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

                                 FORM 10-K
(Mark  One)
 (X)             ANNUAL  REPORT  PURSUANT  TO  SECTION  13  OR  15(D)
                       OF THE SECURITIES EXCHANGE ACT OF 1934
                     FOR THE FISCAL YEAR ENDED: December 31, 1998

                                     OR

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

                      Commission File Number:  1-11675

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


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



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

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


         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.     X
                                                -----
     THE AGGREGATE MARKET VALUE  OF  THE  OUTSTANDING  ORDINARY  SHARES  HELD
BY  NON-AFFILIATES  OF  THE REGISTRANT  AT  MARCH  17,  1999  (FOR  SUCH
PURPOSES  ONLY,  ALL DIRECTORS AND EXECUTIVE  OFFICERS  ARE  PRESUMED  TO  BE
AFFILIATES) WAS APPROXIMATELY $244.9 MILLION,  BASED ON THE CLOSING SALES PRICE
OF $7 ON THE NEW YORK STOCK EXCHANGE.

     AS  OF  MARCH  17,  1999,     36,662,819      ORDINARY  SHARES  OF  THE
                                   ----------
REGISTRANT  WERE  OUTSTANDING.

                       DOCUMENTS INCORPORATED BY REFERENCE
     PORTIONS  OF  THE  PROXY STATEMENT PERTAINING TO THE 1999 ANNUAL MEETING OF
SHAREHOLDERS  OF  TRITON ENERGY LIMITED  ARE INCORPORATED BY REFERENCE INTO PART
III  HEREOF.





<PAGE>





                              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                                                 18
        ITEM 4.          Submission of Matters to a Vote of Security Holders               20

PART    II
        ITEM 5.          Market for Registrant's Common Equity and Related
                         Stockholder Matters                                               21
        ITEM 6.          Selected Financial Data                                           25
        ITEM 7.          Management's Discussion and Analysis of Financial Condition and
                         Results of Operations                                             26
        ITEM 7.A.        Quantitative and Qualitative Disclosures about Market Risk        40
        ITEM 8.          Financial Statements and Supplementary Data                       42
        ITEM 9.          Changes in and Disagreements with Accountants on Accounting and
                         Financial Disclosure                                              42

PART    III
        ITEM 10.         Directors and Executive Officers of the Registrant                43
        ITEM 11.         Executive Compensation                                            43
        ITEM 12.         Security Ownership of Certain Beneficial Owners and Management    43
        ITEM 13.         Certain Relationships and Related Transactions                    43

PART    IV
        ITEM 14.         Exhibits, Financial Statement Schedules, and Reports on Form 8-K  44


</TABLE>

ITEMS  1.  AND  2.     BUSINESS  AND  PROPERTIES


GENERAL

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

     Triton  Energy  Limited  was  incorporated in the Cayman Islands in 1995 to
become  the  parent  holding company of Triton Energy Corporation, a corporation
formed  in  Texas  in 1962 and reincorporated in Delaware in 1995. The Company's
principal executive offices are located at Caledonian House, Mary Street, George
Town,  Grand Cayman, Cayman Islands, and its telephone number is (345) 949-0050.
The  terms  "Company"  and  "Triton" when used in this report mean Triton Energy
Limited  and its subsidiaries and other affiliates through which Triton conducts
its  business,  unless  the context otherwise implies. 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.

CERTAIN  DEVELOPMENTS  IN  1998

     Sale  of  Triton  Pipeline  Colombia,  Inc.
     -------------------------------------------

     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"). See "Item 7.
Management's  Discussion  and  Analysis  of  Financial  Condition and Results of
Operations"  and  note  5  of  Notes  to  Consolidated  Financial  Statements.

     Sale of Interest in Block A-18 of the Malaysia-Thailand Joint Development
     ---------------------------------------------------------------------------
Area
 ---

     In  July  1998, the Company 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  the Atlantic Richfield Company
("ARCO")  one-half  of  the  shares  of the subsidiary through which the Company
owned  its  50%  share  of  Block  A-18.  See  "  -  Oil  and  Gas  Properties -
Malaysia-Thailand"  below,  "Item  7.  Management's  Discussion  and Analysis of
Financial  Condition  and  Results  of  Operations"  and  note  5  of  Notes  to
Consolidated  Financial  Statements.

<PAGE>
     Restructure  of  Operations
     ---------------------------

     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.  See "Item 7. Management's Discussion and Analysis
of  Financial Condition and Results of Operations" and notes 3 and 4 of Notes to
Consolidated  Financial  Statements.

     Stock  Purchase  Agreement  with  an Affiliate of Hicks, Muse, Tate & Furst
     ---------------------------------------------------------------------------
Incorporated
------------

     In  August  1998,  the  Company  and  HM4  Triton,  L.P. ("HM4 Triton"), 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,  resulting  in  the  issuance of 1,822,500 shares of 8% convertible
preference  shares ("8% Preference Shares") in September 1998 (all of which were
issued  to  HM4  Triton)  and  an  additional  3,177,500 8% Preference Shares in
January  1999  (of  which  3,114,863  shares  were  issued to HM4 Triton and the
remainder  of  which  were  issued  to the public in a rights offering). Each 8%
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).  The  Company  and  HM4  Triton  also  entered into a Shareholders
Agreement  (the "Shareholders Agreement") pursuant to which, among other things,
HM4  Triton  (and  its  designated  transferees,  collectively)  may designate a
certain  number  of  nominees  for election to the Company's Board of Directors.
Pursuant  to  the  Shareholders  Agreement,  in  September 1998, the size of the
Company's  Board of Directors was set at ten, and HM4 Triton exercised its right
to  designate  four  out  of  such ten directors.  In addition, the Shareholders
Agreement  provides  that, for so long as HM4 Triton and its affiliates continue
to  hold  a certain minimum number of ordinary shares (assuming conversion of 8%
Preference  Shares  into  ordinary  shares),  the  Company  may not take certain
actions without the consent of HM4 Triton, including entering into any merger or
sale  of  substantial  assets  and  paying dividends on ordinary shares or other
shares  ranking junior to the 8% Preference Shares, other than regular dividends
on the Company's 5% convertible preference shares ("5% Preference Shares").  See
"Item  5.  Market  for  Registrant's  Common  Equity  and  Related  Stockholder
Matters,"  "Item  7. Management's Discussion and Analysis of Financial Condition
and  Results  of  Operations"  and notes 2,  13 and 20 of  Notes to Consolidated
Financial  Statements.


OIL  AND  GAS  PROPERTIES

     Colombia
     --------

     Through  the Company's wholly owned subsidiaries, Triton Colombia, Inc. and
Triton  Resources  Colombia, Inc. (collectively, "Triton Colombia"), the Company
has  varying  participation  interests  in  six  licenses  in  Colombia.

<PAGE>
     Cusiana  and  Cupiagua  Fields

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

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

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

          Recent  Drilling  Results.  In  the Cusiana Field, during 1998, Triton
          -------------------------
Colombia  and its working interest partners completed an additional seven wells,
bringing  the  total completions to date to 40 producing wells, 12 gas injection
wells  and  two  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 five drilling rigs
operating  in  the  Cusiana  Field,  and  the  Company  expects  that  eight oil
production  and  water  or  gas  injection  wells will be completed during 1999.

          In  the  Cupiagua  Field, during 1998, Triton Colombia and its working
interest  partners  completed  an  additional  six  wells,  bringing  the  total
completions  to  date  to 18 producing wells and five gas injection wells. There
are currently six drilling rigs operating in the Cupiagua Field, and the Company
expects  that  eleven  oil  production  and water or gas injection wells will be
completed  during  1999.

          In  January  1998,  the  sidetrack  of  the  suspended Cusiana-5 well,
referred  to  as  the  Cupiagua-EXP  well,  was  completed as a discovery of the
Cupiagua  South extension of the Cupiagua Field. The well penetrated the Mirador
and  Barco  formations  and  confirmed  the upthrown block of the Cupiagua lower
plate.  The  logs  and  other  data  taken  from  the  well  confirmed  that the
hydrocarbon  accumulation has a different oil/water contact than either the core
of  the  Cupiagua  Field or the lower plate discovered in the Cupiagua K-5 well,
drilled  in  late  1995.  The  reservoir discovered by the Cupiagua-EXP well was
designated  the  Cupiagua  South  Field,  which  was  granted  commerciality  by
Ecopetrol  and  placed  on  production  in  June  1998.

          Production Facilities and Pipelines.  The production facilities in the
          -----------------------------------
Cusiana  Field  have  been  completed.  The  components  of  the Cusiana Central
Processing  Facility  (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.

          In  1998,  the  two 100,000 BOPD production trains at the Cupiagua CPF
were  completed  and  put  in  operation,  which  process the condensate and gas
production  from  the Cupiagua producing wells. The gas handling capacity of the
Cupiagua  CPF is approximately 840 million cubic feet of gas per day and a third
compression unit is being installed, which is designed to bring the Cupiagua gas
handling  capacity  to  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  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.

     Other  Areas  in  Colombia

          Triton  owns  rights  to three additional licenses in Colombia. In the
Middle Magdalena Valley basin and adjacent foothills, Triton owns a 50% interest
(before certain royalties and government participation) in the El Pinal contract
area, which covers approximately 36,000 acres (after a partial relinquishment in
1998) 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.

          In  June 1995, the Company was awarded the Guayabo A and B association
contracts,  with  Deminex  Colombia  Petroleum  Gmbh acquiring a 50% interest in
1996. The area is located approximately 150 kilometers (93 miles) north of
Bogota.  The  Guayabo  A block covers approximately 167,000 acres. The Guayabo B
block was  reduced  in  size  to  approximately  148,000  acres  after  a
mandatory relinquishment at the end of the first exploration phase. The Company
expects to spud  an  exploratory  well in the Guayabo A block during 1999. In
the Guayabo B block,  the Company is currently conducting a surface geology
program to satisfy the  commitments  for  the  second  exploration  phase
ending  in  1999.

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

     Through  the  Company's  50%  owned  subsidiaries,  Triton  Oil  Company of
Thailand  (JDA)  Limited  and  Triton  Oil  Company  of Thailand  (collectively,
"Triton  Thailand"),  the  Company has a participating interest in Block A-18 of
the  Malaysia-Thailand Joint Development Area in the Gulf of Thailand. ARCO owns
the  remaining  shares  of  Triton  Thailand.  To  date,  eight fields have been
discovered  on the block. The operator is Carigali-Triton Operating Company Sdn.
Bhd.  ("CTOC"), a company owned equally by Triton Thailand and Petronas Carigali
(JDA)  Sdn.  Bhd.  ("Carigali"),  a  subsidiary  of  the  Malaysian national oil
company.

          Contract  Terms

          In  April  1994,  Triton Thailand signed a production-sharing contract
covering  the  offshore  area  designated as Block A-18 of the Malaysia-Thailand
Joint  Development  Area.  The  contract  area  in  the  Gulf of Thailand, which
encompasses  approximately  731,000  acres,  had been the subject of overlapping
claims  between  Malaysia  and  Thailand.  The  other  parties  to  the
production-sharing  contract  are  the  Malaysia-Thailand  Joint  Authority (the
"MTJA"),  which  has  been  established  by  treaty  to  administer  the  Joint
Development  Area,  and Carigali. The treaty provides for the development of the
Joint Development Area that includes Block A-18. Triton Thailand previously held
a  license  from  Thailand  that  covered  part  of  the Joint Development Area.

          The  term  of  the  contract  is  35  years,  subject  to  possible
relinquishment  of  certain areas and subject to the treaty between Malaysia and
Thailand  creating  the  MTJA  remaining in effect. Triton and Carigali have the
right  to  explore for oil and gas for the first five years of the contract. The
contract  provides  that  if there is a discovery of natural gas (not associated
with  crude  oil),  and if the MTJA agrees, the contractors will be able to hold
that  gas  field without production for an additional five-year period, provided
the contractors submit to the MTJA an acceptable development plan for the field.
The  contractors  then have a five-year period from the MTJA's acceptance of the
development  plan  to  develop the field, and have the right to produce gas from
the  field  for 20 years plus a number of years equal to the number of years, if
any,  prior  to  the end of the holding period that gas production commenced (or
until  the  termination of the contract, if earlier). The contract grants to the
operators  the right to produce oil from an oil field for 25 years (or until the
termination  of the contract, if earlier). Any areas not developed and producing
within  the  periods  provided  will  be relinquished. The MTJA has approved the
gas-holding area applications for the Bulan, Bumi, Cakerawala and Suriya Fields,
which, together represent approximately 91% of the proved reserves of Block A-18
as  of  December  31,  1998.

          As oil and gas are produced, the MTJA is entitled to a 10% royalty. Up
to  50%  of  each  unit of production is considered "cost oil" or "cost gas" and
will  be  allocated to the contractors to the extent of their recoverable costs,
with  the  balance  considered "profit oil" or "profit gas" to be divided 50% to
the  MTJA  and  50%  to the contractors (i.e., 25% to Carigali and 25% to Triton
Thailand).  Triton  Thailand's  share  of production is subject to an additional
royalty  equal  to 0.75% of Block A-18 production. Tax rates imposed by the MTJA
on behalf of the governments of Malaysia and Thailand are 0% for the first eight
years  of production, 10% for the next seven years of production and 20% for any
remaining  production.

          The  MTJA  has  agreed,  subject to government approval, to extend the
five-year  exploration  period  by three years (provided that the holding period
for  any  discovery  in the additional three-year period would not extend beyond
the  tenth  anniversary  of the contract) and to increase the percentage of each
unit  of  production that is considered "cost oil" or "cost gas" from 50% to 60%
for the Cakerawala Field and the Bulan Field, the fields planned for first-phase
development.  The  35-year  term  of  the  contract  is  not  affected.

          The  parties  to the contract executed a "heads of agreement" in April
1998 contemplating a definitive gas-sales agreement for the sale of natural gas
from the block.  Buyers of the gas would be the Petroleum Authority of Thailand
(PTT),  the  Thailand  national  oil  company,  and  Petroliam  Nasional  Berhad
(PETRONAS),  the  Malaysian  national  oil  company,  on  an  equal  basis.  The
representatives  of each of the parties have agreed to present an agreed form of
gas-sales  agreement to their respective Boards of Directors and the governments
of  Malaysia  and  Thailand  for  approval,  but there can be no assurance as to
whether, or when, a definitive gas-sales agreement will be approved or executed.

          Agreements  with  ARCO

          In  August 1998, the Company sold to ARCO for $150 million one-half of
the  shares  of  the  subsidiary  through which the Company owns its interest in
Triton  Thailand.  The  Company's  agreements  with ARCO require ARCO to pay the
future  exploration  and  development  costs  attributable  to Triton Thailand's
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 $101 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 5 of Notes
to  Consolidated  Financial  Statements.

          Recent  Drilling  Results

          During  1998,  two  wells  were  drilled  on  Block  A-18. The Senja-2
appraisal  well  was drilled approximately five kilometers (3 miles) east of the
Senja-1 discovery well drilled in 1997. The Senja-2 well encountered 118 feet of
net  pay,  14.5 feet of which were tested.  By comparison, the Senja-1 discovery
well  encountered 213 feet of net pay.  During a single test of a selected zone,
the  Senja-2  well flowed at a maximum daily rate of 2 million cubic feet of gas
and  59  barrels  of  condensate.  The  Bulan-3  appraisal  well  was  drilled
approximately  three  kilometers (1.9 miles) north of the Bulan-1 discovery well
drilled  in  1996.  The  Bulan-3  well encountered 143 feet of net pay which was
evaluated  with  wireline  tools  and  the well was abandoned without drill stem
testing.

<PAGE>
          Development  Plan

          In December 1997, the MTJA approved the field development plan for the
Cakerawala  Field.  Initial development plans call for three wellhead platforms,
a  production  platform,  a  living  quarters  platform,  a floating storage and
off-loading  vessel for oil and condensate and 35 development wells. The Company
expects  that  development  of  the field will commence following execution of a
definitive  gas-sales  agreement and that development will take approximately 30
to  36  months  to  complete.

     Ecuador
     -------

     The  Company  holds  a 55% interest in Block 19, which covers approximately
494,000  acres  located  in the Andean foothills of the Oriente Basin.  Triton's
partners  in the block are Vintage Petroleum Ecuador, Inc., with a 30% interest,
and  Ranger  Oil  Limited,  with  a  15% interest.  The partners' remaining work
program commitments for Block 19 consist of the drilling of one exploratory well
by  November  2000.

     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  519,000  acres located offshore between the western
coast  of  Greece  and  the  offshore  Ionian  islands  of Lefkas, Kefalonia and
Zakynthos  in  water  depths  of  up to 1,700 feet. The lease provides a primary
exploration  term  expiring  in  September  2001  with  a  commitment  of  2,000
kilometers  (1,250  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  plans  to  acquire  approximately  1,000  kilometers  (625 miles) of new 2D
seismic  in  1999.

     The  Aitoloakarnania  contract  area  covers  approximately  956,000  acres
located onshore in western Greece. The lease provides a primary exploration term
expiring in September 1999 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,  and  has  applied for a one-year extension of the
obligation  to  drill  the  exploratory  wells.

     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.  Applications  for  two  other onshore blocks were withdrawn in 1998.

     The  Company  has  a  40%  interest in each of the contiguous DR71 and DR72
licenses  covering  approximately  493,000  acres in the Adriatic Sea located 45
kilometers  (28 miles) offshore the city of Brindisi. Triton's partners in these
licenses  are Enterprise Oil Italiana, S.p.A. ("Enterprise"), the operator, with
a  45%  interest,  and Mobil Oil Italiana S.p.A. ("Mobil"), with a 15% 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.  In  March 1999, Mobil notified Enterprise and Triton of its intent to
withdraw  and  not  enter  the  second  exploration  period of the DR71 and DR72
licenses.  The  Company  expects that it will receive at least its proportionate
share of Mobil's interest in the blocks, and may acquire all of Mobil's interest
depending  on  Enterprise's  response  to  the  Mobil  notice.

     In  1998,  Triton  acquired  a  20%  interest  in a third offshore license,
FR33AG.  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 km (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 101,000 acres in the Matera province. The Company is the operator,
with  a 50% interest, and Union Texas Adriatic holds the remaining 50% interest.
The  licenses  provide  a  primary  exploration term expiring in August 2002 and
provide a combined work commitment of approximately 200 km (120 miles) of new 2D
seismic  and  the  drilling  of  three  exploratory  wells. The Company plans to
acquire approximately 50 kilometers (30 miles) of seismic data over the licenses
in  1999.

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

     The Company has signed production-sharing contracts covering two contiguous
blocks  (Blocks  F and G)  with the Republic of Equatorial Guinea. The contracts
give the Company the right to explore and develop an area covering approximately
1.3  million  acres  located offshore and southwest of the town of Bata in water
depths  of  up to 5,200 feet. They provide an exploration term expiring in April
2000  with  a  commitment  of  2,000 kilometers (1,250 miles) of seismic and the
drilling  of  one  exploratory well, which the Company intends to drill in 1999.
The  Company  has  acquired  approximately  5,600 kilometers (3,500 miles) of 2D
seismic  followed  by a further 660 kilometers of infill 2D seismic and two site
surveys.

     Madagascar
     ----------

     The  Company  has  signed  a production-sharing contract with the Office of
National  Mines  and  Strategic  Industries  in Madagascar covering the Ambilobe
Block.  The  block  (approximately  4.3  million  acres,  after  a  partial
relinquishment  in  1998)  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  new  2D  seismic.

<PAGE>
     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.  Triton  is currently
reprocessing  approximately  4,100  kilometers  (2,600  miles)  of  existing  2D
seismic.

     1998  Reduction  in  Exploration  Activities
     --------------------------------------------

     In  July  1998,  the  Company  announced  a plan to restructure operations,
reduce  overhead  costs and substantially scale back exploration-related capital
expenditures.  See  "Item  7.  Management's Discussion and Analysis of Financial
Condition and Results of Operations" and notes 3 and 4 of  Notes to Consolidated
Financial  Statements.  As a result of the scale back in exploration and in some
cases  for  technical reasons, during 1998 and early 1999, the Company effected,
or  commenced  the  steps  necessary  for,  the  following:

-  Colombia - relinquished its interest in the Las Amelias license.

-  China - ceased its exploration efforts and closed its local offices.

-  Guatemala  -  ceased its exploration efforts and closed its local office, and
   the Company is in the process of relinquishing its interest in its blocks.

-  Indonesia - sold its interest in the Blora production-sharing contract.

-  Madagascar - relinquished its interest in the Cap St. Marie Block.

-  Oman - relinquished its interest in Block 22.

-  Tunisia - withdrew from its interest in the Medjerda production sharing
   contract.

-  England - closed its regional office.


