UNITED STATES
                      SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C.  20549
(Mark  One)

 ( X )           ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                 FOR THE FISCAL YEAR ENDED: December 31, 1997

                                      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
           (Address  of  principal  executive offices)     (Zip Code)

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

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

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

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

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

                                     None.

     INDICATE  BY  CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED  TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934  DURING  THE  PRECEDING  12  MONTHS  (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT  WAS  REQUIRED  TO  FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO
SUCH  FILING  REQUIREMENTS  FOR  THE  PAST  90  DAYS.    YES X              NO
     INDICATE  BY  CHECK  MARK  IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO
ITEM  405 OF REGULATION S-K (SECTION 229.405 OF THIS CHAPTER) IS NOT CONTAINED
HEREIN,  AND  WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT'S KNOWLEDGE, IN
DEFINITIVE  PROXY  OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART
III  OF  THIS  FORM  10-K  OR  ANY  AMENDMENT  TO  THIS  FORM  10-K.
     THE  AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF
THE  REGISTRANT  AT  MARCH 16, 1998 (FOR SUCH PURPOSES ONLY, ALL DIRECTORS AND
EXECUTIVE  OFFICERS  ARE  PRESUMED  TO  BE  AFFILIATES) WAS APPROXIMATELY $1.2
BILLION,  BASED  ON THE CLOSING SALES PRICE OF $32 13/16 ON THE NEW YORK STOCK
EXCHANGE.

     AS OF MARCH 16, 1998,        36,576,047 ORDINARY SHARES OF THE REGISTRANT
                            ----------------
WERE  OUTSTANDING.

                      DOCUMENTS INCORPORATED BY REFERENCE
       PORTIONS OF THE PROXY STATEMENT PERTAINING TO THE 1998 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>
Form 10-K Item                                                             Page
--------------

PART I
ITEMS 1.   and 2.   Business and Properties                                   2
ITEM 3.    Legal Proceedings                                                 19
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                                           23
ITEM 7.    Management's Discussion and Analysis of Financial Condition and
           Results of Operations                                             24
ITEM 7.A.  Quantitative and Qualitative Disclosures about Market Risk        35
ITEM 8.    Financial Statements and Supplementary Data                       35
ITEM 9.    Changes in and Disagreements with Accountants on Accounting and
           Financial Disclosure                                              35

PART III
ITEM 10.   Directors and Executive Officers of the Registrant                36
ITEM 11.   Executive Compensation                                            36
ITEM 12.   Security Ownership of Certain Beneficial Owners and Management    36
ITEM 13.   Certain Relationships and Related Transactions                    36

PART IV
ITEM 14.   Exhibits, Financial Statement Schedules, and Reports on Form 8-K  37


</TABLE>






<PAGE>
                                    PART I


ITEMS  1.  AND  2. BUSINESS  AND  PROPERTIES

GENERAL

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

RECENT  DEVELOPMENT

          On    March  30,  1998,  the  Company  announced  that  its Board of
Directors  approved the retention of CIBC World Markets Lovegrove & Associates
and  Lehman  Brothers,  Inc.  as  independent  advisers  to assist in studying
strategic  alternatives  for  maximizing  shareholder  value.  The  strategic
alternatives  under consideration may include the sale or farmout of a portion
or  all of the Company's interest in Block A-18 of the Malaysia-Thailand Joint
Development  Area in the Gulf of Thailand, the sale of a portion or all of the
Company's  interest  in  the  Cusiana  and Cupiagua oil fields in Colombia, or
both. The Company can give no assurance that it will be successful in pursuing
any  of  these  strategic  alternatives or as to the terms upon which any such
transaction  may  ultimately  be  consummated.


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 seven licenses in Colombia.

     Cusiana  and  Cupiagua  Fields

          Contract  Terms.    In  the  foothills  of  the Llanos Basin area in
          ---------------
eastern  Colombia, Triton Colombia holds a 12% interest in the SDLA, Tauramena
and  Rio  Chitamena  contract areas, covering approximately 66,000, 36,300 and
6,700  acres,  respectively, where an active appraisal and development program
is being carried out in the Cusiana and Cupiagua fields.  Triton's partners in
these  areas  are Empresa Colombiana De Petroleos ("Ecopetrol"), the Colombian
national  oil  company, with a 50% interest, BP Exploration Company (Colombia)
Limited  ("BP"),  the  operator,  with a 19% interest, and TOTAL Exploratie en
Produktie  Maatschippij  B.V.  ("TOTAL"),  also with a 19% interest.  In 1993,
Ecopetrol  declared  the  Cusiana  and  Cupiagua  fields  to be commercial and
exercised  its right to acquire a 50% interest.  Triton's net revenue interest
is  approximately  9.6% after governmental royalties.  Triton's net revenue is
reduced  by up to 0.36% pursuant to an agreement with an original co-investor,
subject  to  Triton being reimbursed for a proportionate share of expenditures
relating  thereto.

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

          Within  the  first  quarter of 2005, an independent determination of
the original barrels of oil equivalent ("BOE") of petroleum in place under the
unified  area  and under each association contract will be made. 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, Triton Colombia and
          ------------------------
its  working interest partners have completed and have in service 36 producing
wells,  10 gas injection wells and one water injection well. The gas injection
wells recycle to the reservoir 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  well  is injecting 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 it is
expected  that  13  oil-production  and  gas-injection wells will be completed
during 1998. Development drilling is proceeding on a schedule that is intended
to have sufficient well capacity at all times to meet production capacities of
field  facilities  and  export  pipelines  from  the  area.

          During  1997,  Triton  Colombia  and  its  working interest partners
completed  an  additional  seven  wells  in  the  Cupiagua Field, bringing the
yearend  total  completions to date to 17 wells, which are awaiting startup of
production  facilities  in  1998.  There  are  currently  five  drilling  rigs
operating  in  the Cupiagua Field, and it is expected that 13 additional wells
will  be  completed  during  1998.  Development wells drilled during 1997 more
fully defined the areal extent of the field and the  oil/water contacts in the
fields.

          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
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.

<PAGE>

     Production  Facilities and Pipelines.  The four early production units of
     ------------------------------------
the  Cusiana  Field  central  processing  facility  are  designed  to  handle
approximately  180,000  barrels  of  daily production throughput.  In July and
August  1997,  two  80,000  barrels of oil per day ("BOPD") Cusiana production
trains were commissioned, which brought the production capacity of the Cusiana
central  processing  facility to 320,000 BOPD. Startup of the two 100,000 BOPD
production  trains  at the Cupiagua central processing facility is expected in
1998.  Upon  completion  of  the  Cupiagua  facilities,  the  total production
capacity  from the Cusiana/Cupiagua complex is expected to reach 500,000 BOPD.

     In  the  third quarter of 1997, expansion of pipeline and port facilities
to  transport and handle crude oil from the Cusiana and Cupiagua fields to the
Caribbean  port  of  Covenas was completed. These pipeline and port facilities
are  operated by Oleoducto Central S.A. ("OCENSA"), a 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.

          The  new  pipeline  segments  complete  a  793-kilometer  (495-mile)
pipeline  system  from the Cusiana and Cupiagua fields to the port of Covenas.
It  generally  follows  the  route  of the two existing pipelines: the Central
Llanos  pipeline  from  El  Porvenir to Vasconia and the Oleoducto de Colombia
pipeline  from  Vasconia to Covenas.  A portion of the Central Llanos pipeline
and  pump  station  upgrades  at  El  Porvenir and Miraflores were acquired by
OCENSA  in  1995.

     Other  Areas  in  Colombia

          Triton  owns rights to four 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 al  contract  area,  which covers approximately 71,000 acres
approximately 330 kilometers  (205  miles)  north  of Bogota .  In the
southern part of El Pinal, Triton  discovered and confirmed the Liebre Field
with two wells (the Liebre-1 and  -2).    In  1995,  Ecopetrol approved
Triton's application to declare the Liebre  Field  commercial.  Production
from the field, which began in January 1997,  is  currently  370  BOPD  from
the  two  wells.

          In  June  1995,  the Company was awarded the Guayabo A and B and Las
Amelias  association contracts covering a contiguous area of approximately 1.8
million  acres.    The area is located approximately 150 kilometers (93 miles)
north  of  Bogota    and 140 kilometers (87 miles) northwest of the Cusiana and
Cupiagua  fields,  and  is  contiguous  with the El Pinal contract area to the
north.    The terms of these association contracts are less favorable than the
terms  of  the Cusiana and Cupiagua association contracts. Triton has acquired
seismic data in a program totaling 178 kilometers (111 miles) over the Guayabo
A  and B blocks, and 195 kilometers (122 miles) over the Las Amelias block, as
well  as  approximately  15,000 kilometers (9,375 miles) of aeromagnetic data.
Triton's  partner in these areas is Deminex Colombia Petroleum GmbH with a 50%
interest.

<PAGE>
     Malaysia-Thailand
     -----------------

          Through  the Company's wholly 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. To date,
eight  fields  have  been  discovered  on  the  block.

          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  Petronas  Carigali  (JDA)  Sdn.  Bhd. ("Carigali"), a
subsidiary  of the Malaysian national oil company. 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. In 1997, the MTJA agreed, subject to government approval, to extend the
five-year  exploration  period  by three years, but the holding period for any
discovery  in  the  additional  three-year  period would not extend beyond the
tenth  anniversary  of the contract. The 35-year term also was unaffected. 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 plus a
number  of  years  equal  to  the  number of years, if any, prior to the fifth
anniversary  of  the  contract  that  oil  production  commenced (or until the
termination  of  the  contract,  if  earlier).  Any  areas  not  developed and
producing  within  the  periods  provided  will  be  relinquished.

          As  oil and gas are produced, the MTJA is entitled to a 10% royalty.
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).  Triton'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.

          Simultaneously  with  the  execution  of  the  production  sharing
contract,  the  parties  executed  a joint operating agreement governing Block
A-18  operations.  The  operating  agreement  designated  as  operator
Carigali-Triton  Operating Company Sdn. Bhd. ("CTOC"), a company owned equally
by  Triton  Thailand  and  Carigali.

          Negotiations  for  a  Gas-Sales  Agreement

          In  May  1996,  the MTJA, Triton and Carigali signed a Memorandum of
Understanding  on  the sale and purchase of natural gas with Petronas and PTT,
the  national  oil  companies  of  Malaysia  and  Thailand,  respectively. The
Memorandum  of  Understanding  provides a basis for negotiation of a gas-sales
agreement  for  natural  gas  to  be  produced  from  Block  A-18. The parties
currently  are  negotiating a heads of agreement intended to include agreement
in  principle  on  the key gas-sales agreement terms. The Company expects that
negotiation  and  execution of a definitive gas-sales agreement reflecting the
heads  of  agreement  will  follow  execution  of  the  heads  of  agreement.

          Recent  Drilling  Results

          During  1997,  one  appraisal  well  and four exploratory wells were
drilled  on  Block  A-18.

          In  July  1997,  the  Bumi  North-1  appraisal  well  was drilled to
delineate the Bumi Field. The well was tested at a combined rate of 42 MMcf of
gas  and  362  barrels of condensate per day from selected intervals. The well
was drilled in approximately 183 feet of water to a total depth of 9,250 feet,
approximately  15  kilometers  (9  miles)  north-northeast  of  Bumi-1.

          During  1997, exploratory drilling discovered four additional fields
in  Block A-18. The Senja-1 well discovered both oil- and gas-bearing zones in
the  Senja Field. On test, the well flowed at a combined rate of 2,725 barrels
of  oil,  39  MMcf  of gas and 368 barrels of condensate per day from selected
intervals.  The well was drilled in approximately 179 feet of water to a total
depth  of  7,600  feet. The Senja Field is located in the northwest portion of
the  block.  The  Bumi East-1 well tested at a combined rate of 34 MMcf of gas
and  1,681  barrels  of condensate per day from selected intervals in the Bumi
East Field. The well was drilled in approximately 188 feet of water to a total
depth  of  9,100  feet,  approximately  16  kilometers (10 miles) northeast of
Bumi-1. The Samudra-1 well tested at a combined rate of 49 MMcf of gas and 858
barrels of condensate per day from selected intervals. The well was drilled in
approximately  176  feet of water to a total depth of 12,000 feet. The Samudra
Field  is  located  in  the  southwest  portion  of the block. The Wira-1 well
discovered  the  Wira  Field, located in the central portion of the block. The
well was drilled in approximately 174 feet of water to a total depth of 10,000
feet.  One  production  test was conducted to confirm results of electric logs
and  hydrocarbon samples taken from the reservoir. The Wira-1 well flowed at a
maximum  daily  rate of 9.1 MMcf of gas and 137 barrels of condensate per day.

          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 offloading vessel for oil and condensate and 35 development wells.
Development  of  the  field is expected to commence following execution of the
heads  of  agreement  and  to  take approximately 30 to 36 months to complete.

     Ecuador
     -------

          Through  the  Company's  subsidiary,  Triton  Ecuador, Inc. LLC, the
Company  holds  an  interest  in  Block 19, which covers approximately 494,000
acres  located  in  the  Ecuadorian foothills of the eastern side of the Andes
Mountains  in  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' work program commitments for Block 19 consist of
the  acquisition  of  400  kilometers  (250 miles) of new seismic data and the
drilling  of  two exploratory wells during a four-year exploration period. The
Huataracu-1 exploratory well, completed in May 1997, was plugged and abandoned
after  tests failed to confirm the presence of commercial quantities of oil or
gas.  An  environmental impact study for a second exploratory well, Arapino-1,
was  approved  in  December  of  1997.

     Guatemala
     ---------

          Through the Company's subsidiary, Triton Guatemala S.A., the Company
has acquired an interest in two contiguous blocks. The blocks cover a total of
approximately  608,000 acres located on the border with Mexico in an extension
of  the  Chiapas Fold Belt province. In May 1997, Triton executed an agreement
with  Pioneer  Natural  Resources  providing  Pioneer  the right to earn a 40%
interest in both blocks, subject to government approval. The Piedras Blancas-1
exploratory  well  was drilled in 1997, reaching a total depth of 10,188 feet,
and  was  plugged  and abandoned after tests failed to confirm the presence of
commercial  quantities of oil or gas. In 1998, Triton's request for extensions
of  the  seismic  option  periods  for  both  blocks  was  approved. Triton is
reviewing  the  Blocks  for  future  drilling  opportunities.

     China
     -----

          The  Company's  subsidiary,  Triton  China,  Inc.  LLC,  has  signed
production  sharing  contracts  with  the  China National Offshore Oil Company
("CNOOC"),  which  give  the  Company  the  right  to  explore and develop two
contiguous offshore contract areas, Blocks 16/03 and 16/22. The blocks cover a
total of 2.4 million acres located in the Huizhou Sub-Basin of the Pearl River
Mouth  Basin  approximately  175  kilometers (110 miles) offshore Hong Kong in
water  depths  ranging from 300 to 650 feet. Pursuant to extensions granted in
1998,  the  blocks have a primary exploration term expiring on March 31, 1999.
The  obligation  well for Block 16/03 was plugged and abandoned with no tests.
Mobil  Exploration & Producing China Inc. has notified Triton of its intent to
withdraw  from  the  blocks  effective  March  31,  1998.

