaranteed loans of approximately $1.4 million, which expire September
2000, for a Colombian pipeline company, Oleoducto de Colombia S.A., in which the
Company  has  an  ownership  interest.

          On  October  30,  1999,  the  Company  and  the  other  parties to the
production-sharing  contract  for  Block  A-18  executed  a  gas sales agreement
providing  for  the  sale  of the first phase of gas. Under the terms of the gas
sales  agreement, delivery of gas is scheduled to begin by the end of the second
quarter  of  2002,  following timely completion and approval of an environmental
impact  assessment  associated  with  the  buyers'  pipeline  and  processing
facilities. No assurance can be given as to when such approval will be obtained.
In  connection with the sale to ARCO of one-half of the shares through which the
Company  owned  its  interest  in  Block  A-18,  ARCO  agreed  to pay the future
exploration  and  development  costs  attributable  to  the Company's and ARCO's
collective  interest in Block A-18, up to $377 million or until first production
from  a  gas  field.  There  can  be  no assurance that the Company's and ARCO's
collective  share  of  the  cost  of developing the project will not exceed $377
million. See "Certain Factors Relating to Malaysia-Thailand" in note 19 of Notes
to  Consolidated  Financial  Statements.

                              RESULTS OF OPERATIONS
                              ---------------------

                          YEAR ENDED DECEMBER 31, 1999,
                   COMPARED WITH YEAR ENDED DECEMBER 31, 1998

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

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

          As  a  result  of  financial and commodity market transactions settled
during  the  year ended December 31, 1999, the Company's risk management program
resulted  in  lower oil sales of approximately $19.8 million than if the Company
had  not  entered into such transactions.   Additionally, the Company has hedged
its  WTI  price  on  a  portion  of  its  projected  2000  oil  production.  See
"Quantitative  and  Qualitative  Disclosures  about  Market  Risk"  below.

          The  delivery requirement under the forward oil sale will be completed
in  March  2000.  Starting  with the second quarter of 2000, 254,136 barrels per
month,  the amount currently delivered under the forward oil sale and recognized
in  revenues  at  $11.56  per  barrel,  will  become  available  for  sale.

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

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

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

            Operating expenses, which include field operating expenses, pipeline
tariffs  and  production  taxes,  decreased  $5.4  million  in  1999.  On an oil
equivalent-barrel  basis,  operating  expenses  were $4.50 and $5.97 in 1999 and
1998,  respectively.  The  Company  pays  lifting  costs,  production  taxes and
transportation  costs  to  the  Colombian  port  of  Covenas  for  barrels to be
delivered  under  the  forward  oil  sale.  Operating  expenses  on  a  per
equivalent-barrel  basis  were lower primarily due to higher production volumes.
OCENSA  pipeline  tariffs  totaled  $42.1 million  and $49.9 million in 1999 and
1998,  respectively.  Pipeline  tariffs  for  1999 were lower primarily due to a
non-recurring  credit  issued  by OCENSA in February 2000 totaling $4.2 million.
The  credit resulted from OCENSA's compliance with a Colombian government decree
in  December  1999  that  reduced  its  1999 noncash expenses.  OCENSA imposes a
tariff  on  shippers  from  the  Cusiana  and  Cupiagua  fields  (the  "Initial
Shippers"),  which is estimated to recoup: the total capital cost of the project
over  a  15-year  period;  its  operating  expenses, which include all Colombian
taxes;  interest  expense;  and  the  dividend  to  be  paid  by  OCENSA  to its
shareholders.  Any  shippers  of  crude  oil  who  are  not Initial Shippers are
assessed  a  premium  tariff on a per-barrel basis, and OCENSA will use revenues
from  such  tariffs  to  reduce  the  Initial  Shippers'  tariff.

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

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

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

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

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

     In  June  and December 1998, the carrying amount of the Company's evaluated
oil  and  gas  properties  in Colombia was written down by $105.4 million ($68.5
million,  net  of  tax)  and  $135.6  million  ($115.9  million,  net  of  tax),
respectively,  through  application  of  the  full  cost  ceiling  limitation as
prescribed  by  the SEC, principally as a result of a decline in oil prices.  No
adjustments  were  made to the Company's reserves in Colombia as a result of the
decline  in  prices.  The SEC ceiling test was calculated using the June 30, and
December  31,  1998,  WTI oil prices of $14.18 per barrel and $12.05 per barrel,
respectively, that, after a differential for Cusiana crude delivered at the port
of  Covenas in Colombia, resulted in a net price of approximately $13 per barrel
and  $11  per  barrel,  respectively.

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

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

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

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

          As  a  result  of  the  restructuring,  the Company recognized special
charges  of $15 million during the third quarter of 1998 and $3.3 million during
the  fourth  quarter of 1998 for a total of $18.3 million.  Of the $18.3 million
in  special  charges,  $14.5  million related to the reduction in workforce, and
represented  the  estimated  costs  for  severance,  benefit  continuation  and
outplacement  costs,  which  will  be  paid  over  a  period  of up to two years
according  to the severance formula. Since July 1998, the Company has paid $13.1
million in severance, benefit continuation and outplacement costs.    A total of
$2.1  million  of special charges related to the closing of foreign offices, and
represented  the  estimated costs of terminating office leases and the write-off
of  related  assets.   The  remaining  special charges of $1.7 million primarily
related  to  the  write-off  of  other  surplus  fixed assets resulting from the
reduction  in  workforce.  At  December  31, 1999, all of the positions had been
eliminated,  all designated foreign offices had closed and all licenses had been
relinquished, sold, or their commitments renegotiated. During the fourth quarter
of  1999,  the  Company  reversed $.7 million of the accrual associated with the
completion  of restructuring activities.  The remaining liability related to the
restructuring activities undertaken in 1998 was $1 million at December 31, 1999.

          In  March  1999,  the  Company accrued special charges of $1.2 million
related to an additional 15% reduction in the number of employees resulting from
the Company's continuing efforts to reduce costs.  The special charges consisted
of $1 million for severance, benefit continuation and outplacement costs and $.2
million related to the write-off of surplus fixed assets.  Since March 1999, the
Company has paid $.9 million in severance, benefit continuation and outplacement
costs.  At  December  31,  1999,  the  remaining  liability  related  to  the
restructuring  activities  undertaken  in  1999  was  $.1  million.

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

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

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

     Interest  Expense
     -----------------

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

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

          Other  income  (expense), net, included a foreign exchange gain (loss)
of  ($2.7 million) and $2.1 million  in 1999 and 1998, respectively. During 1999
and  1998,  the  Company  recorded  gains  of  $6.2  million  and  $.4  million,
respectively,  representing  the  change  in  the fair value of the call options
purchased  in  anticipation of a forward oil sale.  In addition, during 1999 and
1998,  the  Company  recorded  an  expense  of  $6.9  million  and $3.3 million,
respectively,  in  other income (expense), net, related to the net payments made
under  and  the  change  in  the  fair  value of the equity swap entered into in
conjunction  with  the  sale  of TPC.  Net payments made (or received) under the
equity swap, and any fluctuations in the fair values of the call options and the
equity  swap,  in future periods will affect other income (expense), net in such
periods.  See  "Quantitative  and  Qualitative  Disclosures  About  Market Risk"
below.  In  1999  and 1998, the Company recorded loss provisions of $2.3 million
and  $.8 million, respectively, for certain legal matters.  In 1998, the Company
recognized  gains of $7.6 million on the sale of corporate assets in addition to
the  ARCO  and  TPC  transactions.

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

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

          Current taxes related to the Company's Colombian operations were $20.8
million  and  $4.4  million  in  1999  and  1998,  respectively.  The income tax
provision for 1999 included a foreign deferred tax expense totaling $9.2 million
compared  with  a  foreign  deferred  tax  benefit  of $57 million in 1998.  The
benefit  recognized in 1998 primarily resulted from the writedown of oil and gas
properties.  Additionally,  the  income  tax  provision  included a deferred tax
benefit  in the United States totaling $1.4 million, compared with an expense of
$1.5  million  in  1998.

          At  December  31,  1999,  the  Company  had U.S. NOLs of approximately
$450.2  million  compared  with NOLs of approximately $415.6 million at December
31,  1998.  The  NOLs  expire  from  2000  to  2020.  See  note  10  of Notes to
Consolidated  Financial  Statements.  At  December  31,  1999,  the  Company's
Colombian  operations  and  other  foreign  operations had NOLs and other credit
carryforwards  totaling $57.4 million and $40.7 million, respectively, that will
expire  between  2001  and  2004.

          During  1999,  the Company acquired the Colombian entity of its former
partner in the El Pinal field.  In addition to the working interest in the El
Pinal  field, the acquired entity has tax basis and NOLs totaling approximately
$40 million,  included  in  total  foreign  NOLs above, which the Company
expects to utilize in 2000.  At December 31, 1999, the tax affected amount of
the tax basis and  NOLs  ($14.2 million) has been included in current assets as
a deferred tax asset.  In  addition,  the  Company  recorded  deferred income of
$10.6 million, representing  the difference between the value of the deferred
tax asset and the purchase  price.  During  2000,  the  deferred tax asset and
the deferred income will  be  reduced  as  the  tax  basis  and  NOLs  are
utilized.

          The  Company  recorded a U.S. deferred tax asset of $88.2 million, net
of  a valuation allowance of $72.9 million, at December 31, 1999.  The valuation
allowance  was  primarily  attributable  to  management's  assessment  of  the
utilization  of  NOLs  in  the U.S., the expectation that other tax credits will
expire  without  being  utilized, and certain temporary differences will reverse
without  a  benefit to the Company.  The minimum amount of future taxable income
necessary  to realize the U.S. deferred tax asset is approximately $252 million.
Although  there  can  be  no  assurance  the Company will achieve such levels of
income,  management  believes  the  deferred  tax asset will be realized through
income  from  its  operations.


                          YEAR ENDED DECEMBER 31, 1998,
                   COMPARED WITH YEAR ENDED DECEMBER 31, 1997

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

          Oil and gas sales in 1998 totaled $160.9 million, an 11% increase from
1997,  due  to  higher  production,  which was partially offset by significantly
lower  average realized oil prices.  Total revenue barrels, including production
related  to  barrels  delivered  under  the forward oil sale, totaled 13 million
barrels in 1998, an increase of 58%, compared to the prior year, resulting in an
increase  in  revenues  of $84.2 million. The increased production was primarily
due  to the start-up in late 1997 of two new 80,000 BOPD oil-production units at
the  Cusiana  central  processing  facility.  In  addition,  two  100,000  BOPD
oil-production  units  at  the  Cupiagua  central  processing  facility  began
production  during  the second half of 1998.  The average realized oil price was
$12.31  and  $17.54  in 1998 and 1997, respectively, a decrease of 30% for 1998,
resulting  in  lower  revenues  of  $68.3  million  compared to 1997.  The lower
average  realized  oil  price  resulted  from a significant decrease in the 1998
average  WTI  oil  price.

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

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

          In  June  1997,  the  Company  sold  its Argentine subsidiary for cash
proceeds  of  $4.1  million  and  recognized  a  gain  of  $4.1  million.

     Operating  Expenses  and  Depreciation,  Depletion  and  Amortization
     ---------------------------------------------------------------------

          Operating  expenses increased $22.2 million in 1998, and depreciation,
depletion  and  amortization  increased  $22  million,  primarily  due to higher
production volumes, including barrels delivered under the forward oil sale.  The
Company's operating costs per oil equivalent-barrel were $5.97 and $6.47 in 1998
and 1997, respectively. Operating expenses on a per equivalent-barrel basis were
lower  primarily  due  to higher production volumes and a decrease in production
taxes  of  $7.8 million. Beginning in 1998, no production taxes were assessed on
production  from  the Cusiana field.  These improvements to operating costs were
partially  offset  by an increase in OCENSA pipeline tariffs which totaled $49.9
million  or $4.08 per barrel, and $28.7 million or $3.69 per barrel, in 1998 and
1997,  respectively.  The  OCENSA pipeline expansion was completed at the end of
1997.  At  such  time,  the full cost of the pipeline was included in the tariff
computation,  which  was  the  primary  contributor  to the higher 1998 tariffs.

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

          General  and  administrative  expense  before capitalization decreased
$13.8  million  to  $47.2  million  in  1998,  while  capitalized  general  and
administrative  costs  were  $20.6  million  and $32.4 million in 1998 and 1997,
respectively.  General and administrative expenses, and the portion capitalized,
decreased  as  a  result  of  restructuring  activities  undertaken in the third
quarter  of  1998  to  reduce  overhead  costs  and  exploration  expenses.

     Interest  Expense
     -----------------

          Gross  interest  expense  for  1998 and 1997 totaled $46.4 million and
$49.7  million, respectively, while capitalized interest for 1998 decreased $2.6
million  to $23.2 million. The decrease in capitalized interest is primarily due
to the writedown of unevaluated property totaling $73.9 million in June 1998 and
a  sale  of  50%  of  the  Company's  Block  A-18  project  in  August  1998.

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

          Other  income  (expense), net, included foreign exchange gains of $2.1
million  and  $9.5  million in 1998 and 1997, respectively, primarily related to
noncash  adjustments  to  deferred  tax  liabilities in Colombia associated with
devaluation of the Colombian peso versus the U.S. dollar.  In 1998 and 1997, the
Company  recognized gains of $7.6 million and $1.4 million, respectively, on the
sale  of  corporate  assets.  During  1998 and 1997, the Company recorded a gain
(loss)  of $.4 million and ($9.7 million), respectively, representing the change
in the fair value of the call options purchased in anticipation of a forward oil
sale.  In addition, during 1998, the Company recorded an expense of $3.3 million
in  other  income (expense), net, related to the net payments made under and the
change in the fair value of the equity swap entered into in conjunction with the
sale  of  TPC.

<PAGE>
     Income  Taxes
     -------------

          The  income  tax  provision  for  1998 included a foreign deferred tax
benefit totaling $57 million compared with a foreign deferred tax expense of $16
million  in  1997.  The  benefit  recognized in 1998 primarily resulted from the
writedown  of  oil  and  gas properties.  Additionally, the income tax provision
included  deferred  tax  expense  in  the  United  States totaling $1.5 million,
compared  with  a benefit of $7.9 million in 1997.  Current taxes related to the
Company's  Colombian  operations  were $4.4 million and $3.4 million in 1998 and
1997,  respectively.

     Extraordinary  Item
     -------------------

          In May and June 1997, the Company completed a tender offer and consent
solicitation  with respect to its 1997 Notes and 9 3/4% Notes that resulted in
the retirement  of  the  1997  Notes  and  substantially all of the 9 3/4%
Notes.  The Company's  results  of  operations for 1997 included an
extraordinary expense of $14.5  million,  net  of  a  $7.8  million  tax
benefit,  associated  with  the extinguishment  of  the  1997  Notes  and
9 3/4% Notes.  The remainder of the 9 3/4% Notes  were  retired  in  1998.


                         EXPLORATION  OPERATIONS
                         -----------------------

          Costs  related  to  acquisition,  holding  and  initial exploration of
licenses  in  countries  with  no  proved  reserves  are  initially capitalized,
including  internal  costs directly identified with acquisition, exploration and
development  activities.  The  Company's  exploration  licenses are periodically
assessed  for  impairment  on  a  country-by-country  basis.  If  the  Company's
investment in exploration licenses within a country where no proved reserves are
assigned  is  deemed  to be impaired, the licenses are written down to estimated
recoverable value.  If the Company abandons all exploration efforts in a country
where  no  proved  reserves  are assigned, all acquisition and exploration costs
associated  with the country are expensed.  The Company's assessments of whether
its  investment  within a country is impaired and whether exploration activities
within  a  country  will  be  abandoned  are made from time to time based on its
review and assessment of drilling results, seismic data and other information it
deems  relevant.  Due  to  the  unpredictable  nature  of  exploration  drilling
activities, the amount and timing of impairment expense are difficult to predict
with  any  certainty.  For  example,  in the second quarter of 1998, the Company
recorded  a  $77.3  million ($72.6 million, net of tax) writedown of unevaluated
oil  and  gas properties relating to the Company's operations in China, Ecuador,
Guatemala  and  other countries.  There can be no assurance that, in the future,
the Company will not incur writedowns or expense with respect to its exploration
licenses.  Financial information concerning the Company's assets at December 31,
1999,  including capitalized costs by geographic area, is in note 21 of Notes to
Consolidated  Financial  Statements.


                              ENVIRONMENTAL MATTERS
                              ---------------------

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

                        RECENT ACCOUNTING PRONOUNCEMENTS
                        --------------------------------

               In  June  1998,  the  Financial Accounting Standards Board issued
Statement  No.  133  ("SFAS  133"),  "Accounting  for Derivative Instruments and
Hedging  Activities."  SFAS  133  establishes accounting and reporting standards
for  derivative instruments and for hedging activities.  It requires enterprises
to  recognize  all  derivatives  as  either assets or liabilities in the balance
sheet and measure those instruments at fair value.  The requisite accounting for
changes in the fair value of a derivative will depend on the intended use of the
derivative  and  the  resulting  designation.  The  Company  must adopt SFAS 133
effective  January  1,  2001.  Based  on  the  Company's outstanding derivatives
contracts,  the Company believes that the impact of adopting this standard would
not  have  a material adverse effect on the Company's operations or consolidated
financial  condition.  However,  no  assurances  can be given with regard to the
level of the Company's derivatives activities at the time SFAS 133 is adopted or
the  resulting  effect  on  the  Company's  operations or consolidated financial
condition.

                                YEAR 2000 UPDATE
                                ----------------

          In  1998,  the Company began a formal process to prepare the Company's
internal  computerized  systems  for  the  Year  2000.   From  inception through
December  31, 1999, the Company spent approximately $250,000 related to the Year
2000  readiness  issue.  These costs included external consultants, professional
advisors,  and  software  and  hardware.  No  further  material  expenses  are
anticipated.  To  date, the Company has not experienced any significant problems
related  to  Year  2000  compliance.  Although  the Company has not suffered any
significant Year 2000 issues or related disruptions as a result of the roll over
from  1999  to 2000, including through third parties with whom the Company has a
business  relationship,  it  is possible that certain Year 2000 issues may exist
but  have  not yet materialized. While the Company believes that any future Year
2000  issues  are  of  a  much  lower risk, there can be no assurance that these
issues  will  not  have  a  material  effect  on  the  Company's  operations.

               CERTAIN FACTORS THAT COULD AFFECT FUTURE OPERATIONS
               ---------------------------------------------------

          Certain  information  contained in this report, as well as written and
oral  statements  made  or  incorporated  by  reference from time to time by the
Company  and  its  representatives in other reports, filings with the Securities
and  Exchange  Commission,  press  releases,  conferences,  teleconferences  or
otherwise,  may  be deemed to be "forward-looking statements" within the meaning
of  Section  21E  of  the Securities Exchange Act of 1934 and are subject to the
"Safe  Harbor"  provisions  of that section.  Forward-looking statements include
statements  concerning  the Company's and management's plans, objectives, goals,
strategies  and future operations and performance and the assumptions underlying
such  forward-looking  statements.  When  used  in  this  document,  the  words
"anticipates,"  "estimates,"  "expects,"  "believes,"  "intends,"  "plans"  and
similar  expressions  are  intended to identify such forward-looking statements.
These  statements  include  information  regarding:

-  drilling schedules;

-  expected or planned production capacity;

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

-  the completion of development and commencement of production in
   Malaysia-Thailand;

-  future production of the Ceiba field in Equatorial Guinea, including volumes
   and timing of first production;

-  the acceleration of the Company's exploration, appraisal and development
   activities in Equatorial Guinea;

-  the Company's capital budget and future capital requirements;

-  the Company's meeting its future capital needs;

-  the Company's utilization of net operating loss carryforwards and realization
   of its deferred tax asset;

-  the level of future expenditures for environmental costs;

-  the outcome of regulatory and litigation matters;

-  the estimated fair value of derivative instruments, including the equity
   swap; and

-  proven oil and gas reserves and discounted future net cash flows therefrom.


          These  statements  are  based  on  current  expectations and involve a
number  of  risks and uncertainties, including those described in the context of
such forward-looking statements, and in notes 19 and 20 of Notes to Consolidated
Financial  Statements.  Actual  results and developments could differ materially
from  those  expressed  in  or implied by such statements due to these and other
factors.