RESERVES


     The  following  table  sets  forth  a  summary of the estimated oil and gas
reserves of the Company at December 31, 1998, 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, and by the Company's internal petroleum
engineers with respect to the proved reserves in Malaysia-Thailand on Block A-18
in  the Gulf of Thailand and the Liebre Field in Colombia. This table sets forth
the  estimated  net  quantities  of proved developed and undeveloped oil and gas
reserves  and  total  proved  oil  and  gas  reserves owned by the Company.  For
additional  information  regarding  the  Company's  reserves,  including  the
standardized  measure  of  future  net  cash  flows,  see  note  25  of Notes to
Consolidated Financial Statements. Oil reserves data include natural gas liquids
and  condensate.


<PAGE>

        Net proved reserves at December 31, 1998, 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)            86,039   12,284   49,288       ---   135,327    12,284
Malaysia-Thailand (2)      ---      ---    8,017   570,312     8,017   570,312
                       -------  -------  -------  --------  --------  --------

Total                   86,039   12,284   57,305   570,312   143,344   582,596
                       =======  =======  =======  ========  ========  ========



</TABLE>

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

(1)  Includes liquids to be recovered from Ecopetrol as reimbursement for
precommerciality expenditures.
(2)  As  of  December  31,  1998, the Company did not have a contract for the
sale  of  gas  to  be  produced from its interest in the Malaysia-Thailand Joint
Development  Area. In estimating its reserves attributable to such interest, the
Company  assumed  that production from the interest would be sold at the initial
base  price  for natural gas specified in the heads of agreement entered into in
April  1998.  There can be no assurance that the price to be provided in any gas
contract  will  be  equal  to  the  price  used  in  the Company's calculations.


     Reserve  estimates  are  approximate  and  may  be  expected  to  change as
additional  information becomes available. Furthermore, estimates of oil and gas
reserves, of necessity, are projections based on engineering data, and there are
uncertainties  inherent  in  the  interpretation  of  such  data, as well as the
projection  of  future  rates  of  production  and  the  timing  of  development
expenditures.  Reservoir  engineering  is  a  subjective  process  of estimating
underground  accumulations  of  oil  and gas that cannot be measured in an exact
way,  and  the  accuracy of any reserve estimate is a function of the quality of
available  data  and  of engineering and geological interpretation and judgment.
Accordingly,  there  can be no assurance that the reserves set forth herein will
ultimately  be  produced,  and  there  can  be  no  assurance  that  the  proved
undeveloped  reserves  will  be  developed  within  the  periods  anticipated.

     No estimates of total proved net oil or gas reserves have been filed by the
Company  with,  or  included  in  any  report to, any United States authority or
agency  pertaining  to  the Company's individual reserves since the beginning of
the  Company's  last  fiscal  year.

OIL  AND  GAS  OPERATIONS

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

     The  following  table sets forth the net quantities of oil and gas produced
by  the  Company for the years ended December 31, 1998, 1997 and 1996. The table
includes  production  attributable  to the Company's 49.9% ownership interest in
Crusader  Limited  ("Crusader") through the date of its sale in 1996, as well as
the  minority  interests in Crusader's consolidated subsidiaries. The production
and  sales  information  relating  to  properties  or  subsidiary  or  affiliate
ownership interests acquired or disposed of is reflected in the table only since
or  up  to the effective dates of their respective acquisitions or sales, as the
case  may  be. Certain information concerning the Company's revenues, assets and
certain  other  data  by  geographical  area is contained in note 22 of Notes to
Consolidated  Financial  Statements.


<TABLE>
<CAPTION>
<S>                <C>    <C>    <C>        <C>   <C>   <C>
                     OIL PRODUCTION (1)        GAS PRODUCTION
                   ----------------------- -----------------------
                   YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
                   ----------------------- -----------------------
                    1998   1997  1996       1998   1997  1996
                   -----  -----  -----     -----  -----  -----
                         (MBBLS)                 (MMCF)

Colombia (2)       9,979  5,776  5,738       503    802    298
Indonesia (3)       ---    ---      95       ---    ---    ---
United States (4)   ---    ---      20       ---    ---    475
Crusader (5):
Australia           ---    ---     134       ---    ---  1,744
                   -----  -----  -----     -----  -----  -----
       Total       9,979  5,776  5,987       503    802  2,517
                   =====  =====  =====     =====  =====  =====
</TABLE>


____________________
(1)  Includes natural gas liquids and condensate.
(2)  Includes  Ecopetrol  reimbursement barrels and excludes 3.1 million, 2.5
million and .7 million barrels of oil produced and delivered for the years ended
December 31, 1998, 1997 and 1996, 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  6  of  Notes  to  Consolidated  Financial  Statements.
(3)  In May 1996, the Company sold substantially all of the assets of Triton
Indonesia, Inc.
(4)  In March 1996, Triton sold its domestic royalty and mineral interests.
(5)  In 1996, the Company sold all of its interest in Crusader.


     The  following tables summarize for the years ended December 31, 1998, 1997
and  1996:  (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,
                ------------------------  -----------------------

                 1998    1997    1996        1998   1997   1996
                ------  ------  ------       -----  -----  -----

Colombia (4)    $12.31  $17.54  $19.62       $0.99  $1.15  $2.56
Indonesia          ---     ---   19.54         ---    ---    ---
United States      ---     ---   16.00         ---    ---   1.15
Crusader:
   Australia       ---     ---   19.95         ---    ---   1.69
</TABLE>





<PAGE>


<TABLE>
<CAPTION>
<S>              <C>       <C>     <C>      <C>      <C>      <C>      <C>     <C>    <C>
                                         PER EQUIVALENT BARREL (2)
                 ----------------------------------------------------------------------------
                   AVERAGE SALES PRICE           DEPLETION (3)             PRODUCTION COST
                 -------------------------  ------------------------  -----------------------
                  YEAR ENDED DECEMBER 31,    YEAR ENDED DECEMBER 31,   YEAR ENDED DECEMBER 31,
                 -------------------------  ------------------------  -----------------------
                  1998      1997    1996       1998    1997   1996       1998   1997   1996
                 ------    ------  ------     -----   -----  -----      -----  -----  ------
Colombia (4)     $12.27    $17.37  $19.58     $4.07   $3.67  $2.83      $5.97  $6.47  $ 5.66
Indonesia           ---       ---   19.54       ---     ---   0.52        ---    ---   15.89
United States       ---       ---    8.75       ---     ---   5.59        ---    ---    3.25
Crusader:
Australia           ---       ---   13.23       ---     ---   3.47        ---    ---    4.10


</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 principal
means  of competition in the sale of oil and gas are product availability, price
and  quality.  While  it  is not possible for the Company to state precisely its
competitive  position  in the oil and gas industry, the Company believes that it
represents  a  minor  competitive  factor.

     Markets
     -------

     Crude oil, natural gas, condensate and other oil and gas products generally
are  sold  to  other  oil  and  gas  companies,  government  agencies  and other
industries. The Company does not believe that the loss of any single customer or
contract pursuant to which oil and gas 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 20 of Notes to
Consolidated  Financial  Statements.

<PAGE>
ACREAGE

     The following table shows the total gross and net developed and undeveloped
oil  and gas acreage held by Triton at December 31, 1998.  "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>     <C>


                        DEVELOPED  UNDEVELOPED
                        ACREAGE     ACREAGE (1)
                     ------------  -------------
                     GROSS   NET   GROSS    NET
                     -----  -----  ------  -----
                           (In thousands)
Colombia               109     13     350    175
Malaysia-Thailand      ---    ---     731    183
Ecuador                ---    ---     494    272
Greece                 ---    ---   1,475  1,298
Italy                  ---    ---     667    262
Oman(2)                ---    ---   1,322  1,322
Equatorial Guinea      ---    ---   1,306  1,306
Madagascar             ---    ---   4,300  4,300
                     -----  -----  ------  -----

Total                  109     13  10,645  9,118
                     =====  =====  ======  =====


</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)     Excludes  2.0  million  acres  (gross and net) attributable to Block 22,
which  was  relinquished  in  1999.


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,  1998,  in  Colombia,  Triton  held gross and net working
interests  in 80 and 9.86 productive wells, respectively, which include 17 gross
(2.04  net)  gas-injection  wells and two gross (.24 net) water-injection wells.

<PAGE>
     The following tables set forth the results of the oil and gas well drilling
activity  on  a  gross basis for wells in which the Company held an interest for
the  years  ended  December  31,  1998,  1997  and  1996.



                             GROSS 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,
                 ------------------------  -----------------------  -----------------------
                   1998  1997  1996           1998  1997  1996         1998  1997  1996
                   ----  ----  ----           ----  ----  ----         ----  ----  ----

Colombia              1     1     3            ---     1   ---            1     2     3
Malaysia-Thailand     2     5     7            ---   ---   ---            2     5     7
Argentina           ---   ---   ---            ---   ---     2          ---   ---     2
Italy               ---   ---   ---              2   ---     1            2   ---     1
Guatemala           ---   ---   ---            ---     1   ---          ---     1   ---
China               ---   ---   ---              1   ---     1            1   ---     1
Ecuador             ---   ---   ---            ---     1   ---          ---     1   ---
Tunisia             ---   ---   ---              1   ---   ---            1   ---   ---
Crusader (2):
   Australia        ---   ---    14            ---   ---     4          ---   ---    18
                   ----  ----  ----           ----  ----  ----         ----  ----  ----

            Total     3     6    24              4     3     8            7     9    32
                   ====  ====  ====           ====  ====  ====         ====  ====  ====


</TABLE>

                             GROSS 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,
                 ------------------------  -----------------------  -----------------------

                   1998  1997  1996           1998  1997  1996        1998  1997  1996
                   ----  ----  ----           ----  ----  ----        ----  ----  ----

Colombia             13    18    15            ---   ---   ---           13    18    15
Malaysia-Thailand   ---   ---   ---            ---   ---   ---          ---   ---   ---
Crusader (2):
   Australia        ---   ---     2            ---   ---   ---          ---   ---     2
                   ----  ----  ----           ----  ----  ----         ----  ----  ----

            Total    13    18    17            ---   ---   ---           13    18    17
                   ====  ====  ====           ====  ====  ====         ====  ====  ====

</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)     In  1996,  the  Company  sold  all  of  its  interest  in  Crusader.

<PAGE>
     The  following  tables  set forth the results of drilling activity on a net
basis  for  wells  in  which  the  Company  held an interest for the years ended
December  31,  1998,  1997  and  1996 (those wells acquired or disposed of since
January  1,  1996, 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,
                       ----------------------- -----------------------  -----------------------

                           1998  1997  1996        1998  1997  1996         1998  1997  1996
                           ----  ----  ----        ----  ----  ----         ----  ----  ----

Colombia (2)               0.12  0.12  0.36         ---  0.50   ---         0.12  0.62  0.36
Malaysia-Thailand (3)      1.00  2.50  3.50         ---   ---   ---         1.00  2.50  3.50
Argentina                   ---   ---   ---         ---   ---  2.00          ---   ---  2.00
Italy                       ---   ---   ---        0.80   ---  0.40         0.80   ---  0.40
Guatemala                   ---   ---   ---         ---  0.60   ---          ---  0.60   ---
China                       ---   ---   ---        0.50   ---  0.50         0.50   ---  0.50
Ecuador                     ---   ---   ---         ---  0.55   ---          ---  0.55   ---
Tunisia                     ---   ---   ---        0.50   ---   ---         0.50   ---   ---
Crusader (4):
   Australia                ---   ---  0.34         ---   ---  0.10          ---   ---  0.44
                           ----  ----  ----        ----  ----  ----         ----  ----  ----

            Total          1.12  2.62  4.20        1.80  1.65  3.00         2.92  4.27  7.20
                           ====  ====  ====        ====  ====  ====         ====  ====  ====

</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,
                       ------------------------ ----------------------- -----------------------

                           1998  1997  1996        1998  1997  1996         1998  1997  1996
                           ----  ----  ----        ----  ----  ----         ----  ----  ----

Colombia (2)               1.56  2.16  1.80         ---   ---   ---         1.56  2.16  1.80
Malaysia-Thailand           ---   ---   ---         ---   ---   ---          ---   ---   ---
Crusader (4):
  Australia                 ---   ---  0.05         ---   ---   ---          ---   ---  0.05
                           ----  ----  ----        ----  ----  ----         ----  ----  ----

            Total          1.56  2.16  1.85         ---   ---   ---         1.56  2.16  1.85
                           ====  ====  ====        ====  ====  ====         ====  ====  ====




</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.
(4)     Adjusted  to reflect the Company's 49.9% interest in Crusader, which was
sold  in  1996.


OTHER  PROPERTIES

     The  Company  leases  or  owns  office  space  and other properties for its
operations  in  various  parts  of the world.  For additional information on the
Company's  leases,  including  its  office  leases,  see  note  21  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 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. Forward-looking statements may be identified, without limitation, by
the  use  of  the  words  "anticipates,"  "estimates,"  "expects,"  "believes,"
"intends," "plans" and similar expressions. These statements include information
regarding  drilling  schedules;  expected  or  planned  production capacity; the
closing of branch offices; future production of the Fields; the negotiation of a
gas-sales  contract, completion of development and commencement of production in
Malaysia-Thailand; the Company's capital budget and future capital requirements;
the  Company's  meeting  its  future  capital  needs;  future  general  and
administrative  expense  and  the  portion  to  be  capitalized; future interest
expense  and  the  portion  to  be capitalized; the Company's realization of its
deferred  tax  asset;  the level of future expenditures for environmental costs;
the  outcome  of  regulatory  and  litigation  matters;  the impact of Year 2000
issues; 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 20 and 21 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  17,  1999,  the  Company  employed  approximately  145 full-time
employees.

EXECUTIVE  OFFICERS  OF  THE  COMPANY

   The following table sets forth certain information regarding the executive
officers of the Company at March 17, 1999:

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

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

James C. Musselman                  51  President and Chief Executive
                                        Officer                                   1998
Robert B. Holland, III              46  Executive Vice President, General
                                        Counsel and Secretary                     1993
A.E. Turner, III                    50  Chief Operating Officer                   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 fractioning 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 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.  Holland  has  served  as  General Counsel and Secretary of the Company
since January 1993, and has served as Executive Vice President since March 1999.
Mr.  Holland  also served as Chief Operating Officer of the Company from October
1998  to  March 1999 when he relinquished the title to Mr. Turner, interim Chief
Executive  Officer from July 1998 to October 1998 and Senior Vice President from
January  1993  to  July  1998.

     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. Each case was filed
on  behalf  of  a  putative  class  of persons and/or entities who purchased the
Company's  securities  between March 30, 1998, and July 17, 1998, inclusive, and
seeks  recovery  of  compensatory  damages,  fees  and  costs.  The cases allege
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. Additionally,
one  case  alleges  negligent  misrepresentation  and seeks recovery of punitive
damages.  Each  lawsuit  was  filed  in the United States District Court for the
Eastern  District  of  Texas,  Texarkana  Division.

     On  September  21,  1998, a motion for consolidation and for appointment as
lead  plaintiffs  and  for approval of selection of lead counsel was filed. With
the  exception  of  the request for consolidation, which has been agreed to, the
motion  is presently pending. Also pending is the Company's motion to dismiss or
transfer  for  improper  venue.  The consolidated action is styled In re: Triton
Energy  Limited  Securities  Litigation. The Company believes it has meritorious
defenses  to  these  claims  and  intends to vigorously defend these actions. No
discovery  has been taken at this time, however, and the ultimate outcome is not
currently  predictable.  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.

     During  the  quarter  ending  September  30,  1995,  the  United  States
Environmental  Protection  Agency (the "EPA") and Justice Department advised the
Company  that  one  of  its  domestic oil and gas subsidiaries, as a potentially
responsible  party  for the clean-up of the Monterey Park, California, Superfund
site  operated  by  Operating  Industries,  Inc.,  could  agree  to  contribute
approximately  $2.8 million to settle its alleged liability for certain remedial
tasks at the site.  The offer did not address responsibility for any groundwater
remediation.  The  subsidiary  was  advised  that  if  it  did  not  accept  the
settlement  offer,  it, together with other potentially responsible parties, may
be  ordered to perform or pay for various remedial tasks.  After considering the
cost  of  possible  remedial  tasks,  its legal position relative to potentially
responsible parties and insurers, possible legal defenses and other factors, the
subsidiary  declined  to  accept  the  offer.

     In  October  1997,  the  EPA advised the Company that the 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.

     On August 22, 1997, the Company was sued in the Superior Court of the State
of  California  for  the  County  of  Los  Angeles,  by  David  A. Hite, Nordell
International  Resources  Ltd.,  and  International Veronex Resources, Ltd.  The
Company  and the plaintiffs were adversaries in a 1990 arbitration proceeding in
which the interest of Nordell International Resources Ltd. in the Enim oil field
in  Indonesia  was  awarded to the Company (subject to a 5% net profits interest
for  Nordell) and Nordell was ordered to pay the Company nearly $1 million.  The
arbitration  award  was  followed by a series of legal actions by the parties in
which  the validity of the award and its enforcement were at issue.  As a result
of  these  proceedings,  the  award  was  ultimately  upheld  and  enforced.

     The  current  suit  alleges  that  the  plaintiffs  were damaged in amounts
aggregating  $13  million  primarily  because  of  the  Company's prosecution of
various claims against the plaintiffs as well as its alleged misrepresentations,
infliction  of  emotional distress, and improper accounting practices.  The suit
seeks  specific  performance of the arbitration award, damages for alleged fraud
and  misrepresentation  in  accounting  for  Enim  field  operating  results, an
accounting  for  Nordell's  5%  net  profit  interest, and damages for emotional
distress  and  various  other  alleged torts.  The suit seeks interest, punitive
damages  and  attorneys  fees  in  addition  to  the  alleged actual damages. On
September  26,  1997,  the  Company  removed  the  action  to  the United States
District  Court  for the Central District of California. On August 31, 1998, the
United  States  District  Court for the Central District of California 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.  A trial date has been set for April 27, 1999.
The  Company  has  filed  a writ with the 9th Circuit Court of Appeal requesting
that  the district court be directed to enter an order granting summary judgment
in the Company's favor. The Company believes the remaining claims under the suit
are  without  merit  and  intends  vigorously  to  defend  it.

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

CERTAIN  FACTORS

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


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

     No  matter  was  submitted  by the Company during the fourth quarter of the
year  ended  December 31, 1998, 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 closing sales
prices  of  Triton's  ordinary shares as reported on the New York Stock Exchange
Composite  Tape  for  the  periods  indicated:


<TABLE>
<CAPTION>

CALENDAR PERIODS                                              HIGH      LOW
----------------                                            --------  --------
<S>                                                         <C>       <C>
1999:
 First Quarter*                                                8 5/8     5 1/4
1998:
  First Quarter                                               36 3/4  25 13/16
  Second Quarter                                              42 5/8   33 5/16
  Third Quarter                                               36 3/4   9 15/16
  Fourth Quarter                                             12 7/16    7 5/16
1997:
  First Quarter                                               52 1/2    38 1/4
  Second Quarter                                            45 13/16    32 3/8
  Third Quarter                                                   48   38 3/16
  Fourth Quarter                                              44 7/8    27 5/8
________________________
*Through March 17, 1999.

</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  credit  facilities.  In addition, the Shareholders
Agreement  between  the  Company and HM4 Triton provides that for so long as HM4
Triton  and  its  affiliates  own  a certain number of ordinary shares (assuming
conversion  of  all 8% Preference Shares held by HM4 Triton and its affiliates),
Triton  cannot  pay  a  dividend  on  the  ordinary  shares without HM4 Triton's
consent.  Finally,  the  terms of the 8% Preference Shares and the 5% 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.

     At  March  17,  1999,  there  were  4,212  record  holders of the Company's
ordinary  shares.

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

     As  of March 17, 1999, the Company had outstanding 209,639 shares of its 5%
Preference  Shares  and  5,000,000  shares of its 8% Preference Shares.  Each 5%
Preference  Share  may  be  converted into one Triton ordinary share and bears a
cash  dividend,  which  has priority over dividends on Triton's ordinary shares,
equal  to  5%  per  annum  on  the redemption price of $34.41 per share, payable
semi-annually  on  March  30  and  September 30 of each year.  The 5% Preference
Shares  have  priority  over Triton ordinary shares upon liquidation, and may be
redeemed  at Triton's option at any time for cash equal to the redemption price.
Any  shares  of  5% Preference Shares that remain outstanding on March 30, 2004,
must  be  redeemed at the redemption price, either for cash or, at the Company's
option,  for  Triton  ordinary  shares.  See  note  13  of Notes to Consolidated
Financial  Statements.

     Each  8% Preference Share may be converted into four Triton ordinary shares
and  bears  an  annual  dividend  equal to 8% on the redemption price of $70 per
share,  payable  for  each  semi-annual  period  ending June 30 and December 30,
commencing June 30, 1999. At the Company's option, dividends may be paid in cash
or  by  the  issuance  of  additional whole shares of 8% 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.  Holders  of  8% 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% 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. The 8% Preference Shares can be redeemed by the Company
commencing  September  30,  2001,  but  only if the market value of the ordinary
shares  meets  certain  targets  at  the  time of redemption (but if the Company
redeems  any  shares, it must redeem all of the shares). Under the provisions of
the Company's Articles of Association, the terms of the 8% Preference Shares can
be  amended  with  the  approval of the holders of at least two-thirds of the 8%
Preference  Shares  voting  separately  as  a  class.