          Triton  is  also    party to an offshore Joint Study Agreement with
CNOOC  for  Block  JSA  24/05, which covers approximately 1.5 million acres in
water  depths  ranging  from  50  to 200 feet in the Liedong area of the South
China Sea. In 1998, the Company determined that it would not convert the Joint
Study  Agreement for Block  JSA 24/10  into  a  production  sharing  contract.

     Greece
     ------

          The  Company's subsidiary, Triton Hellas S.A., has signed two leases
with  the  national oil company of Greece, which give the Company the right to
explore  and  develop  an area of approximately 1.5 million acres. The Gulf of
Patraikos  contract  area  is  located  offshore  between the coastline of the
western Greece's mainland and the offshore Ionian islands of Lefkas, Kefalonia
and  Zakynthos  in  water  depths  of  up  to 1,700 feet. The lease provides a
primary  four-year  exploration  term with a commitment of 2,000 kilometers of
seismic  and  the  drilling of one exploratory well for a total expenditure of
not  less  than  $13.5  million.  The Aitoloakarnania contract area is located
onshore  in  the  prefecture  of  Aitoloakarnania in western Greece. The lease
provides  a  primary  two-year  exploration  term  with  a  commitment  of 200
kilometers  of  seismic  and the drilling of two exploratory wells for a total
expenditure  of not less than $13.25 million. Reprocessing of existing seismic
was  completed  in  both  areas  during  1997.

     Italy
     -----

          The  Company  has  a 40% interest in each of the contiguous DR71 and
DR72  licenses  operated  by  Enterprise Oil Italiana, S.p.A., in the Adriatic
Sea,  and  a 50% interest in three onshore licenses, operated by Triton Italy,
Inc.,  in the southern Apennine Mountains. Triton has applications pending for
additional  licenses  onshore  and  offshore.

          The DR71 and DR72 licenses lie 45 kilometers (28 miles) offshore the
city  of  Brindisi  and cover approximately 493,000 acres. One well, Medusa-1,
was  drilled  on  DR72 in 1996 to a total depth of 4,725 feet. The well proved
the  presence of oil and gas in a new play but in noncommercial quantities and
was  not  tested.  Additional  drilling  is  expected  in  1998.

          The  contiguous  southern  Apennines  licenses  -  Fosso  del  Lupo,
Valsinni  and  Masseria  di  Sole  -  cover approximately 101,000 acres in the
Matera  province.  The licenses were awarded  in August 1996.  In 1997, Triton
purchased  and  reprocessed  300 kilometers of seismic data over the licenses.

     Oman
     ----

          The  Company's  subsidiary,  Triton  Oman,  Inc., was awarded a 100%
interest  in  a production-sharing contract covering Block 22, Masirah Bay, by
the  Sultanate  of Oman in June 1996.  The offshore block covers approximately
two  million  acres  in  water depths ranging from 50 to 200 feet. The minimum
contractual  obligation  during  the  initial  three-year  exploration  period
requires the reprocessing and reinterpretation of existing seismic data, 1,000
kilometers  (625  miles)  of  seismic  acquisition  and  one  exploratory well
contingent  on  the  results  of  the  seismic  program.

          During  1997,  the Company reprocessed and interpreted approximately
1,100  kilometers  (688  miles)  of  existing  seismic  data,  and  acquired
approximately  1,750  kilometers  (1,094  miles)  of  2D  seismic  and  24,000
kilometers  (15,000  miles) of high resolution aeromagnetic and remote sensing
studies.  The  seismic acquisition fulfills Triton's seismic obligation on the
block.

     Indonesia
     ---------

          In February 1997, the Company's subsidiary, TriBlora Indonesia B.V.,
acquired  from  Eurafrep  B.V.  a 30% interest in the Blora production-sharing
contract  covering  a  block of approximately 1.4 million acres located within
central  Java.  Triton's  partners are Eurafrep B.V., the operator, with a 40%
interest,  YPF  International Ltd. with a 16.7% interest and Warrior Jawa Inc.
with  a  13.3%  interest.

          The  work  program  calls  for  an  unspecified  amount  of  seismic
reprocessing,  as  well  as the acquisition of 150 kilometers (95 miles) of 2D
seismic  and  the drilling of a well within the three-year initial exploration
period  for  a  total  expenditure  of  not  less  than $4.5 million. In 1997,
reprocessing  of  approximately  1,600 kilometers (1,000 miles) of existing 2D
seismic  was  completed.  Acquisition of 760 kilometers (475 miles)  of new 2D
seismic  data  was  completed in January 1998 and drilling is planned for late
1998.

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

          The Company's subsidiary, Triton Equatorial Guinea, Inc., 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 a primary two-year exploration term with a commitment
of  2,000  kilometers  (1,250  miles)  of  seismic  and  the  drilling  of one
exploratory  well  for  a  total  expenditure  of  not  less  than $5 million.

     Madagascar
     ----------

          The  Company's  subsidiary,  Triton  Madagascar,  Inc.,  has  signed
production-sharing  contracts  covering two blocks with the Office of National
Mines  and  Strategic  Industries  in  Madagascar.  The  Ambilobe  Block
(approximately  7.1  million acres) is located directly offshore from Ambilobe
in  water  depths  of  up  to  11,500  feet  and  the  Cap  St.  Marie  Block
(approximately  6.8  million  acres) is located directly offshore from Cap St.
Marie  in water depths of up to 5,900 feet. The blocks have a primary one-year
exploration  term  involving  geological  and  geophysical  studies.

     Tunisia
     -------

          In  May 1997, the Company's subsidiary, Triton Tunisia, Inc., signed
an agreement with Carthago Oil Company Tunisia, the operator, to acquire a 50%
interest  in  the  Medjerda  production  sharing  contract covering a block of
approximately  1.1  million acres located in northern Tunisia. The first phase
of  the  contract  has  been  extended  to  December 1998 with a commitment to
acquire  250  kilometers  (156  miles) of 2D seismic and drill one exploratory
well.  The  Medjerda-1  well was spudded in January 1998 and is being drilled.

     Argentina
     ---------

          In  1997,  the  Company  sold  its  Argentine  subsidiary.

RESERVES

          The  following  table  sets forth a summary of the estimated oil and
gas  reserves  of  the  Company at December 31, 1997, 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 all proved
reserves  in the Cusiana and Cupiagua fields in Colombia, and by the Company's
internal  petroleum  engineers  with  respect  to  all  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 and its consolidated subsidiaries. At December
31,  1997,  the Company had no proved developed or proved undeveloped reserves
in    Ecuador,  Guatemala,  China,  Greece, Italy, Oman, Indonesia, Equatorial
Guinea,  Madagascar  or  Tunisia.    For  additional information regarding the
Company's  reserves,  including  the  standardized  measure of future net cash
flows,  see  note  24  of    Notes  to  Consolidated Financial Statements. Oil
reserves  data  include  natural  gas  liquids  and  condensate.

          Net  proved  reserves  at  December  31,  1997,  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)               81,931        14,619   64,068         ---   145,999      14,619
Malaysia-Thailand (2)         ---           ---   29,800   1,223,800    29,800   1,223,800
                       ----------  ------------  -------  ----------  --------  ----------
Total                      81,931        14,619   93,868   1,223,800   175,799   1,238,419
                       ----------  ------------  -------  ----------  --------  ----------
</TABLE>


____________________
(1)       Includes liquids to be recovered from Ecopetrol as reimbursement for
precommerciality  expenditures.
(2)       As of December 31, 1997, 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
natural-gas  prices      derived from what the Company believed to be the most
comparable  market  price at December 31, 1997. 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, 1997, 1996 and 1995.
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.

<TABLE>
<CAPTION>


<S>                <C>        <C>     <C>    <C>   <C>     <C>
                      OIL PRODUCTION (1)         GAS PRODUCTION
                   ------------------------  -----------------------
                   YEAR ENDED DECEMBER 31,  YEAR ENDED DECEMBER 31,
                   ------------------------  -----------------------
                      1997     1996   1995       1997   1996  1995
                      ----     ----    ----      ----  ----   ----
                             (MBBLS)                  (MMCF)

Colombia (2)         5,776    5,738  5,089       802    298    158
France (3)             ---      ---    498       ---    ---    ---
Indonesia (4)          ---       95    255       ---    ---    ---
United States (5)      ---       20    121       ---    475  1,207
Crusader (6):
  Australia            ---      134    287       ---  1,744  3,884
  Canada               ---      ---     53       ---    ---     63
                   -------  -------  -----      ----  -----  -----
       Total         5,776    5,987  6,303       802  2,517  5,312
                   -------  -------  -----      ----  -----  -----

</TABLE>


____________________
(1)   Includes  natural  gas  liquids  and  condensate.
(2)   Includes Ecopetrol reimbursement barrels and excludes 2.5 million, .7
million  and  .4  million  barrels of oil produced and delivered for the years
ended  December  31, 1997, 1996 and 1995, respectively, in connection with the
Company's  forward  sale  of  oil  in  May  1995.  See  Item  7, "Management's
Discussion  and  Analysis  of  Financial Condition and Results of Operations -
Results  of  Operations"  and  note  3  of  Notes  to  Consolidated  Financial
Statements.
(3)    In August 1995, Triton Europe sold its interest in its subsidiary,
Triton  France  S.A.
(4)    In  May 1996, the Company sold substantially all of the assets of
Triton  Indonesia,  Inc.
(5)    In March 1996, Triton sold substantially all of its domestic royalty
and  mineral  interests.
(6)    In 1996, the Company sold all of its interest in Crusader. In June
1995,  Crusader  sold  all  of  its  interest  in  Ausquacan  Energy  Limited.

          The  following  tables  summarize  for  the years ended December 31,
1997, 1996 and 1995: (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,
               -------------------------  ------------------------
                 1997     1996      1995   1997     1996     1995
               ------    ------   ------  -----    -----    -----

Colombia       $17.54   $19.62    $16.29  $1.15    $2.56    $1.96
France            ---      ---     18.11    ---      ---      ---
Indonesia         ---    19.54     17.77    ---      ---      ---
United States     ---    16.00     13.62    ---     1.15     1.49
Crusader:
   Australia      ---    19.95     20.38    ---     1.69     1.69
   Canada         ---      ---     15.42    ---      ---     0.99
</TABLE>



<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,
               --------------------------  -------------------------  ------------------------
                 1997      1996    1995      1997     1996    1995      1997    1996    1995
               -------  -------  -------   -------  ------   ------    -----   -----  ------
Colombia       $ 17.37  $ 19.58  $ 16.26   $  3.67  $ 2.83   $ 2.67    $6.47  $ 5.66  $ 5.52
France             ---      ---    18.11      ---      ---     3.14      ---     ---   10.96
Indonesia          ---    19.54    17.77      ---     0.52     0.95      ---   15.89   17.34
United States      ---     8.75    10.68      ---     5.59     6.05      ---    3.25    1.03
Crusader:
 Australia         ---    13.23    13.29      ---     3.47     3.35      ---    4.10    4.77
 Canada            ---      ---    13.87      ---      ---     2.35      ---     ---    7.52




</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.



<PAGE>

     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 is sold would have a
long-term  material, adverse effect on the revenues from the Company's oil and
gas  operations.

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

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

ACREAGE

          The  following  table  shows  the  total gross and net developed and
undeveloped  oil and gas acreage held by Triton at December 31, 1997.  "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.

<PAGE>

<TABLE>
<CAPTION>



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

Colombia                36       5   1,934     938
Malaysia-Thailand      ---     ---     731     366
Ecuador                ---     ---     494     272
Guatemala              ---     ---     608     365
China                  ---     ---   3,978   2,761
Greece                 ---     ---   1,475   1,298
Italy                  ---     ---     594     248
Oman                   ---     ---   2,044   2,044
Indonesia              ---     ---   1,413     424
Equatorial Guinea      ---     ---   1,306   1,306
Madagascar             ---     ---  13,914  13,914
Tunisia                ---     ---   1,102     551
                   -------  ------  ------  ------
Total                   36       5  29,593  24,487
                   -------  ------  ------  ------

</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.

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, 1997, in Colombia, Triton held gross and net working
interests in 64 and 7.7 productive wells, respectively, which include 10 gross
(1.2  net)  gas-injection  wells and one gross (.12 net) water-injection well.

<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,  1997,  1996  and  1995.

<TABLE>
<CAPTION>




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

                                             GROSS EXPLORATORY WELLS


                            PRODUCTIVE (1)             DRY                         TOTAL
                         -----------------------  -----------------------  -----------------------
                         YEAR ENDED DECEMBER 31,   YEAR ENDED DECEMBER 31,  YEAR ENDED DECEMBER 31,
                         ----------------------  -----------------------    ----------------------
                          1997    1996    1995    1997    1996     1995      1997    1996    1995
                         -----   -----   ------  -----    ----    -----     ----    -----   -----

Colombia                    1        3        2      1    ---         2        2        3      4
Malaysia-Thailand           5        7        2    ---    ---       ---        5        7      2
Argentina                 ---      ---      ---    ---      2         2      ---        2      2
Italy                     ---      ---      ---    ---      1       ---      ---        1    ---
Guatemala                 ---      ---      ---      1    ---       ---        1      ---    ---
China                     ---      ---      ---    ---      1       ---      ---        1    ---
Ecuador                   ---      ---      ---      1    ---       ---        1      ---    ---
Crusader (2):
   Argentina              ---      ---        1    ---    ---         2      ---       ---     3
   Australia              ---       14       23    ---      4        11      ---        18    34
                         ----    -----   ------  -----    ---      ----               ----  ----
            Total           6       24       28      3      8        17        9        32    45
                         ----    -----   ------  -----    ---      ----     ----      ----  ----




</TABLE>



<TABLE>
<CAPTION>




<S>                      <C>      <C>       <C>      <C>   <C>     <C>     <C>    <C>
                                               GROSS DEVELOPMENT WELLS


                            PRODUCTIVE (1)               DRY                      TOTAL
                         ------------------------  -----------------------  -----------------------
                         YEAR ENDED DECEMBER 31,   YEAR ENDED DECEMBER 31,  YEAR ENDED DECEMBER 31,
                         ------------------------  -----------------------  -----------------------
                          1997    1996    1995     1997    1996     1995    1997     1996     1995
                         -----  ------   ------   -----    ----     ----    ----     ----     ----

Colombia                   18      15        8     ---     ---      ---      18       15        8
Malaysia-Thailand         ---     ---      ---     ---     ---      ---     ---      ---      ---
Crusader (2):
   Australia              ---       2        5     ---     ---        1     ---        2        6
                          ---  ------    -----    ----    ----     ----    ----     ----      ---
            Total          18      17       13     ---     ---        1      18       17       14
                          ---  ------    -----    ----    ----     ----    ----     ----      ---



</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.  In 1995,
Crusader  sold  its  interests  in  Argentina  and  Canada.