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

Commodity Risk
--------------

     The  Company's  primary commodity market risk exposure is to changes in the
pricing  applicable  to  its  oil  production,  which  is  normally  priced with
reference  to  a defined benchmark, such as light, sweet crude oil traded on the
New  York  Mercantile  Exchange  (WTI).  Actual  prices  received  vary from the
benchmark  depending  on  quality  and  location differentials.  The markets for
crude  oil  historically  have  been  volatile  and are likely to continue to be
volatile  in  the  future. During the three year period ended December 31, 1999,
WTI  oil  prices  fluctuated between a low price of $11.37 per barrel and a high
price  of  $27.07  per  barrel.

     From  time  to  time,  it  is  the Company's policy to use financial market
transactions,  including  swaps,  collars  and  options,  with  creditworthy
counterparties,  primarily  to  reduce the risk associated with the pricing of a
portion  of  the oil and natural gas that it sells.  The policy is structured to
underpin  the Company's planned revenues and results of operations.  The Company
does  not  enter  into  financial  market  transactions  for  trading  purposes.

     During  the  years  ended  December 31, 1999 and 1997, markets provided the
Company the opportunity to realize WTI benchmark oil prices on average $6.37 per
barrel and $2.35 per barrel, respectively, above the WTI benchmark oil price the
Company  set  as  part  of its annual plan for the period. During the year ended
December  31,  1998,  the  Company did not have any outstanding financial market
transactions  to hedge against oil price fluctuations.  As a result of financial
and  commodity  market  transactions settled during the years ended December 31,
1999  and 1997, the Company's risk management program resulted in an average net
realization of approximately $1.65 per barrel and $.11 per barrel, respectively,
lower than if the Company had not entered into such transactions. Realized gains
or  losses from the Company's price risk management activities are recognized in
oil  and  gas  sales  at  the  time  of  settlement  of  the  underlying  hedged
transaction.

With  respect  to the sale of oil to be produced by the Company, the Company has
entered  into  oil price collars with creditworthy counterparties to establish a
weighted  average minimum WTI benchmark price of $18.92 per barrel and a maximum
of $24.45 per barrel on an aggregate of 3.6 million barrels of production during
the  period  from  January  through  June  2000.  As a result, to the extent the
average  monthly  WTI  price  exceeds  $24.45,  the  Company  will  pay  the
counterparties  the difference between the average monthly WTI price and $24.45,
and  to  the  extent  that  the  average  monthly WTI price is below $18.92, the
counterparties  will  pay the Company the difference between the average monthly
WTI  price  and  $18.92.  In  addition,  the  Company  has  entered  into option
contracts  for  an  aggregate of 300,000 barrels of production during the period
from  July  through  September  2000.  As  a  result,  to the extent the monthly
average WTI exceeds $28.43 per barrel, the Company will pay the counterparty the
difference  between  the  average WTI and $28.43, and to the extent WTI is at or
below  $22.00,  the  counterparty  will  pay  the Company $2.00 per barrel.  The
Company  used  a  sensitivity  analysis  technique  to evaluate the hypothetical
effect  that  changes  in  WTI  oil  prices  may have on the fair value of these
contracts.  At  December  31,  1999,  the potential decrease in future earnings,
assuming  a  ten  percent  movement in WTI oil prices, would not have a material
adverse  effect  on  the Company's consolidated financial position or results of
operations.

     In  anticipation of entering into the forward oil sale, in 1995 the Company
purchased  WTI  benchmark call options to retain the ability to benefit from WTI
price  increases  above  a  weighted  average  price  of $20.42 per barrel.  The
volumes  and  expiration dates on the call options coincide with the volumes and
delivery  dates of the forward oil sale, which will be completed in  March 2000.
During  the years ended December 31, 1999, 1998 and 1997, the Company recorded a
gain  (loss)  of $6.1 million, $.4 million, and ($9.7 million), respectively, in
other  income  (expense), net, related to the change in the fair market value of
the call options.  In November 1999, the Company sold WTI benchmark call options
with  the  same  notional  quantities,  strike  price and contract period as the
remaining  call  option  contracts outstanding for a premium of $4.4 million for
the  purpose  of  realizing  the  fair value of the purchased call options. As a
result,  the  Company  has eliminated its exposure to future changes in value of
the  call  options  caused  by  fluctuating  oil  prices.

Interest  Rate  Risk
--------------------

     Equity  Swap
     ------------

          In  conjunction  with  the  sale  of  TPC, the Company entered into an
equity swap with a creditworthy financial institution (the "Counterparty").  The
equity  swap  has  a  notional amount of $97 million and requires the Company to
make  quarterly  floating  LIBOR-based  payments  on  the notional amount to the
Counterparty.  In exchange, the Counterparty is required to make payments to the
Company equivalent to 97% of the dividends TPC receives in respect of its equity
interest in OCENSA.  The Company's LIBOR-based payments commenced in March 1998,
and  OCENSA  commenced  paying  dividends  in  September  1998.  OCENSA's  first
dividend was attributable to the four month period ending June 1998.  During the
years  ended  December  31,  1999  and  1998,  the  Company made payments to the
Counterparty  totaling $6.2 million and $5.9 million, respectively, and received
payments  from  the  Counterparty  totaling  $7.8  million  and  $2.6  million,
respectively.

     The  equity  swap  is carried in the Company's financial statements at fair
value during its term, which, as amended, will expire April 14, 2000.  The value
of  the equity swap in the Company's financial statements is equal to 97% of the
estimated  fair value of the shares of OCENSA owned by TPC.  Because there is no
public  market for the shares of OCENSA, the Company estimates their value using
a discounted cash flow model applied to the distributions expected to be paid in
respect  of  the OCENSA shares.  The discount rate applied to the estimated cash
flows  from  the OCENSA shares is based on a combination of current market rates
of  interest,  a  credit  spread  for OCENSA's debt, and a spread to reflect the
preferred stock nature of the OCENSA shares. During the years ended December 31,
1999  and 1998, the Company recorded an expense of $6.9 million and $3.3 million
in  other  income (expense), net, related to the net payments made under and the
change  in the fair market value of the equity swap.  The Company also evaluated
the  potential effect that near-term changes in interest rates could have on the
fair  value  of  the  equity  swap.  Based upon an analysis utilizing the actual
discount  rate  in  effect  as  of December 31, 1999, and assuming a ten percent
adverse  movement in the discount rate, the potential decrease in the fair value
of  the  equity  swap at December 31, 1999, would be approximately $6.3 million.
Net  payments  made (or received) under the equity swap, and any fluctuations in
the  fair  value of the equity swap, in future periods, will affect other income
(expense),  net  in  such  periods.  There  can  be no assurance that changes in
interest  rates,  or in other factors that affect the value of the OCENSA shares
and/or  the equity swap, will not have a material adverse effect on the carrying
value  of  the  equity  swap.

          Upon  the  expiration  of  the  equity swap in April 2000, the Company
expects  that  the  Purchaser  will  sell the TPC shares. Under the terms of the
equity  swap  with  the  Counterparty, upon any sale by the Purchaser of the TPC
shares,  the  Company  will  receive  from  the  Counterparty,  or  pay  to  the
Counterparty, an amount equal to the excess or deficiency, as applicable, of the
difference  between 97% of the net proceeds from the Purchaser's sale of the TPC
shares  and  the  notional  amount of $97 million.  For example if the Purchaser
sold  the  TPC shares for an amount equal to the value the Company has estimated
for purposes of preparing its balance sheet as of December 31, 1999, the Company
would  have  to  make  a  payment  to  the Counterparty under the equity swap of
approximately  $8.4  million.  There  can  be  no  assurance  that the value the
Purchaser  may realize in any sale of the TPC shares will equal the value of the
shares  estimated  by  the  Company for purposes of valuing the equity swap. The
Company has no right or obligation to repurchase the TPC shares at any time, but
the  Company  is  not  prohibited  from  offering  to purchase the shares if the
Purchaser  offers  to  sell  them.  The  Company  expects  to make a bid for the
acquisition  of  the  TPC  shares  because the Company's pipeline tariffs can be
lowered  by  electing to cancel the dividend to the holder of the OCENSA shares.
See  "Management's Discussion and Analysis of Financial Condition and Results of
Operations  -  Results  of Operations - Other Income and Expenses" and note 2 of
Notes  to  Consolidated  Financial  Statements.

     Indebtedness  of  the  Company
     ------------------------------

          The  Company  believes  its  interest  rate  exposure  on  debt is not
significant  since  only  $13.5  million  out of total debt of $413.5 million at
December  31,  1999,  has  floating  interest  rate  obligations.

Foreign  Currency  Risk
-----------------------

          The  Company  derives  substantially  all of its consolidated revenues
from  international  operations.  A risk inherent in international operations is
the possibility of realizing economic currency-exchange losses when transactions
are  completed  in  currencies  other  than U.S. dollars.  The Company's risk of
realizing  currency-exchange  losses  currently is largely mitigated because the
Company  receives  U.S. dollars for sales of its petroleum products in Colombia.
With  respect  to  expenditures  denominated  in  currencies other than the U.S.
dollar,  the  Company generally converts U.S. dollars to the local currency near
the  applicable  payment  dates to minimize exposure to losses caused by holding
foreign  currency  deposits.  During  the  three-year  period ended December 31,
1999,  the Company did not realize any material foreign exchange losses from its
international  operations.

          The  Company  evaluated  the potential effect that reasonably possible
near-term  changes  in  foreign  exchange  rates  may  have on the fair value of
foreign  currency  denominated  assets.  Based  on analysis utilizing the actual
foreign currency exchange rates at December 31, 1999, and assuming a ten percent
adverse  movement  in  exchange  rates,  the potential decrease in fair value of
foreign  currency  denominated assets does not have a material adverse effect on
the  Company's  consolidated  financial  position  or  results  of  operations.


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

     Not applicable.

                              PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The  information  relating  to  the  Company's  directors  and nominees for
election  as  directors  of the Company is incorporated herein by reference from
the  Proxy  Statement for the 2000 Annual Meeting of Shareholders of the Company
(the "Proxy Statement"), specifically the discussion under the heading "Election
of  Directors."  The  Company  expects that the Proxy Statement will be publicly
available and mailed in April 2000. Certain information as to executive officers
is  included  herein  under  Items 1 and 2, "Business and Properties - Executive
Officers."  The  discussion  under "Section 16(a) Beneficial Ownership Reporting
Compliance"    in  the  Proxy  Statement  is  incorporated  herein by reference.

ITEM 11.  EXECUTIVE COMPENSATION

          The discussion under "Management Compensation" in the Proxy Statement
is incorporated herein by reference.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The  discussion  under  "Security  Ownership  of Management and Certain
Shareholders" in the Proxy Statement is incorporated  herein  by  reference.


ITEM  13.  CERTAIN  RELATIONSHIPS  AND  RELATED  TRANSACTIONS

     The  discussion  under  "Management Compensation - Compensation Committee
Interlocks and Insider Participation and Certain Transactions" in the Proxy
Statement is incorporated herein by reference.