     Pursuant  to the Shareholders Agreement between the Company and HM4 Triton,
in  September 1998, the size of the Company's Board of Directors was set at ten,
and  HM4 Triton 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 (and its designated
transferees, collectively) may designate four nominees for election to the Board
(with such number of designees increasing or decreasing proportionately with any
change  in  the  total  number  of  members of the Board and with any fractional
directorship  rounded up to the next whole number). The right of HM4 Triton (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 and its
affiliates  (assuming  conversion  of 8% Preference Shares into ordinary shares)
represents  less  than  certain  specified percentages of the number of ordinary
shares  (assuming  conversion  of  8%  Preference  Shares  into ordinary shares)
purchased  by  HM4  Triton  pursuant  to  the  Stock  Purchase  Agreement.

     The  Shareholders  Agreement  also provides that, for so long as HM4 Triton
and  its affiliates continue to hold a certain minimum number of ordinary shares
(assuming  conversion of 8% Preference Shares into ordinary shares), the Company
may  not  take  certain actions without the consent of HM4 Triton, including (i)
amending  its  Articles  of Association or the terms of the 8% Preference Shares
with  respect  to  the voting powers, rights or preferences of the holders of 8%
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%  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% 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%  Preference  Shares,  other  than  regular  dividends on the
Company's  5%  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% Preference Shares, other than in
payment of accumulated dividends on the outstanding 8% Preference Shares, (viii)
issuing  any  shares  of  a  class  ranking equal or senior to the 8% 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%
Preference  Shares.  See  "Item  7.  Management's  Discussion  and  Analysis  of
Financial  Condition  and  Results  of  Operations  -  Liquidity  and  Capital
Requirements"  and  notes  2,  13  and  20  of  Notes  to Consolidated Financial
Statements.

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  or its affiliates,
including  Hicks Muse, will  not result in the distribution  of rights unless
and until HM4 Triton'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),  each  right not owned by such person generally becomes  the  right to
purchase  such number of ordinary shares of the Company equal  to  the number
obtained by dividing the right's exercise price (currently $120) by 50% of the
market price of the ordinary shares on the date of the first occurrence.  In
addition, if the Company is subsequently merged or certain other extraordinary
business  transactions  are  consummated,  each  right  generally becomes  a
right  to  purchase  such  number  of  shares of common stock of the acquiring
person  equal to the number obtained by dividing the right's exercise price  by
50% of the market price of the common stock on the date of the first occurrence.

     Under  certain  circumstances, the Company's directors may determine that a
tender  offer  or merger is fair to all shareholders and prevent the rights from
being exercised. At any time after a person or group acquires 15% or more of the
ordinary  shares  outstanding (other than with respect to  HM4 Triton) 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>




ITEM  6.     SELECTED  FINANCIAL  DATA

     The  following table sets forth certain financial and oil and gas data on a
historical  basis.  The  financial  information  for  1998  does not reflect the
issuance by the Company on January 4, 1999, of 3,177,500 8% Preference Shares
for proceeds totaling $218.1 million, net of closing costs. Pro forma total
assets and  shareholders'  equity, as adjusted to give effect to the issuance of
the 8% Preference  Shares,  totaled  $974.2  million and $441.9 million at
December 31, 1998,  respectively.  See  "Item  7.  Management's  Discussion  and
Analysis of Financial  Condition  and Results of Operations" and notes 2, 13 and
20 of Notes to  Consolidated  Financial  Statements.


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


                                                               AS OF OR FOR YEAR ENDED
                                                                      DECEMBER 31,
                                                    -----------------------------------------------
                                                       1998        1997        1996        1995
                                                    ----------  -----------  ---------- ----------


OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA):
Sales and other operating revenues (1)              $ 228,618   $  149,496   $ 133,977  $ 107,472
Earnings (loss) from continuing operations (1) (2)   (187,504)       5,595      23,805      6,541
Earnings (loss) before extraordinary items           (187,504)       5,595      23,805      2,720
Net earnings (loss) (2)                              (187,504)      (8,896)     22,609      2,720
Average ordinary shares outstanding                    36,609       36,471      35,929     35,147
Basic earnings (loss) per ordinary share:
   Continuing operations (1) (2)                    $   (5.21)  $     0.14   $    0.64  $    0.16
   Before extraordinary item                            (5.21)        0.14        0.64       0.05
   Net earnings (loss)                                  (5.21)       (0.26)       0.61       0.05
Diluted earnings (loss) per ordinary share:
   Continuing operations (1) (2)                    $   (5.21)  $     0.14   $    0.62  $    0.16
   Before extraordinary item                            (5.21)        0.14        0.62       0.05
   Net earnings (loss)                                  (5.21)       (0.25)       0.59       0.05

BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment                          $ 556,122   $  835,506   $ 676,833  $ 524,381
Total assets                                          756,133    1,098,039     914,524    824,167
Long-term debt, including current maturities (3)      427,492      573,687     416,630    402,503
Shareholders' equity                                  223,807      296,620     300,644    246,025

CERTAIN OIL AND GAS DATA  (4) :
Production
   Sales volumes (Mbbls) (5)                            9,979        5,776       5,987      6,303
   Forward oil sale deliveries (Mbbls)                  3,050        2,462         701        409
                                                    ----------  -----------  ---------- ----------

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

   Gas (MMcf)                                             503          802       2,517      5,312
Average sales price
   Oil (per bbl) (6)                                $   12.31   $    17.54   $   19.61  $   16.60
   Gas (per Mcf)                                    $    0.99   $     1.15   $    1.69  $    1.64


</TABLE>



<TABLE>
<CAPTION>
<S>                                                    <C>           <C>          <C>
                                                       AS OF OR       AS OF OR
                                                       FOR YEAR      FOR SEVEN  AS OF OR FOR
                                                        ENDED      MONTHS ENDED  YEAR ENDED
                                                       DECEMBER 31, DECEMBER 31,   MAY 31,
                                                       ---------
                                                        1994            1994        1994
                                                       ---------      ---------  ---------
                                                      (unaudited)

OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA):
Sales and other operating revenues (1)                $ 32,952        $ 20,736   $ 43,208
Earnings (loss) from continuing operations (1) (2)     (49,610)        (26,630)    (4,597)
Earnings (loss) before extraordinary items             (52,701)        (27,708)    (9,341)
Net earnings (loss) (2)                                (52,701)        (27,708)    (9,341)
Average ordinary shares outstanding                     34,916          34,944     34,775
Basic earnings (loss) per ordinary share:
   Continuing operations (1) (2)                      $  (1.43)       $  (0.78)  $  (0.13)
   Before extraordinary item                             (1.52)          (0.81)     (0.27)
   Net earnings (loss)                                   (1.52)          (0.81)     (0.27)
Diluted earnings (loss) per ordinary share:
   Continuing operations (1) (2)                      $  (1.43)       $  (0.78)  $  (0.13)
   Before extraordinary item                             (1.52)          (0.81)     (0.27)
   Net earnings (loss)                                   (1.52)          (0.81)     (0.27)

BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment                            $399,658        $399,658   $308,498
Total assets                                           619,201         619,201    616,101
Long-term debt, including current maturities (3)       315,515         315,515    294,753
Shareholders' equity                                   237,195         237,195    263,422

CERTAIN OIL AND GAS DATA  (4) :
Production
   Sales volumes (Mbbls) (5)                             2,534           1,488      2,886
   Forward oil sale deliveries (Mbbls)                     ---             ---        ---
                                                      ---------      ---------  ---------

        Total revenue barrels (Mbbls)                    2,534           1,488      2,886
                                                      =========      =========  =========

   Gas (MMcf)                                            5,516           3,427      9,078
Average sales price
   Oil (per bbl) (6)                                  $  15.26        $  16.41   $  15.15
   Gas (per Mcf)                                      $   1.51        $   1.44   $   1.44


</TABLE>

_________________

(1)  Operating  data  for  the  year ended December 31, 1994 (unaudited), the
seven  months  ended  December  31,  1994,  and the year ended May 31, 1994, are
restated  to  reflect  the  aviation  sales and services segment as discontinued
operations  in  1995.
(2)  Gives  effect to the writedown of assets and loss provisions on a pretax
basis  of  $328.6  million,  $46.2  million,  $1.1  million, $14.7 million, $1.0
million  and $45.8 million for the years ended December 31, 1998, 1996, 1995 and
1994  (unaudited),  the seven months ended December 31, 1994, and the year ended
May  31,  1994,  respectively.
(3)  Includes  current  maturities  totaling  $14.0  million, $130.4 million,
$199.6  million, $1.3 million, $.3 million and $.3 million at December 31, 1998,
1997,  1996,  1995  and  1994,  and  May  31,  1994,  respectively.
(4)  Information presented includes the 49.9% equity investment in Crusader
Limited until its sale in 1996.
(5)  Includes natural gas liquids and condensate.
(6)  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



                              CERTAIN DEVELOPMENTS
                              --------------------

          During 1998 and early 1999, several events had a significant impact on
the  Company and its financial condition and results of operations. These events
are  discussed  in  detail  in  this  Management's  Discussion  and  Analysis of
Financial  Condition and Results of Operations and elsewhere in this report, and
are  summarized  below:

-     February  1998  sale  of  TPC,  a  wholly  owned  subsidiary that held the
Company's  9.6%  equity  interest in the Colombian pipeline company, OCENSA, for
net  proceeds  of  $97.7  million.

-     Significantly  lower prices for crude oil, resulting in writedowns in June
1998  and  December  1998,  of  the  carrying  amount  of  evaluated oil and gas
properties  in  Colombia  through  the application of the full cost ceiling test
limitation,  totaling  approximately  $241  million.

-     July  1998 agreements with ARCO providing financing for the development of
the  Company's  gas  reserves  on  Block  A-18  of  the  Malaysia-Thailand Joint
Development  Area  through (1) the sale to ARCO of one-half of the shares of the
subsidiary  through  which the Company owned its 50% share of Block A-18 for net
proceeds  of  $142  million,  which  was consummated in August 1998, and (2) the
agreement  of  ARCO  to  pay  the  future  exploration  and  development  costs
attributable  to  Triton's  and  ARCO's collective interest in Block A-18, up to
$377  million  or  until  first  production  from  a  gas  field.

-     July  1998  announcement  of  a  plan  to  restructure  operations, reduce
overhead  costs  and  substantially  scale  back  exploration-related  capital
expenditures,  including  the  closing of foreign offices in four countries, the
elimination  of  approximately  41%  of  the workforce and the relinquishment or
disposal  of  several  exploration  licenses,  resulting in writedowns of assets
totaling  approximately  $77  million and special charges totaling approximately
$18  million.

-     August  1998  Stock  Purchase  Agreement  with HM4 Triton, an affiliate of
Hicks  Muse,  which  provided  for  the  issuance by the Company of 5,000,000 8%
Preference Shares for aggregate gross proceeds of $350 million, completed in two
stages  in  September  1998  and  January  1999.


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

HICKS  MUSE  TRANSACTION

          In  August  1998,  the  Company  and HM4 Triton entered into 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
1,822,500  shares  of  8%  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% Preference Shares at $70 per share, with HM4 Triton 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% Preference Shares for proceeds totaling $218.1 million,
net  of  closing  costs  (of  which,  HM4  Triton  purchased  3,114,863 shares).

CASH  AND  CASH  EQUIVALENTS;  CASH  FLOWS

     Proceeds from the First Closing, completed in September 1998, are reflected
in  the  audited  financial  statements  for  the  year ended December 31, 1998.
Proceeds  from  the  Second Closing, completed on January 4, 1999, are reflected
only  in  the unaudited pro forma financial information as of December 31, 1998,
presented  below  and in the Pro Forma Consolidated Balance Sheet as of December
31,  1998,  shown  on  page  F-4.

     Pro  forma  cash and cash equivalents and pro forma working capital, as
adjusted to  give  effect  to  the  issuance  of the 8% Preference Shares,
totaled $237.2 million  and  $196.6  million at December 31, 1998, respectively.
Cash and cash equivalents,  on  an  actual  basis,  totaled $19.1 million and
$13.5 million at December  31, 1998 and 1997, respectively, and working capital
deficit was $21.4 million and $115.2 million at December 31, 1998 and 1997,
respectively.  Current liabilities included deferred income totaling $35.3
million at December 31, 1998 and  1997,  related  to  a  forward  oil  sale
consummated  in  1995.

     The following summary table reflects cash flows of the Company for the
years  ended December 31, 1998, 1997 and 1996, and on a Pro Forma basis for 1998
(in  thousands):


<TABLE>
<CAPTION>


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

                                                  PRO FORMA
                                                     1998     1998        1997        1996
                                                  --------- --------   ---------   ---------

Net cash provided (used) by operating activities  $  1,670  $  1,670   $ (97,416)  $  80,705
Net cash provided (used) by investing activities  $ 84,352  $ 84,352   $(212,700)  $(105,518)
Net cash provided (used) by financing activities  $137,993  $(80,071)  $ 313,368   $ (12,978)


</TABLE>


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


       Cash  flows  provided  by operating activities for the year ended
December  31,  1998,  benefited  from  increased  production  from the Fields in
Colombia.  Gross  production from the Fields averaged approximately 350,000 BOPD
during  1998  compared  with 220,000 BOPD and 175,000 BOPD during 1997 and 1996,
respectively.  The  increased production was partially offset by a significantly
lower  average  realized  oil  price.  During 1998, 1997 and 1996, the Company's
average  realized  oil  price  was $12.31, $17.54 and $19.61, respectively.  See
"Results  of  Operations  -  Oil  and  Gas  Sales"  below.

       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.

<PAGE>
Investing  Activities
---------------------

          The  Company's capital expenditures and other capital investments were
$180.1  million,  $219.2  million  and  $252.7  million  during  the years ended
December  31,  1998,  1997 and 1996, respectively, primarily for exploration and
development  of the Fields in Colombia, and for exploration in Block A-18 of the
Malaysia-Thailand  Joint  Development  Area in the Gulf of Thailand and in other
areas.  Proceeds  from  asset  sales  were $267 million, $5.9 million and $146.6
million  during  1998, 1997 and 1996, respectively.  See "Results of Operations"
below  and  note  5  of  Notes  to  Consolidated  Financial  Statements.

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

     1998
     ----

          On  September  30, 1998, the Company issued to HM4 Triton 1,822,500 8%
Preference Shares for $70 per share, or total proceeds of $127.6 million (before
transaction  costs of $10.8 million). Each 8% 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% 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, commencing June 30, 1999.  At the Company's option, dividends
may  be  paid  in  cash  or  by  the  issuance  of additional whole shares of 8%
Preference  Shares.

          During  1998,  the  Company  borrowed $162.5 million and repaid $360.1
million  under  revolving lines of credit, notes payable and long-term debt.  At
December 31, 1998, the Company had two $25 million credit facilities that expire
in  March  1999  and  a  $50  million  credit facility that expires in May 1999.

1997
----

     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).

<PAGE>
1996
----

     During the year ended December 31, 1996, the Company borrowed $53.9 million
and  repaid  $70.9  million  under revolving lines of credit and long-term debt.

FUTURE  CAPITAL  NEEDS

          For internal planning purposes, the Company's capital spending program
for  the year ending December 31, 1999, is approximately $117 million, excluding
capitalized  interest,  of which approximately $83 million relates to the Fields
and  $34  million relates to the Company's exploration activities in other parts
of the world. The Company expects to fund its capital expenditures for 1999 with
the  proceeds  from  the issuance of the 8% Preference Shares and cash flow from
operations.  In  connection  with  the  sale  to  ARCO of one-half of the shares
through  which  the  Company  owned  its  interest  in  Block  A-18  of  the
Malaysia-Thailand  Joint Development Area in August 1998, 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.

          In  connection  with  the  issuance of the 8% Preference Shares to HM4
Triton  in  September  1998,  the  Company  and  HM4  Triton  entered  into  the
Shareholders  Agreement  pursuant  to which, among other things, HM4 Triton (and
its  designated  transferees,  collectively)  may  designate a certain number of
nominees  for  election  to  the Board.  In addition, the Shareholders Agreement
provides  that,  for so long as HM4 Triton and its affiliates continue to hold a
certain  minimum number of ordinary shares (assuming conversion of 8% Preference
Shares  into  ordinary shares), the Company may not take certain actions without
the consent of HM4 Triton, including (i) amending its Articles of Association or
the  terms of the 8% Preference Shares with respect to the voting powers, rights
or  preferences  of  the  holders  of 8% 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% 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%  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%
Preference  Shares,  other than regular dividends on the Company's 5% 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% Preference Shares, other than in payment of accumulated
dividends  on the outstanding 8% Preference Shares, (viii) issuing any shares of
a  class  ranking equal or senior to the 8% 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%  Preference Shares.

          As  a  result  of  HM4  Triton's ownership of 8% Preference Shares and
ordinary  shares  and  the  rights  conferred  upon HM4 Triton and its designees
pursuant  to  the  Shareholders  Agreement, HM4 Triton 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 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, and the interests
of  HM4 Triton as a shareholder may be different from the interests of the other
shareholders  of  the  Company.

          In  conjunction  with the sale of 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 of the 8% 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. 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. See "-
Results  of  Operations  -  Other  Income  and  Expenses"  below  and  "Item 7A.
Quantitative  and  Qualitative  Disclosures  about  Market  Risk."


                              RESULTS OF 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.

<PAGE>
     Gain  on  Sale  of  Oil  and  Gas  Assets
     -----------------------------------------

          In  July  1998,  the  Company  and  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.

          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.
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.  The  agreements  provide  that  the Company will
recover  its  investment in recoverable costs in the project, approximately $101
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  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.

     Costs  and  Expenses
     --------------------

          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  pays  lifting  costs,  production taxes and transportation costs to the
Colombian  port  of  Covenas  for barrels to be delivered under the forward oil
sale.

          The Company's operating costs per oil equivalent-barrel, which include
field  operating expenses, pipeline tariffs and production taxes, 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 are assessed on production from the Cusiana Field.  The Company
is  required  to  pay  production  taxes  on  production from the Cupiagua Field
equating  to approximately 5.5%, 4% and 2.5% of gross realized oil prices during
1998,  1999  and 2000, respectively.  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.  OCENSA  imposes  a tariff on shippers from the Fields (the
"Initial Shippers"), which is estimated to recoup: the total capital cost of the
project  over  a  15-year  period;  its  operating  expenses,  which include all
Colombian  taxes; interest expense; and the dividend to be paid by OCENSA to its
shareholders.  Any  shippers  of  crude  oil  who  are  not Initial Shippers are
assessed  a  premium  tariff on a per-barrel basis, and OCENSA will use revenues
from  such  tariffs to reduce the Initial Shippers' tariff.  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  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.  The Company
is  continuing its efforts to reduce its general and administrative expenses and
exploration  expenses.  As  a result, the Company expects that gross general and
administrative  expense  and  the  portion of general and administrative expense
that  will  be  capitalized  will  decrease  in  1999.

     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.  An  additional writedown may be required if oil prices fall below
the  December  31,  1998,  level  at  later  quarter  end  dates.

     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 writedown of assets.

     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,  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 writedown of assets.  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.

          As  a  result  of  the  restructuring,  the Company recognized special
charges  totaling  $18.3  million ($15 million and $3.3 million in the third and
fourth  quarters,  respectively).  At  December  31,  1998,  approximately  105
positions  had  been  eliminated,  three  foreign  offices  had closed and eight
licenses  had  been  relinquished,  sold or their commitments renegotiated.  The
Company  expects to close the remaining office and dispose of six other licenses
during  1999.

          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.  During 1998, the Company
paid  $7.4 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. As of December 31, 1998, no changes had been made to
the  Company's  estimate of the total restructuring expenditures to be incurred.
The  remaining liability related to restructuring activities was $7.9 million at
December  31,  1998.

     Other  Income  and  Expenses
     ----------------------------

          In February 1998, the Company sold TPC, a wholly owned subsidiary that
held  the  Company's  9.6%  equity  interest  in the Colombian pipeline company,
OCENSA,  to  an  unrelated  third party (the "Purchaser") for $100 million.  Net
proceeds  were  approximately $97.7 million after $2.3 million of expenses.  The
sale  resulted  in a gain of $50.2 million. TPC's investment in OCENSA, totaling
$47.4  million  at  December  31,  1997,  was  included in assets held for sale.

          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.  The Company
expects  the  portion of interest expense that will be capitalized will be lower
in  1999  due  to the Company's reduced exploration activities and the effect of
the  ARCO  transaction.

          Other income, 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 in addition to the ARCO and TPC transactions.  During 1998 and
1997,  the  Company  recorded an unrealized 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, 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
in  such  periods.  See "Item 7A. Quantitative and Qualitative Disclosures About
Market  Risk."