<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,  1997,  1996 and 1995 (those wells acquired or disposed of since
January  1, 1995 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):

<TABLE>
<CAPTION>




<S>                     <C>      <C>      <C>       <C>   <C>   <C>        <C>     <C>      <C>
                                              NET EXPLORATORY WELLS


                            PRODUCTIVE (1)                DRY                      TOTAL
                        ------------------------  -----------------------  -----------------------
                        YEAR ENDED DECEMBER 31,   YEAR ENDED DECEMBER 31,  YEAR ENDED DECEMBER 31,
                        ------------------------  -----------------------  -----------------------
                         1997    1996     1995    1997     1996     1995    1997    1996     1995
                        -----  ------  --------   ----     ----     ----    ----    ----     ----

Colombia (2)             0.12    0.12      0.12   0.50     0.50     2.00    0.62    0.62     2.12
Malaysia-Thailand        2.50    3.50      1.00    ---      ---      ---    2.50    3.50     1.00
Argentina                 ---     ---       ---    ---     2.00     2.00     ---    2.00     2.00
Italy                     ---     ---       ---    ---     0.40      ---     ---    0.40      ---
Guatemala                 ---     ---       ---   0.60      ---      ---    0.60     ---      ---
China                     ---     ---       ---    ---     0.50      ---     ---    0.50      ---
Ecuador                   ---     ---       ---   0.55      ---      ---    0.55     ---      ---
Crusader (3):
   Argentina              ---     ---      0.06    ---      ---     0.12     ---     ---      0.18
   Australia              ---    0.34      0.35    ---     0.10     0.29     ---    0.44      0.64
                        -----  ------  --------   ----     ----     ----    ----    ----      ----
            Total        2.62    3.96      1.53   1.65     3.50     4.41    4.27    7.46      5.94
                        -----  ------  --------   ----     ----     ----    ----    ----      ----



</TABLE>


<TABLE>
<CAPTION>




<S>                     <C>       <C>      <C>    <C>      <C>   <C>       <C>     <C>     <C>
                                                  NET DEVELOPMENT WELLS


                              PRODUCTIVE (1)               DRY                     TOTAL
                        ------------------------  -----------------------  -----------------------
                        YEAR ENDED DECEMBER 31,   YEAR ENDED DECEMBER 31,  YEAR ENDED DECEMBER 31,
                        ------------------------  -----------------------  -----------------------
                         1997     1996    1995     1997    1996    1995      1997    1996   1995
                        -----  -------   -----    -----  ------    ----      ----    ----   ----

Colombia (2)             2.16     1.80    0.96      ---     ---     ---      2.16    1.80   0.96
Malaysia-Thailand         ---      ---     ---      ---     ---     ---       ---     ---    ---
Crusader (3):
  Australia               ---     0.05    0.10      ---     ---    0.02       ---    0.05   0.12
                         ----  -------   -----     ----    ----    ----      ----    ----   ----
            Total        2.16     1.85    1.06      ---     ---    0.02      2.16    1.85   1.08
                         ----  -------   -----     ----    ----    ----      ----    ----   ----




</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)    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
various  operations in various parts of the world.  For additional information
on  the Company's leases, including its office leases, see note 20 of Notes to
Consolidated  Financial  Statements.

<PAGE>

FORWARD-LOOKING  INFORMATION

          Certain  statements  in  this  Annual Report on Form 10-K, including
expectations,  intentions,  plans  and  beliefs of the Company and management,
including  those  contained  in  or  implied  by  Items 1 and 2, "Business and
Properties",  and  Item  7, "Management's Discussion and Analysis of Financial
Condition  and  Results  of  Operations,"   are forward-looking statements, as
defined  in  Section  21D  of  the  Securities  Exchange Act of 1934, that are
dependent  on  certain events, risks and uncertainties that may be outside the
Company's  control.  These  forward-looking  statements  include statements of
management's  plans  and  objectives  for  future operations and statements of
future  economic  performance;  information  regarding  drilling schedules and
schedules  for  the  start-up  of  production  facilities; expected or planned
production  or  transportation  capacity;  when  the  Fields  might  become
self-financing; future production of the Fields; the negotiation of a heads of
agreement to a gas-sales contract and a gas-sales contract and commencement of
production  in  Malaysia-Thailand;  the  Company's  capital  budget and future
capital  requirements;  the  Company's  meeting  its future capital needs; the
amount by which production from the Fields may increase or when such increased
production  may commence; 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; and proven
oil  and  gas reserves and discounted future net cash flows therefrom; and the
assumptions  described  in  this  report  underlying  such  forward-looking
statements.    Actual  results  and  developments could differ materially from
those  expressed  in or implied by such statements due to a number of factors,
including  those  described  in the context of such forward-looking statements
and  in  notes  19  and  20  of  Notes  to  Consolidated Financial Statements.

EMPLOYEES

          At  March 16, 1998, the Company employed approximately 295 full-time
employees.

<PAGE>

EXECUTIVE  OFFICERS  OF  THE  COMPANY

          The  following  table  sets  forth certain information regarding the
executive  officers  of  the  Company  at  March  16,  1998:

<TABLE>
<CAPTION>



<S>                            <C>          <C>                                            <C>
                                                                                           SERVED WITH
                                                                                           -----------
                                                                                           THE COMPANY
                                                                                           -----------
NAME                            AGE         POSITION WITH THE COMPANY                        SINCE
-----------------------------  ----  ----------------------------------------------------    -----

Thomas G. Finck                  51  Chairman of the Board and Chief Executive Officer        1992
Nick De'Ath                      49  Senior Vice President, Exploration                       1993
Robert B. Holland, III           45  Senior Vice President, General Counsel and Secretary     1993
Peter Rugg                       50  Senior Vice President and Chief Financial Officer        1993
A.E. Turner, III                 49  Senior Vice President, Operations                        1994

</TABLE>



          In  August 1992, Mr. Finck was elected Director, President and Chief
Operating  Officer  of  the  Company.    Effective January 1993, Mr. Finck was
elected  Chief  Executive  Officer,  and  effective  May  1995, he assumed the
additional  position of Chairman of the Board.  From July 1991 to August 1992,
Mr.  Finck  served as President and Chief Executive Officer of American Energy
Group,  an independent oil and natural gas exploration and production company.
From  May  1984  until  June  1991,  Mr.  Finck  served as President and Chief
Executive  Officer  of  Ensign Oil & Gas, Inc., a private domestic oil and gas
exploration  company.

          Mr.  De'Ath  was elected Senior Vice President, Exploration in 1993.
From  1992 to 1993, Mr. De'Ath served as President and owner of Pinnacle Ltd.,
a  management consulting firm providing services to multinational companies in
Colombia,  and from 1971 to 1992 served in various positions with subsidiaries
of British Petroleum Company, p.l.c., including general manager of exploration
for  BP International Limited in Mexico from 1991 to 1992 and  general manager
of  BP's  Colombian  operation  from  1986  to  1991.

          Mr.  Holland  was elected Senior Vice President, General Counsel and
Secretary  of  the Company in January 1993.  For more than five years prior to
joining  the  Company,  Mr. Holland was a partner of the law firm of Jackson &
Walker,  L.L.P.,  Dallas,  Texas.

          Mr.  Rugg  was  elected  Senior  Vice  President and Chief Financial
Officer  in April 1993.  From September 1992 to April 1993, Mr. Rugg served as
Vice President of J.P. Morgan & Co., Incorporated ("J.P. Morgan"), a financial
services  firm,  and for more than the five years prior to September 1992, Mr.
Rugg served as Vice President of Morgan Guaranty Trust Company of New York, an
international  bank  owned  by  J.P.  Morgan.

<PAGE>

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

          All  executive  officers  of the Company are 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

          The  Company  and subsidiaries or former subsidiaries of the Company
were  among  numerous defendants in a lawsuit brought in the Superior Court of
the State of California, County of Los Angeles, by Travelers Indemnity Company
arising  out of a 1988 tidal wave at King Harbor in Redondo Beach, California.
The  lawsuit  alleged,  among  other  things,  that the defendants' negligence
contributed to the collapse of a hotel and the flooding of a restaurant in the
tidal  wave.    This  lawsuit  was  settled  in  1998.

          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 subsidiary
has  a formal period of negotiation regarding performing the final remediation
design  for  the  clean-up of the site, and demanded reimbursement for certain
unpaid  costs  that have been incurred. The government estimates the aggregate
amount being negotiated as $217 million  to be allocated  among  the 280 known
operators.  The  subsidiary's  share  would  be approximately $1 million based
upon  a  volumetric  allocation.    The  Company  has  been  advised  that the
government  expects  that  defendants  such as the subsidiary will be given an
opportunity  to settle some time in the second half of 1998.  At that time, it
is  expected  that an allocation will be made as to such defendants, which may
be  greater  or  less  than  the  estimated  volumetric  allocation.

          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.  The Company
believes  the  suit  is  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, 1997 to security holders, through the solicitation
of  proxies  or  otherwise.






                                    PART II

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

          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>




<S>                    <C>       <C>
CALENDAR PERIODS       HIGH      LOW
----------------     --------  --------
1998:
    First Quarter*   33 15/16  25 13/16
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
1996:
    First Quarter       59 3/4    46 3/4
    Second Quarter      57 1/8    45 3/4
    Third Quarter       49 3/8    40 1/2
    Fourth Quarter      50 5/8    42 1/2

</TABLE>


______________________
*Through  March  16,  1998.

          Triton  has  not  declared any cash dividends on its ordinary shares
since fiscal 1990.  The Company's current intent is to retain earnings for use
in  the Company's business and the financing of its capital requirements.  The
payment  of  any  future  cash  dividends  is  necessarily  dependent upon the
earnings  and  financial needs of the Company, along with applicable legal and
contractual  restrictions.

          The  payment  of  dividends  on  the  Company's  capital  stock  is
restricted  pursuant  to  the  Company's  revolving  credit  facilities.

          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.

          As  of March 16, 1998, the Company had outstanding 217,732 shares of
its  5%  Convertible  Preference  Shares  ("5%  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 on or after March 30, 1998 (or such
earlier date as there are fewer than 133,005 5% Preference Shares outstanding)
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  12  of  Notes  to  Consolidated  Financial  Statements.

          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, Oppenheimer Group, Inc. ("Oppenheimer") may increase its
level  of  beneficial  ownership to 19.9% without triggering a distribution of
the rights. 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
Oppenheimer),  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
Oppenheimer)  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  rights will expire on May 22, 2005, unless such expiration date
is  extended  or  unless  the  rights are earlier redeemed or exchanged by the
Company.   At any time prior to a person acquiring beneficial ownership of 15%
or  more  of  Triton's  ordinary  shares, the Company may redeem the rights in
whole,  but  not  in  part,  at  a price of $.01 per right. For so long as the
rights  are redeemable, the Company may, except with respect to the redemption
price,  amend  the  rights  in  any  manner.

          At  March 16, 1998, there were 4,244 record holders of the Company's
ordinary shares.

<PAGE>



ITEM  6.          SELECTED  FINANCIAL  DATA
<TABLE>
<CAPTION>



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


                                                               AS OF OR FOR YEAR ENDED
                                                                      DECEMBER 31,
                                                        ----------------------------------------------
                                                           1997       1996      1995          1994
                                                       ----------   --------  ---------    ---------
                                                                                          (unaudited)

OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA):
Sales and other operating revenues (1)                 $  149,496   $133,977  $ 107,472    $ 32,952
Earnings (loss) from continuing operations (1) (2)          5,595     23,805      6,541     (49,610)
Earnings (loss) before extraordinary
   items and cumulative effect of
   accounting change                                        5,595     23,805      2,720     (52,701)
Net earnings (loss) (2)                                    (8,896)    22,609      2,720     (52,701)
Average ordinary  shares outstanding                       36,471     35,929     35,147      34,916
Basic earnings (loss) per ordinary share:
   Continuing operations (1) (2)                       $     0.14   $   0.64  $    0.16    $  (1.43)
   Before extraordinary item and
     cumulative effect of accounting change                  0.14       0.64       0.05       (1.52)
   Net earnings (loss)                                      (0.26)      0.61       0.05       (1.52)
Diluted earnings (loss) per ordinary share:
   Continuing operations (1) (2)                       $     0.14   $   0.62  $    0.16    $  (1.43)
   Before extraordinary item and
     cumulative effect of accounting change                  0.14       0.62       0.05       (1.52)
   Net earnings (loss)                                      (0.25)      0.59       0.05       (1.52)

BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment                             $  835,506   $676,833  $ 524,381    $399,658
Total assets                                            1,098,039    914,524    824,167     619,201
Long-term debt (3)                                        443,312    217,078    401,190     315,258
Redeemable preference shares of
   subsidiaries                                               ---        ---        ---         ---
Shareholders' equity                                      296,620    300,644    246,025     237,195

CERTAIN OIL AND GAS DATA  (4) :
Production
   Oil (Mbbls) (5)                                           5,776     5,987      6,303       2,534
   Gas (MMcf)                                                  802     2,517      5,312       5,516
Average sales price
   Oil (per bbl)                                        $    17.54  $  19.61  $   16.60    $  15.26
   Gas (per Mcf)                                        $     1.15  $   1.69  $    1.64    $   1.51





</TABLE>
<TABLE>
<CAPTION>



<S>                                                      <C>            <C>      <C>
                                                          AS OF OR
                                                          FOR SEVEN
                                                          MONTHS ENDED  AS OF OR FOR YEAR ENDED
                                                          DECEMBER 31,        MAY 31,
                                                                        -----------------------
                                                              1994         1994       1993
                                                          ---------     ---------  ---------

OPERATING DATA (IN THOUSANDS, EXCEPT PER SHARE DATA):
Sales and other operating revenues (1)                    $  20,736     $  43,208  $  84,414
Earnings (loss) from continuing operations (1) (2)          (26,630)       (4,597)   (76,509)
Earnings (loss) before extraordinary
   items and cumulative effect of
   accounting change                                         (27,708)      (9,341)   (93,552)
Net earnings (loss) (2)                                      (27,708)      (9,341)   (89,535)
Average ordinary  shares outstanding                          34,944       34,775     34,241
Basic earnings (loss) per ordinary share:
   Continuing operations (1) (2)                          $   (0.78)    $   (0.13) $   (2.23)
   Before extraordinary item and
     cumulative effect of accounting change                   (0.81)        (0.27)     (2.73)
   Net earnings (loss)                                        (0.81)        (0.27)     (2.61)
Diluted earnings (loss) per ordinary share:
   Continuing operations (1) (2)                          $   (0.78)    $   (0.13) $   (2.23)
   Before extraordinary item and
     cumulative effect of accounting change                   (0.81)        (0.27)     (2.73)
   Net earnings (loss)                                        (0.81)        (0.27)     (2.61)

BALANCE SHEET DATA (IN THOUSANDS):
Net property and equipment                                $  399,658    $  308,498 $ 330,151
Total assets                                                 619,201       616,101   561,931
Long-term debt (3)                                           315,258       294,441   159,147
Redeemable preference shares of
   subsidiaries                                                  ---           ---    11,399
Shareholders' equity                                         237,195       263,422   255,432

CERTAIN OIL AND GAS DATA  (4) :
Production
   Oil (Mbbls) (5)                                             1,488         2,886     3,691
   Gas (MMcf)                                                  3,427         9,078    21,958
Average sales price
   Oil (per bbl)                                          $    16.41    $    15.15 $   18.67
   Gas (per Mcf)                                          $     1.44    $     1.44 $    1.27



</TABLE>



(1)       Operating data for the year ended December 31, 1994 (unaudited), the
seven  months  ended  December  31, 1994, and the years ended May 31, 1994 and
1993,  are restated to reflect the aviation sales and services segment and the
wholesale  fuel  products segment as discontinued operations in 1995 and 1993,
respectively.
(2)       Gives effect to the writedown of assets and loss provisions of $46.2
million,  $1.1  million,  $14.7 million, $1.0 million, $45.8 million and $99.9
million  for the years ended December 31, 1996, 1995 and 1994 (unaudited), the
seven  months  ended  December  31, 1994, and the years ended May 31, 1994 and
1993,  respectively.
(3)        Long-term debt does not include current maturities totaling  $130.4
million,  $199.6  million,  $1.3  million,  $.3  million, $.3 million and $3.4
million at December 31, 1997, 1996, 1995 and 1994, and May 31, 1994 and  1993,
respectively.
(4)     Information presented includes the 49.9% equity investment in Crusader
Limited,  which  was  sold  in  1996.
(5)      Includes natural gas liquids and condensate.  Production excludes 2.5
million, .7 million and .4 million barrels of oil produced and delivered under
a  forward  oil sale entered into in May 1995 for the years ended December 31,
1997,  1996  and  1995,  respectively.
<PAGE>



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

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

          Changes  in  Working  Capital
          -----------------------------

          Cash,  cash  equivalents  and  marketable  securities  totaled $13.5
million  and  $14.9  million  at  December  31,  1997  and 1996, respectively.
Working  capital  deficit  improved  to  $115.2  million at December 31, 1997,
compared  with  $182.2  million  at  December 31, 1996.  At December 31, 1997,
borrowings of $164.9 million under the Company's bank credit facilities, which
mature  during  the  period August through November 1998, were classified as a
current  liability.    Current  liabilities  included deferred income totaling
$35.3  million  and $28.5 million at December 31, 1997 and 1996, respectively,
related  to  a  forward  oil  sale  consummated  in  1995.