                                   PART IV


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

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

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

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

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


<TABLE>
<CAPTION>
<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    Rights Agreement dated as of March 25, 1996, between Triton and The Chase
        Manhattan Bank, as Rights Agent, including, as Exhibit A thereto, Resolutions
        establishing the Junior Preference Shares (previously filed as an exhibit to the
        Company's Registration Statement on Form S-3 (No 333-08005) and incorporated herein
        by reference)
 4.3    Resolutions Authorizing the Company's 5% Convertible Preference Shares (previously
        filed as an exhibit to the Company's and Triton Energy Corporation's Registration
        Statement on Form S-4 (No. 333-923) and incorporated herein by reference)
 4.4    Amendment No. 1 to Rights Agreement dated as of August 2, 1996, between Triton
        Energy Limited and The Chase Manhattan Bank, as Rights Agent (previously filed as an
        exhibit to the Company's Registration Statement on Form 8-A/A (Amendment No. 1)
        dated August 14, 1996, and incorporated herein by reference)
 4.5    Amendment No. 2 to Rights Agreement dated as of August 30, 1998, between Triton
        Energy Limited and The Chase Manhattan Bank, as Rights Agent (previously filed
        as an exhibit to the Company's Registration Statement on Form 8-A/A (Amendment No.
        2) dated October 2, 1998, and incorporated herein by reference)
 4.6    Unanimous Written Consent of the Board of Directors authorizing a Series of
        Preference Shares (previously filed as an exhibit to the Company's
        Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and
        incorporated herein by reference.)
 4.7    Amendment No. 3 to Rights Agreement dated as of January 5, 1999, between Triton
        Energy Limited and The Chase Manhattan Bank, as Rights Agent (previously filed
        as an exhibit to the Company's Registration Statement on Form 8-A/A (Amendment No.
        3) dated January 31, 1999, and incorporated herein by reference)
 10.1   Amended and Restated  Retirement Income Plan (previously filed as an exhibit
        to Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended
        November 30, 1993, and incorporated by reference) (1)
 10.2   Amendment to the Retirement Income Plan dated August 1, 1998. (previously filed
        as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
        June 30, 1998, and incorporated herein by reference.) (1)
 10.3   Amendment to Amended and Restated Retirement Income Plan dated
        December 31, 1996 (previously filed as an exhibit to the Company's Quarterly Report
        on Form 10-Q for the quarter ended March 31, 1998, and incorporated herein by
        reference) (1)
 10.4   Amended and Restated Supplemental Executive Retirement Income Plan. (previously
        filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year
        ended December 31, 1997, and incorporated herein by reference.) (1)
 10.5   1981 Employee Non-Qualified Stock Option Plan. (previously filed as an exhibit to
        Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May
        31, 1992 ,and incorporated herein by reference.) (1)
 10.6   Amendment No. 1 to the 1981 Employee Non-Qualified Stock Option Plan. (previously
        filed as an exhibit to Triton Energy Corporation's Annual Report on Form 10-K for
        the fiscal year ended May 31, 1989, and incorporated herein by reference.) (1)
 10.7   Amendment No. 2 to the 1981 Employee Non-Qualified Stock Option Plan. (previously
        filed as an exhibit to Triton Energy Corporation's Annual Report on Form 10-K for the
        fiscal year ended May 31, 1992, and incorporated herein by reference.) (1)
 10.8   Amendment No. 3 to the 1981 Employee Non-Qualified Stock Option Plan. (previously
        filed as an exhibit to Triton Energy Corporation's Quarterly Report on Form 10-Q for
        the quarter ended November 30, 1993, and incorporated by reference.) (1)
 10.9   1985 Stock Option Plan. (previously filed as an exhibit to Triton Energy Corporation's
        Annual Report on Form 10-K for the fiscal year ended May 31, 1990, and incorporated
        herein by reference.) (1)
10.10   Amendment No. 1 to the 1985 Stock Option Plan. (previously filed as an exhibit to
        Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended
        May 31, 1992, and incorporated herein by reference)
10.11   Amendment No. 2 to the 1985 Stock Option Plan. (previously filed as an exhibit to
        Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended
        November 30, 1993, and incorporated by reference.) (1)
10.12   Amended and Restated 1986 Convertible Debenture Plan. (previously filed as an exhibit
        to Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended
        November 30, 1993, and incorporated herein by reference.) (1)
10.13   1988 Stock Appreciation Rights Plan. (previously filed as an exhibit to Triton Energy
        Corporation's Annual Report on Form 10-K for the fiscal year ended May 31, 1993,
        and incorporated by reference herein.) (1)
10.14   1989 Stock Option Plan. (previously filed as an exhibit to Triton Energy Corporation's
        Quarterly Report on Form 10-Q for the quarter ended November 30, 1988, and
        incorporated herein by reference.) (1)
10.15   Amendment No. 1 to 1989 Stock Option Plan. (previously filed as an exhibit to
        Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended
        May 31, 1992, and incorporated herein by reference.) (1)
10.16   Amendment No. 2 to 1989 Stock Option Plan. (previously filed as an exhibit to
        Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended
        November 30, 1993, and incorporated herein by reference.) (1)
10.17   Second Amended and Restated 1992 Stock Option Plan.(previously filed as an
        exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March
        31, 1996, and incorporated herein by reference.) (1)
10.18   Form of Amended and Restated Employment Agreement with Triton Energy Limited
        and certain officers, including Messrs. Dunlevy, Garrett and Maxted (previously filed as
        an exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended
        December 31, 1997, and incorporated herein by reference.) (1)
10.19   Amended and Restated Employment Agreement among Triton Energy Limited, Triton
        Exploration Services, Inc. and Robert B. Holland, III. (previously filed as an exhibit
        to the Company's Quarterly Report on Form 10-Q for the quarter ended
        September 30, 1998, and incorporated herein by reference.) (1)
10.20   Form of Amended and Restated Employment Agreement among Triton Energy Limited,
        Triton Exploration Services, Inc. and each of Peter Rugg and Al E. Turner. (previously
        filed as an exhibit to the Company's Quarterly Report on Form 10-Q for
        the quarter ended September 30, 1998, and incorporated herein by reference.) (1)
10.21   Letter Agreement among Triton Energy Limited, Triton Exploration Services,  Inc.
        and Robert B. Holland, III dated December 17, 1998. (previously filed as an exhibit to
        the Company's Annual Report on Form 10-K for the year ended December 31, 1998 and
        incorporated herein by reference.) (1)
10.22   Letter Agreement among Triton Energy Limited, Triton Exploration Services,  Inc.
        and Peter Rugg dated December 10, 1998. (previously filed as an exhibit to the
        Company's Annual Report on Form 10-K for the year ended December 31, 1998 and
        incorporated herein by reference.) (1)
10.23   Form of Bonus Agreement between Triton Exploration Services,  Inc. and each of
        Al E. Turner, Robert B. Holland, III, and Peter Rugg dated July 15, 1998. (previously
        filed as an exhibit to the Annual Report on Form 10-K for the year ended December 31,
        1998 and incorporated herein by reference.) (1)
10.24   Amended and Restated 1985 Restricted Stock Plan. (previously filed as an exhibit
        to Triton Energy Corporation's Quarterly Report on Form 10-Q for the quarter ended
        November 30, 1993, and incorporated herein by reference.) (1)
10.25   First Amendment to Amended and Restated 1985 Restricted Stock Plan. (previously
        filed as an exhibit to Triton Energy Corporation's Annual Report on Form 10-K for the
        fiscal year ended December 31, 1995, and incorporated herein by reference.) (1)
10.26   Second Amendment to Amended and Restated 1985 Restricted Stock Plan. (previously
        filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter
        ended March 31, 1996, and incorporated herein by reference.) (1)
10.27   Executive Life Insurance Plan. (previously filed as an exhibit to Triton Energy
        Corporation's Annual Report on Form 10-K for the fiscal year ended May 31, 1991,
        and incorporated herein by reference.) (1)
10.28   Long Term Disability Income Plan. (previously filed as an exhibit to Triton Energy
        Corporation's Annual Report on Form 10-K for the fiscal year ended May 31, 1991,
        and incorporated herein by reference.) (1)
10.29   Amended and Restated Retirement Plan for Directors. (previously filed as an exhibit
        to Triton Energy Corporation's Annual Report on Form 10-K for the fiscal year ended
        May 31, 1990, and incorporated herein by reference.) (1)
10.30   Contract for Exploration and Exploitation for Santiago de Atalayas I with an effective
        date of July 1, 1982, between Triton Colombia, Inc., and Empresa Colombiana
        De Petroleos. (previously filed as an exhibit to Triton Energy Corporation's Annual
        Report on Form 10-K for the fiscal year ended May 31, 1990, and incorporated
        herein by reference.)
10.31   Contract for Exploration and Exploitation for Tauramena with an effective date of July
        4, 1988, between Triton Colombia, Inc., and Empresa Colombiana De Petroleos.
        (previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
        10-K for the fiscal year ended May 31, 1990, and incorporated herein by reference.)
10.32   Summary of Assignment legalized by Public Instrument No. 1255 dated September 15,
        1987 (Assignment is in Spanish language). (previously filed as an exhibit to Triton
        Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31,
        1993, and incorporated herein by reference.)
10.33   Summary of Assignment legalized by Public Instrument No. 1602 dated June 11, 1990
        (Assignment is in Spanish language). (previously filed as an exhibit to Triton
        Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31,
        1993, and incorporated herein by reference.)
10.34   Summary of Assignment legalized by Public Instrument No. 2586 dated September 9,
        1992 (Assignment is in Spanish language). (previously filed as an exhibit to Triton
        Energy Corporation's Annual Report on Form 10-K for the fiscal year ended May 31,
        1993, and incorporated herein by reference.)
10.35   401(K) Savings Plan. (previously filed as an exhibit to Triton Energy Corporation's
        Quarterly Report on Form 10-Q for the quarter ended November 30, 1993, and
        incorporated herein by reference.) (1)
10.36   Amendment to the 401(k) Savings Plan dated August 1, 1998. (previously filed as an
        exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
        1998, and incorporated herein by reference.) (1)
10.37   Amendment to 401(k) Savings Plan dated December 31, 1996. (previously filed as an
        exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended March
        31, 1998, and incorporated herein by reference.) (1)
10.38   Contract between Malaysia-Thailand Joint Authority and Petronas Carigali
        SDN.BHD. and Triton Oil Company of Thailand relating to Exploration and Production
        of  Petroleum for Malaysia-Thailand Joint Development Area Block A-18. (previously
        filed as an exhibit to Triton Energy Corporation's Current Report on Form 8-K dated
        April 21, 1994, and incorporated herein by reference.)
10.39   Triton Crude Purchase Agreement between Triton Colombia, Inc. and Oil Co., LTD.
        dated May 25, 1995. (previously filed as an exhibit to Triton Energy Corporation's
        Current Report on Form 8-K dated May 26, 1995, and incorporated herein by reference.)
10.40   Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation,
        NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States
        (previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
        10-K for the fiscal year ended December 31, 1995, and incorporated herein by
        reference.)
10.41   Amendment No. 1 to Credit Agreement among Triton Colombia, Inc., Triton Energy
        Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
        States. (previously filed as an exhibit to Triton Energy Corporation's Annual Report
        on Form 10-K for the fiscal year ended December 31, 1995, and incorporated herein
        by reference.)
10.42   Amendment No. 2 to Credit Agreement among Triton Colombia, Inc., Triton Energy
        Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
        States. (previously filed as an exhibit to the Company's Quarterly Report on Form
        10-Q for the quarter ended March 31, 1996, and incorporated herein by reference)
10.43   Amendment No. 3 to Credit Agreement among Triton Colombia, Inc., Triton Energy
        Corporation, NationsBank, N.A. (Carolinas) and Export-Import Bank of the United
        States. (previously filed as an exhibit to the Company's Quarterly Report on Form
        10-Q for the quarter ended March 31, 1998, and incorporated herein by reference)
10.44   Form of Indemnity Agreement entered into with each director and officer of the
        Company. (previously filed as an exhibit to the Company's Quarterly Report on Form
        10-Q for the quarter ended September 30, 1998, and incorporated herein by reference)
10.45   Description of Performance Goals for Executive Bonus Compensation. (previously
        filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year
        ended December 31, 1996, and incorporated herein by reference) (1)
10.46   Stock Purchase Agreement dated September 2, 1997, between The Strategic
        Transaction Company and Triton International Petroleum, Inc. (previously filed as an
        exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended
        December 31, 1997, and incorporated herein by reference)
10.47   Fourth Amendment to Stock Purchase Agreement dated February 2, 1998, between
        The Strategic Transaction Company and Triton International Petroleum, Inc. (previously
        filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year
        ended December 31, 1997, and incorporated herein by reference)
10.48   Amended and Restated 1997 Share Compensation Plan. (previously filed as an
        exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended
        December 31, 1998, and incorporated herein by reference) (1)
10.49   First Amendment to Amended and Restated Retirement Plan for Directors. (previously
        filed as an exhibit to the Company's Annual Report on Form 10-K for the fiscal year
        ended December 31, 1997, and incorporated herein by reference) (1)
10.50   First Amendment to Second Amended and Restated 1992 Stock Option Plan. (previously
        filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter
        ended March 31, 1997, and incorporated herein by reference) (1)
10.51   Second Amendment to Second Amended and Restated 1992 Stock Option Plan.
        (previously filed as an exhibit to the Company's Annual Report on Form 10-K
        for the fiscal year ended December 31, 1997, and incorporated herein by reference) (1)
10.52   Amended and Restated Indenture dated July 25, 1997, between Triton Energy
        Limited and The Chase Manhattan Bank. (previously filed as an exhibit to the
        Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, and
        incorporated herein by reference)
10.53   Amended and Restated First Supplemental Indenture dated July 25, 1997,
        between Triton Energy Limited and The Chase Manhattan Bank relating
        to the 8 3/4% Senior Notes due 2002. (previously filed as an exhibit to the
        Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, and
        incorporated herein by reference)
10.54   Amended and Restated Second Supplemental Indenture dated July 25, 1997,
        between Triton Energy Limited and The Chase Manhattan Bank relating
        to the 9 1/4% Senior Notes due 2005. (previously filed as an exhibit to the
        Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, and
        incorporated herein by reference)
10.55   Share Purchase Agreement dated July 17, 1998, among Triton Energy Limited, Triton
        Asia Holdings, Inc., Atlantic Richfield Company and ARCO JDA Limited.
        (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
        quarter ended June 30, 1998, and incorporated herein by reference)
10.56   Shareholders Agreement dated August 3, 1998, among Triton Energy Limited, Triton
        Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA Limited.
        (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
        quarter ended June 30, 1998, and incorporated herein by reference)
10.57   Stock Purchase Agreement dated as of August 31, 1998, between Triton Energy
        Limited and HM4 Triton, L.P. (previously filed as an exhibit to the Company's
        Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and
        incorporated herein by reference)
10.58   Shareholders Agreement dated as of September 30, 1998, between Triton Energy
        Limited and HM4 Triton, L.P. (previously filed as an exhibit to the Company's
        Quarterly Report on Form 10-Q for the quarter ended September 30, 1998, and
        incorporated herein by reference)
10.59   Financial Advisory Agreement dated as of September 30, 1998, between Triton Energy
        Limited and Hicks, Muse & Co. Partners, L.P. (previously filed as an exhibit to the
        Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1998,
        and incorporated herein by reference)
10.60   Monitoring and Oversight Agreement dated as of September 30, 1998, between Triton
        Energy Limited and Hicks, Muse & Co. Partners, L.P. (previously filed as an exhibit to
        the Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
        1998, and incorporated herein by reference)
10.61   Severance Agreement dated as of July 15, 1998, between Thomas G. Finck and Triton
        Energy Limited. (previously filed as an exhibit to the Company's Quarterly Report
        on Form 10-Q for the quarter ended September 30, 1998, and incorporated herein by
        reference) (1)
10.62   Severance Agreement dated April 9, 1999, made and entered into by and among Triton
        Energy Limited, Triton Exploration Services, Inc. and Peter Rugg. (previously filed as
        an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
        March 31, 1999, and incorporated herein by reference) (1)
10.63   Consulting and Non-Compete Agreement dated April 9, 1999, made and entered into
        by and between Triton Exploration Services, Inc. and Peter Rugg. (previously filed as
        an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
        March 31, 1999, and incorporated herein by reference) (1)
10.64   Third Amendment to Amended and Restated 1985 Restricted Stock Plan (previously
        filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter
        ended March 31, 1999, and incorporated herein by reference) (1)
10.65   Amendment to Triton Exploration Services, Inc. Retirement Income Plan. (previously
        filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter
        ended June 30, 1999, and incorporated herein by reference) (1)
10.66   Amendment to the Triton Exploration Services, Inc. Supplemental Executive
        Retirement Plan. (previously filed as an exhibit to the Company's Quarterly Report on
        Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by
        reference) (1)
10.67   Third Amendment to the Second Amended and Restated 1992 Stock Option Plan
        (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
        quarter ended June 30, 1999, and incorporated herein by reference) (1)
10.68   First Amendment to the Amended and Restated 1997 Share Compensation Plan
        (previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
        quarter ended June 30, 1999, and incorporated herein by reference) (1)
10.69   Amendment dated May 11, 1999, to Amended and Restated Employment Agreement
        dated July 15, 1998 among Triton Exploration Services, Inc., Triton Energy Limited
        and A.E. Turner, III.(previously filed as an exhibit to the Company's Quarterly Report
        on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by
        reference) (1)
10.70   Form of Amendment dated May 11, 1999, to Employment Agreement
        among Triton Exploration Services, Inc., Triton Energy Limited and certain officers,
        including Messrs. Dunlevy, Garrett and Maxted (previously filed as an exhibit
        to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999,
        and incorporated herein by reference) (1)
10.71   Second Amendment to Retirement Plan for Directors. (previously filed as an exhibit to
        the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999,
        and incorporated herein by reference) (1)
10.72   Amendment to Triton Exploration Services, Inc. 401 (k) Savings Plan. (previously filed
        as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
        June 30, 1999, and incorporated herein by reference) (1)
10.73   Amendment No. 1 to Shareholders Agreement between Triton Energy Limited
        and HM4 Triton, L.P. (previously filed as an exhibit to the Company's Quarterly Report
        on Form 10-Q for the quarter ended June 30, 1999, and incorporated herein by
        reference) (1)
10.74   Amendment No. 4 to the 1981 Employee Nonqualified Stock Option Plan. (previously
        filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter
        ended June 30, 1999, and incorporated herein by reference) (1)
10.75   Amendment No. 3 to the 1985 Stock Option Plan. (previously filed as an exhibit to the
        Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, and
        incorporated herein by reference) (1)
10.76   Amendment No. 3 to the 1989 Stock Option Plan. (previously filed as an exhibit to the
        Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, and
        incorporated herein by reference) (1)
10.77   Supplemental Letter Agreement dated October 28, 1999, among Triton Energy
        Limited, Triton Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA
        Limited (previously filed as an exhibit to the Company's Quarterly Report on Form
        10-Q for the quarter ended September 30, 1999, and incorporated herein by reference)
10.78   Gas Sales Agreement dated October 30, 1999 among the Malaysia-Thailand Joint
        Authority, and Petronas Carigali (JDA) Sdn Bhd, Triton Oil Company of Thailand,
        Triton Oil Company of Thailand (JDA) Limited, as Sellers, and with Petroleum
        Authority of Thailand and Petroliam Nasional Berhad, as Buyers. (previously filed
        as an exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended
        September 30, 1999, and incorporated herein by reference)
10.79*  Form of Stock Option Agreement between Triton Energy Limited and its
        non-employee directors. (1)
10.80*  Form of Stock Option Agreement between Triton Energy Limited and its employees,
        including its executive officers. (1)
10.81*  Amendment to Stock Options dated as of January 3, 2000, between Triton Energy Limited and A.E. Turner. (1)
10.82*  Form of Amendment to Stock Options dated as of January 3, 2000, between Triton
        Energy Limited and its non-employee directors. (1)
10.83*  Production Sharing Contract between the Republic of Equatorial Guinea
        and Triton Equatorial Guinea, Inc. for Block F.
10.84*  Production Sharing Contract between the Republic of Equatorial Guinea and Triton
        Equatorial Guinea, Inc. for Block G.
10.85*  Supplementary Contract (No. 1) to the Production Sharing Contract for Block A-18
        dated 21 April 1994 between Malaysia-Thailand Joint Authority and Petronas
        Carigali (JDA) SDN.BHD., Triton Oil Company of Thailand and Triton Oil Company
        of Thailand (JDA) Limited.
10.86*  Supplementary Contract (No. 2) to the Production Sharing Contract for Block A-18
        dated 21 April 1994 between Malaysia-Thailand Joint Authority and Petronas Carigali
        (JDA) SDN.BHD., Triton Oil Company of Thailand and Triton Oil Company of
        Thailand (JDA) Limited.
10.87*  Credit Agreement dated as of February 29, 2000, among Triton Energy Limited,
        the Lenders party thereto and The Chase Manhattan bank, as Administrative Agent
 12.1*  Computation of Ratio of Earnings to Fixed Charges.
 12.2*  Computation of Ratio of Earnings to Combined Fixed Charges and Preference
        Dividends.
 21.1*  Subsidiaries of the Company.
 23.1*  Consent of PricewaterhouseCoopers LLP.
 23.2*  Consent of DeGolyer and MacNaughton.
 23.3*  Consent of Netherland, Sewell & Associates, Inc.
 24.1*  The power of attorney of officers and directors of the Company
 27.1*  Financial Data Schedule.
 99.1   Rio Chitamena Association Contract. (previously filed as an exhibit to Triton Energy
        Corporation's Current Report on Form 8-K/A dated July 15, 1994, and incorporated
        herein by reference)
 99.2   Rio Chitamena Purchase and Sale Agreement. (previously filed as an exhibit to Triton
        Energy Corporation's Current Report on Form 8-K/A dated July 15, 1994, and
        incorporated herein by reference)
 99.3   Integral Plan - Cusiana Oil Structure. (previously filed as an exhibit to Triton Energy
        Corporation's Current Report on Form 8-K/A dated July 15, 1994, and incorporated
        herein by reference)
 99.4   Letter Agreements with co-investor in Colombia. (previously filed as an exhibit to
        Triton Energy Corporation's Current Report on Form 8-K/A dated July 15, 1994, and
        incorporated herein by reference)
 99.5   Amended and Restated Oleoducto Central S.A. Agreement dated as of March 31,
        1995. (previously filed as an exhibit to Triton Energy Corporation's Quarterly Report
        on Form 10-Q for the quarter ended June 30, 1995, and incorporated herein by
        reference)

-------------------------
*  Previously filed  herewith.


</TABLE>

     (1) Management contract or compensatory plan or arrangement.


(b)          Reports on Form 8-K.

             None

                                   SIGNATURES


     Pursuant  to  the  requirements  of  Section  13 or 15(d) of the Securities
Exchange  Act of 1934, the Registrant has duly caused this Amendment No. 2 to
Annual Report on Form 10-K to be signed by the undersigned thereunto duly
authorized on the 15th day of March, 2000.

                                       TRITON  ENERGY  LIMITED




                                       By:/s/W. Greg Dunlevy
                                          -------------------------------------
                                          W. Greg Dunlevy
                                          Vice President, Finance




     Pursuant  to  the requirements of the Securities Exchange Act of 1934, this
Amendment No. 2 to Annual  Report  on  Form  10-K has been signed below by the
following persons on behalf  of  the  Registrant  and  in  the capacities
indicated on the 15th day of March,  2000.

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



/s/W. Greg Dunlevy                         Vice President
-----------------------
W. Greg Dunlevy                            (Principal Financial Officer)





/s/Kevin B. Wilcox                         Controller
----------------------
Kevin B. Wilcox



          *                         Chairman of the Board
----------------------
   Thomas O. Hicks



          *                        President and Chief Executive Officer
----------------------                     (Principal Executive Officer)
James C. Musselman



          *                                Director
----------------------
Sheldon R. Erikson




          *                                Director
----------------------
Jack D. Furst



          *                                Director
----------------------
Fitzgerald Hudson



          *                                Director
----------------------
John R. Huff



          *                                Director
----------------------
Michael E. McMahon


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


          *                                Director
----------------------
C. Richard Vermillion


          *                                Director
----------------------
   J. Otis Winters


*By /s/ W. Greg Dunlevy
    --------------------------
        W. Greg Dunlevy, Attorney-in-Fact







                     TRITON ENERGY LIMITED AND SUBSIDIARIES
                   INDEX TO FINANCIAL STATEMENTS AND SCHEDULES



<TABLE>
<CAPTION>

<S>                                                                            <C>

                                                                               PAGE
                                                                               -----

TRITON  ENERGY  LIMITED  AND  SUBSIDIARIES:

Report of Independent Accountants. . . . . . . . . . . . . . . . . . . . . . . .  F-2
Consolidated Statements of Operations - Years ended December 31, 1999, 1998
  and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  F-3
Consolidated Balance Sheets - December 31, 1999 and 1998 . . . . . . . . . . . .  F-4
Consolidated Statements of Cash Flows - Years ended December 31, 1999, 1998
  and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  F-5
Consolidated Statements of Shareholders' Equity - Years ended December 31, 1999,
  1998 and 1997. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  F-6
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . .  F-7


SCHEDULE:


II  -  Valuation and Qualifying Accounts - Years ended December 31, 1999,
       1998 and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  F-52
</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, 1999 and 1998, and the
results  of their operations and their cash flows for each of the three years in
the  period  ended  December  31, 1999, in conformity with accounting principles
generally  accepted  in  the  United  States. These financial statements are the
responsibility  of the Company's management; our responsibility is to express an
opinion  on  these  financial  statements based on our audits.  We conducted our
audits  of  these  statements  in  accordance  with auditing standards generally
accepted  in  the United States which require that we plan and perform the audit
to  obtain  reasonable assurance about whether the financial statements are free
of  material  misstatement.  An  audit  includes  examining,  on  a  test basis,
evidence  supporting  the  amounts  and disclosures in the financial statements,
assessing  the  accounting  principles  used  and  significant estimates made by
management,  and  evaluating  the  overall financial statement presentation.  We
believe  that  our  audits  provide a reasonable basis for the opinion expressed
above.



PricewaterhouseCoopers  LLP
Dallas,  Texas
February 23, 2000






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




<TABLE>
<CAPTION>
<S>                                                       <C>        <C>         <C>

                                                              YEAR ENDED DECEMBER 31,
                                                          --------------------------------
                                                            1999        1998       1997
                                                          ---------  ----------  ---------
SALES AND OTHER OPERATING REVENUES:
  Oil and gas sales                                       $247,878   $ 160,881   $145,419
  Gain on sale of oil and gas assets                           ---      67,737      4,077
                                                          ---------  ----------  ---------
                                                           247,878     228,618    149,496
                                                          ---------  ----------  ---------
COSTS AND EXPENSES:
  Operating                                                 68,130      73,546     51,357
  General and administrative                                23,636      26,653     28,607
  Depreciation, depletion and amortization                  61,343      58,811     36,828
  Writedown of assets                                          ---     328,630        ---
  Special charges                                            2,909      18,324        ---
                                                          ---------  ----------  ---------
                                                           156,018     505,964    116,792
                                                          ---------  ----------  ---------

          OPERATING INCOME (LOSS)                           91,860    (277,346)    32,704

Gain on sale of Triton Pipeline Colombia                       ---      50,227        ---
Interest income                                             10,579       3,258      5,178
Interest expense, net                                      (22,648)    (23,228)   (23,858)
Other income (expense), net                                 (3,614)      8,480      2,872
                                                          ---------  ----------  ---------

                                                           (15,683)     38,737    (15,808)
                                                          ---------  ----------  ---------

          EARNINGS (LOSS) BEFORE INCOME TAXES
               AND EXTRAORDINARY ITEM                       76,177    (238,609)    16,896
Income tax expense (benefit)                                28,620     (51,105)    11,301
                                                          ---------  ----------  ---------

          EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM         47,557    (187,504)     5,595
Extraordinary item - extinguishment of debt                    ---         ---    (14,491)
                                                          ---------  ----------  ---------

           NET EARNINGS (LOSS)                              47,557    (187,504)    (8,896)
DIVIDENDS ON PREFERENCE SHARES                              28,671       3,061        400
                                                          ---------  ----------  ---------

          EARNINGS (LOSS) APPLICABLE TO ORDINARY SHARES   $ 18,886   $(190,565)  $ (9,296)
                                                          =========  ==========  =========

Average ordinary shares outstanding                         36,135      36,609     36,471
                                                          =========  ==========  =========

BASIC EARNINGS (LOSS) PER ORDINARY SHARE:

   Earnings (loss) before extraordinary item              $   0.52   $   (5.21)  $   0.14
   Extraordinary item - extinguishment of debt                 ---         ---      (0.40)
                                                          ---------  ----------  ---------

           BASIC EARNINGS (LOSS)                          $   0.52   $   (5.21)  $  (0.26)
                                                          =========  ==========  =========

DILUTED EARNINGS (LOSS) PER ORDINARY SHARE:

   Earnings (loss) before extraordinary item              $   0.52   $   (5.21)  $   0.14
   Extraordinary item - extinguishment of debt                 ---         ---      (0.39)
                                                          ---------  ----------  ---------

           DILUTED EARNINGS (LOSS)                        $   0.52   $   (5.21)  $  (0.25)
                                                          =========  ==========  =========
</TABLE>





          See accompanying Notes to Consolidated Financial Statements.