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

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

          The  income  tax  provision  for  1998 included a foreign deferred tax
benefit  totaling  $57 million compared with 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.

          At  December  31,  1998,  the  Company  had U.S. NOLs of approximately
$415.6  million  compared with NOLs of approximately $406.8 million, and certain
separate  return limitation years ("SRLY") operating loss carryforwards of $40.6
million,  at December 31, 1997.  The NOLs expire from 1999 to 2012.  See note 11
of  Notes  to  Consolidated  Financial  Statements.  At  December  31, 1998, the
Company's  Colombian  operations and other foreign operations had NOLs and other
credit  carryforwards  totaling  $42.3  million and $31.7 million, respectively,
that  will  expire  between  1999  and  2008.

          The  Company recorded a deferred tax asset of $100.9 million, net of a
valuation  allowance  of  $93.6  million,  at  December 31, 1998.  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 deferred tax asset is approximately $246 million and
$42  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 increasing income from its
operations.

     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 1/4% 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.

<PAGE>
     Subsequent  Event
     -----------------

     On  January  4, 1999, the Company issued 3,177,500 8% Preference Shares for
$70  per  share, or total proceeds of $222.4 million (before closing expenses of
$4.3  million).  See  "-  Liquidity  and  Capital  Requirements  -  Hicks  Muse
Transaction"  above.


                          YEAR ENDED DECEMBER 31, 1997,
                   COMPARED WITH YEAR ENDED DECEMBER 31, 1996

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

          Oil  and  gas sales were $145.4 million and $129.8 million in 1997 and
1996, respectively.  Revenues in Colombia increased $18.3 million in 1997 due to
higher  production  ($35  million).  Total  revenue  barrels,  including barrels
delivered under the forward oil sale, increased from 6.4 million barrels in 1996
to 8.2 million barrels in 1997.  Volume increases were partially offset by lower
average  realized oil prices ($16.7 million) reflecting the increased deliveries
under  the  forward  oil  sale and a decrease in the 1997 average WTI oil price,
compared  with  the  prior year.  Forward oil sale deliveries, scheduled in 1995
and  recorded  at  $11.56 per barrel, were 29% of total revenue barrels in 1997,
compared  with  10%  of  the  Company's total revenue barrels in 1996.  In April
1997,  the  Company's  delivery requirement under the forward oil sale increased
from 58,425 barrels per month to 254,136 barrels per month, which had an adverse
effect  on  the  Company's  earnings and cash flows on a per-barrel basis during
1997.  Oil  and  gas  sales  from  properties sold in early 1996 aggregated $2.7
million.

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

          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 March 1996,
the Company sold its royalty interest in U.S. properties for $23.8 million based
on  an effective date of January 1, 1996, and recognized a gain of $4.1 million.

     Costs  and  Expenses
     --------------------

          Operating  expenses increased $14.7 million in 1997, and depreciation,
depletion  and  amortization  increased  $11.2  million, primarily due to higher
production  volumes,  including  barrels  delivered  under the forward oil sale.
The  Company's operating costs per oil equivalent-barrel were $6.47 and $5.77 in
1997  and  1996,  respectively.  Increased per-barrel costs resulted from higher
OCENSA  pipeline tariffs.  During 1997, construction of OCENSA's pipeline system
was  completed,  although its facilities were not utilized to their capacity due
to  delays  in  escalating  production in the Fields.  During 1997 and 1996, the
Company paid production taxes on production from the Cusiana Field totaling $8.5
million,  or  $1.28  per  barrel,  and  $8.4  million,  or  $1.40  per  barrel,
respectively.

          General  and  administrative  expenses before capitalization increased
$10.5  million  to $61 million in 1997, primarily due to growth of the Company's
operations.  Capitalized general and administrative costs were $32.4 million and
$24.6  million  in 1997 and 1996, respectively.  The increased capitalized costs
reflect  the  Company's  increased  exploration  activities  in  1997.

          In  1996,  the  Company's  oil  and gas properties and other assets in
Argentina  were  written  down  $43  million  following  a  review  of technical
information  that  indicated  the  acreage  portfolio did not meet the Company's
exploration  objectives.

     Other  Income  and  Expenses
     ----------------------------

          Interest  expense increased $8 million primarily due to higher average
debt  outstanding  during  1997.  Capitalized interest totaled $25.8 million and
$27.1  million  in  1997  and  1996,  respectively.

          Other  income in 1997 included a foreign exchange gain of $9.5 million
primarily  on  deferred  tax  liabilities  in  Colombia, compared with a foreign
exchange loss of $.6 million in 1996. During 1997 and 1996, the Company recorded
an  unrealized  gain  (loss)  of  ($9.7  million) and $11 million, respectively,
representing  the  change  in the fair market value of call options purchased in
anticipation  of  a  forward  oil  sale.  Other  income in 1996 included a $10.4
million  gain  on the sale of the Company's shareholdings in Crusader Limited, a
$7.6  million  benefit  for  settlement  of  a  lawsuit in which the Company was
plaintiff,  and  a  loss  provision  of  $3.2 million for certain legal matters.

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

          The  income  tax  provision  for  1997 included foreign deferred taxes
totaling  $16  million, primarily related to the Company's Colombian operations,
compared  with  foreign  deferred taxes of $15.4 million in 1996.  Additionally,
the  income  tax  provision included a deferred tax benefit in the United States
totaling  $7.9  million,  compared  with  a  benefit  of  $23.5 million in 1996.
Current  taxes  related  to the Company's Colombian operations were $3.4 million
and  $5.5  million  in  1997  and  1996,  respectively.

                         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.  Financial  information concerning the Company's assets at
December 31, 1998, including capitalized costs by geographic area, is in note 22
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 and Disclosure 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,  2000.  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.

                      Information Systems and the Year 2000
                      -------------------------------------

          The Year 2000 issue involves circumstances where a computerized system
may  not  properly  recognize  or process date-sensitive information on or after
January  1,  2000.  The Company began a formal process in 1998 to identify those
internal computerized systems that are not Year 2000 compliant, prioritize those
business-critical  computerized  systems  that  need remediation or replacement,
test  compliance once the appropriate corrective measures have been implemented,
and  develop  any  contingency  plans  where  considered  necessary.

          The  Company's  information  technology  infrastructure  consists  of
desktop  Pentium  class  Intel  based  PC  systems, servers and Sparc-UNIX based
computers  and  off-the-shelf  software  packages. The systems are networked via
Microsoft  NT  4.0  and other telecommunications equipment. The Company does not
use  mini  or  mainframe  computer  systems and uses only off-the-shelf software
products. The PBX and phone system is a standard off-the-shelf phone system with
voice  mail capability. Additionally, telefax and copier machines are additional
business  tools  used  by  the  Company in conducting its day-to-day activities.

          The  Company  has  substantially  completed its assessment of the Year
2000 readiness of its internal computerized systems. The next phase will include
installing  upgrades  to  its  off-the-shelf  financial and operational software
applications,  hardware  and  telecommunications equipment.  The Company expects
that  such  remediation  procedures  will  be completed by the second quarter of
1999.  The  last  phase will include testing of newly upgraded systems to ensure
compliance  with  Year  2000 date recognition and the development of contingency
plans.  The  Company expects to complete this last phase by the third quarter of
1999.

          All  of  the  Company's  sales are derived from oil and gas production
from  the Fields, which is heavily dependent upon the operation of the Fields by
BP  Exploration  Company  (Colombia)  Limited  (the  "Operator")  and  the
transportation of oil through OCENSA, a Colombian pipeline company.  The Company
is  monitoring  progress  of  the  Operator  of  the  Fields and OCENSA on their
activities  related  to  the  Year 2000.  At this time, the Company expects that
field operations will not be interrupted due to improper recognition of the Year
2000  by  computerized  systems  of  the  Operator  of  the  Fields  or  OCENSA.

          The  Company  also  relies on other oil and gas partners, vendors, and
financial  institutions  in  its  daily operations.  The Company believes it has
identified  those  third-party  relationships that could have a material adverse
effect  on  the  Company's  results  of operations and financial position should
their  computerized  systems not be compliant for the Year 2000.  The Company is
in  the process of surveying the identified third parties on their readiness for
the  Year  2000  and  will  establish appropriate alternatives, if needed, where
noncompliance  may  pose  a  risk  to  the  Company's  operations.

          The  Company  does not believe that the costs to resolve any Year 2000
issues  will  be  material.  To  date,  the  Company  has incurred approximately
$150,000  on  Year  2000  matters  and it expects that the total cost, primarily
consulting  fees,  will  not  exceed  $700,000.

          The  failure  to  correct a material Year 2000 problem by the Company,
its  partners  or other vendors could result in an interruption of the Company's
normal  business activities or operations, including production in the Fields or
transportation  of  the  Company's  crude  oil  to  the  port  of  Covenas. Any
interruptions could result in a material adverse effect on the Company's results
of  operations,  cash  flows  and  financial  condition.  Due  to  the  inherent
uncertainties  relating  to  the  effect  of  the  Year  2000  on  the Company's
operations,  it  is difficult to predict what impact, if any, noncompliance with
the Year 2000 issue will have on the Company's results of operations, cash flows
and  financial  condition.

          As  the  Company progresses further through its Year 2000 analysis, it
intends  to  develop  contingency  plans  for  risks that could cause a material
adverse  effect on the Company's results of operations, cash flows and financial
condition.

               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 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.  Forward-looking  statements  may be identified, without limitation,
by  the  use  of  the  words  "anticipates," "estimates," "expects," "believes,"
"intends,"  "plans"  and  similar  expressions.  These  statements  include
information  regarding  drilling  schedules;  expected  or  planned  production
capacity;  the  closing  of branch offices; future production of the Fields; the
negotiation  of a gas-sales contract, completion of development and commencement
of  production  in  Malaysia-Thailand;  the  Company's capital budget and future
capital  requirements;  the  Company's  meeting its future capital needs; future
general  and  administrative  expense  and the portion to be capitalized; future
interest expense and the portion to be capitalized; the Company's realization of
its  deferred  tax  asset;  the  level  of future expenditures for environmental
costs; the outcome of regulatory and litigation matters; the impact of Year 2000
issues; 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 20 and 21 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.


<PAGE>


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, 1998,
WTI  oil  prices  fluctuated between a low price of $10.72 per barrel and a high
price  of  $26.62  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  its projected oil production.  The policy is structured to underpin
the  Company's planned revenues and results of operations.  The Company may also
enter  into  financial market transactions to benefit from its assessment of the
future  prices  of  its  production  relative  to  other  benchmark  prices.

     During  the  year  ended  December  31,  1998, the Company did not have any
outstanding  financial  market  transactions  to  hedge  against  oil  price
fluctuations.  During  the  years  ended  December  31,  1997  and 1996, markets
provided  the  Company  the  opportunity  to realize WTI benchmark oil prices on
average  $2.35  per  barrel  and  $4.68  per barrel, respectively, above the WTI
benchmark  oil  price the Company set as part of its annual plan for the period.
As  a  result  of financial and commodity market transactions settled during the
years  ended  December  31, 1997 and 1996, the Company's risk management program
resulted  in  an  average  net  realization of approximately $.11 per barrel and
$1.21  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.

     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.  During the years ended December 31,
1998,  1997  and  1996,  the  Company  recorded an unrealized gain (loss) of $.4
million,  ($9.7  million)  and  $11 million, respectively, in other income, net,
related to the change in the fair market value of the call options.  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 call options.  At
December  31, 1998, the potential decrease in fair value, assuming a ten percent
adverse  movement in WTI oil prices, would not have a material adverse effect on
the  Company's  consolidated  financial  position  or  results  of  operations.

<PAGE>
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
year  ended  December  31,  1998,  the Company made payments to the Counterparty
totaling  $5.9 million and received payments from the Counterparty totaling $2.6
million.

     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 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 year ended December 31,
1998,  the  Company  recorded  an  expense of $3.3 million in other income, 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,  1998, 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,  1998, would be approximately $6.6 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 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. 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.  To  the  extent  that  97%  of  the Purchaser's sale proceeds exceeds the
notional  amount,  the  Company will record a gain, and to the extent 97% of the
Purchaser's  sale  proceeds  is  less than the notional amount, the Company will
record  an expense. 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.

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

          The  Company  believes  its  interest  rate  exposure  on  debt is not
significant  since  only  $32.6  million  out of total debt of $432.5 million at
December  31,  1998,  has  floating  interest  rate  obligations, of which $14.5
million  was  repaid  in  January  1999.

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,
1998,  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, 1998, 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.

<PAGE>
                                      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 1999 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 1999. 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 - Certain Transactions" in
the  Proxy  Statement  is  incorporated  herein  by  reference.


<PAGE>

                                     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.  (1)
 3.2  Articles of Association. (1)
 4.1  Specimen Share Certificate of Ordinary Shares, $.01 par value, of the Company. (2)
 4.2  Rights Agreement dated as of March 25, 1996, between Triton and The Chase
      Manhattan Bank, as Rights Agent, including, as Exhibit A thereto, Resolutions
      establishing the Junior Preference Shares. (1)
 4.3  Resolutions Authorizing the Company's 5% Convertible Preference Shares. (3)
 4.4  Amendment No. 1 to Rights Agreement dated as of August 2, 1996, between Triton
      Energy Limited and The Chase Manhattan Bank, as Rights Agent. (4)
 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. (5)
 4.6  Unanimous Written Consent of the Board of Directors authorizing a Series of
      Preference Shares. (6)
 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. (7)
10.1  Amended and Restated  Retirement Income Plan. (8)(27)
10.2  Amendment to the Retirement Income Plan dated August 1, 1998. (9)(27)
10.3  Amendment to Amended and Restated Retirement Income Plan dated
      December 31, 1996. (10)(27)
10.4  Amended and Restated Supplemental Executive Retirement Income Plan. (11)(27)
10.5  1981 Employee Non-Qualified Stock Option Plan. (12)(27)
10.6  Amendment No. 1 to the 1981 Employee Non-Qualified Stock Option Plan. (13)(27)
10.7  Amendment No. 2 to the 1981 Employee Non-Qualified Stock Option Plan. (12)(27)
10.8  Amendment No. 3 to the 1981 Employee Non-Qualified Stock Option Plan. (8)(27)
10.9  1985  Stock  Option  Plan.  (14)(27)
10.10 Amendment No. 1 to the 1985 Stock Option Plan. (12)(27)
10.11 Amendment No. 2 to the 1985 Stock Option Plan. (8)(27)
10.12 Amended and Restated 1986 Convertible Debenture Plan. (8)(27)
10.13 1988 Stock Appreciation Rights Plan. (15)(27)
10.14 1989 Stock Option Plan. (16)(27)
10.15 Amendment No. 1 to 1989 Stock Option Plan. (12)(27)
10.16 Amendment No. 2 to 1989 Stock Option Plan. (8)(27)
10.17 Second Amended and Restated 1992 Stock Option Plan.(17)(27)
10.18 Form of Amended and Restated Employment Agreement with Triton Energy Limited
      and certain officers. (11)(27)
10.19 Amended and Restated Employment Agreement among Triton Energy Limited, Triton
      Exploration Services, Inc. and Robert B. Holland, III. (6)(27)
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. (6)(27)
10.21 Letter Agreement among Triton Energy Limited, Triton Exploration Services,  Inc.
      and Robert B. Holland, III dated December 17, 1998. (27)(28)
10.22 Letter Agreement among Triton Energy Limited, Triton Exploration Services,  Inc.
      and Peter Rugg dated December 10, 1998. (27)(28)
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. (27)(28)
10.24 Amended and Restated 1985 Restricted Stock Plan. (8)(27)
10.25 First Amendment to Amended and Restated 1985 Restricted Stock Plan. (18)(27)
10.26 Second Amendment to Amended and Restated 1985 Restricted Stock Plan. (17)(27)
10.27 Executive Life Insurance Plan. (19)(27)
10.28 Long Term Disability Income Plan. (19)(27)
10.29 Amended and Restated Retirement Plan for Directors. (14)(27)
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. (14)
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. (14)
10.32 Summary of Assignment legalized by Public Instrument No. 1255 dated September 15,
      1987 (Assignment is in Spanish language). (15)
10.33 Summary of Assignment legalized by Public Instrument No. 1602 dated June 11, 1990
      (Assignment is in Spanish language). (15)
10.34 Summary of Assignment legalized by Public Instrument No. 2586 dated September 9,
      1992 (Assignment is in Spanish language). (15)
10.35 401(K) Savings Plan. (8)(27)
10.36 Amendment to the 401(k) Savings Plan dated August 1, 1998. (9)(27)
10.37 Amendment to 401(k) Savings Plan dated December 31, 1996. (10)(27)
10.38 Contract  between  Malaysia-Thailand and Joint Authority and Petronas  Carigali
      SDN.BHD. and Triton Oil Company of Thailand relating to Exploration and Production
      of  Petroleum for Malaysia-Thailand Joint Development Area Block A-18. (20)
10.39 Triton Crude Purchase Agreement between Triton Colombia, Inc. and Oil Co., LTD.
      dated May 25, 1995. (21)
10.40 Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation,
      NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States. (18)
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. (18)
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. (17)
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. (10)
10.44 Form of Indemnity Agreement entered into with each director and officer of the
      Company. (6)
10.45 Description of Performance Goals for Executive Bonus Compensation. (22)(27)
10.46 Stock Purchase Agreement dated September 2, 1997, between The Strategic
      Transaction Company and Triton International Petroleum, Inc. (11)
10.47 Fourth Amendment to Stock Purchase Agreement dated February 2, 1998, between
      The Strategic Transaction Company and Triton International Petroleum, Inc. (11 )
10.48 Amended and Restated 1997 Share Compensation Plan. (27)(28)
10.49 First Amendment to Amended and Restated Retirement Plan for Directors. (11 )(27)
10.50 First Amendment to Second Amended and Restated 1992 Stock Option Plan. (23)(27)
10.51 Second Amendment to Second Amended and Restated 1992 Stock Option Plan.
      (11)(27)
10.52 Amended and Restated Indenture dated July 25, 1997, between Triton Energy
      Limited and The Chase Manhattan Bank. (24)
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. (24)
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. (24)
10.55 Share Purchase Agreement dated July 17, 1998 ,among Triton Energy Limited, Triton
      Asia Holdings, Inc., Atlantic Richfield Company and ARCO JDA Limited. (9)
10.56 Shareholders Agreement dated August 3, 1998, among Triton Energy Limited, Triton
      Asia Holdings, Inc., Atlantic Richfield Company, and ARCO JDA Limited. (9)
10.57 Stock Purchase Agreement dated as of August 31, 1998, between Triton Energy
      Limited and HM4 Triton, L.P. (6)
10.58 Shareholders Agreement dated as of September 30, 1998, between Triton Energy
      Limited and HM4 Triton, L.P. (6)
10.59 Financial Advisory Agreement dated as of September 30, 1998, between Triton Energy
      Limited and Hicks, Muse & Co. Partners, L.P. (6)
10.60 Monitoring and Oversight Agreement dated as of September 30, 1998, between Triton
      Energy Limited and Hicks, Muse & Co. Partners, L.P. (6)
10.61 Severance Agreement dated as of July 15, 1998, between Thomas G. Finck and Triton
      Energy Limited. (6) (27)
 12.1 Computation of Ratio of Earnings to Fixed Charges. (28)
 12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preference
      Dividends. (28)
 21.1 Subsidiaries of the Company. (28)
 23.1 Consent of PricewaterhouseCoopers LLP. (28)
 23.2 Consent of DeGolyer and MacNaughton. (28)
 24.1 The power of attorney of officers and directors of the Company (set forth on the
      signature page hereof). (28)
 27.1 Financial Data Schedule. (28)
 99.1 Heads of Agreement for the Supply of Gas from Block A-18 of the Malaysia-Thailand Joint Development Area. (10)
 99.2 Rio Chitamena Association Contract. (25)
 99.2 Rio Chitamena Purchase and Sale Agreement. (25)
 99.3 Integral Plan - Cusiana Oil Structure. (25)
 99.4 Letter Agreements with co-investor in Colombia. (25)
 99.5 Colombia Pipeline Memorandum of Understanding. (25)
 99.6 Amended and Restated Oleoducto Central S.A. Agreement dated as of March 31,
      1995. (26)

</TABLE>


____________________
<TABLE>
<CAPTION>


<S>  <C>
(1)  Previously filed as an exhibit to the Company's Registration Statement on Form S-3
     (No 333-08005) and incorporated herein by reference.
(2)  Previously filed as an exhibit to the Company's Registration Statement on Form 8-A
     dated March 25, 1996, and incorporated herein by reference.
(3)  Previously filed as an exhibit to the Company's and Triton Energy Corporation's
     Registration Statement on Form S-4 (No. 333-923) and incorporated herein
     by reference.
(4)  Previously filed as an exhibit to the Company's Registration Statement on Form 8-A/A
     (Amendment No. 1) dated August 14, 1996, and incorporated herein by reference.
(5)  Previously filed as an exhibit to the Company's Registration Statement on Form 8-A/A
     (Amendment No. 2) dated October 2, 1998, and incorporated herein by reference.
(6)  Previously  filed  as an exhibit to Triton Energy Corporation's Quarterly Report on
     Form 10-Q for the quarter  ended  September  30,  1998,  and  incorporated  herein
     by reference.
(7)  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.
(8)  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
(9)  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) 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.
(11) 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.
(12) 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.
(13) Previously filed as an exhibit to Triton Energy Corporation's Annual Report on Form
     10-K for the fiscal year ended May 31, 1989, and incorporated by reference herein.
(14) 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.
(15) 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.
(16) 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.
(17) 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.
(18) 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.
(19) 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.
(20) Previously filed as an exhibit to Triton Energy Corporation's current report on Form
     8-K dated April 21, 1994, and incorporated by reference herein.
(21) 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.
(22) 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.
(23) 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.
(24) 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.
(25) Previously filed as an exhibit to Triton Energy Corporation's current report on Form
     8-K/A dated July 15, 1994, and incorporated by reference herein.