          Refinancing  of  Debt
          ---------------------

          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 Senior Subordinated Discount Notes due November 1, 1997 (the "1997
Notes"),  and  9 3/4% Senior Subordinated Discount Notes due December 15, 2000
(the  "9  3/4%  Notes"),  resulting  in  the  retirement of the 1997 Notes and
substantially  all  of  the  9  3/4%  Notes  and  the removal of the financial
covenants in the remaining 9 3/4% Notes.  At December 31, 1996, $189.9 million
principal  amount of the 1997 Notes was classified as a current liability. 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.

          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 for $100 million.  Net proceeds were approximately
$97.7  million  after  $2.3  million  of  expenses.    The sale resulted in an
aftertax gain of $50.2 million, which will be recorded in the first quarter of
1998.    The  Company  used  the  proceeds from the sale of the TPC shares and
borrowings  under other unsecured credit facilities to repay and terminate its
$125  million  unsecured  credit  facility.

<PAGE>
          Funding  of  Capital  Expenditures
          ----------------------------------

          The  Company's  capital  expenditures  and other capital investments
were  $219.2 million, $252.7 million and $178.2 million during the years ended
December  31, 1997, 1996 and 1995, respectively, primarily for exploration and
development of the Cusiana and Cupiagua fields (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.  The 1997 capital spending program
and  repayment  of  debt  were primarily funded with cash flow from operations
($27.4  million, excluding payment of accreted interest on extinguished debt),
issuance  of  the  Senior Notes, and net borrowings under the Company's credit
facilities  ($181  million).

          The  1996 capital spending program and repayment of debt were funded
with  cash, cash flow from operations ($80.7 million), and proceeds from sales
of  marketable  securities  ($38.5 million) and other assets ($108.1 million).
The  1995  capital  spending program was funded with cash flow from operations
(including  a  forward  sale  of  Cusiana  crude  oil  - $86.6 million), cash,
proceeds  from  marketable  securities ($42.1 million), sales of assets ($20.9
million)  and  net  borrowings ($36.3 million).  In May 1995, the Company sold
10.4  million  barrels of oil from the Fields 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,  which is expected in 1998, and when
certain  other  conditions  are  met.

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

          Development  of  the  Fields, including drilling and construction of
additional  production  facilities,  will  require  further  capital  outlays.
Further  exploration  and  development  activities  on  Block  A-18  in  the
Malaysia-Thailand  Joint  Development Area in the Gulf of Thailand, as well as
exploratory drilling in other countries, also will require substantial capital
outlays.   The Company's capital budget for the year ending December 31, 1998,
is  approximately  $176  million,  excluding  capitalized  interest,  of which
approximately $103 million relates to the Fields, $23 million relates to Block
A-18,  and  $50  million relates to the Company's activities in other parts of
the world. The 1998 capital budget includes funding requirements for committed
activities only.  Substantial capital requirements for Block A-18 are expected
prior  to  the  first  deliveries of gas, which are estimated to occur between
30-36  months  after  signing of a heads of agreement to a gas-sales contract.

          The  Company  expects to fund capital expenditures and repay debt in
the  future  with  a  combination of some or all of the following: asset sales
(which  may  involve  interests in material assets), cash flow from operations
(including additional proceeds of $30 million from the 1995 forward oil sale),
cash,  credit  facilities  and additional facilities to be negotiated, and the
issuance  of  debt and equity securities.  Under the most restrictive covenant
in  the  Company's existing credit facilities, the Company generally could not
permit  total  indebtedness  (as  defined in the various agreements) to exceed
$650  million.  The  limitation  on  total  indebtedness will increase to $725
million once the Fields achieve a production level of 340,000 barrels per day.
At  February  28,  1998,  the  Company  had  total indebtedness outstanding of
approximately  $555  million  and  available  borrowing  capacity under unused
credit  facilities  totaling  approximately  $45  million.    The  Company  is
currently  in  negotiations for additional committed bank credit facilities, a
portion  of  which  may  be  needed  to meet the Company's cash needs in 1998.
There  can  be  no  assurance  that  the  Company will be able to successfully
negotiate  additional  credit  facilities,  and the Company may be required to
seek  alternative  sources  of  capital.    To  facilitate  a  possible future
securities  issuance or issuances, the Company has on file with the Securities
and Exchange Commission a shelf registration statement under which the Company
could  issue  up  to  an  aggregate of $200 million debt or equity securities.

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

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

     Sales  and  Other  Operating  Revenues
     --------------------------------------

          Sales  and  other  operating  revenues  were $149.5 million and $134
million  in 1997 and 1996, respectively.  Revenues in Colombia increased $18.3
million  in  1997  due to higher production ($35 million).  Revenue barrels in
Colombia,  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 ($16.8
million)  reflecting the increased deliveries under the forward oil sale and a
decrease  in  the  1997  average  West  Texas  Intermediate ("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 sales volumes in 1997, compared
with 10% of the Company's sales volumes 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.

          Based  on  the  operator's  current projections, the Company expects
gross  production capacity from the Fields to reach 500,000 barrels per day in
1998.    The Company expects that the adverse effect from the forward oil sale
deliveries  on  the  Company's  results  of  operations and cash flows will be
mitigated  by increased production from the Fields. There can be no assurance,
however,  about  the  timing  of  any  increase  in  production.

          Subsequent  to  yearend,  the  price  of oil declined significantly,
which  will  have  a  negative  effect  on  earnings  and  cash  flows  in the
first-quarter of 1998.

          Other  operating  revenues  in  1997 included a gain of $4.1 million
from the sale of the Company's Argentine subsidiary.  Other operating revenues
in 1996 included a gain of $4.1 million from the sale of the Company's royalty
interests  in  U.S.  properties.

     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  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 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 to 500,000
barrels  per  day.    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
("Third  Party  Shippers")  are  assessed  a tariff on a per-barrel basis, and
OCENSA  will  use  revenues  from such tariffs to reduce the Initial Shippers'
tariff.

          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.  Beginning January 1,
1998,  no  production  taxes  will  be assessed on production from the Cusiana
Field.

          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.  At the end of
1997,  the  Company had licenses to explore for oil and gas on 28 blocks in 12
countries.   During 1997, the Company acquired eight new exploration blocks in
five  countries,  and  during  1996,  the Company acquired six new exploration
blocks  in  four  countries.

          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  ("Crusader"),  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
           -------------

          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 1997 and 1996 represented current and
deferred  taxes in Colombia, deferred taxes on exploration projects throughout
the  world,  and  a  deferred  tax  benefit  in  the  United States related to
anticipated  future  utilization  of  NOLs.   Subject to the factors described
above,  the  Company currently expects that its foreign deferred tax provision
will substantially exceed its current tax provision (i.e., actual taxes paid),
resulting  in  an effective tax for income statement purposes that will exceed
statutory  tax  rates,  at  least until the Fields reach peak production.  The
primary  reason  for  the  expected  difference  is  the  nondeductibility for
Colombian  tax  purposes  of  certain  capital  expenses  and the treatment of
reimbursements  for  pre-commerciality  costs  as  a  return  of capital under
Colombian  tax  laws.    Conversely,  Colombian tax law permits the Company to
adjust  the  tax basis of certain assets based on the Colombian inflation rate
and  to  include any resulting increases in tax depreciation of the underlying
asset  based on rates of production and other factors.  The Company's deferred
tax  liability  has  not  been reduced to reflect the impact of this inflation
adjustment.

          At  December  31,  1997,  the Company had U.S. NOLs of approximately
$406.8  million,  and certain U.S. subsidiaries had separate return limitation
years  ("SRLY")   operating loss carryforwards of approximately $40.6 million,
compared  with  NOLs  of  approximately $230.7 million and SRLY operating loss
carryforwards of $50.9 million at December 31, 1996.  During 1997, the Company
amended  certain  prior-year  tax  returns that increased the Company's unused
NOLs.    The  NOLs  expire  from  1998  to  2013,  and the SRLY operating loss
carryforwards  expire from 1998 to 2002.  See note 10 of Notes to Consolidated
Financial  Statements.

          The Company recorded a deferred tax asset of $87.1 million, net of a
valuation  allowance  of  $75.1  million  at December 31, 1997.  The valuation
allowance  was  primarily  attributable  to  management's  assessment  of  the
utilization  of  NOLs, SRLY operating losses that are currently not realizable
due to the lack of potential future income in the applicable subsidiaries, and
the  expectation  that  other  tax credits will expire without being utilized.
The  minimum amount of future taxable income necessary to realize the deferred
tax  asset  is approximately $249 million.  Although there can be no assurance
the  Company  will  achieve  such  levels  of  income, management believes the
deferred  tax  asset  will  be  realized  through  increasing  income from its
operations.

          The  income  tax  provision for 1997 included foreign deferred taxes
totaling  $16  million  in  1997, 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.

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

          The  Company's results of operations for the year ended December 31,
1997,  included  an  extraordinary  expense  of  $14.5  million, net of a $7.8
million  tax benefit, associated with extinguishment of the 1997 Notes and the
9 3/4% Notes.  During the year ended December 31, 1996, the Company recognized
an  extraordinary  expense  of $1.2 million, net of a $.6 million tax benefit,
resulting  from  the  purchase  of  $30  million face value of its 1997 Notes.

     Subsequent  Events
     ------------------

          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 an aftertax gain of $50.2 million, which will
be  recorded  in  the  first  quarter  of  1998.

          In  conjunction  with  the  sale  of TPC, the Company entered into a
five-year  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 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 with
respect to its equity interest in OCENSA.  Upon a sale by the Purchaser of the
TPC  shares,  the  Company  will receive from the Counterparty, or make a cash
payment  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.  The equity swap
will be carried in the Company's financial statements at fair value during the
five-year term.  Fluctuations in the fair value of the equity swap will affect
other  income  as  noncash  adjustments.

<PAGE>

                         YEAR ENDED DECEMBER 31, 1996,
                  COMPARED WITH YEAR ENDED DECEMBER 31, 1995

     Revenues
     --------

          Sales  and  other  operating  revenues  were $134 million and $107.5
million  in  1996  and  1995, respectively.  Revenues in Colombia increased by
$37.2  million in 1996 due to higher production ($15.7 million) and higher oil
prices  ($21.5  million)  resulting  from more favorable market conditions and
batching  of  Cusiana  crude  that  began  in  mid-1995.    Revenue barrels in
Colombia,  including  barrels  delivered under the forward oil sale, increased
from  5.5  million barrels in 1995 to 6.4 million barrels in 1996, even though
the  Company  received  .7  million  fewer barrels in 1996 as reimbursement of
pre-commerciality  costs related to the Cusiana Field.  Oil and gas sales from
properties  sold  in  late 1995 and early 1996 aggregated $17 million in 1995,
compared  with  $2.7  million  in  1996.

          Other  operating  revenues  in  1996 included a gain of $4.1 million
resulting  from the sale of the Company's royalty interests in U.S. properties
for  $23.8  million  based  on  an  effective  date  of  January  1,  1996.

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

          Operating expenses increased $1.4 million in 1996, and depreciation,
depletion  and  amortization increased $2.4 million.   The Company's operating
costs  per  oil  equivalent-barrel  were  $5.77  and  $6.28  in 1996 and 1995,
respectively.  Higher  production  in Colombia increased operating expenses by
$9.9  million  and  depreciation  and  depletion  by  $3.6 million.  Operating
expenses  from  properties  sold in late 1995 and early 1996 were $1.8 million
and  $10.2  million  in  1996  and  1995,  respectively.

          General  and administrative expenses before capitalization increased
$3.8  million  in  1996 to $50.5 million, primarily due to greater exploration
activities.    Capitalized general and administrative costs were $24.6 million
and  $21.1  million  in  1996  and  1995,  respectively.

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

          Interest  expense  before  capitalization  increased $2.7 million in
1996  to  $43  million.   Capitalized interest increased from $16.2 million in
1995  to  $27.1  million  in 1996 due to construction of support equipment and
facilities  in  the  Fields  and greater exploration activities throughout the
world.

          Other  income, net in 1996 included a $10.4 million gain on the sale
of  the  Company's  shareholdings  in  Crusader,  a  $7.6  million benefit for
settlement  of a lawsuit in which the Company was plaintiff and an $11 million
unrealized  gain  representing  the  change  in  fair  market value of the WTI
benchmark  call  options  purchased  in 1995.  These gains were offset by $3.2
million  in  loss  provisions for certain legal matters.  Other income, net in
1995  included  $7.2  million  received from legal settlements, a $3.5 million
gain  on  the  sale  of Triton France and $2.9 million received from the early
redemption  of  the  Crusader convertible notes.  These gains were offset by a
$4.2  million  unrealized expense representing the change in fair market value
of  the  WTI  benchmark  call  options.

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

          The  income  tax  provision  for 1996 decreased primarily due to the
recognition  of  a  deferred  tax  benefit in the United States totaling $23.5
million  related  to  anticipated  future utilization of NOLs, compared with a
similar benefit of $12.8 million in 1995.  Foreign current tax expense of $5.4
million  in  1996  increased  $1.4  million from 1995, mainly due to increased
profitability  from  the Company's Colombian operations.  Foreign deferred tax
expense  of  $15.4 million in 1996 decreased $2.9 million from 1995, primarily
due to the writedown of the Company's Argentine assets, which lowered taxes by
$3.7  million  in  1996  compared  with  1995.