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


<TABLE>
<CAPTION>

<S>                                                                 <C>         <C>


                            ASSETS                                       DECEMBER 31,
                                                                    ---------------------
                                                                      1999         1998
                                                                    ----------  ---------

CURRENT  ASSETS:
   Cash and equivalents                                             $ 186,323   $ 18,757
   Trade receivables, net                                              17,246      9,514
   Other receivables                                                   23,814     47,756
   Deferred income taxes                                               20,090        ---
   Inventories, prepaid expenses and other                              7,806      1,639
                                                                    ----------  ---------

                    TOTAL CURRENT ASSETS                              255,279     77,666

Property and equipment, at cost, net                                  524,152    470,907
Investment in affiliate                                                93,188     84,735
Deferred income taxes                                                  88,228    100,916
Other assets                                                           13,628     20,056
                                                                    ----------  ---------

                                                                    $ 974,475   $754,280
                                                                    ==========  =========

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
    Current maturities of long-term debt                            $   9,027   $ 14,027
    Short-term borrowings                                                 ---      5,000
    Accounts payable and accrued liabilities                           62,576     44,973
    Deferred income and other                                          22,347     35,254
                                                                    ----------  ---------

                    TOTAL CURRENT LIABILITIES                          93,950     99,254

Long-term debt, excluding current maturities                          404,460    413,465
Deferred income taxes                                                   6,677      3,235
Other liabilities                                                       6,336     14,519

SHAREHOLDERS' EQUITY:
   5% preference shares, par value $.01; authorized 420,000
       shares; issued 209,639 shares at December 31, 1999 and
       1998, respectively, stated value $34.41                          7,214      7,214
   8% preference shares, par value $.01; authorized 11,000,000
       shares; issued 5,193,643 and 1,822,500 shares at
       December 31, 1999 and 1998, respectively, stated value $70     363,555    127,575
   Ordinary shares, par value $.01; authorized 200,000,000
       shares; issued 35,763,728 and 36,643,478 shares at
       December 31, 1999 and 1998, respectively                           358        366
   Additional paid-in capital                                         531,904    575,863
   Accumulated deficit                                               (437,528)  (485,085)
   Accumulated other non-owner changes in shareholders' equity         (2,451)    (2,126)
                                                                    ----------  ---------

                    TOTAL SHAREHOLDERS' EQUITY                        463,052    223,807
Commitments and contingencies (note 20)                                   ---        ---
                                                                    ----------  ---------

                                                                    $ 974,475   $754,280
                                                                    ==========  =========

</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>

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


                                                                         YEAR ENDED DECEMBER 31,
                                                                   ----------------------------------
                                                                      1999        1998        1997
                                                                   ----------  ----------  ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss)                                                $  47,557   $(187,504)  $  (8,896)
Adjustments to reconcile net earnings to net cash provided (used)
 by operating activities:
   Depreciation, depletion and amortization                           61,343      58,811      36,828
   Proceeds from forward oil sale                                     31,932       1,770         830
   Amortization of deferred income                                   (35,254)    (35,254)    (28,467)
   Gain on sale of oil and gas assets                                    ---     (67,737)     (4,077)
   Gain on sale of Triton Pipeline Colombia                              ---     (50,227)        ---
   Writedown of assets                                                   ---     328,630         ---
   Payment of accreted interest on extinguishment of debt                ---         ---    (124,794)
   Extraordinary loss on extinguishment of debt, net of tax              ---         ---      14,491
   Amortization of debt discount                                         ---         ---       7,949
   Deferred income taxes                                               7,827     (55,592)      8,078
   Gain on sale of other assets                                         (677)     (7,590)     (1,409)
   Other, net                                                          8,921       3,962       6,100
   Changes in working capital:
      Trade and other receivables                                    (16,131)      6,300      (3,238)
      Inventories, prepaid expenses and other                         (3,577)        918       1,794
      Accounts payable and accrued liabilities                        14,581       4,979      (2,605)
                                                                   ----------  ----------  ----------

          Net cash provided (used) by operating activities           116,522       1,466     (97,416)
                                                                   ----------  ----------  ----------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Capital expenditures and investments                             (121,483)   (180,215)   (219,216)
   Proceeds from sale of oil and gas assets                              ---     147,027       4,077
   Proceeds from sale of Triton Pipeline Colombia                        ---      97,656         ---
   Proceeds from sales of other assets                                 2,353      22,353       1,822
   Other                                                                 600      (2,630)        617
                                                                   ----------  ----------  ----------

          Net cash provided (used) by investing activities          (118,530)     84,191    (212,700)
                                                                   ----------  ----------  ----------

CASH FLOWS FROM FINANCING ACTIVITIES:
   Proceeds from revolving lines of credit and long-term debt            ---     162,530     620,413
   Payments on revolving lines of credit and long-term debt          (19,028)   (350,511)   (321,515)
   Short-term notes payable, net                                         ---      (9,600)      9,600
   Issuance of 8% preference shares, net                             217,805     115,329         ---
   Issuances of ordinary shares                                          419       2,544       5,260
   Repurchase of ordinary shares                                     (11,285)        ---         ---
   Dividends paid on preference shares                               (17,617)       (368)       (400)
   Other                                                                (151)          5          10
                                                                   ----------  ----------  ----------

          Net cash provided (used) by financing activities           170,143     (80,071)    313,368
                                                                   ----------  ----------  ----------

Effect of exchange rate changes on cash and equivalents                 (569)       (280)       (849)
                                                                   ----------  ----------  ----------
Net increase in cash and equivalents                                 167,566       5,306       2,403
CASH AND EQUIVALENTS AT BEGINNING OF YEAR                             18,757      13,451      11,048
                                                                   ----------  ----------  ----------

CASH AND EQUIVALENTS AT END OF YEAR                                $ 186,323   $  18,757   $  13,451
                                                                   ==========  ==========  ==========
</TABLE>




          See accompanying Notes to Consolidated Financial Statements.



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





<TABLE>
<CAPTION>

<S>                                                    <C>         <C>       <C>         <C>         <C>         <C>
                                                                               YEAR ENDED DECEMBER 31,
                                                       ------------------------------------------------------------------
                                                                1999                  1998                    1997
                                                       --------------------  ----------------------  --------------------
OWNER  SOURCES  OF  SHAREHOLDERS'  EQUITY:
  5%  PREFERENCE  SHARES:
    Balance at beginning of period                     $   7,214             $   7,511               $   8,515
    Conversion of 5% preference shares                       ---                  (297)                 (1,004)
                                                       ----------            ----------              ----------
    Balance at end of period                               7,214                 7,214                   7,511
                                                       ----------            ----------              ----------
  8% PREFERENCE SHARES:
    Balance at beginning of period                       127,575                   ---                     ---
    Issuances of 8% preference shares at $70 per share   222,425               127,575                     ---
    Conversion of 8% preference shares                      (192)                  ---                     ---
    Stock dividends, 8% preference shares                 13,747                   ---                     ---
                                                       ----------            ----------              ----------

    Balance at end of period                             363,555               127,575                     ---
                                                       ----------            ----------              ----------
  ORDINARY SHARES:
    Balance at beginning of period                           366                   365                     363
    Stock repurchase                                          (9)                  ---                     ---
    Exercise of employee stock options and debentures          1                     1                       2
                                                       ----------            ----------              ----------
    Balance at end of period                                 358                   366                     365
                                                       ----------            ----------              ----------
  ADDITIONAL PAID-IN CAPITAL:
    Balance at beginning of period                       575,863               588,454                 582,581
    Dividends, 5% preference shares                         (361)                 (368)                   (400)
    Dividends, 8% preference shares                      (28,310)               (2,693)                    ---
    Exercise of employee stock options and debentures        418                 2,548                   3,831
    Conversion of 5% preference shares                       ---                   297                   1,004
    Conversion of 8% preference shares                       192                   ---                     ---
    Transaction costs for issuance of
      8% preference shares                                (4,620)              (12,370)                    ---
    Stock repurchase                                     (11,276)                ---                       ---
    Other, net                                                (2)                   (5)                  1,438
                                                       ----------            ----------              ----------
    Balance at end of period                             531,904               575,863                 588,454
                                                       ----------            ----------              ----------
  TREASURY SHARES:
    Balance at beginning of period                           ---                    (3)                     (2)
    Retirement and other, net                                ---                     3                      (1)
                                                       ----------            ----------              ----------
    Balance at end of period                                 ---                   ---                      (3)
                                                       ----------            ----------              ----------

      TOTAL OWNER SOURCES OF SHAREHOLDERS' EQUITY        903,031               711,018                 596,327
                                                       ----------            ----------              ----------

NON-OWNER SOURCES OF SHAREHOLDERS' EQUITY:
  ACCUMULATED DEFICIT:
    Balance at beginning of period                      (485,085)             (297,581)               (288,685)
    Net earnings (loss)                                   47,557   $47,557    (187,504)  $(187,504)     (8,896)  $(8,896)
                                                       ----------            ----------              ----------
    Balance at end of period                            (437,528)             (485,085)               (297,581)
                                                       ----------            ----------              ----------
  ACCUMULATED OTHER NON-OWNER CHANGES IN
      SHAREHOLDERS' EQUITY:
    Balance at beginning of period                        (2,126)               (2,126)                 (2,128)
    Valuation reserve on marketable securities                         ---                     ---                     2
    Adjustment for minimum pension liability                          (325)                    ---                   ---
                                                                   --------              ----------              --------

    Other non-owner changes in shareholders' equity         (325)     (325)        ---         ---           2         2
                                                       ----------  --------  ----------  ----------  ----------  --------

    Non-owner changes in shareholders' equity                      $47,232               $(187,504)              $(8,894)
                                                                   ========              ==========              ========

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

      TOTAL NON-OWNER SOURCES OF
              SHAREHOLDERS' EQUITY                      (439,979)             (487,211)               (299,707)
                                                       ----------            ----------              ----------

TOTAL SHAREHOLDERS' EQUITY                             $ 463,052             $ 223,807               $ 296,620
                                                       ==========            ==========              ==========
</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" when used herein means Triton and its
subsidiaries  and  other  affiliates  through  which  the  Company  conducts its
business.  The  Company's  principal  properties,  operations,  and  oil and gas
reserves  are located in Colombia, Malaysia-Thailand and Equatorial Guinea.  The
Company  is  exploring  for  oil  and gas in these areas, as well as in southern
Europe,  Africa,  and the Middle East.  All sales are currently derived from oil
and  gas  production  in  Colombia.

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

PRINCIPLES  OF  CONSOLIDATION

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

CASH  EQUIVALENTS

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

INVENTORIES

Inventories  consist  principally of oil produced but not sold, stated at market
value,  and  materials  and  supplies,  stated  at  the lower of cost or market.

PROPERTY  AND  EQUIPMENT

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

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

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

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

Support  equipment  and  facilities are depreciated using the unit-of-production
method based on total reserves of the field related to the support equipment and
facilities.  Other  property  and  equipment,  which  includes  furniture  and
fixtures,  vehicles and leasehold improvements, are depreciated principally on a
straight-line  basis  over  estimated  useful  lives ranging from 3 to 20 years.

Repairs and maintenance are expensed as incurred, and renewals and improvements
are  capitalized.

ENVIRONMENTAL  MATTERS

Environmental  costs  are  expensed  or  capitalized  depending  on their future
economic  benefit.  Costs  that  relate  to an existing condition caused by past
operations  and  have  no future economic benefit are expensed.  Liabilities for
future  expenditures  of  a  noncapital  nature  are  recorded  when  future
environmental  expenditures and/or remediation is deemed probable, and the costs
can  be  reasonably  estimated.  Costs  of future expenditures for environmental
remediation  obligations  are  not  discounted  to  their  present  value.

INCOME  TAXES

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

REVENUE  RECOGNITION

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

FOREIGN  CURRENCY  TRANSLATION

The  U.S.  dollar is the designated functional currency for all of the Company's
foreign  operations.  The  cumulative  translation  adjustment  represents  the
cumulative  effect of translating the balance sheet accounts of Triton Colombia,
Inc.  from  the functional currency into U.S. dollars during the period when the
Colombian  peso  was  the  functional  currency.

RISK  MANAGEMENT

Oil  and natural gas sold by the Company are normally priced with reference to a
defined  benchmark,  such  as  light,  sweet  crude  oil  traded on the New York
Merchantile Exchange (West Texas Intermediate or "WTI").  Actual prices received
vary  from  the  benchmark depending on quality and location differentials. From
time  to  time, it is the Company's policy to use financial market transactions,
including  swaps,  collars  and  options,  with  creditworthy  counterparties,
primarily to reduce risk associated with the pricing of a portion of the oil and
natural  gas  that  it  sells.  The Company does not enter into financial market
transactions  for  trading  purposes.

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

STOCK-BASED  COMPENSATION

Statement  of  Financial  Accounting Standards No. 123 ("SFAS 123"), "Accounting
for Stock-Based Compensation," encourages, but does not require, the adoption of
a  fair  value-based  method of accounting for employee stock-based compensation
transactions.  The  Company  has  elected  to apply the provisions of Accounting
Principles  Board Opinion No. 25 ("Opinion 25"), "Accounting for Stock Issued to
Employees,"  and  related  interpretations,  in  accounting  for its stock-based
compensation  plans.  Under  Opinion  25,  compensation  cost is measured as the
excess, if any, of the quoted market price of the Company's stock at the date of
the  grant  above  the  amount  an  employee  must  pay  to  acquire  the stock.

EARNINGS  PER  ORDINARY  SHARE

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

COMPREHENSIVE  INCOME

Statement  of  Financial  Accounting Standards No. 130, "Reporting Comprehensive
Income,"  established  standards  for the reporting and display of comprehensive
income  and  its  components,  specifically  net income and all other changes in
shareholders'  equity  except  those  resulting  from  investments  by  and
distributions  to  shareholders.  The  Company,  which  adopted  the  standard
beginning  January  1,  1998,  has  elected  to display comprehensive income (or
non-owner  changes  in  shareholders'  equity)  in the Consolidated Statement of
Shareholders'  Equity.

RECENT  ACCOUNTING  PRONOUNCEMENTS

In  June 1998, the Financial Accounting Standards Board issued Statement No. 133
("SFAS  133"),  "Accounting  for Derivative Instruments and Hedging Activities."
SFAS  133  establishes  accounting  and  reporting  standards  for  derivative
instruments  and  for  hedging activities.  It requires enterprises to recognize
all derivatives as either assets or liabilities in the balance sheet and measure
those  instruments  at  fair value.  The requisite accounting for changes in the
fair value of a derivative will depend on the intended use of the derivative and
the resulting designation.  The Company must adopt SFAS 133 effective January 1,
2001.  Based  on  the  Company's  outstanding derivatives contracts, the Company
believes  that  the  impact  of adopting this standard would not have a material
adverse  effect on the Company's operations or consolidated financial condition.
However,  no  assurances  can be given with regard to the level of the Company's
derivatives  activities  at the time SFAS 133 is adopted or the resulting effect
on  the  Company's  operations  or  consolidated  financial  condition.

THE  USE  OF  ESTIMATES  IN  PREPARING  FINANCIAL  STATEMENTS

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

RECLASSIFICATIONS

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

 2.  ASSET  DISPOSITIONS

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

In  July  1998,  the  Company  and Atlantic Richfield Company ("ARCO") signed an
agreement  providing financing for the development of the Company's gas reserves
on  Block  A-18 of the Malaysia-Thailand Joint Development Area.  Under terms of
the  agreement,  consummated in August 1998, the Company sold to a subsidiary of
ARCO for $150 million one-half of the shares of the subsidiary through which the
Company owned its 50% share of Block A-18.  The Company received net proceeds of
$142 million and recorded a gain of $63.2 million in gain on the sale of oil and
gas  assets. After the sale, which resulted in a 50% ownership in the previously
wholly  owned  subsidiary,  the  Company's  remaining ownership is accounted for
using  the  equity  method.  This  investment  in  Block  A-18  is  presented in
investment  in  affiliate  at  December  31,  1999  and  1998.

The  agreements  also require ARCO to pay the future exploration and development
costs  attributable  to  the  Company's  and ARCO's collective interest in Block
A-18, up to $377 million or until first production from a gas field, after which
the  Company  and  ARCO  would  each  pay  50%  of  such costs.  There can be no
assurance  that  the  Company's  and  ARCO's  collective  share  of  the cost of
developing  the  project  will  not  exceed  $377  million.  Additionally,  the
agreements  require  ARCO  to  pay the Company an additional $65 million each at
July  1,  2002, and July 1, 2005, if certain specific development objectives are
met by such dates, or $40 million each if the objectives are met within one year
thereafter.  There  can  be  no  assurance  that  the  Company  will receive any
incentive  payments.  The  agreements  provide that the Company will recover its
investment  in recoverable costs in the project, approximately $100 million, and
that  ARCO  will  recover  its  investment  in recoverable costs, on a first-in,
first-out  basis  from  the  cost-recovery  portion  of  future  production.

In  February  1998,  the  Company sold Triton Pipeline Colombia, Inc. ("TPC"), a
wholly  owned  subsidiary  that  held  the Company's 9.6% equity interest in the
Colombian  pipeline  company, Oleoducto Central S.A. ("OCENSA"), to an unrelated
third party (the "Purchaser") for $100 million.  Net proceeds were approximately
$97.7  million.    The  sale  resulted  in  a  gain  of  $50.2  million.

In  conjunction  with  the  sale of TPC, the Company entered into an equity swap
with a creditworthy financial institution (the "Counterparty").  The equity swap
has  a notional amount of $97 million and requires the Company to make quarterly
floating  LIBOR-based  payments  on the notional amount to the Counterparty.  In
exchange,  the  Counterparty  is  required  to  make  payments  to  the  Company
equivalent  to  97%  of  the  dividends  TPC  receives  in respect of its equity
interest  in  OCENSA.  The  equity  swap  is  carried in the Company's financial
statements  at  fair value during its term, which, as amended, will expire April
14, 2000.  The value of the equity swap in the Company's financial statements is
equal  to  97% of the estimated fair value of the shares of OCENSA owned by TPC.
Because  there  is  no  public  market  for  the  shares  of OCENSA, the Company
estimates  their  value  using  a  discounted  cash  flow  model  applied to the
distributions expected to be paid in respect of the OCENSA shares.  The discount
rate  applied  to  the estimated cash flows from the OCENSA shares is based on a
combination  of  current  market rates of interest, a credit spread for OCENSA's
debt,  and  a spread to reflect the preferred stock nature of the OCENSA shares.
During  the  years  ended  December  31,  1999 and 1998, the Company recorded an
expense  of  $6.9  million  and  $3.3  million,  respectively,  in  other income
(expense),  net,  related to the net payments made under the equity swap and its
change in fair value. Net payments made (or received) under the equity swap, and
any  fluctuations  in the fair value of the equity swap, in future periods, will
affect  other income in such periods.  There can be no assurance that changes in
interest  rates,  or in other factors that affect the value of the OCENSA shares
and/or  the equity swap, will not have a material adverse effect on the carrying
value  of  the  equity  swap.

Upon  the  expiration of the equity swap in April 2000, the Company expects that
the  Purchaser will sell the TPC shares. Under the terms of the equity swap with
the  Counterparty, upon any sale by the Purchaser of the TPC shares, the Company
will  receive from the Counterparty, or pay to the Counterparty, an amount equal
to the excess or deficiency, as applicable, of the difference between 97% of the
net proceeds from the Purchaser's sale of the TPC shares and the notional amount
of $97 million.  For example, if the Purchaser sold the TPC shares for an amount
equal  to  the  value  the  Company  has estimated for purposes of preparing its
balance  sheet as of December 31, 1999, the Company would have to make a payment
to  the Counterparty under the equity swap of approximately $8.4 million.  There
can  be no assurance that the value the Purchaser may realize in any sale of the
TPC  shares  will  equal  the  value  of the shares estimated by the Company for
purposes  of  valuing the equity swap. The Company has no right or obligation to
repurchase  the  TPC  shares at any time, but the Company is not prohibited from
offering  to  purchase  the  shares  if    the  Purchaser  offers  to sell them.

In  June  1997,  the  Company sold its Argentine subsidiary for cash proceeds of
$4.1  million  and  recognized a gain of $4.1 million in gain on sale of oil and
gas  assets.