(26) 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.
(27)  Management contract or compensatory plan or arrangement.
(28)  Filed herewith.
</TABLE>




(b)          Reports on Form 8-K.

             None

<PAGE>
                                   SIGNATURES



     Pursuant  to  the  requirements  of  Section  13 or 15(d) of the Securities
Exchange  Act of 1934, the Registrant has duly caused this Annual Report on Form
10-K  to  be signed by the undersigned thereunto duly authorized on the 17th day
of  March,  1999.

                              TRITON  ENERGY  LIMITED




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


                           POWER OF ATTORNEY

     KNOW  ALL  MEN BY THESE PRESENTS, that each of the undersigned officers and
directors  of  Triton  Energy  Limited  (the  "Company")  hereby constitutes and
appoints  James  C. Musselman, Robert B. Holland, III, and Bernard Gros-Dubois,
or any of them  (with  full  power  to  each  of  them  to act alone), his true
and lawful attorney-in-fact  and agent, with full power of substitution, for him
and on his behalf  and  in  his  name, place and stead, in any and all
capacities, to sign, execute,  and file any and all documents relating to the
Company's Annual Report on  Form  10-K  for  the  year  ended  December  31,
1998, including any and all amendments and supplements thereto, with any
regulatory authority, granting unto said  attorneys,  and  each  of them, full
power and authority to do and perform each and every act and thing requisite and
necessary to be done in and about the premises in order to effectuate the same
as fully to all intents and purposes as he  himself  might  or  could  do  if
personally  present, hereby ratifying and confirming  all that said
attorneys-in-fact and agents, or any of them, or their or  his  substitute  or
substitutes,  may  lawfully  do  or  cause  to be done.

     Pursuant  to  the requirements of the Securities Exchange Act of 1934, this
Annual  Report  on  Form  10-K has been signed below by the following persons on
behalf  of  the  Registrant  and  in the capacities indicated on the 17th day of
March,  1999.

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




      /s/Bernard Gros-Dubois            Vice President
 -----------------------------
         Bernard Gros-Dubois            (Principal Accounting and
                                         Financial Officer)

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





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



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



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



    /s/Fitzgerald S. Hudson             Director
------------------------------
       Fitzgerald Hudson



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



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



    /s/C. Lamar Norsworthy              Director
------------------------------
       C. Lamar Norsworthy



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



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



<PAGE>





                     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, 1998, 1997,
and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  F-3
Consolidated Balance Sheets - Pro Forma December 31, 1998 (Unaudited), and
December 31, 1998 and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . .  F-4
Consolidated Statements of Cash Flows - Years ended December 31, 1998, 1997
and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  F-5
Consolidated Statements of Shareholders' Equity - Years ended December 31, 1998,
1997 and 1996. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  F-6
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . .  F-7



SCHEDULE:
 II  -  Valuation and Qualifying Accounts - Years ended December 31, 1998,
         1997 and 1996                                                            F- 50
</TABLE>
























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

<PAGE>




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



PricewaterhouseCoopers  LLP
Dallas,  Texas
February  2,  1999
<PAGE>



                     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,
                                                          --------------------------------
                                                             1998       1997       1996
                                                          ----------  ---------  ---------
SALES AND OTHER OPERATING REVENUES:
  Oil and gas sales                                       $ 160,881   $145,419   $129,795
  Gain on sale of oil and gas assets                         67,737      4,077      4,182
                                                          ----------  ---------  ---------
                                                            228,618    149,496    133,977
                                                          ----------  ---------  ---------
COSTS AND EXPENSES:
  Operating                                                  73,546     51,357     36,654
  General and administrative                                 26,653     28,607     25,945
  Depreciation, depletion and amortization                   58,811     36,828     25,640
  Writedown of assets                                       328,630        ---     42,960
  Special charges                                            18,324        ---        ---
                                                          ----------  ---------  ---------
                                                            505,964    116,792    131,199
                                                          ----------  ---------  ---------

          OPERATING INCOME (LOSS)                          (277,346)    32,704      2,778

Gain on sale of Triton Pipeline Colombia                     50,227        ---        ---
Interest income                                               3,258      5,178      6,703
Interest expense, net                                       (23,228)   (23,858)   (15,897)
Other income, net                                             8,480      2,872     27,361
                                                          ----------  ---------  ---------

                                                             38,737    (15,808)    18,167
                                                          ----------  ---------  ---------

          EARNINGS (LOSS) BEFORE INCOME TAXES
               AND EXTRAORDINARY ITEM                      (238,609)    16,896     20,945
Income tax expense (benefit)                                (51,105)    11,301     (2,860)
                                                          ----------  ---------  ---------

          EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM        (187,504)     5,595     23,805
Extraordinary item - extinguishment of debt                     ---    (14,491)    (1,196)
                                                          ----------  ---------  ---------

           NET EARNINGS (LOSS)                             (187,504)    (8,896)    22,609
DIVIDENDS ON PREFERENCE SHARES                                3,061        400        985
                                                          ----------  ---------  ---------

          EARNINGS (LOSS) APPLICABLE TO ORDINARY SHARES   $(190,565)  $ (9,296)  $ 21,624
                                                          ==========  =========  =========

Average ordinary shares outstanding                          36,609     36,471     35,929
                                                          ==========  =========  =========

BASIC EARNINGS (LOSS) PER ORDINARY SHARE:

   Earnings (loss) before extraordinary item              $   (5.21)  $   0.14   $   0.64
   Extraordinary item - extinguishment of debt                  ---      (0.40)     (0.03)
                                                          ----------  ---------  ---------

           BASIC EARNINGS (LOSS)                          $   (5.21)  $  (0.26)  $   0.61
                                                          ==========  =========  =========

DILUTED EARNINGS (LOSS) PER ORDINARY SHARE:

   Earnings (loss) before extraordinary item              $   (5.21)  $   0.14   $   0.62
   Extraordinary item - extinguishment of debt                  ---      (0.39)     (0.03)
                                                          ----------  ---------  ---------

           DILUTED EARNINGS (LOSS)                        $   (5.21)  $  (0.25)  $   0.59
                                                          ==========  =========  =========
</TABLE>





          See accompanying Notes to Consolidated Financial Statements.
<PAGE>

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





<TABLE>
<CAPTION>

<S>                                                                  <C>                <C>                <C>
                                                                       PRO FORMA
                        ASSETS                                        DECEMBER 31,                DECEMBER 31,
                                                                                        -------------------------------
                                                                         1998               1998               1997
                                                                     -------------      -------------     -------------
                                                                     (Unaudited)
CURRENT ASSETS:
   Cash and equivalents                                              $    237,186       $     19,122      $     13,451
   Trade receivables, net                                                   9,554              9,554            12,963
   Other receivables                                                       48,415             48,415            52,162
   Inventories, prepaid expenses and other                                  1,655              1,655             5,219
   Assets held for sale                                                       ---                ---            58,178
                                                                     -------------      -------------     -------------

                    TOTAL CURRENT ASSETS                                  296,810             78,746           141,973

Property and equipment, at cost, net                                      556,122            556,122           835,506
Deferred income taxes                                                     100,916            100,916            87,148
Other assets                                                               20,349             20,349            33,412
                                                                     -------------      -------------     -------------

                                                                     $    974,197       $    756,133      $  1,098,039
                                                                     =============      =============     =============

                    LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
    Current maturities of long-term debt                             $     14,027       $     14,027      $    130,375
    Short-term borrowings                                                   5,000              5,000            54,600
    Accounts payable and accrued liabilities                               45,892             45,892            36,964
    Deferred income                                                        35,254             35,254            35,254
                                                                     -------------      -------------     -------------

                    TOTAL CURRENT LIABILITIES                             100,173            100,173           257,193

Long-term debt, excluding current maturities                              413,465            413,465           443,312
Deferred income taxes                                                       4,169              4,169            50,968
Deferred income and other                                                  14,519             14,519            49,946

SHAREHOLDERS' EQUITY:
   5% preference shares, par value $.01; authorized 420,000
       shares; issued 209,639 and 218,285 shares at December 31,
       1998 and 1997, respectively, stated value $34.41                     7,214              7,214             7,511
   8% preference shares, par value $.01; authorized 11,000,000
       shares; issued 1,822,500 shares (pro forma 5,000,000 shares)
       at December 31, 1998, stated value $70                             350,000            127,575               ---
   Ordinary shares, par value $.01; authorized 200,000,000
       shares; issued 36,643,478 and 36,541,064 shares at
        December 31, 1998 and 1997, respectively                              366                366               365
   Additional paid-in capital                                             571,502            575,863           588,454
   Accumulated deficit                                                   (485,085)          (485,085)         (297,581)
   Accumulated other non-owner changes in shareholders' equity             (2,126)            (2,126)           (2,126)
                                                                     -------------      -------------     -------------

                                                                          441,871            223,807           296,623
   Less cost of ordinary shares in treasury                                  ---                ---                  3
                                                                     -------------      -------------     -------------

                    TOTAL SHAREHOLDERS' EQUITY                            441,871            223,807           296,620
Commitments and contingencies (note 21)                                       ---                ---               ---
                                                                     -------------      -------------     -------------

                                                                     $    974,197       $    756,133      $  1,098,039
                                                                     =============      =============     =============
</TABLE>



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


<PAGE>


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



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

                                                                          YEAR ENDED DECEMBER 31,
                                                                   ----------------------------------
                                                                      1998        1997        1996
                                                                   ----------  ----------  ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
 Net earnings (loss)                                               $(187,504)  $  (8,896)  $  22,609
 Adjustments to reconcile net earnings to net cash provided (used)
    by operating activities:
   Depreciation, depletion and amortization                           58,811      36,828      25,640
   Amortization of deferred income                                   (35,254)    (28,467)     (8,105)
   Gain on sale of oil and gas assets                                (67,737)     (4,077)     (4,182)
   Gain on sale of Triton Pipeline Colombia                          (50,227)        ---         ---
   Writedown of assets                                               328,630         ---      42,960
   Payment of accreted interest on extinguishment of debt                ---    (124,794)        ---
   Extraordinary loss on extinguishment of debt, net of tax              ---      14,491       1,196
   Amortization of debt discount                                         ---       7,949      15,897
   Deferred income taxes                                             (55,592)      8,078      (8,115)
   Gain on sale of other assets                                       (7,590)     (1,409)    (11,649)
   Other, net                                                          3,962       6,100      (4,862)
   Changes in working capital:
   Marketable debt securities - trading                                  ---       1,856       4,149
   Receivables                                                         7,371      (2,408)     (5,048)
   Inventories, prepaid expenses and other                               902         (62)       (787)
   Accounts payable and accrued liabilities                            5,898      (2,605)     11,002
                                                                   ----------  ----------  ----------

       Net cash provided (used) by operating activities                1,670     (97,416)     80,705
                                                                   ----------  ----------  ----------

CASH FLOWS FROM INVESTING ACTIVITIES:
 Capital expenditures and investments                               (180,054)   (219,216)   (252,684)
 Proceeds from sale of oil and gas assets                            147,027       4,077      22,624
 Proceeds from sale of Triton Pipeline Colombia                       97,656         ---         ---
 Proceeds from sales of other assets                                  22,353       1,822      15,881
 Proceeds from sale of investments and marketable securities             ---       2,000      38,507
 Proceeds from sale of shareholdings in Crusader                         ---         ---      69,583
 Other                                                                (2,630)     (1,383)        571
                                                                   ----------  ----------  ----------

       Net cash provided (used) by investing activities               84,352    (212,700)   (105,518)
                                                                   ----------  ----------  ----------

CASH FLOWS FROM FINANCING ACTIVITIES:
 Proceeds from revolving lines of credit and long-term debt          162,530     620,413      53,911
 Payments on revolving lines of credit and long-term debt           (350,511)   (321,515)    (70,884)
 Short-term notes payable, net                                        (9,600)      9,600         ---
 Issuance of 8% preference shares, net                               115,329         ---         ---
 Issuances of ordinary shares                                          2,544       5,260       5,874
 Other                                                                  (363)       (390)     (1,879)
                                                                   ----------  ----------  ----------

       Net cash provided (used) by financing activities              (80,071)    313,368     (12,978)
                                                                   ----------  ----------  ----------

Effect of exchange rate changes on cash and equivalents                 (280)       (849)       (211)
                                                                   ----------  ----------  ----------
Net increase (decrease) in cash and equivalents                        5,671       2,403     (38,002)
CASH AND EQUIVALENTS AT BEGINNING OF YEAR                             13,451      11,048      49,050
                                                                   ----------  ----------  ----------

CASH AND EQUIVALENTS AT END OF YEAR                                $  19,122   $  13,451   $  11,048
                                                                   ==========  ==========  ==========
</TABLE>




          See accompanying Notes to Consolidated Financial Statements.


<PAGE>



                      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,
                                                       -----------------------------------------------------------------


                                                                1998                   1997                  1996
                                                       ----------------------  -------------------- --------------------
OWNER  SOURCES  OF  SHAREHOLDERS'  EQUITY:
 5%  PREFERENCE  SHARES:
  Balance at beginning of period                      $    7,511               $   8,515             $  14,109
  Conversion of 5% preference shares                        (297)                 (1,004)               (5,594)
                                                       ----------              ----------            ----------
  Balance at end of period                                 7,214                   7,511                 8,515
                                                       ----------              ----------            ----------
8% PREFERENCE SHARES:
  Balance at beginning of period                             ---                    ---                    ---
  Issuances of 1,822,500 shares at $70 per share         127,575                    ---                    ---
                                                       ----------              ----------            ----------

  Balance at end of period                               127,575                    ---                    ---
                                                       ----------              ----------            ----------
ORDINARY SHARES:
  Balance at beginning of period                             365                     363                35,927
  Exercise of employee stock options and debentures            1                       2                    81
  Conversion of 5% preference shares                         ---                     ---                   153
  Reduction in par value                                     ---                     ---               (35,783)
  Other, net                                                 ---                     ---                   (15)
                                                       ----------              ----------            ----------
  Balance at end of period                                   366                     365                   363
                                                       ----------              ----------            ----------
ADDITIONAL PAID-IN CAPITAL:
  Balance at beginning of period                         588,454                 582,581               516,326
  Cash dividends, 5% preference shares                      (368)                   (400)                 (985)
  Cash dividends, 8% preference shares                    (2,693)                   ---                   ---
  Exercise of employee stock options and debentures        2,548                   3,831                 7,974
  Conversion of 5% preference shares                         297                   1,004                 5,441
  Reduction in par value                                     ---                     ---                35,783
  Transaction costs for issuance of
   8% preference shares                                  (12,370)                    ---                   ---
  Sale of shareholdings in Crusader                          ---                     ---                20,413
  Other, net                                                  (5)                  1,438                (2,371)
                                                       ----------              ----------            ----------
  Balance at end of period                               575,863                 588,454               582,581
                                                       ----------              ----------            ----------
TREASURY SHARES:
  Balance at beginning of period                              (3)                     (2)                 (338)
  Retirement of treasury shares                                5                      ---                  204
  Other, net                                                  (2)                     (1)                  132
                                                       ----------              ----------            ----------
  Balance at end of period                                   ---                      (3)                   (2)
                                                       ----------              ----------            ----------

    TOTAL OWNER SOURCES OF SHAREHOLDERS' EQUITY          711,018                 596,327               591,457
                                                       ----------              ----------            ----------

NON-OWNER SOURCES OF SHAREHOLDERS' EQUITY:
 ACCUMULATED DEFICIT:
  Balance at beginning of period                        (297,581)               (288,685)             (311,294)
  Net earnings (loss)                                   (187,504)  $(187,504)     (8,896)  $(8,896)     22,609   $22,609
                                                       ----------              ----------            ----------

  Balance at end of period                              (485,085)               (297,581)             (288,685)
                                                       ----------              ----------            ----------
ACCUMULATED OTHER NON-OWNER CHANGES IN
    SHAREHOLDERS' EQUITY:
  Balance at beginning of period                          (2,126)                 (2,128)               (8,705)
  Foreign currency translation adjustments:
    Sale of shareholdings in Crusader                                    ---                   ---                 4,890
    Translation rate changes                                             ---                   ---                 1,600
  Valuation reserve on marketable securities                             ---                     2                    87
                                                                   ----------              --------              -------

  Other non-owner changes in shareholders' equity            ---         ---           2         2       6,577     6,577
                                                       ----------  ----------  ----------  --------  ----------  -------

  Non-owner changes in shareholders' equity                        $(187,504)              $(8,894)              $29,186
                                                                   ==========              ========              =======

  Balance at end of period                             (2,126)                 (2,126)               (2,128)
                                                       ----------              ----------            ----------

          TOTAL NON-OWNER SOURCES OF
              SHAREHOLDERS' EQUITY                      (487,211)               (299,707)             (290,813)
                                                       ----------              ----------            ----------

TOTAL SHAREHOLDERS' EQUITY                             $ 223,807               $ 296,620             $ 300,644
                                                       ==========              ==========            ==========
</TABLE>

               See accompanying Notes to Consolidated Financial Statements.
<PAGE>




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



1.     SUMMARY  OF  SIGNIFICANT  ACCOUNTING  POLICIES

GENERAL

Triton Energy Limited ("Triton") is an international oil and gas exploration and
production  company.  The  term  "Company" when used herein means Triton and its
subsidiaries  and  other  affiliates  through  which  the  Company  conducts its
business.  The  Company's  principal  properties,  operations,  and  oil and gas
reserves  are  located  in  Colombia  and  Malaysia-Thailand.  The  Company  is
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.  The  Company  also  consolidates  its
proportionate share of assets, liabilities and results of operations for oil and
gas ventures.  The investment in a previously owned 49.9% affiliate in which the
Company  exercised  significant  influence over operating and financial policies
was  accounted  for using the equity method.  Investments in less than 20%-owned
affiliates  are  accounted  for  using  the  cost  method.

CASH  EQUIVALENTS  AND  MARKETABLE  SECURITIES

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

Investments  in marketable debt securities are reported at fair value except for
those  investments  that  management  has the positive intent and the ability to
hold  to  maturity.  Investments  available-for-sale are classified based on the
stated  maturity  of the securities, and changes in fair value are reported as a
separate  component of shareholders' equity.  Trading investments are classified
as  current  regardless of the stated maturity of the underlying securities, and
changes  in fair value are reported in other income, net.  Investments that will
be  held  to  maturity  are  classified  based  on  the  stated  maturity of the
securities.

PROPERTY  AND  EQUIPMENT

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

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

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

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

Support  equipment  and  facilities are depreciated using the unit-of-production
method based on total reserves of the field related to the support equipment and
facilities.  Other  property  and  equipment,  which  includes  furniture  and
fixtures,  vehicles 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 improve-ments
are  capitalized.
<PAGE>

ENVIRONMENTAL  MATTERS

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

INCOME  TAXES

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

REVENUE  RECOGNITION

Oil  and  gas  revenues  are  recognized at the point of first measurement after
production,  which is generally upon delivery into field storage tank/processing
facilities  or  pipelines.  Cost  reimbursements  arising from carried interests
granted  by  the  Company  are  revenues  to  the  extent the reimbursements are
contingent  upon  and  derived  from  production.  Obligations  arising from net
profit  interest  conveyances  are  recorded  as  operating  expenses  when  the
obligation  is  incurred.

FOREIGN  CURRENCY  TRANSLATION

The  U.S.  dollar is the designated functional currency for all of the Company's
foreign  operations, except for foreign operations of a formerly owned affiliate
where  the  local  currency was used as the functional currency.  The cumulative
translation  effects from translating balance sheet accounts from the functional
currency into U.S. dollars are included as a separate component of shareholders'
equity.

RISK  MANAGEMENT

Oil  and natural gas sold by the Company are normally priced with reference to a
defined  benchmark,  such  as  light,  sweet  crude  oil  traded on the New York
Merchantile Exchange (West Texas Intermediate or "WTI").  Actual prices received
vary  from  the  benchmark depending on quality and location differentials. From
time  to  time, it is the Company's policy to use financial market transactions,
including  swaps,  collars  and  options,  with  creditworthy  counterparties,
primarily to reduce risk associated with the pricing of a portion of the oil and
natural  gas  that  it  sells.  The Company may also enter into financial market
transactions  to  benefit  from  its  assessment  of  the  future  prices of its
production  relative  to  other  benchmark  prices.