                         Discontinued  Operations
                         ------------------------

          The  results  of  operations  for  the  aviation  sales and services
segment  have  been  reported  as  discontinued operations.  In June 1995, the
Company sold the assets of its subsidiary, Jet East, Inc., for $2.9 million in
cash and a note, and realized a loss of $1.4 million on the sale.  The Company
accrued  $.6  million for costs associated with final disposal of the segment,
which  occurred  in  August  1995.

                        Petroleum Price 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.

          In  anticipation  of  entering  into a forward oil sale, 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,  1997,  1996 and 1995, the Company recorded an unrealized
gain  (loss)  of ($9.7 million), $11 million and ($4.2 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.

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

                            International Operations
                            ------------------------

          The  Company  derives substantially all of its consolidated revenues
from international operations.  A risk inherent in international operations is
the  possibility  of  realizing  economic  currency-exchange  losses  when
transactions  are  completed  in  currencies  other  than  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,  1997,  the  Company did not realize any material
foreign  exchange  losses  from  its  international  operations.

                            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 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.  Financial information concerning
the  Company's  assets,  including capitalized costs by geographic area, is in
note  21  of  Notes  to  Consolidated  Financial  Statements.

                             Environmental Matters
                             ---------------------

          The  Company  is  subject  to  extensive  environmental  laws  and
regulations.  These laws regulate the discharge of oil, gas or other materials
into  the  environment  and  may require the Company to remove or mitigate the
environmental  effects of the disposal or release of such materials at various
sites.   Also, the Company may remain liable for certain environmental matters
that may arise from formerly owned fuel businesses.  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.

<PAGE>
                Recent Accounting and Disclosure Pronouncements
                -----------------------------------------------

          In  January  1997,  the  Securities  and  Exchange Commission issued
"Disclosure  of  Accounting  Policies for Derivative Financial Instruments and
Derivative  Commodity  Instruments  and  Disclosure  of  Quantitative  and
Qualitative  Information  about  Market  Risk Inherent in Derivative Financial
Instruments,  Other  Financial  Instruments,  and  Derivative  Commodity
Instruments."  The rule amends and expands existing disclosure requirements to
include  quantitative  and qualitative information about market risks inherent
in  market-risk  sensitive  instruments,  including  derivative  financial
instruments,  other  financial  instruments and derivative commodity financial
instruments.  The Company is required to adopt the disclosure requirements for
quantitative  and  qualitative  information  beginning  with  filings with the
Commission that include the Company's annual financial statements for the year
ended  December  31,  1998.    The  required  quantitative  and  qualitative
information  must  be  disclosed  outside the financial statements and related
notes  thereto.

          In  1997,  the Financial Accounting Standards Board issued Statement
No.  128  ("SFAS 128"), "Earnings Per Share."  This Statement is effective for
financial  statements issued for periods ending after December 15, 1997.  SFAS
128  requires  the  presentation  of  basic and diluted earnings per share for
entities  with  complex  capital  structures.    Prior-year earnings per share
amounts  have  been  restated  to  conform  with  SFAS  128.

          In  June  1997,  the  Financial  Accounting  Standards  Board issued
Statement  No.  130  ("SFAS  130"),  "Reporting  Comprehensive  Income."
Comprehensive  income includes net income and several other items that current
accounting  standards  require  to  be recognized outside of net income.  This
standard  established  standards  for  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.    SFAS  130  is  effective  for fiscal years
beginning after December 15, 1997, and the Company will adopt the standard for
its  fiscal  year beginning January 1, 1998.  This statement will not have any
effect  on  the  Company's  results  of  operations  or  financial  position.

          In  June  1997,  the  Financial  Accounting  Standards  Board issued
Statement  No.  131 ("SFAS 131"), "Disclosures about Segments of an Enterprise
and Related Information," replacing Statement No. 14 and its amendments.  This
standard  requires  enterprises  to report certain information about operating
segments  in  annual  financial  statements to shareholders.  Additionally, it
requires that enterprises report selected information about operating segments
in  interim  financial  reports  issued  to  shareholders.    The  basis  for
determining  an  enterprise's  operating  segments  is  the  manner  in  which
financial  information  is used internally by the enterprise's chief operating
decision  maker.    SFAS  131  is  effective  for fiscal years beginning after
December  15,  1997,  and  the Company intends to adopt the standard in fiscal
year  1998.   This statement will not have any effect on the Company's results
of  operations  or  financial  position.

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

          The  Company  has  reviewed  its  operational,  financial  and other
information  systems  for potential conflicts with the Year 2000.  The Company
believes  that the Year 2000 will not cause any significant disruptions to its
information  systems,  and  any  costs to resolve Year 2000 issues will not be
material.

          The  Company has begun an investigation into the potential impact to
its  operations  caused by Year 2000 problems that may occur at third parties,
including  its oil and gas partners, financial institutions, and vendors.  The
Company  has  identified  certain  third  parties that may encounter Year 2000
problems,  but  has  not  yet determined the potential impact to the Company's
operations  or the costs to the Company, if any, associated with these issues.
The  Company  intends  to engage a third-party Year 2000 consultant in 1998 to
validate  the  Company's  assumptions  and  identify  nonconformance.

               Certain Factors that Could Affect Future Operations
               -------------------------------------------------

          Certain  statements  in  this  report,  including  expectations,
intentions,  plans  and  beliefs  of  the  Company  and  management,  are
forward-looking  statements,  as  defined  in  Section  21D  of the Securities
Exchange  Act  of  1934,    that  are  dependent  on certain events, risks and
uncertainties  that  may  be  outside  the  Company's  control.    These
forward-looking  statements  include  statements  of  management's  plans  and
objectives  for  the  Company's  future  operations  and  statements of future
economic  performance;  information regarding drilling schedules and schedules
for  the  start-up of production facilities; expected or planned production or
transportation  capacity;  when the Fields might become self-financing; future
production  of  the  Fields;  the  negotiation  of  a  heads of agreement to a
gas-sales  contract and a gas-sales contract and commencement of production in
Malaysia-Thailand;  the  Company's  capital  budget  and  future  capital
requirements;  the  Company's meeting its future capital needs;  the amount by
which  production  from  the  Fields  may  increase  or  when  such  increased
production  may commence; 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; and proven
oil  and  gas reserves and discounted future net cash flows therefrom; and the
assumptions  described  in  this  report  underlying  such  forward-looking
statements.    Actual  results  and  developments could differ materially from
those  expressed  in or implied by such statements due to a number of factors,
including  those  described  in the context of such forward-looking statements
and  in  notes  19  and  20  of  Notes  to  Consolidated Financial Statements.

<PAGE>

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

               Not  applicable.

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 1998 Annual Meeting of Shareholders of the Company
(the  "Proxy  Statement"),  specifically  the  discussion  under  the  heading
"Election of Directors."  It is currently anticipated that the Proxy Statement
will  be  publicly available and mailed in April 1998.  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  "Voting  and  Principal Shareholders" in the
Proxy  Statement  is  incorporated  herein  by  reference.


ITEM  13. CERTAIN  RELATIONSHIPS  AND  RELATED  TRANSACTIONS

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

<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>



<C>        <S>

     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 Chemical 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 and
             Chemical Bank, as Rights Agent.(4)
    10.1     Amended and Restated  Retirement Income Plan.(5)(23)
    10.2     Amended and Restated Supplemental Executive Retirement Income Plan.(23)(24)
    10.3     1981 Employee Non-Qualified Stock Option Plan.(6)(23)
    10.4     Amendment No. 1 to the 1981 Employee Non-Qualified Stock Option Plan.(7)(23)
    10.5     Amendment No. 2 to the 1981 Employee Non-Qualified Stock Option Plan.(6)(23)
    10.6     Amendment No. 3 to the 1981 Employee Non-Qualified Stock Option Plan.(5)(23)
    10.7     1985 Stock Option Plan.(8)(23)
    10.8     Amendment No. 1 to the 1985 Stock Option Plan.(6)(23)
    10.9     Amendment No. 2 to the 1985 Stock Option Plan.(5)(23)
   10.10     Amended and Restated 1986 Convertible Debenture Plan.(5)(23)
   10.11     1988 Stock Appreciation Rights Plan.(9)(23)
   10.12     1989 Stock Option Plan.(10)(23)
   10.13     Amendment No. 1 to 1989 Stock Option Plan.(6)(23)
   10.14     Amendment No. 2 to 1989 Stock Option Plan.(5)(23)
   10.15     Second Amended and Restated 1992 Stock Option Plan.(11)(23)
   10.16     Form of Amended and Restated Employment Agreement with Triton Energy Limited
             and its executive officers.(23)(24)
   10.17     Form of Amended and Restated Employment Agreement with Triton Energy Limited
             and certain officers.(23)(24)
   10.18     Amended and Restated 1985 Restricted Stock Plan.(5)(23)
   10.19     First Amendment to Amended and Restated 1985 Restricted Stock Plan.(13)(23)
   10.20     Second Amendment to Amended and Restated 1985 Restricted Stock Plan.(11)(23)
   10.21     Executive Life Insurance Plan.(14)(23)
   10.22     Long Term Disability Income Plan.(14)(23)
   10.23     Amended and Restated Retirement Plan for Directors.(8)(23)
   10.24     Amended and Restated Indenture dated as of March 25, 1996 between Triton and
             Chemical Bank, with respect to the issuance of Senior Subordinated Discount Notes
             due 1997.(11)
   10.25     Amended and Restated Senior Subordinated Indenture by and between the Company and
             United States Trust Company of New York, dated as of March 25, 1996.(11)
   10.26     Contract for Exploration and Exploitation for Santiago de Atalayas I with an effective
             date of July 1, 1982, between Triton Colombia, Inc., and Empresa Colombiana
             De Petroleos.(8)
   10.27     Contract for Exploration and Exploitation for Tauramena with an effective date of July
             4, 1988, between Triton Colombia, Inc., and Empresa Colombiana De Petroleos.(9)
   10.28     Summary of Assignment legalized by Public Instrument No. 1255 dated September 15,
             1987 (Assignment is in Spanish language).(9)
   10.29     Summary of Assignment legalized by Public Instrument No. 1602 dated June 11, 1990
             (Assignment is in Spanish language).(9)
   10.30     Summary of Assignment legalized by Public Instrument No. 2586 dated September 9,
             1992 (Assignment is in Spanish language).(9)
   10.31     401(K) Savings Plan.(5)(23)
   10.32     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.(15)
   10.33     Triton Crude Purchase Agreement between Triton Colombia, Inc. and Oil Co., LTD.
             dated May 25, 1995.(16)
   10.34     Credit Agreement among Triton Colombia, Inc., Triton Energy Corporation,
             NationsBank, N.A. (Carolinas) and Export-Import Bank of the United States.(13)
   10.35     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.(13)
   10.36     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.(11)
   10.37     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.(24)
   10.38     Agreement and Plan of Merger among Triton Energy Corporation, Triton Energy
             Limited and TEL Merger Corp.(13)
   10.39     Credit Agreement among Triton Energy Limited and Triton Energy Corporation, as
             Borrowers, and NationsBank of Texas, N.A., Barclays Bank PLC, Meespierson N.V.,
             The Chase Manhattan Bank and Societe Generale, Southwest Agency dated
             August 30, 1996.(17)
   10.40     Form of Indemnity Agreement entered into with each director and officer of the
             Company.(17)
   10.41     Restated Employment Agreement between John Tatum and the Company. (12)(23)
   10.42     Description of Performance Goals for Executive Bonus Compensation. (12)(23)
   10.43     Stock Purchase Agreement dated September 2, 1997 between The Strategic
             Transaction Company and Triton International Petroleum, Inc. ( 24)
   10.44     Fourth Amendment to Stock Purchase Agreement dated February 2, 1998 between
             The Strategic Transaction Company and Triton International Petroleum, Inc. (24 )
   10.45     Supplemental Indenture dated April 17, 1997 among Triton Energy Corporation
             Triton Energy Limited and The Chase Manhattan Bank  (formerly known as
             Chemical Bank) amending Amended and Restated Indenture dated as of March 25, 1996
             relating to the Senior Subordinated Discount Notes due 1997. (18)
   10.46     Supplemental Indenture dated April 17, 1997 among Triton Energy Corporation,
             Triton Energy Limited and United States Trust Company of New York amending
             Amended and Restated Senior Subordinated Indenture dated as of  March 25,
             1996 relating to the 9 3/4% Senior Subordinated Discount Notes due 2000. (18)
   10.47     Senior Indenture dated April 10, 1997 among Triton Energy Limited and The
             Chase Manhattan Bank. (18)
   10.48     First Supplemental Indenture dated April 10, 1997 among Triton Energy Corporation,
             Triton Energy Limited and The Chase Manhattan Bank amending Senior
             Indenture dated as of April 10, 1997 relating to the 8 3/4% Senior
             Notes due 2002. (18)
   10.49     Second Supplemental Indenture dated April 10, 1997 among Triton Energy Corporation,
             Triton Energy Limited and The Chase Manhattan Bank amending Senior
             Indenture dated as of April 10, 1997 relating to the 9 1/4% Senior Notes
             due 2005. (18)
   10.50     First Amendment to Credit Agreement dated as of April 4, 1997 among Triton
             Energy Limited and Triton Energy Corporation, as Borrowers, and
             NationsBank of Texas, N.A., Barclays Bank PLC, Meespierson N.V., The
             Chase Manhattan Bank and Societe Generale, Southwest Agency. (18)
   10.51     1997 Share Compensation Plan. (18)(23)
   10.52     First Amendment to 1997 Share Compensation Plan. (23 )(24)
   10.53     First Amendment to Amended and Restated Retirement Plan for Directors.(23)(24)
   10.54     First Amendment to Second Amended and Restated 1992 Stock Option Plan. (18)(23)
   10.55     Second Amendment to Second Amended and Restated 1992 Stock Option Plan. (23)(24)
   10.56     Agreement to Release Triton Energy Corporation and Second Amendment
             to Credit Agreement dated as of July 21, 1997 among Triton Energy Limited
             and Triton Energy Corporation, as Borrowers, and NationsBank of Texas,
             N.A., Barclays Bank PLC, MeesPierson N.V., The Chase Manhattan Bank
              and Societe Generale, Southwest Agency. (19)
   10.57     Amended and Restated Indenture dated July 25, 1997 between Triton Energy
             Limited and The Chase Manhattan Bank. (19)
   10.58     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. (19)
   10.59     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. (19)
   10.60     Third Amendment to Credit Agreement dated as of September 30, 1997
             among Triton Energy Limited, NationsBank of Texas, N.A., Barclays Bank PLC,
             MeesPierson N.V., The Chase Manhattan Bank and Societe Generale,
             Southwest Agency. (20)
    12.1     Computation of Ratio of Earnings to Fixed Charges. (24)
    12.2     Computation of Ratio of Earnings to Combined Fixed Charges and Preference
             Dividends(24)
    21.1     Subsidiaries of the Company.(24)
    23.1     Consent of Price Waterhouse LLP.(24)
    23.2     Consent of DeGolyer and MacNaughton.(24)
    24.1     The power of attorney of officers and directors of the Company (set forth on the
             signature page hereof).(24)
    27.1     Financial Data Schedule.(24)
    99.1     Rio Chitamena Association Contract.(21)
    99.2     Rio Chitamena Purchase and Sale Agreement.(21)
    99.3     Integral Plan - Cusiana Oil Structure.(21)
    99.4     Letter Agreements with co-investor in Colombia.(21)
    99.5     Colombia Pipeline Memorandum of Understanding.(21)
    99.6     Amended and Restated Oleoducto Central S.A. Agreement dated as of March 31,
             1995.(22)

</TABLE>


____________________

<TABLE>
<CAPTION>



<C>   <S>

 (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 Triton Energy Corporation's Quarterly Report on Form
        10-Q for the quarter ended November 30, 1993 and incorporated by reference herein.
 (6)    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.
 (7)    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.
 (8)    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.
 (9)    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.
(10)    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.
(11)    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.
(12)    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.
(13)    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.
(14)    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.
(15)    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.
(16)    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.
(17)    Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
        quarter ended September 30, 1996 and incorporated herein by reference.
(18)    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.
(19)    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.
(20)    Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
        quarter ended September 30, 1997 and incorporated herein by reference.
(21)    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.
(22)    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.
(23)    Management contract or compensatory plan or arrangement.
(24)    Filed herewith.