 3.  WRITEDOWN  OF  ASSETS

Writedown  of  assets  in  1998  is  summarized  as  follows:



<TABLE>
<CAPTION>

<S>                                                              <C>
                                                                  YEAR ENDED
                                                                 DECEMBER 31,
                                                                     1998
                                                                 -----------

Evaluated oil and gas properties (SEC ceiling test)              $  241,005
Unevaluated oil and gas properties                                   73,890
Other assets                                                         13,735
                                                                 -----------

                                                                 $  328,630
                                                                 ===========
</TABLE>



In  June  and  December 1998, the carrying amount of the Company's evaluated oil
and  gas  properties  in  Colombia  was  written  down  by $105.4 million ($68.5
million,  net  of  tax)  and  $135.6  million  ($115.9  million,  net  of  tax),
respectively,  through  application  of  the  full  cost  ceiling  limitation as
prescribed  by  the Securities and Exchange Commission ("SEC"), principally as a
result  of  a  decline in oil prices.  No adjustments were made to the Company's
reserves in Colombia as a result of the decline in prices.  The SEC ceiling test
was  calculated  using  the  June  30,  and December 31, 1998, WTI oil prices of
$14.18  per  barrel  and  $12.05  per  barrel,  respectively,  that,  after  a
differential  for  Cusiana  crude  delivered at the port of Covenas in Colombia,
resulted  in  a  net  price  of approximately $13 per barrel and $11 per barrel,
respectively.

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

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

 4.  SPECIAL  CHARGES

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

In  July  1998,  the  Company  commenced  a  plan  to  restructure the Company's
operations,  reduce  overhead  costs  and  substantially  scale  back
exploration-related  expenditures.  The plan contemplated the closing of foreign
offices  in  four  countries, the elimination of approximately 105 positions, or
41%  of  the  worldwide  workforce,  and the relinquishment or other disposal of
several  exploration  licenses.  As  a  result of the restructuring, the Company
recognized  special  charges of $15 million during the third quarter of 1998 and
$3.3 million during the fourth quarter of 1998 for a total of $18.3 million.  Of
the  $18.3 million in special charges, $14.5 million related to the reduction in
workforce,  and  represented  the  estimated  costs  for  severance,  benefit
continuation  and  outplacement costs, which will be paid over a period of up to
two  years  according to the severance formula. Since July 1998, the Company has
paid $13.1 million in severance, benefit continuation and outplacement costs.  A
total  of  $2.1  million  of  special  charges related to the closing of foreign
offices,  and  represented  the estimated costs of terminating office leases and
the  write-off of related assets.  The remaining special charges of $1.7 million
primarily  related to the write-off of other surplus fixed assets resulting from
the reduction in workforce.  At December 31, 1999, all of the positions had been
eliminated,  all designated foreign offices had closed and all licenses had been
relinquished, sold or their commitments renegotiated.  During the fourth quarter
of  1999,  the  Company  reversed $.7 million of the accrual associated with the
completion  of restructuring activities.  The remaining liability related to the
restructuring activities undertaken in 1998 was $1 million at December 31, 1999.

In March 1999, the Company accrued special charges of $1.2 million related to an
additional  15%  reduction  in  the  number  of  employees  resulting  from  the
Company's  continuing efforts to reduce costs.  The special charges consisted of
$1  million  for  severance, benefit continuation and outplacement costs and $.2
million related to the write-off of surplus fixed assets.  Since March 1999, the
Company has paid $.9 million in severance, benefit continuation and outplacement
costs.  At  December  31,  1999,  the  remaining  liability  related  to  the
restructuring  activities  undertaken  in  1999  was  $.1  million.


5.  OTHER RECEIVABLES

    Other receivables consisted of the following:


<TABLE>
<CAPTION>

<S>                                                   <C>      <C>
                                                        DECEMBER 31,
                                                      ----------------
                                                       1999     1998
                                                      -------  -------

Receivables from and advances to partners and others  $10,684  $ 2,007
Receivable from financial market transactions           4,861      180
Receivable from insurance                               2,300    7,800
Receivable from the forward oil sale                    1,081   31,932
Other                                                   4,888    5,837
                                                      -------  -------

                                                      $23,814  $47,756
                                                      =======  =======
</TABLE>






<PAGE>
 6.  PROPERTY AND EQUIPMENT

        Property and equipment, at cost, are summarized as follows:


<TABLE>
<CAPTION>
<S>                                          <C>       <C>
                                                 DECEMBER 31,
                                             ------------------
                                                1999     1998
                                             --------  --------
Oil and gas properties, full cost method:

   Evaluated                                 $560,240  $543,514
   Unevaluated                                 78,527    70,836
   Support equipment and facilities           303,953   289,659
Other                                          17,535    18,790
                                             --------  --------

                                              960,255   922,799
Less accumulated depreciation and depletion   436,103   451,892
                                             --------  --------

                                             $524,152  $470,907
                                             ========  ========
</TABLE>



The  Company  capitalized  general  and  administrative  expenses  related  to
exploration  and development activities of $6.9 million, $20.6 million and $32.4
million  in  the  years  ended  December  31, 1999, 1998 and 1997, respectively.

 7.  ACCOUNTS  PAYABLE  AND  ACCRUED  LIABILITIES

Accounts  payable  and  accrued  liabilities  are  summarized  as  follows:


<TABLE>
<CAPTION>

<S>           <C>


                                                    DECEMBER 31,
                                                 ----------------
                                                   1999     1998
                                                 -------  -------
Colombian income taxes                           $14,471  $   ---
Accrued exploration and development                9,762    3,774
Equity swap                                        8,435      ---
Accrued interest payable                           7,864    8,160
Taxes other than income                            7,713    2,970
Litigation and environmental matters               3,872    2,064
Accrued special charges                            1,246    7,869
Accounts payable, principally trade                1,242    9,136
Dividends payable                                    ---    2,693
Other                                              7,971    8,307
                                                 -------  -------

                                                 $62,576  $44,973
                                                 =======  =======
</TABLE>

 8.  DEFERRED INCOME AND OTHER


In  May  1995, the Company sold 10.4 million barrels of oil from the Cusiana and
Cupiagua fields in Colombia in a forward oil sale.  Under the terms of the sale,
the Company received approximately $87 million of the approximately $124 million
net  proceeds.  In 1999, the Company received substantially all of the remaining
proceeds totaling approximately $31.9 million.  The Company has recorded the net
proceeds  as deferred income and recognizes such revenue when the barrels of oil
are  delivered  during  the  five-year period that began in June 1995. Under the
terms of the agreement, the Company must deliver to the buyer 58,425 barrels per
month  through March 1997 and 254,136 barrels per month from April 1997 to March
2000.  At  December  31,  1999  and  1998,  $8.8  million  and  $35.3  million,
respectively,  were  recorded  as  deferred  income  and  included  in  current
liabilities.

During  1999, the Company acquired the Colombian entity of its former partner in
the  El Pinal field.  In addition to the working interest in the El Pinal field,
the  acquired entity has tax basis and net operating loss carryforwards ("NOLs")
totaling  approximately  $40  million,  which  the Company expects to utilize in
2000.  At  December  31, 1999, the tax affected amount of the tax basis and NOLs
($14.2  million)  was  included  in  current assets as a deferred tax asset.  In
addition,  the  Company  recorded deferred income of $10.6 million, representing
the  difference  between  the  value  of the deferred tax asset and the purchase
price.  During  2000,  the  deferred  tax  asset and the deferred income will be
reduced  as  the  tax  basis  and  NOLs  are  utilized.

 9.  DEBT

A  summary  of  long-term  debt  follows:


<TABLE>
<CAPTION>

<S>                                      <C>       <C>

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

Senior Notes due 2005                    $200,000  $200,000
Senior Notes due 2002                     199,947   199,924
Term credit facility maturing 2001         13,540    22,568
Revolving credit facility maturing 1999       ---     5,000
                                         --------  --------

                                          413,487   427,492
 Less current maturities                    9,027    14,027
                                         --------  --------

                                         $404,460  $413,465
                                         ========  ========
</TABLE>



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

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

In  November  1995, a subsidiary signed an unsecured term credit facility with a
bank  supported  by  a  guarantee issued by the Export-Import Bank of the United
States  ("EXIM")  for $45 million, which matures in January 2001.  Principal and
interest payments are due semi-annually on January 15 and July 15 and borrowings
bear  interest at LIBOR plus .25%, adjusted on a semi-annual basis.  At December
31,  1999,  the  Company  had  outstanding borrowings of $13.5 million under the
facility.

In  February  2000,  the  Company  entered  into an unsecured two-year revolving
credit  facility  with  a  group  of banks, which matures in February 2002.  The
credit  facility  gives  the Company the right to borrow from time to time up to
the  amount  of  the  borrowing base determined by the banks, not to exceed $150
million.  As  of February 2000, the borrowing base was $150 million.  The credit
facility  contains  various  restrictive  covenants,  including  covenants  that
require  the  Company  to  maintain  a  ratio  of  earnings  before  interest,
depreciation,  depletion,  amortization and income taxes to net interest expense
of  at least 2.5 to 1, and that prohibit the Company from permitting net debt to
exceed  the  product  of  3.75  times  the  Company's  earnings before interest,
depreciation,  depletion,  amortization  and  income  taxes,  in each case, on a
trailing  four  quarters  basis.

The  Company  capitalizes interest on qualifying assets, principally unevaluated
oil  and  gas properties, major development projects in progress and investments
accounted for by the equity method while the investee has activities in progress
necessary  to  commence its principle operations.  Capitalized interest amounted
to  $14.5  million,  $23.2 million and $25.8 million in the years ended December
31,  1999,  1998  and  1997,  respectively.

The  Company amortizes debt issue costs over the life of the borrowing using the
interest method.  Amortization related to the Company's debt issue costs was $.5
million,  $2.9 million and $2 million in the years ended December 31, 1999, 1998
and 1997, respectively.  The aggregate maturities of long-term debt for the five
years  during  the  period ending December 31, 2004, are as follows:  2000 -- $9
million;  2001 -- $4.5 million; 2002 -- $199.9 million; 2003 -- nil; and 2004 --
nil.

<PAGE>
10.  INCOME  TAXES

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




<TABLE>
<CAPTION>
<S>                    <C>             <C>               <C>


                                    YEAR ENDED DECEMBER 31,
                       --------------------------------------------
                         1999              1998              1997
                       ---------        ----------        ---------
Cayman Islands         $(35,907)        $  82,995         $(12,969)
United States            (7,810)          (24,003)         (31,694)
Foreign - other         119,894          (297,601)          61,559
                       ---------        ----------        ---------

                       $ 76,177         $(238,609)        $ 16,896
                       =========        ==========        =========
</TABLE>



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

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



<TABLE>
<CAPTION>
<S>               <C>       <C>        <C>


                       YEAR ENDED DECEMBER 31,
                   -----------------------------
                     1999       1998      1997
                   --------  ---------  --------
Current:
  Cayman Islands   $   ---   $    ---   $   ---
  United States        ---        ---        (7)
  Foreign - other   20,793      4,487     3,230
                   --------  ---------  --------

    Total current   20,793      4,487     3,223
                   --------  ---------  --------
Deferred:
  Cayman Islands       ---        ---       ---
  United States     (1,410)     1,457    (7,929)
  Foreign - other    9,237    (57,049)   16,007
                   --------  ---------  --------

   Total deferred    7,827    (55,592)    8,078
                   --------  ---------  --------

     Total         $28,620   $(51,105)  $11,301
                   ========  =========  ========

</TABLE>
<PAGE>


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




<TABLE>
<CAPTION>

<S>                                                   <C>      <C>      <C>
                                                       YEAR ENDED DECEMBER 31,
                                                      ---------------------------
                                                       1999      1998     1997
                                                      -------  -------  ---------

Tax provision at statutory tax rate                     0.0 %    0.0 %      0.0 %
Increase (decrease) resulting from:
   Net change in valuation allowance                  (15.7)%    3.9 %    263.0 %
   Foreign items without tax benefit                   18.9 %  (34.9)%     77.8 %
   Income subject to tax in excess of statutory rate   36.6 %   32.6 %     36.9 %
   Current year change in NOL/credit carryforwards     (7.6)%   (4.8)%   (356.7)%

   Temporary differences:
      Oil and gas basis adjustments                     3.3 %   25.7 %     32.5 %
      Reimbursement of pre-commerciality costs          2.3 %   (1.1)%     13.2 %
   Other                                               (0.2)%    --- %      0.2 %
                                                      -------  -------  --------

                                                       37.6%    21.4 %     66.9 %
                                                      =======  =======  =========
</TABLE>





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

<TABLE>
<CAPTION>


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

                                                   DECEMBER 31, 1999               DECEMBER 31, 1998
                                             ------------------------------  -------------------------------
                                                                    OTHER                            OTHER
                                                U.S.    COLOMBIA   FOREIGN      U.S.    COLOMBIA    FOREIGN
                                             ---------  --------  ---------  ---------  ---------  ---------
Deferred tax asset:
  Net operating loss carryforwards           $157,558   $20,090   $  9,832   $145,475   $  7,992   $  7,219
  Depreciable/depletable property               1,748     8,778        ---      1,252     27,730        ---
  Credit carryforwards                          2,048       ---        ---      1,731      6,813        ---
  Reserves                                        819       ---        ---      2,502        ---        ---
  Other                                           176       ---        ---      1,505        ---        ---
                                             ---------  --------  ---------  ---------  ---------  ---------

Gross deferred tax asset                      162,349    28,868      9,832    152,465     42,535      7,219
Valuation allowances                          (72,908)   (8,778)       ---    (65,881)   (27,730)       ---
                                             ---------  --------  ---------  ---------  ---------  ---------

Net deferred tax asset                         89,441    20,090      9,832     86,584     14,805      7,219
                                             ---------  --------  ---------  ---------  ---------  ---------

Deferred tax liability:
  Depreciable/depletable property                 ---       ---    (16,509)       ---        ---    (10,454)
  Other                                        (1,213)      ---        ---       (473)       ---        ---
                                             ---------  --------  ---------  ---------  ---------  ---------

Net deferred tax asset (liability)             88,228    20,090     (6,677)    86,111     14,805     (3,235)
Less current deferred tax asset (liability)       ---    20,090        ---        ---        ---        ---
                                             ---------  --------  ---------  ---------  ---------  ---------

Noncurrent deferred tax asset (liability)    $ 88,228   $   ---   $ (6,677)  $ 86,111   $ 14,805   $ (3,235)
                                             =========  ========  =========  =========  =========  =========
</TABLE>




At  December 31, 1999, the Company had NOLs and depletion carryforwards for U.S.
tax  purposes  of  $450.2 million and $20.3 million, respectively. The U.S. NOLs
expire  from  2000  through  2020  as  follows:


<TABLE>
<CAPTION>

<S>                  <C>
                       NOLS
                     EXPIRING
                      BY YEAR
                     ---------
May 2000             $  19,571
May 2001                30,389
May 2002                22,702
May 2003                20,566
May 2004                 8,263
May 2005 - May 2020    348,675
                     ---------

                     $ 450,166
                     =========
</TABLE>



At  December  31,  1999,  the  Company's  Colombian operations and other foreign
operations  had  NOLs  and other credit carryforwards totaling $57.4 million and
$40.7  million,  respectively.    The  NOLs  expire  from  2001  through  2004.

The  deferred  tax valuation allowance of $81.7 million at December 31, 1999, is
primarily  attributable to management's assessment of the utilization of NOLs in
the  U.S.,  the  expectation  that  other  tax credits will expire without being
utilized,  and  certain  temporary differences will reverse without a benefit to
the  Company.  The  minimum amount of future taxable income necessary to realize
the deferred tax asset is approximately $252 million and $57 million in the U.S.
and Colombia, respectively.  Although there can be no assurance the Company will
achieve  such  levels of income, management believes the deferred tax asset will
be  realized  through  income  from  its  operations.

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


11.  EMPLOYEE  BENEFITS

PENSION  PLANS

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

The  funding  status  of  the  plans  follows:


<TABLE>
<CAPTION>
<S>                                                <C>        <C>       <C>        <C>

                                                                  DECEMBER 31,
                                                    ----------------------------------------
                                                           1999                 1998
                                                    -------------------  -------------------
                                                     DEFINED              DEFINED
                                                     BENEFIT     SERP     BENEFIT     SERP
                                                      PLAN       PLAN      PLAN       PLAN
                                                    ---------  --------  ---------  --------

Change in benefit obligation:
   Benefit obligation at beginning of year          $  6,435   $ 6,579   $  6,008   $ 6,621
   Service cost                                          392       537        560       799
   Interest cost                                         421       435        438       607
   Amendments                                            ---       ---        ---       434
   Actuarial loss/(gain)                                (750)    1,465        472       913
   Benefits paid                                        (531)   (1,385)      (377)   (1,617)
   Curtailment gain                                      ---       ---       (666)   (1,178)
                                                    ---------  --------  ---------  --------

   Benefit obligation at end of year                   5,967     7,631      6,435     6,579
                                                    ---------  --------  ---------  --------

Change in plan assets:
   Fair value of plan assets at beginning of year      7,068       ---      5,531       ---
   Actual return on plan assets                        1,971       ---      1,446       ---
   Company contribution                                  480     1,385        468     1,617
   Benefits paid                                        (531)   (1,385)      (377)   (1,617)
                                                    ---------  --------  ---------  --------

   Fair value of plan assets at end of year            8,988       ---      7,068       ---
                                                    ---------  --------  ---------  --------

Reconciliation:
   Funded status                                       3,021    (7,631)       633    (6,579)
   Unrecognized actuarial (gain)/loss                 (2,999)    1,945       (908)      480
   Unrecognized transition (asset)/obligation             (6)      527         (8)      695
   Unrecognized prior service cost                       317       226        373       253
                                                    ---------  --------  ---------  --------

   Prepaid/(accrued) pension cost                        333    (4,933)        90    (5,151)
                                                    ---------  --------  ---------  --------

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

Adjusted prepaid/(accrued) pension cost             $    333   $(6,188)  $     90   $(5,151)
                                                    =========  ========  =========  ========
</TABLE>



The  adjustment required to recognize the minimum liability for the SERP plan at
December  31,  1999, resulted in the recognition of $.8 million as an intangible
asset  and $.5 million ($.3 million, net of tax) as a charge to accumulated
other non-owner  changes  in  shareholder's  equity.

<PAGE>
A  summary  of  the  components  of  pension  expense  follows:



<TABLE>
<CAPTION>
<S>                                     <C>      <C>      <C>

                                            YEAR ENDED DECEMBER 31,
                                           -------------------------
                                            1999      1998    1997
                                           -------  -------  -------
Components of net periodic pension cost:
   Service cost                            $  929   $1,359   $  832
   Interest cost                              856    1,045      783
   Expected return on plan assets            (618)    (481)    (416)
   Recognized net actuarial loss/(gain)       (12)     ---      ---
   Amortization of transition obligation      166      591      166
   Amortization of prior service cost          83      538       67
                                           -------  -------  -------

Net periodic pension cost                  $1,404   $3,052   $1,432
                                           =======  =======  =======
</TABLE>



The  projected  benefit  obligations  at  December  31,  1999 and 1998, assume a
discount  rate  of  7.75%  and  6.75%,  respectively,  and a rate of increase in
compensation  expense of 5%.  The expected long-term rate of return on assets is
9% for the defined benefit plan.  During 1998, work-force reductions resulted in
the  recognition  of  additional  prior service cost of $.2 million each for the
defined  benefit  plan and the SERP plan and additional transition obligation of
$.4  million  for  the  SERP  plan.

EMPLOYEE  STOCK  OWNERSHIP  PLAN

Effective  January  1, 1994, the Company amended and restated the employee stock
ownership  plan  to  form  a  401(k)  plan (the "Plan").  The Company recognizes
expense  based  on  actual amounts contributed to the Plan.  The cost recognized
for  the  Plan  was $.2 million, $.6 million and $.6 million for the years ended
December  31,  1999,  1998  and  1997,  respectively.

12.  SHAREHOLDERS'  EQUITY

5%  CONVERTIBLE  PREFERENCE  SHARES

In  connection with the acquisition of the minority interest in Triton Europe in
1994,  the  Company  designated  a  series  of 550,000 preferred shares (522,460
shares  issued)  as  5%  Preferred  Stock,  no par value, with a stated value of
$34.41  per  share.  Pursuant to the Reorganization, Triton converted each share
of  5% Preferred Stock into one 5% Convertible Preference Share, par value $.01.
Each share of the Company's 5% Convertible Preference Shares is convertible into
one  Triton  ordinary  share  and bears a cash dividend, which has priority over
dividends  on  Triton's ordinary shares, equal to 5% per annum on the redemption
price of $34.41 per share, payable semi-annually on March 30 and September 30 of
each  year.  The  5%  Convertible  Preference  Shares  have priority over Triton
ordinary  shares upon liquidation, and may be redeemed at Triton's option at any
time  on  or  after March 30, 1998, for cash equal to the redemption price.  Any
shares  that  remain  outstanding  on  March  30,  2004, must be redeemed at the
redemption  price,  either  for  cash  or,  at  the Company's option, for Triton
ordinary  shares.  At  December  31,  1999  and  1998,  there  were  209,639  5%
Convertible  Preference  Shares outstanding and at December 31, 1997, there were
218,285  shares  outstanding.