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

The  Company  occasionally enters into foreign exchange contracts to reduce risk
of  unfavorable  exchange-rate  movements.  The  gains  or  losses  arising from
currency  exchange  contracts  offset  foreign  exchange  gains or losses on the
underlying assets or liabilities or are deferred and offset against the carrying
value  of  the  firm  commitment.

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.  Prior
to the Company's sale of its investment in Crusader Limited ("Crusader") in July
1996,  the  Company's proportionate shares owned by Crusader were not considered
outstanding  for  purposes  of  determining  weighted  average  number of shares
outstanding.  Diluted  earnings (loss) per ordinary share 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

In  June 1997, the Financial Accounting Standards Board issued Statement No. 130
("SFAS  130"),  "Reporting Comprehensive Income." SFAS 130 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.  This statement does not
have  any  effect  on the Company's results of operations or financial position.

RECENT  ACCOUNTING  AND  DISCLOSURE  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,
2000.  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.     PRO  FORMA  BALANCE  SHEET  -  8%  PREFERENCE  SHARES  ISSUANCE

In  August  1998,  the Company and HM4 Triton, L.P. ("HM4 Triton"), 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 1,822,500 shares of 8% convertible
preference  shares  ("8%  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% Preference Shares at $70 per share, with HM4 Triton 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% Preference Shares for proceeds totaling $218.1 million,
net  of  closing  costs  (of  which,  HM4  Triton  purchased  3,114,863 shares).

Proceeds  from  the First Closing, completed in September 1998, are reflected in
the  audited financial statements for the year ended December 31, 1998. Proceeds
from the Second Closing, completed on January 4, 1999, are only reflected in the
unaudited Pro Forma Consolidated Balance Sheet as of December 31, 1998, shown on
page  F-4.

3.     WRITEDOWN  OF  ASSETS

Writedown  of  assets  is  summarized  as  follows:



<TABLE>
<CAPTION>

<S>                                                  <C>       <C>    <C>
                                                          DECEMBER 31,
                                                     ------------------------
                                                       1998    1997    1996
                                                     --------  -----  -------

Evaluated oil and gas properties (SEC ceiling test)  $241,005  $ ---  $   ---
Unevaluated oil and gas properties                     73,890    ---   39,963
Other assets                                           13,735    ---    2,997
                                                     --------  -----  -------

                                                     $328,630  $ ---  $42,960
                                                     ========  =====  =======
</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.  An  additional writedown may be required if oil prices fall below
the  December  31,  1998,  level  at  later  quarter  end  dates.

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.

In 1996, the Company's oil and gas properties and other assets in Argentina were
written  down  $40  million  and $3 million, respectively, following a review of
technical  information  that  indicated  the  acreage portfolio did not meet the
Company's  exploration  objectives.

4.     SPECIAL  CHARGES

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 totaling $18.3 million ($15 million and $3.3 million
in  the  third  and  fourth  quarters,  respectively).  At  December  31,  1998,
approximately  105  positions  had  been  eliminated,  three foreign offices had
closed  and  eight  licenses  had  been  relinquished, sold or their commitments
renegotiated.  The  Company expects to close the remaining office and dispose of
six  other  licenses  during  1999.

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.  During 1998, the Company paid
$7.4 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. As of December 31, 1998, no changes had been made to
the  Company's  estimate of the total restructuring expenditures to be incurred.
The  remaining liability related to restructuring activities was $7.9 million at
December  31,  1998.

5.     ASSET  DISPOSITONS

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.

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.  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.  The agreements provide that the Company will recover its investment
in  recoverable  costs in the project, approximately $101 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  after  $2.3 million of expenses.  The sale resulted in a gain of
$50.2  million.  TPC's  investment in OCENSA, totaling $47.4 million at December
31,  1997,  was  included  in  assets  held  for  sale.

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
year  ended  December  31,  1998,  the Company made payments to the Counterparty
totaling  $5.9 million and received payments from the Counterparty totaling $2.6
million.

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 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  year ended December 31, 1998, the
Company recorded an expense of $3.3 million in other income, net, related to the
net  payments  made  under and the change in the fair market value of the equity
swap.  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.  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. To the extent
that  97%  of  the  Purchaser's  sale  proceeds exceeds the notional amount, the
Company  will  record  a  gain,  and  to  the extent 97% of the Purchaser's sale
proceeds  is  less than the notional amount, the Company will record an expense.
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.

In  June and July 1996, the Company sold its 49.9% shareholdings in Crusader for
total  cash  proceeds  of $69.6 million in conjunction with a May 1996 take-over
bid  for  the outstanding shares of Crusader.  The Company recorded a total gain
of  $10.4  million  in  other income, net, and an increase to additional paid-in
capital  of  $20.4  million,  representing  the  Company's  proportion of Triton
ordinary  shares owned by Crusader that were previously treated as Triton owned.

In  March  1996,  the  Company sold its royalty interests in U.S. properties for
$23.8  million  based  on  an  effective  date  of January 1, 1996.  The Company
recorded  the  resulting  gain  of  $4.1  million in gain on sale of oil and gas
assets.

6.     FORWARD  SALE  OF  COLOMBIAN  OIL  PRODUCTION

In  May  1995, the Company sold 10.4 million barrels of oil from the Cusiana and
Cupiagua  fields  (the  "Fields")  in Colombia in a forward oil sale.  Under the
terms  of  the  sale,  the  Company  received  approximately  $87 million of the
approximately $124 million net proceeds and is entitled to receive substantially
all  of  the  remaining  proceeds  (now held in various interest-bearing reserve
accounts)  when  the  Company's  Cusiana  and  Cupiagua  fields  project becomes
self-financing, as defined in the agreement, which is expected in 1999, and when
certain  other  conditions  are  met.  At  December  31,  1998, proceeds held in
interest-bearing  reserve  accounts  of $31.9 million and $1.1 million have been
recorded  as  current  and  long-term receivables, respectively. The Company has
recorded  the  net  proceeds  as deferred income and will recognize such revenue
when  the  barrels  of oil are delivered during a five-year period that began in
June  1995.  Under  the  terms of the agreement, the Company must deliver to the
buyer  58,425 barrels per month through March 1997 and 254,136 barrels per month
from  April  1997  to  March  2000.

7.     OTHER  RECEIVABLES

Other  receivables  consisted  of  the  following:


<TABLE>
<CAPTION>

<S>                                   <C>      <C>

                                         DECEMBER 31,
                                      ----------------
                                       1998     1997
                                      -------  -------

Receivable from the forward oil sale  $31,932  $31,770
Receivable from insurance               8,413    1,852
Receivable from partners                2,007   11,152
Other                                   6,063    7,388
                                      -------  -------

                                      $48,415  $52,162
                                      =======  =======
</TABLE>

At  December  31, 1998, the Company had recorded a receivable from its insurance
carriers  of  $8.4  million  associated with claims on previously drilled wells.


8.     PROPERTY  AND  EQUIPMENT

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


<TABLE>
<CAPTION>
<S>                                          <C>         <C>
                                                 DECEMBER 31,
                                             --------------------
                                               1998        1997
                                             ---------  ---------
Oil and gas properties, full cost method:
   Evaluated                                 $ 608,616  $ 518,580
   Unevaluated                                  90,918    130,626
   Support equipment and facilities            289,659    250,193
Other                                           18,915     25,121
                                             ---------  ---------

                                             1,008,108    924,520
Less accumulated depreciation and depletion    451,986     89,014
                                             ---------  ---------

                                             $ 556,122  $ 835,506
                                             =========  =========
</TABLE>



In  1998,  the carrying amount of the Company's evaluated oil and gas properties
was  written  down  by $241 million through application of the full cost ceiling
limitation  as  prescribed  by the SEC as a result of the decline in oil prices.
Additionally, unevaluated oil and gas properties were written down $73.9 million
during  1998 in conjunction with a plan to restructure the Company's operations.
See  note  3  -  Writedown  of  Assets.

The  Company  capitalizes interest on qualifying assets, principally unevaluated
oil  and gas properties and major development projects in progress.  Capitalized
interest amounted to $23.2 million, $25.8 million and $27.1 million in the years
ended  December  31, 1998, 1997 and 1996, respectively.  The Company capitalized
general  and  administrative  expenses  related  to  exploration and development
activities of $20.6 million, $32.4 million, and $24.6 million in the years ended
December  31,  1998,  1997  and  1996,  respectively.

9.     ACCOUNTS  PAYABLE  AND  ACCRUED  LIABILITIES

Accounts  payable  and  accrued  liabilities  are  summarized  as  follows:


<TABLE>
<CAPTION>

<S>                                   <C>      <C>
                                        DECEMBER 31,
                                      ----------------
                                        1998    1997
                                      -------  -------
Accounts payable, principally trade   $ 9,144  $ 5,819
Accrued interest payable                8,160    9,449
Accrued special charges                 7,869      ---
Accrued exploration and development     4,598   12,903
Dividends payable                       2,693      ---
Litigation and environmental matters    2,064    2,715
Other                                  11,364    6,078
                                      -------  -------

                                      $45,892  $36,964
                                      =======  =======
</TABLE>




10.  DEBT

SHORT-TERM BORROWINGS


At December 31, 1998, the Company had outstanding borrowings totaling $5 million
under  a  $25 million unsecured bank revolving credit facility.  Borrowings bear
interest  at  various  spreads over the Eurodollar rate or, at the option of the
Company,  at  LIBOR  or  prime.  The  interest  rate on short-term borrowings at
December  31,  1998,  was  7.75%.

At  December  31,  1997,  the  Company  had  outstanding borrowings totaling $45
million  under  two  unsecured  revolving  credit  facilities  and  outstanding
borrowings  of $9.6 million under a $10 million unsecured demand promissory note
with  a  bank  that  renews  monthly.  The  weighted  average  interest rates on
short-term  borrowings  outstanding  at  December  31,  1997,  was  7.3%.

<PAGE>


LONG-TERM  DEBT

A  summary  of  long-term  debt  follows:

<TABLE>
<CAPTION>

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

                                               DECEMBER 31,
                                         ------------------------
                                           1998            1997
                                         --------        --------

Senior Notes due 2005                    $200,000        $200,000
Senior Notes due 2002                     199,924         199,900
Term credit facility maturing 2001         22,568          31,595
Revolving credit facility maturing 1999     5,000          17,500
Revolving credit facility maturing 1998       ---         119,900
Other notes and capitalized leases            ---           4,792
                                         --------        --------

                                          427,492         573,687
 Less current maturities                   14,027         130,375
                                         --------        --------

                                         $413,465        $443,312
                                         ========        ========
</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 due
April  15, 2005 (the "2005 Notes" and, together with the 2002 Notes, the "Senior
Notes"),  at  100%  of the principal amount, for total aggregate net proceeds of
$399.9  million  before deducting transaction costs of approximately $1 million.

Interest  on  the  Senior Notes is payable semi-annually on April 15 and October
15.  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,  1998,  the  Company  had  outstanding borrowings of $22.6 million under the
facility.

During  1997,  the  Company  signed  an unsecured bank revolving credit facility
providing  for  borrowings of up to $50 million that, as amended, matures in May
1999.  Borrowings  bear interest at various spreads over the Eurodollar rate or,
at  the  Company's option, at LIBOR or prime.  At December 31, 1998, the Company
had  outstanding  borrowings  of  $5  million  under  the  facility.

At  December  31, 1997, the Company had outstanding borrowings of $119.9 million
and  letters  of  credit  for  $4.5  million under a $125 million unsecured bank
revolving  credit  facility.  The  facility  was  repaid and terminated in 1998.

In  May  and  June  1997,  the  Company  completed  a  tender  offer and consent
solicitation with respect to its Senior Subordinated Discount Notes due November
1,  1997  ("1997  Notes") and  9 3/4% Senior  Subordinated  Discounted Notes due
December  15, 2000 ("9 3/4%  Notes") that resulted in the retirement of the 1997
Notes  and substantially all  of  the  9 3/4 % Notes.  The  Company's results of
operations  included  an  extraordinary  expense of $14.5 million, net of a $7.8
million  tax  benefit,  associated with the extinguishment of the 1997 Notes and
the 9 3/4% Notes.  The Company's reported cash flows from operating activities
for the  year  ended  December  31,  1997, were reduced by $124.8 million, which
was attributable  to  the interest accreted with respect to the 1997 Notes and
the 9 3/4 %  Notes  through the dates of retirement.  The remainder of the
9 3/4% Notes were retired  in  1998.

During  1996, the Company purchased in the open market $30 million face value of
its  1997  Notes and realized an extraordinary expense of $1.2 million, net of a
$.6  million  tax  benefit.

The  Company amortizes debt issue costs over the life of the borrowing using the
interest  method.  Amortization  related  to  the Company's debt-issue costs was
$2.9  million, $2 million and $3.6 million in the years ended December 31, 1998,
1997 and 1996, respectively.  The aggregate maturities of long-term debt for the
five  years during the period ending December 31, 2003, are as follows:  1999 --
$14  million;  2000 -- $9 million; 2001 -- $4.5 million; 2002 -- $199.9 million;
and  2003  --  nil.

11.     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,
                       --------------------------------------------
                          1998             1997              1996
                       ----------       ----------        ---------

Cayman Islands         $  82,995        $ (12,969)        $   (452)
United States            (24,003)         (31,694)         (16,641)
Foreign - other         (297,601)          61,559           38,038
                       ----------        ---------        ---------

                       $(238,609)        $ 16,896         $ 20,945
                       ==========        =========        =========
</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.

<PAGE>

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

<TABLE>
<CAPTION>

<S>              <C>        <C>       <C>
                     YEAR ENDED DECEMBER 31,
                 ------------------------------
                   1998       1997      1996
                 ---------  --------  ---------
Current:
  Cayman Islands $    ---   $   ---   $    ---
  United States       ---        (7)      (172)
  Foreign - other   4,487     3,230      5,427
                 ---------  --------  ---------

   Total current    4,487     3,223      5,255
                 ---------  --------  ---------
Deferred:
  Cayman Islands      ---       ---        ---
  United States     1,457    (7,929)   (23,489)
  Foreign - other (57,049)   16,007     15,374
                 ---------  --------  ---------

   Total deferred  (55,592)    8,078     (8,115)
                 ---------  --------  ---------

   Total         $(51,105)  $11,301   $ (2,860)
                 =========  ========  =========
</TABLE>

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,
                                                      ---------------------------------
                                                       1998         1997         1996
                                                      --------    --------     --------
Tax provision at statutory tax rate                      0.0 %       0.0 %        0.0 %
Increase (decrease) resulting from:
   Net change in valuation allowance                     3.9 %     263.0 %     (111.6)%
   Recognition of outside basis adjustments              --- %       --- %      (20.3)%
   Foreign items without tax benefit                   (34.9)%      77.8 %       25.8 %
   Income subject to tax in excess of statutory rate    32.6 %      36.9 %       58.4 %
   Current year change in NOL/credit carryforwards      (4.8)%    (356.7)%      (59.2)%
   Temporary differences:
      Oil and gas basis adjustments                     25.7 %      32.5 %       80.6 %
      Reimbursement of pre-commerciality costs          (1.1)%      13.2 %       10.9 %
   Other                                                 --- %       0.2 %        1.8 %
                                                      --------    --------     --------

                                                        21.4 %      66.9 %      (13.6)%
                                                      ========    ========     ========
</TABLE>






<PAGE>

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



<TABLE>
<CAPTION>


<S>                                          <C>        <C>        <C>        <C>        <C>        <C>
                                                   DECEMBER 31, 1998                DECEMBER 31, 1997
                                             -------------------------------  -------------------------------
                                                                     OTHER                            OTHER
                                                 U.S.    COLOMBIA    FOREIGN     U.S.     COLOMBIA   FOREIGN
                                             ---------  ---------  ---------  ---------  ---------  ---------
Deferred tax asset:
  Net operating loss carryforwards           $145,475   $  7,992   $  7,219   $156,579   $ 10,088   $  8,187
  Depreciable/depletable property               1,252     27,730        ---      2,046        ---        ---
  Credit carryforwards                          1,731      6,813        ---      1,726      3,986        ---
  Reserves                                      2,502        ---        ---      1,090        ---        ---
  Other                                         1,505        ---        ---        799        ---        ---
                                             ---------  ---------  ---------  ---------  ---------  ---------

Gross deferred tax asset                      152,465     42,535      7,219    162,240     14,074      8,187
Valuation allowances                          (65,881)   (27,730)       ---    (75,092)       ---        ---
                                             ---------  ---------  ---------  ---------  ---------  ---------

Net deferred tax asset                         86,584     14,805      7,219     87,148     14,074      8,187
                                             ---------  ---------  ---------  ---------  ---------  ---------

Deferred tax liability:
  Depreciable/depletable property                 ---        ---    (11,388)       ---    (58,143)   (15,086)
  Other                                          (473)       ---        ---        ---        ---        ---
                                             ---------  ---------  ---------  ---------  ---------  ---------

Net deferred tax asset (liability)             86,111     14,805     (4,169)    87,148    (44,069)    (6,899)
Less current deferred tax asset (liability)       ---        ---        ---        ---        ---        ---
                                             ---------  ---------  ---------  ---------  ---------  ---------

Noncurrent deferred tax asset (liability)    $ 86,111   $ 14,805   $ (4,169)  $ 87,148   $(44,069)  $ (6,899)
                                             =========  =========  =========  =========  =========  =========
</TABLE>



At  December 31, 1998, the Company had net operating loss ("NOLs") and depletion
carryforwards  for  U.S.  tax  purposes  of  $415.6  million  and $20.3 million,
respectively.  The  U.S.  NOLs  expire  from  1999  through  2012  as  follows:


<TABLE>
<CAPTION>

<S>                  <C>
                       NOLS
                     EXPIRING
                      BY YEAR
                     ---------

May 1999             $  16,745
May 2000                19,571
May 2001                30,389
May 2002                22,670
May 2003                20,566
May 2004 - May 2012    305,668
                     ---------

                     $ 415,609
                     =========
</TABLE>



At  December  31,  1998,  the  Company's  Colombian operations and other foreign
operations  had  NOLs  and other credit carryforwards totaling $42.3 million and
$31.7  million,  respectively.  The  NOLs  expire  from  1999  through  2008.

The  deferred  tax valuation allowance of $93.6 million at December 31, 1998, 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 $246 million and $42 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  increasing  income  from  its  operations.

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

12.     EMPLOYEE  BENEFITS

PENSION  PLANS

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


<PAGE>
The  funding  status  of  the  plans  follows:


<TABLE>
<CAPTION>

                                                               DECEMBER 31,
                                                 ----------------------------------------
                                                         1998                1997
                                                 -------------------  -------------------
                                                  DEFINED              DEFINED
                                                  BENEFIT     SERP     BENEFIT     SERP
                                                   PLAN       PLAN      PLAN       PLAN
                                                 ---------  --------  ---------  --------

<S>                                              <C>        <C>       <C>        <C>
Change in benefit obligation:
  Benefit obligation at beginning of year        $  6,008   $ 6,621   $  4,849   $ 5,288
  Service cost                                        560       799        343       489
  Interest cost                                       438       607        375       408
  Amendments                                          ---       434        ---       ---
  Actuarial loss/(gain)                               472       913        756       699
  Benefits paid                                      (377)   (1,617)      (315)     (263)
  Curtailment gain                                   (666)   (1,178)       ---       ---
                                                 ---------  --------  ---------  --------

Benefit obligation at end of year                   6,435     6,579      6,008     6,621
                                                 ---------  --------  ---------  --------

Change in plan assets:
  Fair value of plan assets at beginning of year    5,531       ---      4,789       ---
  Actual return on plan assets                      1,446       ---        921       ---
  Company contribution                                468     1,617        136       263
  Benefits paid                                      (377)   (1,617)      (315)     (263)
                                                 ---------  --------  ---------  --------

    Fair value of plan assets at end of year        7,068       ---      5,531       ---
                                                 ---------  --------  ---------  --------

Reconciliation:
  Funded status                                       633    (6,579)      (477)   (6,621)
  Unrecognized actuarial (gain)/loss                 (908)      480        250       745
  Unrecognized transition (asset)/obligation           (8)      695        (10)    1,288
  Unrecognized prior service cost                     373       253        598       133
                                                 ---------  --------  ---------  --------

    Prepaid/(accrued) pension cost                     90    (5,151)       361    (4,455)
                                                 ---------  --------  ---------  --------

    Adjustment for minimum liability                  ---       ---        ---      (326)
                                                 ---------  --------  ---------  --------

    Adjusted prepaid/(accrued) pension cost      $     90   $(5,151)  $    361   $(4,781)
                                                 =========  ========  =========  ========


</TABLE>

A  summary  of  the  components  of  pension  expense  follows:


<TABLE>
<CAPTION>

<S>                                    <C>      <C>      <C>
                                           YEAR ENDED DECEMBER 31,
                                          -------------------------
                                           1998      1997    1996
                                          -------  -------  -------

Components of net periodic pension cost:
  Service cost                            $1,359   $  832   $  767
  Interest cost                            1,045      783      736
  Expected return on plan assets            (481)    (416)    (375)
  Amortization of transition obligation      591      166      166
  Amortization of prior service cost         538       67       66
                                          -------  -------  -------

    Net periodic pension cost             $3,052   $1,432   $1,360
                                          =======  =======  =======
</TABLE>




<PAGE>
The  projected  benefit  obligations  at  December  31,  1998 and 1997, assume a
discount  rate  of  6.75%  and  7.5%,  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.