</TABLE>



     (b)          Reports  on  Form  8-K.

          None
                                  SIGNATURES

     Pursuant  to  the  requirements  of Section 13 or 15(d) of the Securities
Exchange  Act  of  1934,  the Registrant has duly caused this Annual Report on
Form  10-K to be signed by the undersigned thereunto duly authorized on the 27
day  of  March,  1998.

                              TRITON  ENERGY  LIMITED



                              By:   /s/Thomas  G.  Finck
                                   ------------------------
                                   Thomas  G.  Finck
                                   Chairman  of  the Board and Chief Executive
                                   Officer

                               POWER OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and
directors  of  Triton  Energy  Limited  (the "Company") hereby constitutes and
appoints  Thomas  G.  Finck, Robert B. Holland, III, and Peter Rugg, or any of
them  (  with  full  power  to each of them to act alone), his true and lawful
attorney-in-fact  and  agent,  with full power of substitution, for him and on
his  behalf  and  in  his name, place and stead, in any and all capacities, to
sign, execute, and file any and all documents relating to the Company's Annual
Report  on  Form  10-K for the year ended December 31, 1997, 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 27 day of
March,  1998.

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


      /s/Thomas  G.  Finck                     Chairman of the Board and Chief
-------------------------------------          Financial Officer
Thomas  G.  Finck


      /s/Peter  Rugg                           Senior  Vice  President and
-------------------------------------          Chief Financial Officer
          Peter  Rugg                           (Principal  Accounting  and
                                                 Financial  Officer)


      /s/John  P.  Lewis                       Director  March  17, 1998
-------------------------------------
         John  P.  Lewis


      /s/Michael  E.  McMahon                  Director  March  17, 1998
-------------------------------------
         Michael  E.  McMahon


      /s/Ernest  E. Cook                       Director  March  17, 1998
-------------------------------------
         Ernest  E.  Cook


      /s/Sheldon  R.  Erikson                  Director  March  17, 1998
-------------------------------------
         Sheldon  R.  Erikson


      /s/Jesse  E.  Hendricks                  Director  March  17, 1998
---------------------------------------
         Jesse  E.  Hendricks


     /s/Fitzgerald S. Hudson                   Director  March  17, 1998
---------------------------------------
         Fitzgerald  S.  Hudson


     /s/John  R.  Huff                         Director  March  17, 1998
---------------------------------------
         John  R.  Huff


     /s/Thomas  P.  Kellogg,  Jr.              Director  March  17, 1998
---------------------------------------
        Thomas  P.  Kellogg,  Jr.


     /s/Edwin  D. Williamson                   Director  March  17, 1998
---------------------------------------
         Edwin  D.  Williamson







                    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, 1997, 1996
and 1995                                                                          F-3
Consolidated Balance Sheets - December 31, 1997 and 1996                          F-4
Consolidated Statements of Cash Flows - Years ended December 31, 1997, 1996
and 1995                                                                          F-5
Consolidated Statements of Shareholders' Equity - Years ended December 31, 1997,
1996 and 1995                                                                     F-6
Notes to Consolidated Financial Statements                                        F-7
</TABLE>


<TABLE>
<CAPTION>



<S>        <C>
SCHEDULE:
II         -  Valuation and Qualifying Accounts - Years ended December 31, 1997,
              1996 and 1995                                                       F-47
</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, 1997
and 1996, and the results of their operations and their cash flows for each of
the  three  years  in  the  period ended December 31, 1997, 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.



Price  Waterhouse  LLP
Dallas,  Texas
February  5,  1998
<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,
                                                --------------------------------
                                                   1997       1996       1995
                                                ----------  ---------  ---------
SALES AND OTHER OPERATING REVENUES:

Oil and gas sales                               $ 145,419   $129,795   $106,844
Other operating revenues                            4,077      4,182        628
                                                ----------  ---------  ---------
                                                  149,496    133,977    107,472
                                                ----------  ---------  ---------
COSTS AND EXPENSES:
Operating                                          51,357     36,654     35,276
General and administrative                         28,607     25,945     25,672
Depreciation, depletion and amortization           36,828     25,640     23,208
Writedown of assets                                   ---     42,960        ---
                                                ----------  ---------  ---------
                                                  116,792    131,199     84,156
                                                ----------  ---------  ---------

OPERATING INCOME                                   32,704      2,778     23,316

Interest income                                     5,178      6,703      7,954
Interest expense, net                             (23,858)   (15,897)   (24,055)
Other income, net                                   2,872     27,361      9,385
                                                ----------  ---------  ---------
                                                  (15,808)    18,167     (6,716)
                                                ----------  ---------  ---------

EARNINGS FROM CONTINUING OPERATIONS
 BEFORE INCOME TAXES AND EXTRAORDINARY ITEM        16,896     20,945     16,600
Income tax expense (benefit)                       11,301     (2,860)    10,059
                                                ----------  ---------  ---------
                                                    5,595     23,805      6,541
DISCONTINUED OPERATIONS:
Loss from operations                                  ---        ---     (1,858)
Loss on disposal                                      ---        ---     (1,963)
                                                ----------  ---------  ---------
EARNINGS BEFORE EXTRAORDINARY ITEM                  5,595     23,805      2,720
Extraordinary item - extinguishment of debt       (14,491)    (1,196)       ---
                                                ----------  ---------  ---------
NET EARNINGS (LOSS)                                (8,896)    22,609      2,720
DIVIDENDS ON PREFERENCE SHARES                        400        985        802
                                                ----------  ---------  ---------
EARNINGS (LOSS) APPLICABLE TO ORDINARY SHARES   $  (9,296)  $ 21,624   $  1,918
                                                ----------  ---------  ---------

Average ordinary shares outstanding                36,471     35,929     35,147
                                                ----------  ---------  ---------
BASIC EARNINGS (LOSS) PER ORDINARY SHARE:
Continuing operations                           $    0.14   $   0.64   $   0.16
Discontinued operations                               ---        ---      (0.11)
Extraordinary item                                  (0.40)     (0.03)       ---
                                                ----------  ---------  ---------
NET EARNINGS (LOSS)                             $   (0.26)  $   0.61   $   0.05
                                                ----------  ---------  ---------

DILUTED EARNINGS (LOSS) PER ORDINARY SHARE:
Continuing operations                           $    0.14   $   0.62   $   0.16
Discontinued operations                               ---        ---      (0.11)
Extraordinary item                                  (0.39)     (0.03)       ---
                                                ----------  ---------  ---------
NET EARNINGS (LOSS)                             $   (0.25)  $   0.59   $   0.05
                                                ----------  ---------  ---------



</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>
ASSETS                                                            DECEMBER  31,
                                                            ------------------------
                                                                 1997        1996
                                                            ------------  ----------
CURRENT ASSETS:
Cash and equivalents                                        $    13,451   $  11,048
Short-term marketable securities                                    ---       3,866
Trade receivables, net                                           12,963      11,526
Other receivables                                                52,162      49,000
Inventories, prepaid expenses and other                           5,219       8,920
Assets held for sale                                             58,178         ---
                                                            ------------  ----------
TOTAL CURRENT ASSETS                                            141,973      84,360
Property and equipment, at cost, net                            835,506     676,833
Deferred income taxes                                            87,148      71,416
Investments and other assets                                     33,412      81,915
                                                            ------------  ----------
                                                            $ 1,098,039   $ 914,524
                                                            ------------  ----------
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
Current maturities of long-term debt                        $   130,375   $ 199,552
Short-term borrowings                                            54,600         ---
Accounts payable and accrued liabilities                         36,964      38,545
Deferred income                                                  35,254      28,466
                                                            ------------  ----------
TOTAL CURRENT LIABILITIES                                       257,193     266,563

Long-term debt, excluding current maturities                    443,312     217,078
Deferred income taxes                                            50,968      45,431
Deferred income and other                                        49,946      84,808
Convertible debentures due to employees                             ---         ---

SHAREHOLDERS' EQUITY:
Preference shares, par value $.01; authorized
  20,000,000 shares; issued 218,285 and 247,469
  shares at December 31, 1997 and 1996, respectively;
  stated value $34.41                                             7,511       8,515
Ordinary shares, par value $.01; authorized
  200,000,000 shares; issued 36,541,064 and
  36,342,181 shares at December 31, 1997 and
  1996, respectively                                                365         363
Additional paid-in capital                                      588,454     582,581
Accumulated deficit                                            (297,581)   (288,685)
Other                                                            (2,126)     (2,128)
                                                            ------------  ----------
                                                                296,623     300,646
Less cost of ordinary shares in treasury                              3           2
                                                            ------------  ----------
TOTAL SHAREHOLDERS' EQUITY                                      296,620     300,644
Commitments and contingencies (note 20)                             ---         ---
                                                            ------------  ----------
                                                            $ 1,098,039   $ 914,524
                                                            ------------  ----------
</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,
                                                                 ------------------------------------
                                                                      1997        1996        1995
                                                                 ------------  ----------  ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
    Net earnings (loss)                                          $    (8,896)  $  22,609   $   2,720
    Adjustments to reconcile net earnings to net cash provided
       (used) by operating activities:
    Depreciation, depletion and amortization                          36,828      25,640      23,467
    Amortization of debt discount                                      7,949      15,897      23,928
    Proceeds from forward oil sale                                       ---         ---      86,610
    Amortization of deferred income                                  (28,467)     (8,105)     (4,725)
    Gain on sale of assets, net                                       (5,486)    (15,831)     (2,938)
    Payment of accreted interest on extinguishment of debt          (124,794)        ---         ---
    Extraordinary loss on extinguishment of debt, net of tax          14,491       1,196         ---
    Writedowns, loss provisions and discontinued operations              ---      45,753       7,192
    Deferred income taxes                                              8,078      (8,115)      5,444
    Other, net                                                         6,100      (7,655)       (536)
    Changes in working capital:
      Marketable debt securities - trading                             1,856       4,149       8,074
      Receivables                                                     (2,408)     (5,048)     (1,677)
      Inventories, prepaid expenses and other                            (62)       (787)       (790)
      Accounts payable and accrued liabilities                        (2,605)     11,002       2,325
                                                                 ------------  ----------  ----------
          Net cash provided (used) by operating activities           (97,416)     80,705     149,094
                                                                 ------------  ----------  ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Capital expenditures and investments                              (219,216)   (252,684)   (178,161)
  Purchases of investments and marketable securities                     ---         ---     (45,281)
  Proceeds from sale of investments and marketable securities          2,000      38,507      42,050
  Proceeds from sale of shareholdings in Crusader                        ---      69,583         ---
  Sales of property and equipment and other assets                     5,899      38,505      20,866
  Other                                                               (1,383)        571         732
                                                                 ------------  ----------  ----------
          Net cash used by investing activities                     (212,700)   (105,518)   (159,794)
                                                                 ------------  ----------  ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Proceeds from revolving lines of credit and long-term debt         620,413      53,911      85,627
  Payments on revolving lines of credit and long-term debt          (321,515)    (70,884)    (39,366)
  Short-term notes payable, net                                        9,600         ---     (10,000)
  Issuance of ordinary shares                                          5,260       5,874       8,398
  Other                                                                 (390)     (1,879)     (5,756)
                                                                 ------------  ----------  ----------
          Net cash provided (used) by financing activities           313,368     (12,978)     38,903
                                                                 ------------  ----------  ----------
Effects of exchange rate changes on cash and equivalents                (849)       (211)     (1,494)
                                                                 ------------  ----------  ----------
Net increase (decrease) in cash and equivalents                        2,403     (38,002)     26,709
CASH AND EQUIVALENTS AT BEGINNING OF YEAR                             11,048      49,050      22,341
                                                                 ------------  ----------  ----------
CASH AND EQUIVALENTS AT END OF YEAR                              $    13,451   $  11,048   $  49,050
                                                                 ------------  ----------  ----------

</TABLE>






         See accompanying Notes to Consolidated Financial Statements.



<PAGE>


                    TRITON ENERGY LIMITED AND SUBSIDIARIES
               CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
                   (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>



<S>                                                 <C>          <C>         <C>
                                                         YEAR ENDED DECEMBER 31,
                                                    -----------------------------------
                                                        1997        1996        1995
                                                    -----------  ----------  ----------
PREFERENCE SHARES:
Balance at beginning of year                        $    8,515   $  14,109   $  17,976
Conversion of 5% preference shares                      (1,004)     (5,594)     (3,867)
                                                    -----------  ----------  ----------
Balance at end of year                                   7,511       8,515      14,109
                                                    -----------  ----------  ----------
ORDINARY SHARES:
Balance at beginning of year                               363      35,927      35,577
Exercise of employee stock options and debentures            2          81         238
Conversion of 5% preference shares                         ---         153         112
Reduction in par value                                     ---     (35,783)        ---
Other, net                                                 ---         (15)        ---
                                                    -----------  ----------  ----------
Balance at end of year                                     365         363      35,927
                                                    -----------  ----------  ----------
ADDITIONAL PAID-IN CAPITAL:
Balance at beginning of year                           582,581     516,326     505,256
Cash dividends, 5% preference shares                      (400)       (985)       (802)
Exercise of employee stock options and debentures        3,831       7,974       8,160
Issuances under stock plans                              1,427         702         313
Conversion of 5% preference shares                       1,004       5,441       3,755
Reduction in par value                                     ---      35,783         ---
Sale of shareholdings in Crusader                          ---      20,413         ---
Other, net                                                  11      (3,073)       (356)
                                                    -----------  ----------  ----------
Balance at end of year                                 588,454     582,581     516,326
                                                    -----------  ----------  ----------
ACCUMULATED DEFICIT:
Balance at beginning of year                          (288,685)   (311,294)   (314,014)
Net earnings (loss)                                     (8,896)     22,609       2,720
                                                    -----------  ----------  ----------
Balance at end of year                                (297,581)   (288,685)   (311,294)
                                                    -----------  ----------  ----------
FOREIGN CURRENCY TRANSLATION ADJUSTMENT:
Balance at beginning of year                            (2,126)     (8,616)     (5,639)
Sale of foreign operations                                 ---         ---      (3,268)
Sale of shareholdings in Crusader                          ---       4,890         ---
Translation rate changes                                   ---       1,600         291
                                                    -----------  ----------  ----------
Balance at end of year                                  (2,126)     (2,126)     (8,616)
                                                    -----------  ----------  ----------
OTHER, NET:
Balance at beginning of year                                (2)        (89)     (1,384)
Valuation reserve on marketable securities                   2          87       1,295
                                                    -----------  ----------  ----------
Balance at end of year                                     ---          (2)        (89)
                                                    -----------  ----------  ----------
TREASURY SHARES:
Balance at beginning of year                                (2)       (338)       (577)
Purchase of treasury shares                                 (1)         (5)         (4)
Transfer of shares to employee benefit plans               ---         137         243
Retirement of treasury shares                              ---         204         ---
                                                    -----------  ----------  ----------
Balance at end of year                                      (3)         (2)       (338)
                                                    -----------  ----------  ----------
TOTAL SHAREHOLDERS' EQUITY                          $  296,620   $ 300,644   $ 246,025
                                                    -----------  ----------  ----------

</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
actively  exploring  for  oil  and  gas in these areas, as well as in southern
Europe,  Africa,  Asia  and  the Middle East.  All sales are currently derived
from  oil  and  gas  production  in  Colombia.