8%  CONVERTIBLE  PREFERENCE  SHARES

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

Each 8% Convertible Preference Share is convertible at any time at the option of
the  holder  into  four  ordinary  shares  of  the  Company  (subject to certain
antidilution  protections).  Holders  of  8%  Convertible  Preference Shares are
entitled  to receive, when and if declared by the Board of Directors, cumulative
dividends  at  a rate per annum equal to 8% of the liquidation preference of $70
per share, payable for each semi-annual period ending June 30 and December 30 of
each  year.  At  the  Company's  option, dividends may be paid in cash or by the
issuance  of  additional  whole shares of 8% Convertible Preference Shares. If a
dividend  is to be paid in additional shares, the number of additional shares to
be  issued  in payment of the dividend will be determined by dividing the amount
of  the  dividend by $70, with amounts in respect of any fractional shares to be
paid  in cash. The first dividend period was the period from January 4, 1999, to
June  30, 1999. The Company's Board of Directors elected to pay the dividend for
that  period  in  additional  shares  resulting  in  the  issuance of 196,388 8%
Convertible  Preference  Shares.  The  dividend  for  the period July 1, 1999 to
December  31,  1999  was paid in cash.  The declaration of a dividend in cash or
additional  shares  for  any period should not be considered an indication as to
whether  the Board will declare dividends in cash or additional shares in future
periods.  Holders  of 8% Convertible Preference Shares are entitled to vote with
the  holders  of ordinary shares on all matters submitted to the shareholders of
the  Company for a vote, with each 8% Convertible Preference Share entitling its
holder to a number of votes equal to the number of ordinary shares into which it
could  be  converted at that time.  At December 31, 1999 and 1998, 5,193,643 and
1,822,500  8%  Convertible  Preference  Shares  were  outstanding, respectively.

<PAGE>
ORDINARY  SHARES

Changes  in  issued  ordinary  shares  were  as  follows:


<TABLE>
<CAPTION>
<S>                                 <C>          <C>          <C>

                                             YEAR ENDED DECEMBER 31,
                                       ------------------------------------
                                           1999        1998         1997
                                       -----------  -----------  ----------
Balance at beginning of year           36,643,478   36,541,064   36,342,181
   Share repurchase                      (948,300)         ---          ---
   Issuances under stock plans             49,367       46,648       35,961
   Conversion of 8% preference shares      10,980          ---          ---
   Exercise of employee stock options       8,213       47,238       83,736
   Conversion of 5% preference shares         ---        8,646       29,184
   Other, net                                 (10)        (118)      50,002
                                       -----------  -----------  ----------

Balance at end of year                 35,763,728   36,643,478   36,541,064
                                       ===========  ===========  ==========

</TABLE>

Changes  in  ordinary  shares  held  in  treasury  were  as  follows:



<TABLE>
<CAPTION>

<S>                              <C>    <C>


                                 YEAR ENDED DECEMBER 31,
                                 -----------------------
                                  1998             1997
                                 ------           ------
Balance at beginning of year        73               40
   Purchase of treasury shares      64               33
   Retirement of treasury shares  (137)             ---
                                  -----             ---

Balance at end of year             ---               73
                                 ======           ======
</TABLE>



SHARE  REPURCHASE


In  April  1999,  the Company's Board of Directors authorized a share repurchase
program  enabling  the  Company to repurchase up to ten percent of the Company's
then  outstanding 36.7 million ordinary shares.  Purchases of ordinary shares by
the  Company began in April and may be made from time to time in the open market
or  through  privately  negotiated  transactions  at  prevailing  market  prices
depending on market conditions.  The Company has no obligation to repurchase any
of  its  outstanding  shares and may discontinue the share repurchase program at
management's  discretion.  As  of  December  31, 1999, the Company had purchased
948,300  ordinary  shares  for $11.3 million.  The Company canceled and returned
the repurchased ordinary shares to the status of authorized but unissued shares.
The Company's revolving credit facility entered into in February 2000, generally
does not permit the Company to repurchase its ordinary shares without the bank's
consent.

<PAGE>
SHAREHOLDER  RIGHTS  PLAN

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

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

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

<PAGE>
13.  STOCK  COMPENSATION  PLANS

STOCK  OPTION  PLANS

Options  to  purchase  ordinary shares of the Company may be granted to officers
and  employees  under  various  stock  option  plans. The exercise price of each
option  is  equal  to or greater than the market price of the Company's ordinary
shares  on  the date of grant. Grants generally become exercisable in 25% or 33%
cumulative  annual  increments  beginning one year from the date of issuance and
generally  expire  during  a  period from 5 to 10 years after the date of grant,
depending  on  terms  of  the  grant.  In  addition,  each non-employee director
receives  an  option  to  purchase  15,000 shares each year. These grants become
exercisable  at  the  date  of  the grant and expire at the end of 10 years.  At
December  31,  1999  and  1998,  shares  available  for grant were 1,019,021 and
2,521,133,  respectively.

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



<TABLE>
<CAPTION>

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

                                             DECEMBER 31, 1999     DECEMBER 31, 1998    DECEMBER 31, 1997
                                           -------------------- ---------------------  -------------------
                                                       WEIGHTED             WEIGHTED             WEIGHTED
                                                        AVERAGE              AVERAGE              AVERAGE
                                                       EXERCISE             EXERCISE             EXERCISE
                                              SHARES     PRICE     SHARES      PRICE     SHARES    PRICE
                                           -----------  ------- ------------  -------  ----------  -------
Outstanding at beginning of year            4,057,207   $26.51    4,449,435   $39.05   3,854,046   $38.81
Granted                                     2,150,000    14.03    2,894,603    20.56     744,250    39.99
Exercised                                      (8,213)   10.57      (47,238)   29.30     (83,736)   30.76
Canceled                                     (351,138)   29.24   (3,239,593)   38.39     (65,125)   46.09
                                           -----------          ------------          -----------

Outstanding at end of year                  5,847,856    21.78    4,057,207    26.51   4,449,435    39.05
                                           ===========          ============          ===========

Options exercisable at year-end             3,121,601             2,804,584            2,728,254
Weighted average fair value of options:
  Granted at market prices                 $     2.71           $      6.12           $    16.37
  Granted at greater than market prices          4.93                  2.84                  ---
</TABLE>



On  December 2, 1998, the Compensation Committee approved the grant of new stock
options  totaling  440,103  shares  with  an  exercise  price  of  $14.50  to
substantially  all  of  its  employees.  Each participating employee was granted
options in an amount equal to one-half of any options then held by the employees
with  an  exercise  price  greater than $30.00 per share and the options with an
exercise  price  greater  than  $30.00  per  share  expired.

<PAGE>
The  following  table  summarizes information about stock options outstanding at
December  31,  1999:


<TABLE>
<CAPTION>
<S>             <C>             <C>          <C>        <C>             <C>

                         OPTIONS OUTSTANDING             OPTIONS EXERCISABLE
                --------------------------------------  -------------------------
                                  WEIGHTED
   RANGE                           AVERAGE    WEIGHTED                   WEIGHTED
     OF             NUMBER        REMAINING    AVERAGE       NUMBER       AVERAGE
  EXERCISE      OUTSTANDING AT  CONTRACTUAL   EXERCISE   EXERCISABLE AT  EXERCISE
   PRICES        DEC. 31, 1999      LIFE       PRICE     DEC. 31, 1999    PRICE
--------------  --------------  -----------  ---------  --------------  ---------

$  6.94 - 14.50     2,904,852    4.9 years   $  14.10         657,773   $  12.75
  16.81 - 29.50     1,607,932    3.9 years      20.52       1,150,006      21.64
  31.75 - 39.63       667,072    2.4 years      34.10         667,072      34.10
  40.25 - 52.25       668,000    3.6 years      45.86         646,750      46.04
                --------------                          --------------

                    5,847,856                               3,121,601
                ==============                          ==============

</TABLE>

EMPLOYEE  STOCK  PURCHASE  PLAN


The  Company  has an employee stock purchase plan that provides for the award of
ordinary  shares  to  officers  and  employees.  Under  the  terms  of the plan,
employees  can  choose each semi-annual period to have up to 15% of their annual
gross  or  base compensation withheld to purchase the Company's ordinary shares.
The  purchase  price of the stock is 85% of the lower of its beginning of period
or  end  of  period market price. Under the plan, the Company sold 49,367 shares
and  46,648  shares to employees for the years ended December 31, 1999 and 1998,
respectively.

FAIR  VALUE  OF  STOCK  COMPENSATION

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



<TABLE>
<CAPTION>

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


                                                        YEAR ENDED DECEMBER 31,
                                                    ------------------------------
                                                     1999       1998       1997
                                                    -------  ----------  ---------
Net earnings (loss) applicable to ordinary shares:
  As reported                                       $18,886  $(190,565)  $ (9,296)
  Pro forma                                          12,579   (200,147)   (16,802)

Basic earnings (loss) per ordinary share:
  As reported                                       $  0.52  $   (5.21)  $  (0.26)
  Pro forma                                            0.35      (5.47)     (0.46)

Diluted earnings (loss) per ordinary share:
  As reported                                       $  0.52  $   (5.21)  $  (0.25)
  Pro forma                                            0.35      (5.47)     (0.46)
</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  1999,  1998  and 1997: dividend yield of 0%;
expected  volatility  of approximately 54%, 40% and 26%, respectively; risk-free
interest  rates  of  approximately  6%, 5% and 6%, respectively; and an expected
life  of  approximately  three  to  seven  years.

STOCK  APPRECIATION  RIGHTS  PLAN

The Company had a stock appreciation rights ("SARs") plan which granted  SARs to
non-employee  directors of the Company.  Upon exercise, SARs allow the holder to
receive  the  difference  between  the  SARs' exercise price and the fair market
value  of the ordinary shares covered by SARs on the exercise date and expire at
the  earlier  of  10  years  or  a date based on the termination of the holder's
membership  on  the  board  of  directors.  At  December 31, 1999, SARs covering
20,000  ordinary  shares,  with  an  exercise  price  of  $8.00  per share, were
outstanding.

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

FAIR VALUE OF FINANCIAL INSTRUMENTS

At December 31, 1999 and 1998, the Company's financial instruments included cash
and  equivalents,  short-term receivables, long-term receivables, short-term and
long-term debt, and financial market transactions.  The fair value of cash, cash
equivalents,  short-term  receivables  and short-term debt approximated carrying
values because of the short maturities of these instruments.  The fair values of
the  Company's long-term receivables and financial market transactions, based on
broker  quotes and discounted cash flows, approximated the carrying values.  The
estimated fair value of long-term debt, based on quoted market prices and market
data  for  similar instruments, was $416 million (carrying value - $413 million)
and  $397 million (carrying value - $428 million) at December 31, 1999 and 1998,
respectively.

RISK  MANAGEMENT

Oil  and natural gas sold by the Company are normally priced with reference to a
defined  benchmark,  such  as  light,  sweet  crude  oil  traded on the New York
Mercantile  Exchange  (WTI).  Actual  prices  received  vary  from the benchmark
depending  on  quality and location differentials.  From time to time, it is the
Company's  policy to use financial market transactions, including swaps, collars
and  options,  with  creditworthy  counterparties  primarily  to  reduce  risk
associated  with  the  pricing  of  a portion of the oil and natural gas that it
sells.  The  policy is structured to underpin the Company's planned revenues and
results  of  operations.  The  Company  does  not  enter  into  financial market
transactions  for  trading  purposes.  There can be no assurance that the use of
financial  market  transactions  will  not  result  in  losses.

During  the years ended December 31, 1999 and 1997, markets provided the Company
the  opportunity to realize WTI benchmark oil prices on average $6.37 per barrel
and  $2.35  per  barrel,  respectively,  above  the  WTI benchmark oil price the
Company  set  as  part  of its annual plan for the period. During the year ended
December  31,  1998,  the  Company did not have any outstanding financial market
transactions  to hedge against oil price fluctuations.  As a result of financial
and  commodity  market  transactions settled during the years ended December 31,
1999  and 1997, the Company's risk management program resulted in an average net
realization of approximately $1.65 per barrel and $.11 per barrel, respectively,
lower  than  if  the  Company  had  not  entered  into  such  transactions.

In  anticipation  of  entering  into  the  forward oil sale, in 1995 the Company
purchased  WTI  benchmark call options to retain the ability to benefit from WTI
price  increases  above  a  weighted  average  price  of $20.42 per barrel.  The
volumes  and  expiration dates on the call options coincide with the volumes and
delivery  dates  of  the forward oil sale which will be completed in March 2000.
During  the years ended December 31, 1999, 1998 and 1997, the Company recorded a
gain  (loss)  of $6.1 million, $.4 million, and ($9.7 million), respectively, in
other  income  (expense), net, related to the change in the fair market value of
the call options.  In November 1999, the Company sold WTI benchmark call options
with  the  same  notional  quantities,  strike  price and contract period as the
remaining  call  option  contracts outstanding for a premium of $4.4 million for
the  purpose  of  realizing  the fair value of the purchased call options.  As a
result,  the  Company  has eliminated its exposure to future changes in value of
the  call  options  caused  by  fluctuations  in  oil  prices.

CONCENTRATION  OF  CREDIT  RISK

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

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

<PAGE>
15.  OTHER  INCOME  (EXPENSE),  NET

Other  income  (expense),  net  is  summarized  as  follows:



<TABLE>
<CAPTION>

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

                                      YEAR ENDED DECEMBER 31,
                                     ----------------------------
                                       1999      1998     1997
                                     --------  --------  --------

Equity swap                          $(6,858)  $(3,283)    $---
Change in fair market value of WTI
    benchmark call options             6,150       366    (9,689)
Foreign exchange gain (loss)          (2,674)    2,113     9,549
Loss provisions                       (2,250)     (750)      ---
Gain on sale of corporate assets         443     7,593     1,414
Other                                  1,575     2,441     1,598
                                     --------  --------  --------

                                     $(3,614)  $ 8,480   $ 2,872
                                     ========  ========  ========
</TABLE>



In  1999,  1998  and  1997,  the  Company recognized a net foreign exchange gain
(loss)  of  ($2.7  million),  $2.1  million  and  $9.5  million,  respectively,
consisting  primarily  of  noncash  adjustments  related  to  deferred  taxes in
Colombia  associated  with  devaluation  of  the  Colombian peso versus the U.S.
dollar.

16.  EARNINGS  PER  ORDINARY  SHARE

The  following table reconciles the numerators and denominators of the basic and
diluted  earnings  per  ordinary  share computation for earnings from continuing
operations  for  the  years  ended  December  31,  1999  and  1997.


<TABLE>
<CAPTION>

<S>                                              <C>             <C>
                                                                              <C>
                                                     INCOME        SHARES        PER-SHARE
                                                  (NUMERATOR)   (DENOMINATOR)     AMOUNT
                                                   ------------  ------------  ------------
YEAR ENDED DECEMBER 31, 1999:

  Net earnings                                     $     47,557
  Less: Preference share dividends                      (28,671)
                                                   ------------

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








<PAGE>


<TABLE>
<CAPTION>

<S>          <C>            <C>
                                                   INCOME        SHARES      PER-SHARE
                                                 (NUMERATOR)  (DENOMINATOR)   AMOUNT
                                                 -----------  -------------  ---------
YEAR ENDED DECEMBER 31, 1997:

Earnings before extraordinary item               $    5,595
Less: Preference share dividends                       (400)
                                                 -----------

Earnings available to ordinary shareholders           5,195
        Basic earnings per ordinary share                           36,471   $   0.14
                                                              =============
Effect of dilutive securities
        Stock options                                   ---            457
        Convertible debentures                          ---             80
                                                 -----------  -------------
Earnings available to ordinary shareholders and
        assumed conversions                      $    5,195
                                                 ===========
        Diluted earnings per ordinary share                         37,008   $   0.14
                                                              =============  =========
</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, 1999, 5,193,643 shares of 8% Convertible Preference Shares and
209,639  shares  of  5% Convertible Preference Shares were outstanding.  Each 8%
Convertible  Preference Share is convertible any time into four ordinary shares,
subject to adjustment in certain events. Each 5% Convertible Preference Share is
convertible  any  time into one ordinary share, subject to adjustment in certain
events.  The  8%  Convertible  Preference  Shares  and 5% Convertible Preference
Shares  were  not  included  in the computation of diluted earnings per ordinary
share  because  the  effect  of  assuming  conversion  was  antidilutive.

17.  STATEMENTS  OF  CASH  FLOWS

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


<TABLE>
<CAPTION>
<S>                      <C>   <C>


                                              YEAR ENDED DECEMBER 31,
                                            ---------------------------
                                              1999      1998     1997
                                            --------  -------  --------
Cash  paid  during  the  year  for:
   Interest (net of amount capitalized)      $22,810  $24,517  $133,265
   Income taxes                                5,564    4,339     4,666

Noncash financing activities:
   8% Convertible preference shares issued
        in lieu of cash dividend             $13,747  $   ---  $    ---
   Conversion of preference shares into
       ordinary shares                           192      297     1,004
</TABLE>




Cash paid for interest in 1997 included $124.8 million of interest accreted with
respect to the Senior Subordinated Discount Notes due November 1, 1997 and the
9 3/4% Senior Subordinated Discount Notes due September 15, 2000 through the
dates of retirement.

18.  RELATED  PARTY  TRANSACTIONS

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

Pursuant  to  a monitoring agreement (the "Monitoring Agreement") between Triton
and  Hicks  Muse  Partners, Hicks Muse Partners will provide financial oversight
and  monitoring services as requested by the Company and the Company will pay to
Hicks  Muse Partners an annual fee of $.5 million. In addition, the Company will
reimburse  Hicks  Muse  Partners  for reasonable disbursements and out-of-pocket
expenses  incurred  by  Hicks Muse Partners or its affiliates for the account of
the  Company  or in connection with the performance of its services.  During the
years ended December 31, 1999 and 1998, the Company paid Hicks Muse Partners $.6
million  and  $.1  million,  respectively,  under  the  terms  of the Monitoring
Agreement.

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

In  1999,  the  Company  sold  its  hunting lease and related facilities to HMTF
Operating,  L.P.,  an  affiliate  of Hicks Muse, for proceeds of $.9 million and
recognized  a  gain  of  $.4  million  in  other  income  (expense),  net.

19.  CERTAIN  FACTORS  THAT  COULD  AFFECT  FUTURE  OPERATIONS

Certain  information  contained  in  this  report,  as  well as written and oral
statements  made  or  incorporated by reference from time to time by the Company
and  its  representatives  in  other  reports,  filings  with the Securities and
Exchange Commission, press releases, conferences, teleconferences, or otherwise,
may  be  deemed to be "forward-looking statements" within the meaning of Section
21E  of the Securities Exchange Act of 1934 and are subject to the "Safe Harbor"
provisions  of  that  section.  Forward-looking  statements  include  statements
concerning  the  Company's and management's plans, objectives, goals, strategies
and  future  operations  and  performance  and  the  assumptions underlying such
forward-looking  statements.  When  used  in  this  document,  the  words
"anticipates,"  "estimates,"  "expects,"  "believes,"  "intends,"  "plans,"  and
similar  expressions  are  intended to identify such forward-looking statements.
These  statements  include  information  regarding:

-  drilling schedules;
-  expected or planned production capacity;
-  future production from the Cusiana and Cupiagua fields in Colombia, including
   from the Recetor license;
-  the completion of development and commencement of production in
   Malaysia-Thailand;
-  future production of the Ceiba field in Equatorial Guinea, including volumes
   and timing of first production;
-  the acceleration of the Company's exploration, appraisal and development
   activities in Equatorial Guinea;
-  the Company's capital budget and future capital requirements;
-  the Company's meeting its future capital needs;
-  the Company's utilization of net operating loss carryforwards and realization
   of its deferred tax asset;
-  the level of future expenditures for environmental costs;
-  the outcome of regulatory and litigation matters;
-  the estimated fair value of derivative instruments, including the equity
   swap; and
-  proven oil and gas reserves and discounted future net cash flows therefrom.

These statements are based on current expectations and involve a number of risks
and  uncertainties,  including  those  described  in  the  context  of  such
forward-looking  statements,  as  well as those presented below.  Actual results
and  developments  could differ materially from those expressed in or implied by
such  statements  due  to  these  and  other  factors.