13.     SHAREHOLDERS'  EQUITY

5%  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 ("5% Preference
Shares"),  par  value $.01.  Each share of the Company's 5% Preference Shares is
convertible  into one Triton ordinary share and bears a cash dividend, which has
priority  over  dividends  on Triton's ordinary shares, equal to 5% per annum on
the  redemption price of $34.41 per share, payable semi-annually on March 30 and
September  30  of each year.  The 5% Preference Shares have priority over Triton
ordinary  shares upon liquidation, and may be redeemed at Triton's option at any
time  on  or  after March 30, 1998, 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,  1998,  1997 and 1996, 209,639, 218,285 and
247,469  5%  Preference  Shares  were  outstanding,  respectively.

8%  PREFERENCE  SHARES

In  August  1998, the Company entered into the Stock Purchase Agreement with HM4
Triton.  The  First  Closing,  as  contemplated by the Stock Purchase Agreement,
occurred  on  September  30,  1998,  pursuant to which the Company issued to HM4
Triton  1,822,500  shares  of  8%  Preference Shares for $70 per share, or total
proceeds  of  $127.6  million  (before  expenses  of  $10.8  million).  Each  8%
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% 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, commencing June 30, 1999.  At
the  Company's  option,  dividends  may  be  paid  in cash or by the issuance of
additional  whole  shares  of  8%  Preference  Shares.  Holders of 8% 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 share of 8%
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.

ORDINARY  SHARES

Changes  in  issued  ordinary  shares  were  as  follows:


<TABLE>
<CAPTION>

<S>                                 <C>          <C>         <C>
                                          YEAR ENDED DECEMBER 31,
                                    ------------------------------------
                                       1998         1997        1996
                                    -----------  ----------  -----------

Balance at beginning of year        36,541,064   36,342,181  35,927,279
  Exercise of employee stock options
   and debentures                       47,238      133,736     258,333
  Issuances under stock plans           46,648       35,961       9,910
  Conversion of 5% preference shares     8,646       29,184     162,548
  Other, net                              (118)           2     (15,889)
                                    -----------  ----------  -----------

Balance at end of year              36,643,478   36,541,064  36,342,181
                                    ===========  ==========  ===========


</TABLE>


Changes  in  ordinary  shares  held  in  treasury  were  as  follows:


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

                                                 YEAR ENDED DECEMBER 31,
                                              ----------------------------
                                                1998      1997      1996
                                              --------  --------  --------

Balance at beginning of year                       73        40    26,635
  Purchase of treasury shares                      64        33        91
  Transfer of shares to employee benefit plans    ---       ---   (10,797)
  Retirement of treasury shares                  (137)      ---   (15,889)
                                              --------  --------  --------

Balance at end of year                           ---        73         40
                                              ========  ========  ========




</TABLE>


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 or its affiliates, including
Hicks,  Muse,  Tate & Furst Incorporated, will not result in the distribution of
rights unless and until HM4 Triton'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), each right not owned by such person generally becomes the right to
purchase  such  number  of  ordinary  shares  of the Company equal to the number
obtained  by  dividing the right's exercise price (currently $120) by 50% of the
market  price  of  the  ordinary  shares on the date of the first occurrence. In
addition,  if  the Company is subsequently merged or certain other extraordinary
business  transactions  are consummated, each right generally becomes a right to
purchase  such number of shares of common stock of the acquiring person equal to
the  number obtained by dividing the right's exercise price by 50% of the market
price  of  the  common  stock  on  the  date  of  the  first  occurrence.

Under certain circumstances, the Company's directors may determine that a tender
offer  or  merger  is fair to all shareholders and prevent the rights from being
exercised.  At  any  time  after  a  person or group acquires 15% or more of the
ordinary  shares  outstanding (other than with respect to  HM4 Triton) 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.

14.     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%
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,  1998  and  1997,  shares  available  for grant were 2,521,133 and
1,040,965,  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, 1998     DECEMBER 31, 1997     DECEMBER 31, 1996
                                         --------------------- --------------------- ---------------------
                                                      WEIGHTED              WEIGHTED             WEIGHTED
                                                      AVERAGE               AVERAGE              AVERAGE
                                                      EXERCISE              EXERCISE             EXERCISE
                                            SHARES     PRICE      SHARES     PRICE      SHARES     PRICE
                                         ------------ -------- ------------ -------- ------------ --------
Outstanding at beginning of year           4,449,435   $39.05   3,854,046   $38.81   3,177,304   $35.49
Granted                                    2,894,603    20.56     744,250    39.99     971,000    47.97
Exercised                                    (47,238)   29.30     (83,736)   30.76    (216,333)   30.40
Canceled                                  (3,239,593)   38.39     (65,125)   46.09     (77,925)   40.74
                                         ------------          ------------          ------------

Outstanding at end of year                 4,057,207    26.51   4,449,435    39.05   3,854,046    38.81
                                         ============          ============          ============

Options exercisable at year-end            2,804,584            2,728,254            2,042,492
Weighted average fair value of options:
  Granted at market prices               $      6.12           $    16.37           $    19.89
  Granted at greater than market prices  $      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.

The  following  table  summarizes information about stock options outstanding at
December  31,  1998:


<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, 1998      LIFE       PRICE     DEC. 31, 1998    PRICE
--------------  --------------  -----------  ---------  --------------  ---------

$ 8.38 - 19.88      1,780,453    4.7 years   $  15.66         646,330   $  15.02
 25.13 - 39.63      1,581,504    3.9 years      30.23       1,526,504      30.36
 40.25 - 49.13        386,250    4.2 years      41.47         342,750      41.60
 50.25 - 52.25        309,000    4.9 years      51.24         289,000      51.29
                --------------                          --------------

                    4,057,207                               2,804,584
                ==============                          ==============

</TABLE>

<PAGE>


CONVERTIBLE  DEBENTURE  PLAN


Under  the  Company's Amended and Restated Convertible Debenture Plan, executive
officers  of  the  Company  have  from  time  to time purchased from the Company
convertible  debentures  convertible  into Ordinary Shares at a conversion price
equal  to  the  market value of the Ordinary Shares at the date of purchase. The
consideration for the convertible debentures given by each executive officer was
a personal promissory note payable to the Company in a principal amount equal to
the  principal amount of the convertible debentures purchased. In July 1998, the
Company  agreed  with  each  of its executive officers to exchange the Company's
interest  in  the  officer's  note for the officer's interest in the convertible
debentures.  In  connection  with  his  severance  from the Company, the Company
redeemed  the  convertible  debentures  held  by  a  former executive officer in
accordance  with  their terms. As a result, all outstanding debentures, totaling
$14.2  million,  were  cancelled.


EMPLOYEE  STOCK  PURCHASE  PLAN

The  Company  has an employee stock purchase plan that provides for the award of
ordinary  shares  to  key  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 46,648 shares
and  24,961  shares to employees for the years ended December 31, 1998 and 1997,
respectively.

FAIR  VALUE  OF  STOCK  COMPENSATION

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


<TABLE>
<CAPTION>

<S>                                                 <C>         <C>        <C>
                                                       YEAR ENDED DECEMBER 31,
                                                    ------------------------------
                                                       1998       1997      1996
                                                    ----------  ---------  -------
Net earnings (loss) applicable to ordinary shares:
  As reported                                       $(190,565)  $ (9,296)  $21,624
  Pro forma                                          (200,147)   (16,802)   17,414

Basic earnings (loss) per ordinary share:
  As reported                                       $   (5.21)  $  (0.26)  $  0.61
  Pro forma                                             (5.47)     (0.46)     0.48

Diluted earnings (loss) per ordinary share:
  As reported                                       $   (5.21)  $  (0.25)  $  0.59
  Pro forma                                             (5.47)     (0.46)     0.47
</TABLE>



The  fair value of each option or debenture granted was estimated on the date of
grant  using  the Black-Scholes option-pricing model with the following weighted
average  assumptions  used  for grants in 1998, 1997 and 1996: dividend yield of
0%; expected volatility of approximately 40%, 26% and 27%, respectively;
risk-free interest rates of approximately 5%, 6% and 6%, respectively; and an
expected life of approximately four to seven  years.

STOCK  APPRECIATION  RIGHTS  PLAN

The  Company  has a stock appreciation rights ("SARs") plan which authorizes the
granting  of SARs to non-employee directors of the Company.  Upon exercise, SARs
allow  the holder to receive the difference between the SARs' exercise price and
the  fair  market  value  of the ordinary shares covered by SARs on the exercise
date and expire at the earlier of 10 years or a date based on the termination of
the  holder's  membership on the board of directors.  At December 31, 1998, SARs
covering 20,000 ordinary shares, with an exercise price of $8.00 per share, were
outstanding.

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

FAIR VALUE OF FINANCIAL INSTRUMENTS

At  December  31,  1998  and  1997, the Company's financial instruments included
cash,  cash  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 $397
million  (carrying value - $428 million) and $596 million (carrying value - $574
million)  at  December  31,  1998  and  1997,  respectively.

RISK  MANAGEMENT

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

During  the  year  ended  December  31,  1998,  the  Company  did  not  have any
outstanding  financial  market  transactions  to  hedge  against  oil  price
fluctuations.  During  the  years  ended  December  31,  1997  and 1996, markets
provided  the  Company  the  opportunity  to realize WTI benchmark oil prices on
average  $2.35  per  barrel  and  $4.68  per barrel, respectively, above the WTI
benchmark  oil  price the Company set as part of its annual plan for the period.
As  a  result  of financial and commodity market transactions settled during the
years  ended  December  31, 1997 and 1996, the Company's risk management program
resulted  in  an  average  net  realization of approximately $.11 per barrel and
$1.21  per  barrel, respectively, lower than if the Company had not entered into
such  transactions.

In  anticipation  of  entering  into  a  forward  oil  sale, in 1995 the Company
purchased  WTI  benchmark  call  options  to  retain the ability to benefit from
future  WTI price increases above a weighted average price of $20.42 per barrel.
The  volumes  and expiration dates on the call options coincide with the volumes
and delivery dates of the forward oil sale.  During the years ended December 31,
1998,  1997  and  1996,  the  Company  recorded an unrealized gain (loss) of $.4
million,  ($9.7  million)  and  $11  million, respectively, in other income, net
related  to  the  change  in  the fair market value of the call options.  Future
fluctuations  in  the  fair  market  value  of the call options will continue to
affect  other  income  as  noncash  adjustments.

CONCENTRATION  OF  CREDIT  RISK

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

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

<PAGE>
16.     OTHER  INCOME,  NET

Other  income,  net  is  summarized  as  follows:


<TABLE>
<CAPTION>

<S>                                         <C>       <C>       <C>
                                               YEAR ENDED DECEMBER 31,
                                            ----------------------------
                                              1998       1997     1996
                                            --------  --------  --------

Gain on sale of corporate assets             $7,593    $1,414     $---
Equity swap                                  (3,283)      ---      ---
Foreign exchange gain (loss)                  2,113     9,549      (561)
Change in fair market value of WTI
    benchmark call options                      366    (9,689)   10,987
Proceeds from legal settlements                 ---       765     7,624
Gain on sale of shareholdings in Crusader       ---       ---    10,417
Loss provisions                                (750)      ---    (3,193)
Other                                         2,441       833     2,087
                                            --------  --------  --------

                                            $ 8,480   $ 2,872   $27,361
                                            ========  ========  ========
</TABLE>



During  1998  and  1997,  the  Company  sold  certain  corporate assets for cash
proceeds of $20.6 million and $1.8 million, respectively.  In 1998 and 1997, the
Company  recognized  foreign  exchange  gains  of $2.1 million and $9.5 million,
respectively,  primarily  noncash  adjustments  to  deferred  tax liabilities in
Colombia  associated  with  devaluation  of  the  Colombian peso versus the U.S.
dollar.

17.     EARNINGS  PER  ORDINARY  SHARE

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.

<PAGE>

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,  1997  and  1996.



<TABLE>
<CAPTION>

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



YEAR ENDED DECEMBER 31, 1996:

Earnings from continuing operations          $     23,805
Less: Preference share dividends                     (985)
                                             -------------

Earnings available to ordinary shareholders        22,820
        Basic earnings per ordinary share                         35,929   $       0.64
                                                                           =============
Effect of dilutive securities
        Stock options                                 ---            843
        Convertible debentures                        ---            147
                                             -------------  -------------
Earnings available to ordinary shareholders
   and assumed conversions                   $     22,820
                                             =============
        Diluted earnings per ordinary share                       36,919   $       0.62
                                                            =============  =============
</TABLE>


At  December  31,  1998,  1,822,500  shares  of 8% Preference Shares and 209,639
shares  of  5%  Preference Shares were outstanding.  Each 8% Preference Share is
convertible any time into four ordinary shares, subject to adjustment in certain
events.  Each  5%  Preference  Share  is  convertible any time into one ordinary
share, subject to adjustment in certain events.  The 8% Preference Shares and 5%
Preference  Shares  were not included in the computation of diluted earnings per
ordinary  share because the effect of assuming conversion was antidilutive.  The
Company  issued  an  additional  3,177,500 8% Preference Shares in January 1999,
which will affect diluted earnings per share in future periods.  See note 2, Pro
Forma  Balance  Sheet  -  8%  Preference  Share  Issuance.

<PAGE>
18.     STATEMENTS  OF  CASH  FLOWS

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


<TABLE>
<CAPTION>

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

                                            YEAR ENDED DECEMBER 31,
                                          ----------------------------
                                             1998    1997       1996
                                          -------- --------   --------
Cash  paid  during  the  year  for:
  Interest (net of amount capitalized)    $24,517  $133,265   $   ---
  Income taxes                              4,339     4,666       200

Noncash financing activities:
  Conversion of preference shares into
      ordinary shares                     $   297  $  1,004   $  5,594



</TABLE>


At  December  31, 1998, the Company had an accrual of $2.7 million for dividends
declared  with  respect to the 8% Preference Shares, which was paid during 1999.


Cash paid for interest in 1997 included $124.8 million of interest accreted with
respect to the 1997 Notes and the 9 3/4% Notes through the dates of retirement.
Proceeds  from  the  sale  of  available-for-sale securities were $2 million and
$19.5  million  in  the  years  ended  December 31, 1997 and 1996, respectively.

19.     RELATED  PARTY  TRANSACTIONS

Pursuant  to a financial advisory agreement (the "Financial Advisory Agreement")
between  Triton  and Hicks, Muse & Co. Partners L.P., an affiliate of Hicks Muse
("Hicks  Muse  Partners"), the Company paid Hicks Muse Partners transaction fees
aggregating  approximately $9.6 million for services as financial advisor to the
Company  in connection with the First Closing 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
year  ended  December 31, 1998, the Company paid Hicks Muse Partners $.1 million
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 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% Preference Shares held by HM4 Triton
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.

20.     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 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.  Forward-looking  statements  may be identified, without limitation,
by  the  use  of  the  words  "anticipates," "estimates," "expects," "believes,"
"intends,"  "plans"  and  similar  expressions.  These  statements  include
information  regarding  drilling  schedules;  expected  or  planned  production
capacity;  the  closing  of branch offices; future production of the Fields; the
negotiation  of a gas-sales contract, completion of development and commencement
of  production  in  Malaysia-Thailand;  the  Company's capital budget and future
capital  requirements;  the  Company's  meeting its future capital needs; future
general  and  administrative  expense  and the portion to be capitalized; future
interest expense and the portion to be capitalized; the Company's realization of
its  deferred  tax  asset;  the  level  of future expenditures for environmental
costs; the outcome of regulatory and litigation matters; the impact of Year 2000
issues; 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  Company's  strategy  is  to  focus  its  exploration activities on what the
Company  believes  are relatively high-potential prospects.  No assurance can be
given  that these prospects contain significant oil and gas reserves or that the
Company  will  be successful in its exploration activities thereon.  The Company
follows  the  full  cost method of accounting for exploration and development of
oil  and gas reserves whereby all acquisition, exploration and development costs
are  capitalized.  Costs related to acquisition, holding and initial exploration
of  licenses  in  countries  with  no proved reserves are initially capitalized,
including  internal  costs directly identified with acquisition, exploration and
development  activities.  The  Company's  exploration  licenses are periodically
assessed  for  impairment  on  a  country-by-country  basis.  If  the  Company's
investment in exploration licenses within a country where no proved reserves are
assigned  is  deemed  to be impaired, the licenses are written down to estimated
recoverable value.  If the Company abandons all exploration efforts in a country
where  no  proved  reserves  are assigned, all 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, 1998, including capitalized costs by geographic area, is set forth
in  note  22.

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

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

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

CERTAIN  FACTORS  RELATING  TO  INTERNATIONAL  OPERATIONS

The  Company  derives  substantially  all  of  its  consolidated  revenues  from
international  operations.  Risks  inherent  in international operations include
loss  of  revenue,  property  and  equipment from such hazards as expropriation,
nationalization,  war,  insurrection and other political risks; trade protection
measures;  risks  of  increases  in  taxes  and  governmental  royalties;  and
renegotiation  of  contracts  with  governmental entities; as well as changes in
laws and policies governing operations of other companies.  Other risks inherent
in  international  operations  are  the  possibility  of  realizing  economic
currency-exchange  losses  when  transactions  are completed in currencies other
than  U.S.  dollars  and the Company's ability to freely repatriate its earnings
under  existing  exchange  control  laws.  To  date, the Company's international
operations  have  not  been  materially  affected  by  these  risks.

CERTAIN  FACTORS  RELATING  TO  COLOMBIA

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

From time to time, guerrilla activity in Colombia has disrupted the operation of
oil  and gas projects causing increased costs.  Such activity increased over the
last  year,  causing  delays in the development of the Cupiagua Field.  Although
the  Colombian  government,  the  Company  and  its partners have taken steps to
maintain  security  and favorable relations with the local population, there can
be  no  assurance  that attempts to reduce or prevent guerrilla activity will be
successful or that guerrilla activity will not disrupt operations in the future.

 Colombia is among several nations whose progress in stemming the production and
transit  of illegal drugs is subject to annual certification by the President of
the  United  States.  The  President  of  the  United  States has announced that
Colombia  would  be  certified.   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 northeast of Kuala Lumpur and 750
kilometers  south of Bangkok as a contractor under a production-sharing contract
covering  Block  A-18  of  the  Malaysia-Thailand  Joint Development Area.  Test
results  to  date  indicate that significant gas and oil deposits lie within the
block.  Development  of gas production is in the planning stage, but is expected
to  take  several  years  and  require  the drilling of additional wells and the
installation  of  production  facilities.  Pipelines also will be required to be
connected  between  Block  A-18 and ultimate markets.  The terms under which any
gas  produced  from the Company's contract area in Malaysia-Thailand is sold may
be  affected  adversely by the present monopoly, gas-purchase and transportation
conditions  in  both  Malaysia  and  Thailand.  In connection with the sale to a
subsidiary  of  ARCO  of one-half of the shares of the Company's subsidiary that
held  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.  See note 5 -
Asset  Dispositions.

INFLUENCE  OF  HICKS  MUSE

In  connection with the issuance of the 1,822,500 shares of 8% Preference Shares
to  HM4  Triton  in  September  1998,  the Company and HM4 Triton 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 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 (and its designated
transferees, collectively) may designate four nominees for election to the Board
(with such number of designees increasing or decreasing proportionately with any
change  in  the  total  number  of  members of the Board and with any fractional
directorship  rounded up to the next whole number). The right of HM4 Triton (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 and its
affiliates  (assuming  conversion of  8% Preference Shares into ordinary shares)
represents  less  than  certain  specified percentages of the number of ordinary
shares  (assuming  conversion  of  8%  Preference  Shares  into ordinary shares)
purchased  by  HM4  Triton pursuant to the Stock Purchase Agreement.

The  Shareholders  Agreement  provides  that,  for so long as HM4 Triton and its
affiliates  continue  to  hold  a  certain  minimum  number  of  ordinary shares
(assuming  conversion of 8% Preference Shares into ordinary shares), the Company
may  not  take  certain actions without the consent of HM4 Triton, including (i)
amending  its  Articles  of Association or the terms of the 8% Preference Shares
with  respect  to  the voting powers, rights or preferences of the holders of 8%
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%  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% 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%  Preference  Shares,  other  than  regular  dividends on the
Company's  5%  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% Preference Shares, other than in
payment of accumulated dividends on the outstanding 8% Preference Shares, (viii)
issuing  any  shares  of  a  class  ranking equal or senior to the 8% 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%
Preference  Shares.