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

PRINCIPLES  OF  CONSOLIDATION

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

CASH  EQUIVALENTS  AND  MARKETABLE  SECURITIES

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

Investments  in  marketable  debt securities are reported at fair value except
for  those investments that management has the positive intent and the ability
to  hold  to maturity.  Investments available-for-sale are classified based on
the  stated maturity of the securities, and changes in fair value are reported
as  a  separate  component  of  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,  aircraft  and  leasehold  improvements,  are depreciated
principally  on a straight-line basis over estimated useful lives ranging from
3  to  20  years.

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

<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 certain affiliates where
the  local  currencies  are  used  as the functional currency.  The cumulative
translation  effects  from  translating  balance  sheet  accounts  from  the
functional  currency  into U.S. dollars at current exchange rates 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.

DISCONTINUED  OPERATIONS  AND  RECLASSIFICATIONS

The  results  of  operations  for  the  Company's  aviation sales and services
segment  in  1995  have  been  reported  as  discontinued  operations.

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

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

In  1997,  the  Financial  Accounting Standards Board issued Statement No. 128
("SFAS 128"), "Earnings Per Share."  This Statement is effective for financial
statements  issued  for  periods  ending  after  December  15, 1997.  SFAS 128
requires the presentation of basic and diluted earnings per share for entities
with  complex  capital structures.  Prior-year earnings per share amounts have
been  restated  to  conform  with  SFAS  128.

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 is calculated
to  show earnings per share assuming 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.

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.

2. DIVESTITURES  AND  DISCONTINUED  OPERATIONS

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 other operating
revenues.

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
takeover  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 other operating revenues.

In  August 1995, the Company sold Triton France S.A.  The Company received net
proceeds,  including  repayment  of  intercompany  debt,  of approximately $16
million  and  recorded  a  net  gain  of  $3.5  million  and  a  reduction  in
shareholders'  equity  of  approximately $3.3 million for the foreign currency
translation  adjustment.

In  June  1995, the Company sold the assets of its subsidiary, Jet East, Inc.,
for  $2.9  million  in cash and a note, and realized a loss of $1.4 million on
the  sale.    The  Company accrued $.6 million for costs associated with final
disposal of the segment, which occurred in August 1995.  Revenues and net loss
for the aviation sales and services segment during the year ended December 31,
1995,  were  $4.7  million  and  $2  million,  respectively.

3. 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,  which is expected in 1998, and when
certain  other  conditions  are  met.  At  December 31, 1997, proceeds held in
interest-bearing  reserve  accounts  of $31.8 million and $3 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.

4. OTHER  RECEIVABLES

Other  receivables  consisted  of  the  following:

<TABLE>
<CAPTION>


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

  Receivable from the forward oil sale        $31,770  $30,000
  Receivable from partners                     11,152    5,371
  Central Llanos pipeline upgrade receivable      ---    6,380
  Other                                         9,240    7,249
                                              -------  -------
                                              $52,162  $49,000
                                              -------  -------
</TABLE>













<PAGE>


5. ASSETS  HELD  FOR  SALE

Assets  held  for  sale  consisted  of  the  following:

<TABLE>
<CAPTION>


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

Investment in OCENSA  $      47,429
Corporate assets             10,749
                      -------------
                      $      58,178
                      -------------

</TABLE>


The Company's wholly owned subsidiary, Triton Pipeline Colombia, Inc. ("TPC"),
owns  the Company's 9.6% equity interest in Oleoducto Central S.A. ("OCENSA").
See  note  22  -  Subsequent  Events.

6. PROPERTY  AND  EQUIPMENT

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

<TABLE>
<CAPTION>



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

Oil and gas properties, full cost method:
   Evaluated                                 $518,580  $465,097
   Unevaluated                                130,626    82,997
   Support equipment and facilities           250,193   194,116
Other                                          25,121    31,044
                                             --------  --------
                                              924,520   773,254
Less accumulated depreciation and depletion    89,014    96,421
                                             --------  --------
                                             $835,506  $676,833
                                             --------  --------

</TABLE>



The Company capitalizes interest on qualifying assets, principally unevaluated
oil  and  gas  properties  and  major  development  projects  in  progress.
Capitalized  interest  amounted  to  $25.8  million,  $27.1  million and $16.2
million  in  the  years  ended December 31, 1997, 1996 and 1995, respectively.
The  Company  capitalized  general  and  administrative  expenses  related  to
exploration  and  development  activities  of $32.4 million, $24.6 million and
$21.1  million  in  the  years  ended  December  31,  1997,  1996  and  1995,
respectively.

Evaluated  oil  and  gas properties and accumulated depreciation and depletion
were  reduced  by $40 million each in 1997 due to the Company's sale of Triton
Argentina,  Inc.    In  1996, evaluated oil and gas properties and accumulated
depreciation  and depletion were reduced by $246.9 million and $228.3 million,
respectively,  due  to  the  sales  of the Company's royalty interests in U.S.
properties  and  the  assets  of  Triton  Indonesia,  Inc.

<PAGE>

7. INVESTMENTS  AND  OTHER  ASSETS

Investments  and  other  assets  consisted  of  the  following:
<TABLE>
<CAPTION>



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

Investment in OCENSA                  $   ---  $34,311
Investment in ODC                      11,108   11,108
WTI benchmark call options              2,678   11,048
Unamortized debt issue costs            2,538    6,878
Receivable from the forward oil sale    3,013    5,613
Other                                  14,075   12,957
                                      -------  -------
                                      $33,412  $81,915
                                      -------  -------
</TABLE>




The  Company  owns  approximately  6.6% of Oleoducto de Colombia S.A. ("ODC").

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 million, $3.6 million and $2.3 million in the years ended December 31,
1997,  1996  and  1995,  respectively.

8.          ACCOUNTS  PAYABLE  AND  ACCRUED  LIABILITIES

Accounts  payable  and  accrued  liabilities  are  summarized  as  follows:

<TABLE>
<CAPTION>


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


Accrued exploration and development   $12,903  $21,082
Accrued interest payable                9,449    2,046
Accounts payable, principally trade     5,819    2,697
Litigation and environmental matters    2,715    3,282
Other                                   6,078    9,438
                                      -------  -------
                                      $36,964  $38,545
                                      -------  -------
</TABLE>



<PAGE>

9. DEBT

SHORT-TERM  BORROWINGS

At  December  31, 1997, the Company had outstanding borrowings of $9.6 million
under  a  $10 million unsecured demand promissory note with a bank that renews
monthly.    Borrowings  bear  interest  at  LIBOR  plus  .75%.

At  December  31,  1997,  the  Company had outstanding borrowings totaling $45
million  under  two unsecured revolving credit facilities with banks providing
for borrowings of up to $30 million and $25 million, respectively.  Borrowings
bear interest at various spreads over the Eurodollar rate or, at the option of
the  Company,  at  LIBOR  or  prime.   The revolving credit facilities contain
certain  covenants  requiring  certain  levels  of production and limiting the
incurrence  of  certain  liens,  sales/leaseback  transactions,  dividends  on
ordinary  shares,  and  mergers  and  consolidations.

The  weighted  average  interest rates on short-term borrowings outstanding at
December  31,  1997,  was  7.3%.

LONG-TERM  DEBT

A  summary  of  long-term  debt  follows:

<TABLE>
<CAPTION>



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


Senior Notes due 2005                        $200,000  $    ---
Senior Notes due 2002                         199,900       ---
Revolving credit facility maturing 1998       119,900    11,000
Term credit facility maturing 2001             31,595    40,622
Revolving credit facility maturing 1999        17,500       ---
Senior Subordinated Discount Notes due 2000       854   170,000
Senior Subordinated Discount Notes due 1997       ---   189,869
Other notes and capitalized leases              3,938     5,139
                                             --------  --------
                                              573,687   416,630
 Less current maturities                      130,375   199,552
                                             --------  --------
                                             $443,312  $217,078
                                             --------  --------




</TABLE>




<PAGE>

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  commencing  October 15, 1997.  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 1992, the Company completed the sale of $240 million in principal
amount  of  Senior  Subordinated Discount Notes ("1997 Notes") due November 1,
1997,  providing  net  proceeds  to the Company of approximately $126 million.
The  original  issue price was 54.76% of par, representing a yield to maturity
of  12  1/2%  per  annum  compounded  on  a semi-annual basis without periodic
payments  of  interest.

In 1993, the Company completed the sale of $170 million in principal amount of
9  3/4%  Senior  Subordinated Discount Notes ("9 3/4% Notes") due December 15,
2000,  providing  net  proceeds  to the Company of approximately $124 million.
The original issue price was 75.1% of par, representing a yield to maturity of
9  3/4%.    No interest was payable on the 9 3/4% Notes during the first three
years  of  issue.   Commencing December 15, 1996, interest on the 9 3/4% Notes
began  to  accrue at the rate of 9 3/4% per annum and is payable semi-annually
on  June  15  and  December  15,  beginning  on  June  15,  1997.

In  May  and  June  1997,  the  Company  completed  a tender offer and consent
solicitation with respect to the 1997 Notes and the 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.

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.

During 1997, the Company signed two unsecured bank revolving credit facilities
providing  for  borrowings of up to $50 million and $25 million, respectively,
that  mature  in  November  and  December 1999, respectively.  Borrowings bear
interest  at  various  spreads  over  the Eurodollar rate or, at the Company's
option,  at  LIBOR  or prime.  The revolving credit facilities contain certain
covenants  requiring  certain levels of production and limiting the incurrence
of  certain liens, sales/leaseback transactions, dividends on ordinary shares,
and  mergers  and  consolidations.  Under the most restrictive covenant in the
Company's  existing  credit facilities, the Company generally could not permit
total  indebtdness  (as  defined  in  the  various  agreements) to exceed $650
million.    At  December  31,  1997, the Company had outstanding borrowings of
$17.5  million  under  the  $50  million  facility.

In  1996,  the  Company  signed a $125 million unsecured bank revolving credit
facility  that  matures  in  August 1998.  Borrowings bear interest at various
spreads  over  either  prime or LIBOR.  The revolving credit facility contains
financial  covenants  that  include  certain  limitations  on  dividends,
investments,  prepayments  of  debt, transactions with affiliates, and mergers
and  acquisitions,  and  include  certain mandatory pay-down requirements.  At
December  31,  1997,  the Company had outstanding borrowings of $119.9 million
and  letters  of  credit  for  $4.5 million under the facility.  See note 22 -
Subsequent  Events.

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 beginning on
July  15, 1996, and borrowings bear interest at LIBOR plus .25%, adjusted on a
semi-annual  basis.    At  December  31,  1997,  the  Company  had outstanding
borrowings  of  $31.6  million  under  the  facility.

The  aggregate  maturities  of  long-term  debt  for the five years during the
period ending December 31, 2002, are as follows:  1998 -- $130.4 million; 1999
--  $27.1  million;  2000  --  $9.6 million; 2001 -- $5.1 million; and 2002 --
$200.4  million.

10. INCOME  TAXES

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

<TABLE>
<CAPTION>


<S>                <C>         <C>        <C>
                      YEAR ENDED DECEMBER 31,
                   --------------------------------
                      1997       1996       1995
                   ----------  ---------  ---------

  Cayman Islands   $ (12,969)  $   (452)  $    ---
  United States      (31,694)   (16,641)   (21,412)
  Foreign - other     61,559     38,038     38,012
                   ----------  ---------  ---------
                   $  16,896   $ 20,945   $ 16,600
                   ----------  ---------  ---------
</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,
                   -------------------------------
                      1997       1996       1995
                   ---------  ---------  ---------
  Current:
  Cayman Islands   $    ---   $    ---   $    ---
  United States          (7)      (172)       627
  Foreign - other     3,230      5,427      3,988
                   ---------  ---------  ---------
  Total current       3,223      5,255      4,615
                   ---------  ---------  ---------
  Deferred:
  Cayman Islands        ---        ---        ---
  United States      (7,929)   (23,489)   (12,797)
  Foreign - other    16,007     15,374     18,241
                   ---------  ---------  ---------
  Total deferred      8,078     (8,115)     5,444
                   ---------  ---------  ---------
       Total       $ 11,301   $ (2,860)  $ 10,059
                   ---------  ---------  ---------
</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,
                                                        ------------------------
                                                          1997     1996    1995
                                                        --------  -------  ------

  Tax provision at statutory tax rate                      0.0 %     0.0 %   35.0 %
  Increase (decrease) resulting from:
     Net change in valuation allowance                    263.0 % (111.6)% (201.6)%
     Recognition of outside basis adjustments               --- %  (20.3)% (107.6)%
     Foreign items without tax benefit                     77.8 %   25.8 %   23.9 %
     Income tax rate changes                                --- %    --- %   16.9 %
     Income subject to tax in excess of statutory rate     36.9 %   58.4 %    --- %
     Branch loss recapture/Subpart F                        --- %    --- %   97.1 %
     Current year change in NOL/credit carryforwards     (356.7)%  (59.2)%   51.2 %