CERTAIN  FACTORS  RELATING  TO  THE  OIL  AND  GAS  INDUSTRY

The  markets  for  oil  and  natural gas historically have been volatile and are
likely  to  continue  to  be volatile in the future.  Oil and natural gas prices
have been subject to significant fluctuations during the past several decades in
response  to  relatively  minor  changes in the supply of and demand for oil and
natural  gas,  market  uncertainty  and a variety of additional factors that are
beyond  the control of the Company.  These factors include the level of consumer
product demand, weather conditions, domestic and foreign government regulations,
political  conditions in the Middle East and other production areas, the foreign
supply  of oil and natural gas, the price and availability of alternative fuels,
and overall economic conditions.  It is impossible to predict future oil and gas
price  movements  with  any  certainty.

The  Company  follows  the  full  cost  method of accounting for exploration and
development  of  oil  and gas reserves, whereby all acquisition, exploration and
development  costs  are  capitalized.  Costs related to acquisition, holding and
initial  exploration  of  licenses  in  countries  with  no  proved reserves are
initially  capitalized,  including  internal  costs  directly  identified  with
acquisition,  exploration and development activities.  The Company's exploration
licenses are periodically assessed for impairment on a country-by-country basis.
If  the  Company's  investment in exploration licenses within a country where no
proved  reserves are assigned is deemed to be impaired, the licenses are written
down  to  estimated  recoverable value.  If the Company abandons all exploration
efforts  in a country where no proved reserves are assigned, all acquisition and
exploration  costs  associated  with  the  country  are expensed.  The Company's
assessments  of  whether its investment within a country is impaired and whether
exploration  activities within a country will be abandoned are made from time to
time  based  on  its review and assessment of drilling results, seismic data and
other  information  it  deems  relevant.  Due  to  the  unpredictable  nature of
exploration drilling activities, the amount and timing of impairment expense are
difficult  to  predict with any certainty.  Financial information concerning the
Company's assets at December 31, 1999, including capitalized costs by geographic
area,  is  set  forth  in  note  21.

The Company's oil and gas business is also subject to all of the operating risks
normally  associated  with  the  exploration  for and production of oil and gas,
including, without limitation, blowouts, explosion, uncontrollable flows of oil,
gas or well fluids,  pollution, earthquakes, formations with abnormal pressures,
labor disruptions and fires, each of which could result in substantial losses to
the  Company  due  to injury or loss of life and damage to or destruction of oil
and  gas  wells,  formations,  production  facilities  or  other properties.  In
accordance  with  customary  industry practices, the Company maintains insurance
coverage  limiting  financial  loss  resulting  from  certain of these operating
hazards.  Losses  and  liabilities arising from uninsured or underinsured events
would  reduce  revenues  and  increase  costs  to  the Company.  There can be no
assurance  that  any  insurance will be adequate to cover losses or liabilities.
The  Company  cannot  predict  the  continued  availability of insurance, or its
availability  at  premium  levels  that  justify  its  purchase.

The  Company's  oil  and  gas  business  is  also  subject  to  laws,  rules and
regulations  in  the  countries  where  it  operates, which generally pertain to
production  control,  taxation,  environmental  and  pricing concerns, and other
matters  relating to the petroleum industry.  Many jurisdictions have at various
times  imposed  limitations  on  the  production  of  natural  gas  and  oil  by
restricting  the  rate  of flow for oil and natural gas wells below their actual
capacity.  There  can be no assurance that present or future regulation will not
adversely  affect  the  operations  of  the  Company.

The  Company  is subject to extensive environmental laws and regulations.  These
laws  regulate the discharge of oil, gas or other materials into the environment
and  may  require the Company to remove or mitigate the environmental effects of
the  disposal  or  release of such materials at various sites.  In addition, the
Company could be held liable for environmental damages caused by previous owners
of  its  properties  or its predecessors.  The Company does not believe that its
environmental  risks are materially different from those of comparable companies
in  the  oil  and  gas  industry.  Nevertheless,  no assurance can be given that
environmental laws and regulations will not, in the future, adversely affect the
Company's  consolidated results of operations, cash flows or financial position.
Pollution  and  similar  environmental  risks generally are not fully insurable.

CERTAIN  FACTORS  RELATING  TO  INTERNATIONAL  OPERATIONS

The  Company  derives  substantially  all  of  its  consolidated  revenues  from
international  operations.  Risks  inherent  in international operations include
risk  of  expropriation,  nationalization,  war,  revolution,  border  disputes,
renegotiation  or  modification  of  existing  contracts,  import,  export  and
transportation regulations and tariffs; taxation policies, including royalty and
tax  increases  and  retroactive  tax  claims;  exchange  controls,  currency
fluctuations  and  other  uncertainties  arising  out  of  foreign  government
sovereignty  over  the  Company's international operations; laws and policies of
the  United  States  affecting  foreign  trade, taxation and investment; and the
possibility  of  having  to  be subject to the exclusive jurisdiction of foreign
courts  in  connection with legal disputes and the possible inability to subject
foreign  persons  to  the jurisdiction of courts in the United States.  To date,
the  Company's  international  operations  have  not been materially affected by
these  risks.

CERTAIN  FACTORS  RELATING  TO  COLOMBIA

The  Company  is  a  participant  in  significant oil and gas discoveries in the
Cusiana  and  Cupiagua  fields, located approximately 160 kilometers (100 miles)
northeast  of  Bogota,  Colombia.  Development  of  reserves  in the Cusiana and
Cupiagua  fields  is  ongoing  and  will require additional drilling.  Pipelines
connect  the  major  producing  fields  in  Colombia to export facilities and to
refineries.

From time to time, guerrilla activity in Colombia has disrupted the operation of
oil and gas projects.  Such activity increased over the last year and appears to
be  increasing  as  political  negotiations  among  government and various rebel
groups  proceed.  In  one  recent  case, a bomb planted near the pipeline caused
OCENSA  to  halt  shipments,  which in turn caused the operator of the fields to
curtail  production  for  approximately  two  days.  Although  the  Colombian
government,  the  Company and its partners have taken steps to maintain security
and  favorable  relations  with  the local population, there can be no assurance
that attempts to reduce or prevent guerrilla activity will be successful or that
guerrilla  activity  will  not  disrupt  operations  in  the  future.

Colombia  is among several nations whose progress in stemming the production and
transit  of illegal drugs is subject to annual certification by the President of
the  United  States.  Although  the  President granted Colombia certification in
1999,  Colombia  was denied certification the last two years and only received a
national  interest  waiver  for  one  of those years.  There can be no assurance
that,  in the future, Colombia will receive certification or a national interest
waiver.  The  consequences of the failure to receive certification or a national
interest  waiver  generally  include  the  following:  all bilateral aid, except
anti-narcotics  and humanitarian aid, would be suspended; the Export-Import Bank
of  the  United States and the Overseas Private Investment Corporation would not
approve  financing  for  new  projects  in  Colombia;  U.S.  representatives  at
multilateral  lending  institutions  would  be required to vote against all loan
requests from Colombia, although such votes would not constitute vetoes; and the
President  of  the  United  States  and Congress would retain the right to apply
future  trade  sanctions.  Each  of  these  consequences could result in adverse
economic  consequences  in Colombia and could further heighten the political and
economic  risks  associated  with  the  Company's  operations  in Colombia.  Any
changes  in  the  holders  of  significant government offices could have adverse
consequences  on  the  Company's  relationship  with  the Colombian national oil
company  and  the Colombian government's ability to control guerrilla activities
and could exacerbate the factors relating to foreign operations discussed above.

CERTAIN  FACTORS  RELATING  TO  MALAYSIA-THAILAND

The Company is a partner in a significant gas exploration project located in the
Gulf  of  Thailand  approximately  450 kilometers (280 miles) northeast of Kuala
Lumpur  and  750 kilometers (470 miles) south of Bangkok as a contractor under a
production-sharing  contract  covering Block A-18 of the Malaysia-Thailand Joint
Development Area.  On October 30, 1999, the Company and the other parties to the
production-sharing  contract  for  Block  A-18  executed  a  gas sales agreement
providing  for  the sale of the first phase of gas. Under terms of the gas sales
agreement,  delivery  of  gas  is  scheduled  to  begin by the end of the second
quarter  of  2002,  following timely completion and approval of an environmental
impact  assessment  associated  with  the  buyers'  pipeline  and  processing
facilities. No assurance can be given as to when such approval will be obtained.
A  lengthy  approval  process,  or  significant opposition to the project, could
delay  construction  and  the  commencement  of  gas  sales.

In  connection with the sale to ARCO of one-half of the shares through which the
Company  owned  its  interest  in  Block  A-18,  ARCO  agreed  to pay the future
exploration  and  development  costs  attributable  to  the Company's and ARCO's
collective  interest in Block A-18, up to $377 million or until first production
from  a  gas  field, after which the Company and ARCO would each pay 50% of such
costs.  There can be no assurance that the Company's and ARCO's collective share
of  the  cost  of developing the project will not exceed $377 million. ARCO also
agreed  to  pay  the Company certain incentive payments if certain criteria were
met.  The first $65 million in incentive payments is conditioned upon having the
production  facilities for the sale of gas from Block A-18 completed by June 30,
2002.  If  the  facilities are completed after June 30, 2002 but before June 30,
2003,  the  incentive  payment  would  be  reduced  to  $40  million.  A lengthy
environmental  approval  process, or unanticipated delays in construction of the
facilities,  could result in the Company's receiving a reduced incentive payment
or  possibly  the complete loss of the first incentive payment. In addition, the
Company  has  agreed  to share with ARCO some of the risk that the environmental
approval might be delayed by agreeing to pay to ARCO $1.25 million per month for
each  month,  if  applicable,  that first gas sales are delayed beyond 30 months
following  the  commitment  to  an  engineering,  procurement  and  construction
contract  for  the  project.  The Company's obligation is capped at 24 months of
these  payments.

INFLUENCE  OF  HICKS  MUSE

In  connection  with  the  issuance  of  8% Convertible Preference Shares to HM4
Triton,  L.P.,  the  Company  and  HM4  Triton, L.P. entered into a shareholders
agreement  (the "Shareholders Agreement") pursuant to which, among other things,
the  size  of  the  Company's Board of Directors was set at ten, and HM4 Triton,
L.P.  exercised  its  right  to  designate  four  out of such ten directors. The
Shareholders  Agreement  provides  that,  in  general, for so long as the entire
Board of Directors consists of ten members, HM4 Triton, L.P. (and its designated
transferees, collectively) may designate four nominees for election to the Board
of  Directors. The right of HM4 Triton, L.P. (and its designated transferees) to
designate  nominees  for  election to the Board will be reduced if the number of
ordinary shares held by HM4 Triton, L.P. and its affiliates (assuming conversion
of  8%  Convertible Preference Shares into ordinary shares) represents less than
certain  specified  percentages  of  the  number  of  ordinary  shares (assuming
conversion  of  8% Convertible Preference Shares into ordinary shares) purchased
by  HM4  Triton,  L.P.  pursuant  to  the  Stock  Purchase  Agreement.

The  Shareholders  Agreement  provides that, for so long as HM4 Triton, L.P. and
its  affiliates  continue  to  hold  a certain minimum number of ordinary shares
(assuming  conversion of 8% Convertible Preference Shares into ordinary shares),
the  Company  may  not  take  certain actions without the consent of HM4 Triton,
L.P.,  including (i) amending its Articles of Association or the terms of the 8%
Convertible  Preference  Shares  with  respect  to  the voting powers, rights or
preferences  of  the  holders of 8% Convertible Preference Shares, (ii) entering
into  a  merger  or  similar  business  combination  transaction, or effecting a
reorganization,  recapitalization  or  other  transaction  pursuant  to  which a
majority  of  the  outstanding  ordinary shares or any 8% Convertible Preference
Shares  are exchanged for securities, cash or other property, (iii) authorizing,
creating  or  modifying  the  terms  of any series of securities that would rank
equal  to  or  senior  to  the 8% Convertible Preference Shares, (iv) selling or
otherwise disposing of assets comprising in excess of 50% of the market value of
the  Company,  (v)  paying  dividends on ordinary shares or other shares ranking
junior  to the 8% Convertible Preference Shares, other than regular dividends on
the  Company's  5% Convertible Preference Shares, (vi) incurring or guaranteeing
indebtedness  (other than certain permitted indebtedness), or issuing preference
shares,  unless the Company's leverage ratio at the time, after giving pro forma
effect  to  such  incurrence or issuance and to the use of the proceeds, is less
than  2.5  to  1,  (vii)  issuing additional shares of 8% Convertible Preference
Shares,  other  than  in  payment of accumulated dividends on the outstanding 8%
Convertible  Preference  Shares,  (viii)  issuing  any shares of a class ranking
equal  or  senior  to  the  8%  Convertible Preference Shares, (ix) commencing a
tender  offer or exchange offer for all or any portion of the ordinary shares or
(x)  decreasing  the  number  of  shares designated as 8% Convertible Preference
Shares.

As  a result of HM4 Triton, L.P.'s ownership of 8% Convertible Preference Shares
and  ordinary  shares  and  the  rights  conferred upon HM4 Triton, L.P. and its
designees  pursuant  to  the  Shareholder  Agreement,  HM4  Triton,  L.P.  has
significant  influence  over  the  actions  of  the  Company and will be able to
influence,  and  in  some  cases determine, the outcome of matters submitted for
approval  of  the  shareholders.  The  existence  of  HM4  Triton,  L.P.  as  a
shareholder  of  the  Company  may  make  it more difficult for a third party to
acquire,  or discourage a third party from seeking to acquire, a majority of the
outstanding  ordinary  shares.  A third party would be required to negotiate any
such  transaction with HM4 Triton, L.P. and the interests of HM4 Triton, L.P. as
a  shareholder  may be different from the interests of the other shareholders of
the  Company.

POSSIBLE  FUTURE  ACQUISITIONS

The Company's strategy includes the possible acquisition of additional reserves,
including  through  possible future business combination transactions. There can
be  no  assurance  as  to  the  terms  upon which any such acquisitions would be
consummated  or  as  to  the  affect  any  such  transactions  would have on the
Company's  financial  condition  or results of operations. Such acquisitions, if
any,  could  involve  the  use  of  the  Company's  cash, or the issuance of the
Company's  debt  or equity securities, which could have a dilutive effect on the
current  shareholders.

COMPETITION

The  Company  encounters  strong competition from major oil companies (including
government-owned  companies),  independent  operators  and  other  companies for
favorable  oil  and  gas concessions, licenses, production-sharing contracts and
leases,  drilling  rights and markets.  Additionally, the governments of certain
countries  in  which  the  Company  operates  may,  from  time  to  time,  give
preferential  treatment to their nationals.  The oil and gas industry as a whole
also  competes  with  other  industries  in  supplying  the  energy  and  fuel
requirements  of  industrial,  commercial and individual consumers.  The Company
believes  that the principal means of competition in the sale of oil and gas are
product  availability,  price  and  quality.

MARKETS

Crude oil, natural gas, condensate, and other oil and gas products generally are
sold  to  other oil and gas companies, government agencies and other industries.
The  availability  of  ready markets for oil and gas that might be discovered by
the  Company and the prices obtained for such oil and gas depend on many factors
beyond  the  Company's  control,  including  the  extent of local production and
imports  of  oil  and  gas,  the  proximity  and capacity of pipelines and other
transportation facilities, fluctuating demands for oil and gas, the marketing of
competitive  fuels,  and  the  effects of governmental regulation of oil and gas
production  and  sales.  Pipeline  facilities  do  not exist in certain areas of
exploration  and,  therefore, any actual sales of discovered oil or gas might be
delayed  for  extended  periods  until  such  facilities  are  constructed.

LITIGATION

The outcome of litigation and its impact on the Company are difficult to predict
due  to  many  uncertainties,  such as jury verdicts, the application of laws to
various  factual  situations,  the actions that may or may not be taken by other
parties  and the availability of insurance.  In addition, in certain situations,
such  as  environmental  claims,  one  defendant  may  be  responsible  for  the
liabilities  of  other  parties. Moreover, circumstances could arise under which
the  Company  may  elect  to  settle claims at amounts that exceed the Company's
expected  liability  for  such  claims in an attempt to avoid costly litigation.
Judgments  or  settlements  could,  therefore,  exceed  any  reserves.

20.  COMMITMENTS  AND  CONTINGENCIES

For  internal  planning purposes, the Company's capital spending program for the
year  ending  December  31,  2000,  is  approximately  $191  million,  excluding
capitalized  interest  and  acquisitions,  of  which  approximately $122 million
relates  to  exploration  and  development  activities in Equatorial Guinea, $58
million  relates  to the Cusiana and Cupiagua fields in Colombia and $11 million
relates  to  the  Company's  exploration activities in other parts of the world.

During  the  normal  course  of business, the Company is subject to the terms of
various  operating  agreements  and  capital  commitments  associated  with  the
exploration  and  development of its oil and gas properties.  It is management's
belief  that  such  commitments, including the capital requirements in Colombia,
Equatorial  Guinea  and  other  parts  of the world discussed above, will be met
without  any material adverse effect on the Company's operations or consolidated
financial  condition.

The  Company  leases  office space, other facilities and equipment under various
operating  leases expiring through 2005.  Total rental expense was $1.3 million,
$2.1  million  and  $2  million  for the years ended December 31, 1999, 1998 and
1997,  respectively.  At  December 31, 1999, the minimum payments required under
terms  of  the leases are as follows 2000 -- $1.5 million; 2001 -- $1.6 million;
2002 -- $1.6 million; 2003 -- $1.6 million; 2004 -- $1.6 million; and thereafter
$1  million.

GUARANTEES

At  December  31, 1999, the Company had guaranteed the performance of a total of
$16.4  million  in  future  exploration  expenditures  to  be  incurred  through
September 2001 in various countries.  A total of approximately $6 million of the
exploration  expentitures  are  included  in  the  2000 capital spending program
related  to  a  commitment  for  two onshore exploratory wells in Greece.  These
commitments  are  backed  primarily by unsecured letters of credit.  The Company
also  had guaranteed loans of approximately $1.4 million, which expire September
2000,  for  a  Colombian  pipeline  company,  ODC,  in  which the Company has an
ownership  interest.

ENVIRONMENTAL  MATTERS

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

LITIGATION

In  July through October 1998, eight lawsuits were filed against the Company and
Thomas  G.  Finck  and  Peter  Rugg,  in  their capacities as Chairman and Chief
Executive  Officer  and Chief Financial Officer, respectively. The lawsuits were
filed  in  the  United  States District Court for the Eastern District of Texas,
Texarkana  Division,  and  have  been  consolidated and are styled In re: Triton
Energy  Limited  Securities Litigation. In November 1999, the plaintiffs filed a
consolidated complaint. It alleges violations of Sections 10(b) and 20(a) of the
Securities  Exchange  Act  of  1934,  as  amended,  and  Rule  10b-5 promulgated
thereunder,  in connection with disclosures concerning the Company's properties,
operations, and value relating to a prospective sale of the Company or of all or
a  part  of  its  assets. The lawsuits seek recovery of an unspecified amount of
compensatory  damages,  fees  and  costs.  In  the  consolidated  complaint, the
plaintiffs  abandoned  a  claim  for  negligent  misrepresentation  and punitive
damages  that had previously been asserted in one of the eight individual suits.

     In September 1999, the court granted the plaintiffs' motion for appointment
as  lead  plaintiffs  and  for approval of selection of lead counsel. In October
1999,  the  defendants filed a motion to dismiss the claims alleged in the eight
individual  suits,  and  in  December 1999, the defendants filed a supplement to
their  motion  to dismiss to address the plaintiffs' consolidated complaint. The
Company's  motion,  as  supplemented,  is  currently  pending.