As  a  result  of  HM4  Triton's  ownership of 8% Preference Shares and ordinary
shares  and  the  rights conferred upon HM4 Triton and its designees pursuant to
the Shareholder Agreement, HM4 Triton 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  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, and the interests of HM4 Triton
as  a  shareholder may be different from the interests of the other shareholders
of  the  Company.

COMPETITION

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

MARKETS

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

LITIGATION

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

<PAGE>
21.     COMMITMENTS  AND  CONTINGENCIES

For  internal  planning purposes, the Company's capital spending program for the
year  ending  December  31,  1999,  is  approximately  $117  million,  excluding
capitalized  interest,  of which approximately $83 million relates to the Fields
and  $34  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 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 2002.  Total rental expense was $2.1 million,
$2  million and $2 million for the years ended December 31, 1998, 1997 and 1996,
respectively.  At  December  31, 1998, the minimum payments required under terms
of the leases are as follows 1999 -- $1.8 million; 2000 -- $1.1 million; 2001 --
$.1  million;  and  2002  --  nil.

GUARANTEES

At  December  31,  1998,  the Company had guaranteed loans of approximately $1.4
million  for  a Colombian pipeline company in which the Company has an ownership
interest.  The  Company  also  guaranteed performance of $21.6 million in future
exploration  expenditures  in  various  countries.  These commitments are backed
primarily  by  unsecured  letters  of  credit.

ENVIRONMENTAL  MATTERS

The  Company  is subject to extensive environmental laws and regulations.  These
laws  regulate the discharge of oil, gas or other materials into the environment
and  may  require the Company to remove or mitigate the environmental effects of
the disposal or release of such materials at various sites. 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.  Each case was
filed on behalf of a putative class of persons and/or entities who purchased the
Company's  securities  between March 30, 1998, and July 17, 1998, inclusive, and
seeks  recovery  of  compensatory  damages,  fees  and  costs.  The cases allege
violations  of  securities  laws  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. Additionally, one case alleges
negligent misrepresentation and seeks recovery of punitive damages. On September
21,  1998, a motion for consolidation and for appointment as lead plaintiffs and
for  approval  of selection of lead counsel was filed with respect to the cases.
With  the  exception of the request for consolidation, which has been agreed to,
the  motion  is  presently  pending.  Also,  pending  is the Company's motion to
dismiss  or  transfer  for  improper  venue.

The  Company believes it has meritorious defenses to these claims and intends to
vigorously defend these actions.   No discovery has been taken at this time,
however,and the  ultimate  outcome  is not currently predictable.  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.

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

22.     GEOGRAPHIC  INFORMATION

In  June 1997, the Financial Accounting Standards Board issued Statement No. 131
("SFAS  131"),  "Disclosures  about  Segments  of  an  Enterprise  and  Related
Information."  SFAS  131  changes  the  way enterprises report information about
operating  segments  and  related  disclosures  about  products  and  services,
geographic  areas  and  major  customers.  The Company adopted SFAS 131 in 1998.
Information  for  1997  and  1996  has  been  restated  from  the  prior  year's
presentation  in  order  to  conform  to  the  1998  presentation.

Triton's  operations  are  primarily  related  to  crude  oil  and  natural-gas
exploration  and  production. The Company's principle properties, operations and
oil and gas reserves are located in Colombia and Malaysia-Thailand.  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:

<PAGE>


<TABLE>
<CAPTION>

<S>                                        <C>         <C>          <C>            <C>          <C>
                                                                                    CORPORATE
                                                        MALAYSIA-                      AND
                                            COLOMBIA    THAILAND     EXPLORATION      OTHER        TOTAL
                                           ----------  -----------  -------------  -----------  -----------
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        (79,827)     (39,360)    (277,346)
Depreciation, depletion and amortization      53,641           49            176        4,945       58,811
Writedown of assets                          251,312          ---         76,664          654      328,630
Capital expenditures                         106,624       25,158         47,516          756      180,054
Assets                                       468,533       86,928         88,852      111,820      756,133

YEAR ENDED DECEMBER 31, 1997:
Sales and other operating revenues         $ 145,419   $      ---   $      4,077   $      ---   $  149,496
Operating income (loss)                       59,719         (536)        (6,312)     (20,167)      32,704
Depreciation, depletion and amortization      31,186           60            505        5,077       36,828
Capital expenditures                         129,589       37,328         47,842        4,457      219,216
Assets                                       712,512      148,780        110,561      126,186    1,098,039

YEAR ENDED DECEMBER 31, 1996:
Sales and other operating revenues         $ 127,071   $      ---   $      6,906   $      ---   $  133,977
Operating income (loss)                       70,874         (509)       (44,098)     (23,489)       2,778
Depreciation, depletion and amortization      19,061           38            807        5,734       25,640
Writedown of assets                              ---          ---         42,960          ---       42,960
Capital expenditures                         160,131       53,679         29,036        9,838      252,684
Assets                                       629,978      113,364         57,849      113,333      914,524
</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  profit  (loss).  See  note  5  --Asset  Dispositions.

Colombia  operating profit (loss) for the year ended December 31, 1998, included
an  SEC  full  cost ceiling limitation writedown of $241 million.  Additionally,
Exploration  operating  profit  (loss)  included  writedowns  of  oil  and  gas
properties  and  other  assets  in  Guatemala  ($27.2  million) and China ($22.5
million)  for  the  year  ended December 31, 1998.  Exploration operating profit
(loss) for the year ended December 31, 1996, included a writedown of $43 million
for  the  Company's  oil  and gas properties and other assets in Argentina.  See
note  3  -  Writedown  of  Assets.

At  December  31,  1998,  corporate  assets  were  principally  cash  and  cash
equivalents,  the  U.S.  deferred  tax asset and other fixed assets. Exploration
assets included $43.9 million, $14.9 million, $10.8 million and $10.2 million of
capitalized  costs  in  Italy, Greece, Equatorial Guinea and Oman, respectively.

<PAGE>
23.     SUBSEQUENT  EVENT

On  January  4,  1999, the Company issued 3,177,500 8% Preference Shares for $70
per  share, or total proceeds of $222.4 million (before closing expenses of $4.3
million).  See note 2,  Pro Forma Balance Sheet - 8% Preference Shares Issuance.



24.  QUARTERLY FINANCIAL DATA (UNAUDITED)


<TABLE>
<CAPTION>

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

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

YEAR ENDED DECEMBER 31, 1997:
Sales and other operating revenues              $33,759  $  32,569   $ 36,993  $  46,175
Gross profit                                     15,095     13,645     14,583     17,988
Net earnings (loss) before extraordinary item     3,486       (308)     6,201     (3,784)
Net earnings (loss)                               3,486    (14,799)     6,201     (3,784)
Basic earnings (loss) per ordinary share:
      Before extraordinary item                    0.09      (0.01)      0.16      (0.10)
      Net earnings (loss)                          0.09      (0.41)      0.16      (0.10)
Diluted earnings (loss) per ordinary share:
      Before extraordinary item                    0.09      (0.01)      0.16      (0.10)
      Net earnings (loss)                          0.09      (0.41)      0.16      (0.10)
</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.

In  the  fourth  quarter  of  1998,  the  Company recorded a writedown of $115.9
million,  net  of  tax,  related  to  the  application  of the full cost ceiling
limitation  as  prescribed  by  the  SEC.    See  note  3 - Writedown of Assets.

25.     OIL  AND  GAS  DATA  (UNAUDITED)

The  following tables provide additional information about the Company's oil and
gas  exploration  and  production  activities.

<PAGE>
RESULTS  OF  OPERATIONS

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


<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)
                                      ==========  ==========  =========  ===========

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
                                      ==========  ==========  =========  ===========

YEAR ENDED DECEMBER 31, 1996:
        Revenues                      $ 127,071   $     ---   $  6,906   $  133,977
        Costs:
          Production costs               34,822         ---      1,832       36,654
          General operating expenses      1,909         ---      1,327        3,236
          Depletion                      18,515         ---        603       19,118
          Writedown of assets               ---         ---     42,960       42,960
          Income tax expense (benefit)   25,766         ---    (12,888)      12,878
                                      ----------  ----------  ---------  -----------

        Results of operations         $  46,059   $     ---   $(26,928)  $   19,131
                                      ==========  ==========  =========  ===========
</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,  1997,  and 1996, included gains of $4.5
million,  $4.1  million,  and  $4.1  million  from  the  sale  of  the Company's
Bangladesh  subsidiary,  Argentine  subsidiary,  and  royalty  interests in U.S.
properties,  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>

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

DECEMBER  31,  1998:
Costs incurred:
  Property acquisition                      $    ---   $    ---   $    500   $    500
  Exploration                                  2,886     21,215     48,756     72,857
  Development                                 83,088      1,026        ---     84,114
Depletion per equivalent
  barrel of production                          4.07        ---        ---       4.07

Cost of properties at year-end:
  Unevaluated                               $    ---   $ 20,392   $ 70,526   $ 90,918
                                            =========  =========  =========  =========

  Evaluated                                 $467,147   $ 65,102   $ 76,367   $608,616
                                            =========  =========  =========  =========

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

DECEMBER 31, 1997:
Costs incurred:
  Property acquisition                      $    ---   $    ---   $  3,128   $  3,128
  Exploration                                  7,583     36,373     47,864     91,820
  Development                                 62,251        187        ---     62,438
Depletion per equivalent
  barrel of production                          3.67        ---        ---       3.67

Cost of properties at year-end:
  Unevaluated                               $  2,172   $ 30,327   $ 98,127   $130,626
                                            =========  =========  =========  =========

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

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

DECEMBER 31, 1996:
Costs incurred:
  Property acquisition                      $    ---   $    ---   $    600  $     600
  Exploration                                 18,875     60,955     33,103    112,933
  Development                                 39,902        470        ---     40,372
Depletion per equivalent
  barrel of production                          2.83        ---       3.11       2.84

Cost of properties at year-end:
  Unevaluated                               $  2,487   $ 30,500   $ 50,010   $ 82,997
                                            =========  =========  =========  =========

  Evaluated                                 $338,955   $ 77,512   $ 48,630   $465,097
                                            =========  =========  =========  =========

  Support equipment and
   facilities                               $194,116   $   ---    $    ---   $194,116
                                            =========  =========  =========  =========
Accumulated depletion and
  depreciation at year-end                  $ 35,723   $   ---    $ 48,630   $ 84,353
                                            =========  =========  =========  =========


</TABLE>

A summary of costs excluded from depletion at December 31, 1998, by year
incurred follows:





<TABLE>
<CAPTION>

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


                                        DECEMBER 31,
                                ----------------------------------
                                                          1995 AND
                        TOTAL     1998    1997      1996    PRIOR
                      --------  -------  -------  -------  -------
Property acquisition  $  2,800  $   500  $ 1,700  $   600  $   ---
Exploration            127,290   45,244   40,398   37,098    4,550
Capitalized interest    25,930   14,051   11,758      106       15
                      --------  -------  -------  -------  -------

    Total worldwide   $156,020  $59,795  $53,856  $37,804  $ 4,565
                      ========  =======  =======  =======  =======
</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  $85.5 million ($65.1 million and $20.4
million classified as evaluated and unevaluated, respectively) for Block A-18 in
the  Malaysia-Thailand  Joint  Development Area that will become depletable once
production  begins,  which  is  estimated  to  occur  between 30-36 months after
signing  of  a  gas-sales  contract.  Additionally,  excluded  costs  include
exploration  costs  of  $29.5 million, $12.2 million, $10.8 million, $10 million
and  $8.1  million  in  Italy,  Greece,  Equatorial Guinea, Oman and Madagascar,
respectively.  At this time, the Company is unable to predict either the timing
of the inclusion of these costs and the related oil and  gas  reserves in its
depletion computation or their potential future impact on  depletion  rates.
Drilling  or  other  exploration  activities  are  being conducted  in  each
of  these  cost  centers.


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 Fields in Colombia were
prepared  by  the  Company's  independent  petroleum  engineers,  DeGolyer  and
MacNaughton.  The estimates for the proved reserves in Malaysia-Thailand and the
Liebre  Field  in  Colombia  were  prepared  by the Company's internal petroleum
reservoir  engineers.  The  Company  emphasizes  that  reserve  estimates  are
approximate  and  are  expected  to  change  as  additional  information becomes
available.  Reservoir  engineering  is  a  subjective  process  of  estimating
underground  accumulations  of  oil  and gas that cannot be measured in an exact
way,  and  the  accuracy of any reserve estimate is a function of the quality of
available  data  and  of engineering and geological interpretation and judgment.
Accordingly,  there  can be no assurance that the reserves set forth herein will
ultimately  be  produced,  and  there  can  be  no  assurance  that  the  proved
undeveloped  reserves  will  be  developed within the periods anticipated. As of
December 31, 1998, the Company did not have a contract for the sale of gas to be
produced  from its interest in the Malaysia-Thailand Joint Development Area.  In
estimating  its reserves attributable to such interest, the Company assumed that
production from the interest would be sold at the initial base price for natural
gas specified in the Heads of Agreement entered into in April 1998. There can be
no  assurance that the price to be provided in any gas contract will be equal to
the  price  used  in  the  Company's  calculations.



<TABLE>
<CAPTION>

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


                                    COLOMBIA        MALAYSIA-THAILAND       OTHER           TOTAL WORLDWIDE
                                -----------------  -------------------  ----------------  --------------------
                                   OIL      GAS      OIL        GAS        OIL     GAS      OIL        GAS
                                --------  -------  --------  ---------  -------  -------  --------  ----------
PROVED  DEVELOPED  AND
  UNDEVELOPED  RESERVES:
AS OF DECEMBER 31, 1995         121,426   15,690       ---         ---     764    6,957   122,190      22,647
    Revisions                       270     (403)      ---         ---     ---     ---        270        (403)
    Sales                          (548)    (338)      ---         ---    (649)  (6,482)   (1,197)     (6,820)
    Extensions and discoveries   19,900      ---    24,700     871,100     ---      ---    44,600     871,100
    Production                   (5,738)    (298)      ---         ---    (115)    (475)   (5,853)       (773)
                                --------  -------  --------  ---------  -------  -------  --------  ----------

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)
    Sales                           ---      ---       ---         ---     ---      ---       ---         ---
    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
    Revisions                      (693)  (1,832)   (6,583)    (41,588)    ---      ---    (7,276)    (43,420)
    Sales                           ---      ---   (15,200)   (625,400)    ---      ---   (15,200)   (625,400)
    Extensions and discoveries      ---      ---       ---      13,500     ---      ---       ---      13,500
    Production                   (9,979)    (503)      ---         ---     ---      ---    (9,979)       (503)
                                --------  -------  --------  ---------  -------  -------  --------  ----------

AS OF DECEMBER 31, 1998         135,327   12,284     8,017     570,312     ---      ---   143,344     582,596
                                ========  =======  ========  =========  =======  =======  ========  ==========
</TABLE>


<TABLE>
<CAPTION>

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

                                                      MALAYSIA-
                                       COLOMBIA       THAILAND      TOTAL WORLDWIDE
                                    --------------  --------------  ---------------
                                     OIL      GAS     OIL     GAS     OIL     GAS
                                    ------  ------  ------  ------  ------  ------
PROVED DEVELOPED RESERVES AT:

DECEMBER 31, 1996                   67,193  11,146     ---     ---  67,193  11,146
                                    ======  ======  ======  ======  ======  ======

DECEMBER 31, 1997                   81,931  14,619     ---     ---  81,931  14,619
                                    ======  ======  ======  ======  ======  ======

DECEMBER 31, 1998                   86,039  12,284     ---     ---  86,039  12,284
                                    ======  ======  ======  ======  ======  ======
</TABLE>





STANDARDIZED  MEASURE  OF DISCOUNTED FUTURE NET CASH INFLOWS AND CHANGES THEREIN

The  following  table  presents  for  the  net  quantities of proved oil and gas
reserves a standardized measure of 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.  Future  price  changes were considered only to the extent provided by
contractual  agreements  in  existence  at  year-end.

Future  production  and  development  costs  were  computed  by estimating those
expenditures  expected  to  occur in developing and producing the proved oil and
gas  reserves  at  the  end  of  the year, based on year-end costs.  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 of the subsidiary
through  which the Company owned its 50% share of 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  objective  are met by such dates, or $40 million
each  if the objectives are met within one year thereafter.  Future cash inflows
for  Malaysia-Thailand  at  December 31, 1998, include incentive payments of $65
million  each  in July 2002 and July 2005.  As of December 31, 1998, the Company
did  not have a contract for the sale of gas to be produced from its interest in
the  Malaysia-Thailand  Joint Development Area.  In estimating discounted future
net  cash  inflows  attributable  to  such  interest,  the  Company assumed that
production from the interest would be sold at the initial base price for natural
gas  specified  in  the  Heads  of  Agreement  entered  into  in  April  1998.


<TABLE>
<CAPTION>

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


                                                       MALAYSIA-     TOTAL
                                            COLOMBIA   THAILAND    WORLDWIDE
                                           ----------  ----------  ----------
DECEMBER 31, 1998:
      Future cash inflows                  $1,481,065  $1,555,929  $3,036,994
      Future production and
        development costs                     734,025     695,575   1,429,600
                                           ----------  ----------  ----------
      Future net cash inflows before
        income taxes                       $  747,040  $  860,354  $1,607,394
                                           ==========  ==========  ==========

      Future net cash inflows before
        income taxes discounted at 10%
        per annum                          $  415,127  $  253,535  $  668,662
      Future income taxes discounted at
        10% per annum                           3,909       8,917      12,826
                                           ----------  ----------  ----------
      Standardized measure of discounted
        future net cash inflows            $  411,218  $  244,618  $  655,836
                                           ==========  ==========  ==========

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>






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


                                                       MALAYSIA-     TOTAL
                                            COLOMBIA   THAILAND    WORLDWIDE
                                           ----------  ----------  ----------
DECEMBER 31, 1996:
      Future cash inflows                  $3,519,893  $2,530,702  $6,050,595
      Future production and
        development costs                   1,283,851   1,188,981   2,472,832
                                           ----------  ----------  ----------
      Future net cash inflows before
        income taxes                       $2,236,042  $1,341,721  $3,577,763
                                           ==========  ==========  ==========

      Future net cash inflows before
        income taxes discounted at 10%
        per annum                          $1,283,158  $  320,900  $1,604,058
      Future income taxes discounted at
        10% per annum                         290,763      21,100     311,863
                                           ----------  ----------  ----------
      Standardized measure of discounted
        future net cash inflows            $  992,395  $  299,800  $1,292,195
                                           ==========  ==========  ==========

</TABLE>

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


<TABLE>
<CAPTION>

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

                                                           DECEMBER 31,
                                                 -------------------------------------
                                                    1998         1997         1996
                                                 -----------  -----------  -----------
Total worldwide:
 Beginning of year                               $1,069,343   $1,292,195   $  641,696
  Sales, net of production costs                    (87,335)     (94,062)     (97,323)
  Sales of reserves                                 (70,543)         ---      (10,473)
  Revisions of quantity estimates                   (29,321)      75,253        2,617
  Net change in prices and production costs        (579,212)    (552,863)     228,349
  Extensions, discoveries and improved recovery       6,516       42,918    1,125,733
  Change in future development costs                (46,633)      (5,936)    (652,902)
  Development and facilities costs incurred         105,808       53,199       92,856
  Accretion of discount                             120,270      160,406       80,672
  Changes in production rates and other             (30,772)      (3,089)      19,088
  Net change in income taxes                        197,715      101,322     (138,118)
                                                 -----------  -----------  -----------

 End of year                                     $  655,836   $1,069,343   $1,292,195
                                                 ===========  ===========  ===========
</TABLE>






<PAGE>



                                                                     SCHEDULE II

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



<TABLE>
<CAPTION>

<S>                        <C>          <C>           <C>          <C>           <C>
                                               ADDITIONS
                                        -------------------------

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

Year ended Dec. 31, 1996:
   Allowance for doubtful
       receivables         $       810  $        35   $       ---  $      (769)  $      76
                           ===========  ============  ===========  ============  =========

   Allowance for deferred
       tax asset           $    54,046  $   (23,389)  $       ---  $       ---   $  30,657
                           ===========  ============  ===========  ============  =========

Year ended Dec. 31, 1997:
   Allowance for doubtful
       receivables         $        76  $       ---   $       ---  $       (35)  $      41
                           ===========  ============  ===========  ============  =========

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

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

   Allowance for deferred
       tax asset           $    75,092  $    18,519   $       ---  $       ---   $  93,611
                           ===========  ============  ===========  ============  =========
</TABLE>




___________________
Note --  Deductions for the allowance for doubtful receivables in the year ended
December  31,  1996,  related  primarily  to  disposal  of  other  assets.