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

In  November  1999,  a  lawsuit  was  filed  against the Company, and one of its
subsidiaries  and  Thomas  G.  Finck,  Peter Rugg and Robert B. Holland, III, in
their  capacities as officers of the Company, in the District Court of the State
of  Texas  for  Dallas  County.  The lawsuit is styled Aaron Sherman, et al. vs.
Triton Energy Corporation et al. and seeks an unspecified amount of compensatory
and punitive damages and interest. The lawsuit alleges as causes of action fraud
and  negligent  misrepresentation  in connection with disclosures concerning the
prospective  sale  by  the  Company  of  all or a substantial part of its assets
announced  in  March  1998.  The  Company's date to answer has not yet run.  Its
subsidiary  has  filed  various motions to dispose of the lawsuit on the grounds
that the plantiffs do not have standing.  The Court has ordered the plantiffs to
replead  and  has  stayed  discovery  pending  its  further  orders.
In  August  1997,  the  Company  was  sued in the Superior Court of the State of
California  for  the  County  of  Los  Angeles,  by  David  A.  Hite,  Nordell
International  Resources  Ltd.,  and  International  Veronex Resources, Ltd. The
action  has  since  been  removed  to  the  United States District Court for the
Central  District of California. The Company and the plaintiffs were adversaries
in  a 1990 arbitration proceeding in which the interest of Nordell International
Resources  Ltd.  in  the  Enim oil field in Indonesia was awarded to the Company
(subject  to  a  5% net profits interest for Nordell) and Nordell was ordered to
pay  the  Company  nearly  $1  million.  The arbitration award was followed by a
series  of  legal  actions by the parties in which the validity of the award and
its  enforcement were at issue.  As a result of these proceedings, the award was
ultimately  upheld  and  enforced.  The current suit alleges that the plaintiffs
were  damaged  in  amounts  aggregating  $13  million  primarily  because of the
Company's  prosecution  of  various claims against the plaintiffs as well as its
alleged  misrepresentations,  infliction  of  emotional  distress,  and improper
accounting  practices.  The  suit  seeks specific performance of the arbitration
award,  damages  for  alleged fraud and misrepresentation in accounting for Enim
field operating results, an accounting for Nordell's 5% net profit interest, and
damages  for emotional distress and various other alleged torts.  The suit seeks
interest,  punitive damages and attorneys fees in addition to the alleged actual
damages. In August 1998, the district court dismissed all claims asserted by the
plaintiffs  other  than  claims for malicious prosecution and abuse of the legal
process,  which the court held could not be subject to a motion to dismiss.  The
abuse  of process claim was later withdrawn, and the damages sought were reduced
to  approximately  $700,000  (not  including  punitive damages). The lawsuit was
tried  and  the  jury found in favor of the plaintiffs and assessed compensatory
damages against the Company in the amount of approximately $700,000 and punitive
damages  in the amount of approximately $11 million. The Company believes it has
acted  appropriately  and  intends  to  appeal  the  verdict.

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

21.  GEOGRAPHIC  INFORMATION

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


<TABLE>
<CAPTION>
<S>       <C>        <C>         <C>          <C>        <C>

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

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

YEAR ENDED DECEMBER 31, 1997:
  Sales and other operating revenues         $ 145,419   $    ---   $   ---    $   4,077    $     ---  $  149,496
  Operating income (loss)                       59,719       (536)      (42)      (6,270)     (20,167)     32,704
  Depreciation, depletion and amortization      31,186         60       ---          505        5,077      36,828
  Capital expenditures and investments         129,589     37,328     4,471       43,371        4,457     219,216
  Assets                                       712,512    148,780     4,841      105,720      126,186   1,098,039

</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 Dispositions.  After
the  sale,  which  resulted  in  a  50% ownership in the previously wholly owned
subsidiary,  the Company's remaining ownership is accounted for using the equity
method.  This  investment in Block A-18 is presented in Malaysia-Thailand assets
at  December  31,  1999  and  1998.

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

At December 31, 1999, corporate assets were principally cash and equivalents and
the  U.S.  deferred tax asset. Exploration assets included  $41.6 million, $17.6
million,  $16.5  million and $8.4 million in Italy, Greece, Oman and Madagascar,
respectively.

22.  QUARTERLY FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>
<S>                                          <C>      <C>         <C>       <C>

                                                             QUARTER
                                             -------------------------------------------
                                               FIRST     SECOND     THIRD      FOURTH
                                             ---------  ----------  --------  ----------
YEAR ENDED DECEMBER 31, 1999:
  Sales and other operating revenues         $ 49,170   $  59,622   $ 67,295  $  71,791
  Gross profit                                 14,823      25,151     32,349     46,082
  Net earnings                                  1,887      10,883     11,762     23,025
  Basic earnings (loss) per ordinary share       0.05       (0.08)      0.32       0.24
  Diluted earnings (loss) per ordinary share     0.03       (0.08)      0.20       0.23
  Investment in affiliate                      86,704      88,179     91,008     93,188

YEAR ENDED DECEMBER 31, 1998:
  Sales and other operating revenues         $ 36,175   $  36,378   $105,862  $  50,203
  Gross profit (loss)                           8,409    (180,179)    73,751   (134,350)
  Net earnings (loss)                          42,912    (150,062)    47,208   (127,562)
  Basic earnings (loss) per ordinary share       1.17       (4.10)      1.28      (3.55)
  Diluted earnings (loss) per ordinary share     1.16       (4.10)      1.28      (3.55)
  Investment in affiliate                         ---         ---     82,511     84,735
</TABLE>



Gross  profit  (loss)  is  comprised  of sales and other operating revenues less
operating  expenses,  depreciation,  depletion  and amortization, and writedowns
pertaining  to  operating  assets.  Gross profit for the fourth quarter of 1999
included a non-recurring credit issued by OCENSA in February 2000 totaling $4.2
million.  The credit to pipeline tariffs resulted from OCENSA's compliance
with a Colombian government decree in December 1999 that reduced its 1999
noncash expenses.

23.  OIL  AND  GAS  DATA  (UNAUDITED)

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

RESULTS  OF  OPERATIONS

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


<TABLE>
<CAPTION>

<S>                                   <C>
                                      COLOMBIA
                                      --------


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

        Results of operations         $ 74,199
                                      ========
</TABLE>




<TABLE>
<CAPTION>

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

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




<TABLE>
<CAPTION>
<S>                                   <C>       <C>     <C>

                                                           TOTAL
                                      COLOMBIA   OTHER   WORLDWIDE
                                      --------  -------  ---------
YEAR  ENDED  DECEMBER  31,  1997:
        Revenues                      $145,419  $ 4,077  $ 149,496
        Costs:
          Production costs              51,357      ---     51,357
          General operating expenses     2,886      ---      2,886
          Depletion                     30,729      ---     30,729
          Income tax expense            22,167    1,223     23,390
                                      --------  -------  ---------

        Results of operations         $ 38,280  $ 2,854  $  41,134
</TABLE>                              ========  =======  =========



Malaysia-Thailand revenues for the year ended December 31, 1998, included a gain
of  $63.2  million  from  the  sale  of one-half of the shares of the subsidiary
through which the Company owned its 50% share of Block A-18.  Other revenues for
the  years ended December 31, 1998 and 1997, included gains of $4.5 million, and
$4.1  million from the sale of the Company's Bangladesh subsidiary and Argentine
subsidiary,  respectively.

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

<PAGE>
COSTS  INCURRED  AND  CAPITALIZED  COSTS


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

<TABLE>
<CAPTION>

<S>                                  <C>      <C>        <C>     <C>
                                              EQUATORIAL           TOTAL
                                     COLOMBIA   GUINEA    OTHER  WORLDWIDE
                                     --------  -------   ------  ---------
DECEMBER  31,  1999:
  Costs  incurred:
    Property acquisition             $  6,400  $   ---  $    20  $  6,420
    Exploration                           155   23,631   13,051    36,837
    Development                        80,782      ---      ---    80,782
  Depletion per equivalent
    barrel of production                 3.80      ---      ---      3.80

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

    Evaluated                        $530,947  $28,613  $   680  $560,240
                                     ========  =======  =======  ========

    Support equipment and
      facilities                     $303,244  $   709  $   ---  $303,953
                                     ========  =======  =======  ========
  Accumulated depletion and
    depreciation at year-end         $419,651  $   ---  $   680  $420,331
                                     ========  =======  =======  ========
</TABLE>




<TABLE>
<CAPTION>

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

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

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

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

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




<PAGE>


<TABLE>
<CAPTION>
<S>                                 <C>        <C>         <C>       <C>    <C>

                                                MALAYSIA-  EQUATORIAL        TOTAL
                                     COLOMBIA   THAILAND      GUINEA   OTHER  WORLDWIDE
                                     --------  ---------  ----------  ------  ---------
DECEMBER  31,  1997:
  Costs  incurred:
    Property acquisition             $    ---  $     ---  $    1,500  $ 1,628 $   3,128
    Exploration                         7,583     36,373       2,971   44,893    91,820
    Development                        62,251        187         ---      ---    62,438
  Depletion per equivalent
    barrel of production                 3.67        ---         ---      ---      3.67

  Cost of properties at year-end:
    Unevaluated                      $  2,172  $  30,327  $    4,841  $93,286  $130,626
                                     ========  =========  ==========  =======  ========

    Evaluated                        $396,774  $ 114,243  $      ---  $ 7,563  $518,580
                                     ========  =========  ==========  =======  ========

    Support equipment and
      facilities                     $250,193  $     ---  $      ---  $   ---  $250,193
                                     ========  =========  ==========  =======  ========
  Accumulated depletion and
    depreciation at year-end         $ 66,250  $     ---  $      ---  $ 7,563  $ 73,813
                                     ========  =========  ==========  =======  ========

</TABLE>

A  summary  of  costs  excluded  from  depletion  at  December 31, 1999,
by year incurred  follows:



<TABLE>
<CAPTION>
<S>                   <C>       <C>      <C>      <C>      <C>
                                          DECEMBER 31,
                                ----------------------------------------
                        TOTAL     1999     1998     1997  1996 AND PRIOR
                      --------  -------  -------  ------- --------------

Property acquisition  $  2,820  $    20  $   500  $ 1,700  $        600
Exploration             93,258   29,697   34,394   16,008        13,159
Capitalized interest    11,062    6,587    2,971    1,383           121
                      --------  -------  -------  -------  ------------

    Total worldwide   $107,140  $36,304  $37,865  $19,091  $     13,880
                      ========  =======  =======  =======  ============
</TABLE>



The  Company  excludes  from  its depletion computation property acquisition and
exploration  costs  of  unevaluated properties and major development projects in
progress.  The  excluded  costs  include  $34.4  million ($28.6 million and $5.8
million  classified  as  evaluated  and  unevaluated, respectively) which relate
primarily  to  the  Ceiba field in Equatorial Guinea that will become depletable
once  production  begins,  currently estimated for year end 2000.  Additionally,
excluded  costs include exploration costs of $34.6 million, $16.8 million, $11.8
million  and  $8.4  million in Italy, Greece, Oman and Madagascar, respectively,
where  there  are  no  proved  reserves  at December 31, 1999. At this time, the
Company  is  unable to predict either the timing of the inclusion of these costs
and  any  related  oil  and  gas  reserves in its depletion computation or their
potential  future  impact  on  depletion  rates.  Drilling  or other exploration
activities  are  being  conducted  in  each  of  these  cost  centers.

The  Company's share of costs incurred for Block A-18 were $8.2 million and $3.2
million  for  the  years  ended  December  31, 1999 and 1998, respectively.  Net
capitalized  costs were $90.2 million and $85.2 million at December 31, 1999 and
1998,  respectively.

<PAGE>

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

The  following  tables present the Company's estimates of its proved oil and gas
reserves.  The  estimates  for  the  proved reserves in the Cusiana and Cupiagua
fields in Colombia and the Ceiba field in Equatorial Guinea were prepared by the
Company's  independent  petroleum  engineers,  DeGolyer  and  MacNaughton  and
Netherland,  Sewell  & Associates, Inc., respectively.  The estimates for proved
reserves  in Malaysia-Thailand were prepared by the internal petroleum engineers
of  the  operating  company,  Carigali-Triton  Operating  Company  (CTOC).  The
estimates  for the proved reserves in the Liebre field in Colombia were prepared
by the Company's internal petroleum reservoir engineers.  The Company emphasizes
that  reserve estimates are approximate and are expected to change as additional
information becomes available.  Reservoir engineering is a subjective process of
estimating  underground  accumulations of oil and gas that cannot be measured in
an  exact  way,  and  the  accuracy of any reserve estimate is a function of the
quality  of  available data and of engineering and geological interpretation and
judgment.  Accordingly,  there  can  be no assurance that the reserves set forth
herein  will  ultimately  be  produced,  and  there can be no assurance that the
proved  undeveloped  reserves  will be developed within the periods anticipated.
As  of  December  31,  1999,  gas sales had not yet commenced from the Company's
interest  in  the  Malaysia-Thailand  Joint Development Area.  In estimating its
reserves attributable to such interest, the Company assumed that production from
the  interest  would  be  sold  at  the base price in the gas sales agreement of
$2.30.  The  base  price  is  subject  to  annual  adjustments  based on various
indices.  There can be no assurance as to what the actual price will be when gas
sales  commence.


<TABLE>
<CAPTION>
<S>                             <C>       <C>      <C>       <C>      <C>      <C>      <C>     <C>
                                                                                         EQUITY INVESTMENT
                                     COLOMBIA      EQUATORIAL GUINEA  TOTAL WORLDWIDE  MALAYSIA-THAILAND
                                -----------------  -----------------  ----------------  -----------------
                                   OIL      GAS      OIL       GAS     OIL       GAS       OIL     GAS
                                --------  -------  ------    -------  -------   ------  ------  ---------
PROVED  DEVELOPED  AND
  UNDEVELOPED RESERVES AS OF
  DECEMBER 31, 1998             135,327    12,284     ---       ---  135,327    12,284   8,017   570,312
    Revisions                      (567)     (259)    ---       ---     (567)     (259)  5,206   (16,450)
    Purchases                     3,280      ---      ---       ---    3,280       ---     ---       ---
    Extensions and discoveries      ---       ---  32,033       ---   32,033       ---     ---       ---
    Production                  (12,469)     (459)    ---       ---  (12,469)     (459)    ---       ---
                                --------  -------  ------  --------  --------  -------  ------  ---------

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

  PROVED DEVELOPED RESERVES AT
   DECEMBER 31, 1999             91,859    11,566     ---       ---   91,859    11,566     ---       ---
                                ========  =======  ======  ========  ========  =======  ======  =========
</TABLE>




<PAGE>



<TABLE>
<CAPTION>

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

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

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

PROVED DEVELOPED RESERVES AT
  DECEMBER 31, 1998              86,039    12,284      ---         ---    86,039       12,284    ---        ---
                                ========  =======  ========  ==========  ========  ==========  =====  =========
</TABLE>


<TABLE>
<CAPTION>

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

                                    COLOMBIA         MALAYSIA-THAILAND    TOTAL WORLDWIDE
                                -----------------  -------------------  --------------------
                                  OIL       GAS      OIL        GAS       OIL       GAS
                                --------  -------  -------  ----------  --------  ----------
PROVED  DEVELOPED  AND
  UNDEVELOPED  RESERVES  AS  OF
  DECEMBER 31, 1996             135,310   14,651   24,700     871,100   160,010     885,751
    Revisions                    14,157      770   (2,000)     (7,600)   12,157      (6,830)
    Extensions and discoveries    2,308      ---    7,100     360,300     9,408     360,300
    Production                   (5,776)    (802)     ---         ---    (5,776)       (802)
                                --------  -------  -------  ----------  --------  ----------

AS OF DECEMBER 31, 1997         145,999   14,619   29,800   1,223,800   175,799   1,238,419
                                ========  =======  =======  ==========  ========  ==========

PROVED DEVELOPED RESERVES AT
  DECEMBER 31, 1997              81,931   14,619      ---         ---    81,931      14,619
                                ========  =======  =======  ==========  ========  ==========
</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 discounted future net cash inflows discounted
at  an  annual  rate  of  10%.  The  future  net cash inflows were calculated in
accordance  with  Securities  and  Exchange  Commission guidelines.  Future cash
inflows were computed by applying year-end prices of oil and gas relating to the
Company's  proved  reserves  to  the  estimated  year-end  quantities  of  those
reserves.   The  future  cash  inflow  estimates  for  1999  attributable to oil
reserves were based on the year end WTI crude oil price of $25.60 per barrel for
the Company's reserves in Colombia and Malaysia-Thailand, and the year end Brent
crude  oil  price  of $24.89 per barrel for the Company's reserves in Equatorial
Guinea,  in  each  case  before  adjustments  for oil quality and transportation
costs.

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

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

In  connection with the sale to ARCO of one-half of the shares through which the
Company  owned  its  interest  in  Block A-18, ARCO agreed to pay the Company an
additional  $65  million  each  at  July  1,  2002, and July 1, 2005, if certain
specific  development  objectives  are met by such dates, or $40 million each if
the  objectives are met within one year thereafter.  For purposes of calculating
future  cash  inflows  for  Malaysia-Thailand  at December 31, 1999, the Company
assumed  that it would receive an incentive payment of $65 million in July 2002.
There can be no assurances that the Company will receive any incentive payments.
See  note  19,  "Certain  Factors  that Could Affect Future Operations - Certain
Factors  Related  to  Malaysia-Thailand."



<TABLE>
<CAPTION>

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

                                                                                EQUITY
                                                                              INVESTMENT
                                                       EQUATORIAL    TOTAL     MALAYSIA-
                                            COLOMBIA     GUINEA    WORLDWIDE    THAILAND
                                           ----------  ----------  ----------  ----------
DECEMBER  31,  1999:
      Future cash inflows                  $3,152,352  $  765,275  $3,917,627  $1,649,881
      Future production and
        development costs                     817,065     399,365   1,216,430     703,419
                                           ----------  ----------  ----------  ----------
      Future net cash inflows before
        income taxes                       $2,335,287  $  365,910  $2,701,197  $  946,462
                                           ==========  ==========  ==========  ==========

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




<PAGE>


<TABLE>
<CAPTION>

<S>                                        <C>         <C>

                                                       EQUITY
                                                      INVESTMENT
                                                       MALAYSIA-
                                           COLOMBIA    THAILAND
                                          ----------  ----------
DECEMBER  31,  1998:
      Future cash inflows                  $1,481,065  $1,555,929
      Future production and
        development costs                     734,025     695,575
                                           ----------  ----------
      Future net cash inflows before
        income taxes                       $  747,040  $  860,354
                                           ==========  ==========

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




<TABLE>
<CAPTION>

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

                                                        MALAYSIA-    TOTAL
                                            COLOMBIA    THAILAND   WORLDWIDE
                                           ----------  ----------  ----------
 DECEMBER  31,  1997:
      Future cash inflows                  $2,524,291  $4,078,609  $6,602,900
      Future production and
        development costs                   1,142,382   1,883,881   3,026,263
                                           ----------  ----------  ----------
      Future net cash inflows before
        income taxes                       $1,381,909  $2,194,728  $3,576,637
                                           ==========  ==========  ==========

      Future net cash inflows before
        income taxes discounted at 10%
        per annum                          $  852,421  $  427,463  $1,279,884
      Future income taxes discounted at
        10% per annum                         173,785      36,756     210,541
                                           ----------  ----------  ----------
      Standardized measure of discounted
        future net cash inflows            $  678,636  $  390,707  $1,069,343
                                           ==========  ==========  ==========


</TABLE>

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

<TABLE>
<CAPTION>

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




                                                             DECEMBER 31,
                                                 -------------------------------------
                                                    1999         1998         1997
                                                 -----------  -----------  -----------
Total worldwide:
  Beginning of year                              $  411,218   $1,069,343   $1,292,195
  Sales, net of production costs                   (179,748)     (87,335)     (94,062)
  Sales of reserves                                     ---      (70,543)         ---
  Equity investment                                     ---     (244,618)         ---
  Revisions of quantity estimates                    (6,546)     (29,321)      75,253
  Net change in prices and production costs       1,105,963     (579,212)    (552,863)
  Extensions, discoveries and improved recovery     206,260        6,516       42,918
  Change in future development costs                (61,728)     (46,633)      (5,936)
  Purchases of reserves                               6,400          ---          ---
  Development and facilities costs incurred          70,828      105,808       53,199
  Accretion of discount                              74,704      120,270      160,406
  Changes in production rates and other             (10,567)     (30,772)      (3,089)
  Net change in income taxes                       (387,887)     197,715      101,322
                                                 -----------  -----------  -----------

  End of year                                    $1,228,897   $  411,218   $1,069,343
                                                 ===========  ===========  ===========
</TABLE>





                                                                     SCHEDULE II

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


                                              ADDITIONS
                                              ---------
<TABLE>
<CAPTION>
<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, 1997:
   Allowance for doubtful
       receivables         $        76  $       ---   $       ---  $       (35)  $      41
                           ===========  ============  ===========  ============  =========

   Allowance for deferred
       tax asset           $    30,657  $    44,435   $       ---  $       ---   $  75,092
                           ===========  ============  ===========  ============  =========

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

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

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