     Temporary differences:
        Oil and gas basis adjustments                      32.5 %   80.6 %  116.4 %
        Reimbursement of pre-commerciality costs           13.2 %   10.9 %   30.5 %
     Other                                                  0.2 %    1.8 %  (1.2) %
                                                        ---------  -------  ------
                                                           66.9 %  (13.6)%   60.6 %
                                                        ---------  -------  ------
</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, 1997                 DECEMBER 31, 1996
                                               ---------------------------------  -------------------------------
                                                                        OTHER                              OTHER
                                                  U.S.     COLOMBIA    FOREIGN        U.S.    COLOMBIA    FOREIGN
                                               ---------  ----------  ----------  ---------  ---------  ---------
  Deferred tax asset:
    Net operating loss carryforwards           $ 156,579   $  10,088   $   8,187   $ 98,555   $  9,540    $ 2,347
    Depreciable/depletable property                2,046         ---         ---      1,558        ---        ---
    Credit carryforwards                           1,726       3,986         ---      2,054        ---        ---
    Reserves                                       1,090         ---         ---      1,259        ---        ---
    Other                                            799         ---         ---        792        ---        ---
                                               ---------  ----------  ----------  ---------  ---------   --------
  Gross deferred tax asset                       162,240      14,074       8,187    104,218      9,540      2,347
  Valuation allowances                           (75,092)        ---         ---    (30,657)       ---        ---
                                               ---------  ----------  ----------  ---------  ---------   --------
  Net deferred tax asset                          87,148      14,074       8,187     73,561      9,540      2,347
                                               ---------  ----------  ----------  ---------  ---------   --------

  Deferred tax liability:
    Depreciable/depletable property                  ---     (58,143)    (15,086)       ---    (50,874)    (6,444)
    WTI benchmark call options                       ---         ---         ---     (2,145)       ---        ---
                                               ---------  ----------  ----------  ---------  ---------   --------

  Net deferred tax asset (liability)              87,148     (44,069)     (6,899)    71,416    (41,334)    (4,097)
  Less current deferred tax asset (liability)        ---         ---         ---        ---        ---        ---
                                               ---------  ----------  ----------  ---------  ---------   --------
  Noncurrent deferred tax asset (liability)    $  87,148   $ (44,069)  $  (6,899)  $ 71,416   $(41,334)   $(4,097)
                                               ---------  ----------  ----------  ---------  ---------   --------



</TABLE>




At  December  31,  1997,  the  Company  had  net  operating  loss ("NOLs") and
depletion  carryforwards  for  U.S.  tax  purposes  of $406.8 million and $6.8
million, respectively. During 1997, the Company amended certain prior-year tax
returns  that  increased  the Company's unused NOLs.  In addition, at December
31,  1997,  certain  U.S.  subsidiaries  had  separate  return limitation year
("SRLY") operating loss and depletion carryforwards of $40.6 million and $13.5
million,  respectively,  which are available to offset only the future taxable
income  of  those  subsidiaries.    The  depletion carryforwards are available
indefinitely.  The U.S. NOLs and SRLY operating loss carryforwards expire from
1998  through  2013  as  follows:

<TABLE>
<CAPTION>


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

  May 1998             $  11,594  $   8,964
  May 1999                 8,809      9,660
  May 2000                 7,315     12,256
  May 2001                20,713      9,675
  May 2002                22,670         32
  May 2003                20,566        ---
  May 2004 - May 2013    315,114        ---
                       ---------  ---------
                       $ 406,781  $  40,587
                       ---------  ---------
</TABLE>



The deferred tax valuation allowance of $75.1 million at December 31, 1997, is
primarily  attributable to management's assessment of the utilization of NOLs,
SRLY  operating  losses  that  are currently not realizable due to the lack of
potential  future  income  in the applicable subsidiaries, and the expectation
that other tax credits will expire without being utilized.  The minimum amount
of  future  taxable  income  necessary  to  realize  the deferred tax asset is
approximately  $249  million.   Although there can be no assurance the Company
will achieve such levels of income, management believes the deferred tax asset
will  be  realized  through  increasing  income  from  its  operations.

At  December  31,  1997,  the Company's Colombian operations and other foreign
operations  had  NOLs  totaling $28.8 million and $28.7 million, respectively.
The  NOLs  expire  from  1998  through  2007.

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.

11.EMPLOYEE  BENEFITS

PENSION  PLANS

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

<PAGE>

The  funding  status  of  the  plans  follows:

<TABLE>
<CAPTION>



<S>                                                     <C>        <C>        <C>     <C>
                                                                     DECEMBER 31,
                                                        --------------------------------------
                                                                 1997              1996
                                                        -------------------  -----------------
                                                        DEFINED              DEFINED
                                                        BENEFIT      SERP    BENEFIT    SERP
                                                         PLAN        PLAN     PLAN      PLAN
                                                        --------  ---------  -------  --------

Actuarial present value of benefit obligations:
   Vested benefit obligations                           $ 4,218   $  4,781   $3,748   $ 4,079
                                                        --------  ---------  -------  --------
   Accumulated benefit obligations                      $ 4,790   $  4,781   $4,037   $ 4,079
                                                        --------  ---------  -------  --------

Projected benefit obligations                           $ 6,008   $  6,621   $4,849   $ 5,288
Plan assets at fair value, primarily listed stocks
   and U. S. government securities                        5,531        ---    4,790       ---
                                                        --------  ---------  -------  --------
Unfunded projected benefit obligations                      477      6,621       59     5,288
Unrecognized net gain (loss)                               (250)      (745)       2       (46)
Prior service cost not yet recognized in net periodic
   pension cost                                            (598)      (133)    (653)     (144)
Unrecognized net asset (liability) at adoption               10     (1,288)      11    (1,456)
Adjustment required to recognize minimum liability          ---        326      ---       437
                                                        --------  ---------  -------  --------
      Accrued (prepaid) pension cost                    $  (361)  $  4,781   $ (581)  $ 4,079
                                                        --------  ---------  -------  --------
</TABLE>



A  summary  of  the  components  of  pension  expense  follows:

<TABLE>
<CAPTION>



<S>                                            <C>         <C>      <C>
                                                YEAR ENDED DECEMBER 31,
                                               ---------------------------
                                                  1997     1996     1995
                                               ---------  -------  -------

Service cost - benefits earned
   during the year                             $    832   $  767   $  780
Interest cost on projected benefit obligation       783      736      653
Actual return on plan assets                       (921)    (387)    (849)
Net amortization and deferral                       738      244      793
                                               ---------  -------  -------
                                               $  1,432   $1,360   $1,377
                                               ---------  -------  -------

</TABLE>







The  projected  benefit  obligations  at  December 31, 1997 and 1996, assume a
discount  rate  of  7.5%  and  8%,  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.

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.

<PAGE>

12. SHAREHOLDERS'  EQUITY

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% preference share, 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,  (or  such  earlier  date as there are fewer than 133,005 5%
preference  shares  outstanding), 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, 1997, 1996 and 1995, 218,285, 247,469 and
410,017  preference  shares  were  outstanding,  respectively.

ORDINARY  SHARES

Changes  in  issued  ordinary  shares  were  as  follows:

<TABLE>
<CAPTION>


<S>                                 <C>         <C>          <C>
                                         YEAR ENDED DECEMBER 31,
                                    -----------------------------------
                                        1997        1996         1995
                                    ----------  -----------  ----------

Balance at beginning of year        36,342,181  35,927,279   35,577,009
Exercise of employee stock options
   and debentures                      133,736     258,333      237,875
Issuances under stock plans             35,961       9,910          ---
Conversion of 5% preference shares      29,184     162,548      112,395
Other, net                                   2     (15,889)         ---
                                    ----------  -----------  ----------
Balance at end of year              36,541,064  36,342,181   35,927,279
                                    ----------  -----------  ----------
</TABLE>



Changes  in  ordinary  shares  held  in  treasury  were  as  follows:

<TABLE>
<CAPTION>


<S>                                           <C>       <C>       <C>
                                                YEAR ENDED DECEMBER 31,
                                              ----------------------------
                                                 1997     1996      1995
                                              --------  --------  --------

Balance at beginning of year                        40   26,635    45,837
Purchase of treasury shares                         33       91        89
Transfer of shares to employee benefit plans       ---  (10,797)  (19,291)
Retirement of treasury shares                      ---  (15,889)      ---
                                              --------  --------  --------
Balance at end of year                              73       40    26,635
                                              --------  --------  --------
</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  of  the  Company  at a price of $120 per one one-thousandth of a share.
Generally,  the  rights  become  distributable  only  if  a  person  acquires
beneficial  ownership  of  15%  or  more  of  the Company's ordinary shares or
announces  a  tender  offer for 15% or more of the ordinary shares.  If, among
other  events,  any such person becomes the beneficial owner of 15% or more of
the  Company's  ordinary shares, 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,  which is equal to the amount obtained by dividing the
right's  exercise  price by 50% of the market price of the common stock on the
date  of the first occurrence.  The rights will expire on May 22, 2005, unless
such  expiration date is extended or unless the rights are earlier redeemed or
exchanged  by the Company.  At any time prior to a person acquiring beneficial
ownership  of  15%  or  more of the Company's ordinary shares, the Company may
redeem  the  rights  in  whole, but not in part, at a price of $.01 per right.

13. STOCK  COMPENSATION  PLANS

STOCK  OPTION  PLANS

Options  to purchase ordinary shares of the Company may be granted to officers
and  employees  under  various  stock option plans. The exercise price of each
option equals 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 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 in 33% cumulative annual
increments  beginning one year from the date of issuance and expire at the end
of  10  years.  At December 31, 1997 and 1996, shares available for grant were
1,040,965  and  731,090,  respectively.

<PAGE>

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, 1997         DECEMBER 31, 1996           DECEMBER 31, 1995
                                       ---------------------------  ----------------------   ---------------------
                                                    WEIGHTED                     WEIGHTED                WEIGHTED
                                                    AVERAGE                      AVERAGE                 AVERAGE
                                                    EXERCISE                     EXERCISE                EXERCISE
                                       SHARES       PRICE             SHARES     PRICE       SHARES      PRICE
                                       -----------  ---------       -----------  ---------   ---------   ---------

Outstanding at beginning of year        3,854,046    $38.81           3,177,304   $35.49     3,074,854     $33.80
Granted                                   744,250     39.99             971,000    47.97       373,500      49.33
Exercised                                 (83,736)    30.76            (216,333)   30.40      (237,875)     35.30
Canceled                                  (65,125)    46.09             (77,925)   40.74       (33,175)     35.62
                                       ----------                   -----------              ----------
Outstanding at end of year              4,449,435     39.05           3,854,046    38.81     3,177,304      35.49
                                       ----------                   -----------              ----------

Options exercisable at yearend          2,728,254                     2,042,492              1,449,424
Weighted average fair value per share
   of options granted during the year  $    16.37                   $     19.89            $     20.75
</TABLE>



The  following table summarizes information about stock options outstanding at
December  31,  1997:

<TABLE>
<CAPTION>


<C>             <S>                  <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, 1997     LIFE          PRICE      DEC. 31, 1997    PRICE
--------------  --------------     -----------  ----------  --------------  ----------
$ 8.38 - 19.88         58,343        2.9 years  $    10.83          58,343  $    10.83
 28.50 - 39.63      2,556,117        6.6 years       34.37       1,802,613       33.17
 40.00 - 49.13      1,082,375        6.1 years       42.35         536,748       42.12
 50.25 - 57.38        752,600        8.1 years       52.43         330,550       51.97
                --------------                                   ---------
                    4,449,435                                    2,728,254
                --------------                                   ---------

</TABLE>


CONVERTIBLE  DEBENTURE  PLAN

The  Company  has  a  convertible  debenture  plan  under which key management
personnel  and  others  may  purchase  debentures  that  are  convertible into
ordinary  shares  of  the  Company.  The  aggregate  number of ordinary shares
issuable  upon  conversion  of  the debentures cannot exceed 1,000,000 shares,
subject  to  adjustment  in  certain  events.  Each  debenture  represents  an
unsecured,  subordinated  obligation due in 10 years and may be redeemed after
three  years  at  a  redemption  price  of  120% of the principal amounts. The
debentures  outstanding at December 31, 1997, bear interest at the prime rate.

The  participants  in  the plan purchased debentures by delivery of promissory
notes  to the Company. The promissory notes are secured by the debentures that
are  held  as security by the Company, are due on the earlier of 10 years from
the  date  of  issue  or termination of employment and require annual interest
payments  equal  to  prime  plus  1/8%.  The  debentures  are  reflected  as a
noncurrent liability, net of the related promissory notes, in the Consolidated
Balance  Sheets  as  follows:

<TABLE>
<CAPTION>


<S>                                   <C>             <C>
                                          DECEMBER 31,
                                      --------------------
                                         1997       1996
                                      ----------  --------
Convertible debentures due employees  $  14,234   $ 15,491
Promissory notes                        (14,234)   (15,491)
                                      ----------  --------
                                      $     ---   $    ---
                                      ----------  --------
</TABLE>



A  summary  of  the  status  of  the  Company's  convertible debenture plan is
presented  below:

<TABLE>
<CAPTION>


<S>                                          <C>            <C>         <C>       <C>        <C>        <C>
                                                 DECEMBER 31, 1997      DECEMBER 31, 1996      DECEMBER 31, 1995
                                             ------------------------  -------------------   -------------------
                                                            WEIGHTED              WEIGHTED              WEIGHTED
                                                            AVERAGE               AVERAGE               AVERAGE
                                                            EXERCISE              EXERCISE              EXERCISE
                                               SHARES       PRICE       SHARES    PRICE       SHARES    PRICE
                                             ----------   -----------  --------  ---------   ---------  --------

Outstanding at beginning of year                458,000   $     33.82   500,000  $   33.94     250,000  $  25.13
Granted                                             ---           ---       ---        ---     250,000     42.75
Exercised                                       (50,000)        25.13   (42,000)     35.20         ---       ---
                                             ----------                --------              ---------
Outstanding at yearend                          408,000         34.89   458,000      33.82     500,000     33.94
                                             ----------                --------              ---------

Options exercisable at yearend                  408,000                 458,000                250,000
Weighted average fair value per share
   of convertible debentures granted during
   the year                                  $      ---               $     ---            $     19.45
</TABLE>



The  following  table  summarizes  information  about  convertible  debentures
outstanding  at  December  31,  1997:

<TABLE>
<CAPTION>


<S>           <C>              <C>           <C>            <C>             <C>
                      DEBENTURES OUTSTANDING                 DEBENTURES EXERCISABLE
              ----------------------------------------      ------------------------
                               WEIGHTED
   RANGE                       AVERAGE        WEIGHTED                      WEIGHTED
    OF         NUMBER          REMAINING      AVERAGE       NUMBER          AVERAGE
   EXERCISE    OUTSTANDING AT  CONTRACTUAL    EXERCISE      EXERCISABLE AT  EXERCISE
   PRICES      DEC. 31, 1997   LIFE           PRICE         DEC. 31, 1997   PRICE
   -------    --------------   -----------    --------      --------------  --------


   $ 25.13           182,000     6.3 years    $  25.13             182,000    $ 25.13
     42.75           226,000     7.4 years       42.75             226,000      42.75
              --------------                                --------------
                     408,000                                       408,000
              --------------                                --------------




<PAGE>

EMPLOYEE  STOCK  PURCHASE  PLAN

The Company has an employee stock purchase plan that provides for the award of
up  to  100,000 ordinary shares to key officers and employees. At December 31,
1997  and  1996,  shares  available  for  grant  were  24,456  and  49,417,
respectively.    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 24,961 shares and 20,707
shares  to  employees  for  the  years  ended  December  31,  1997  and  1996,
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>
<TABLE>
<CAPTION>


<S>                                                 <C>         <C>      <C>
                                                      YEAR ENDED DECEMBER 31,
                                                    ---------------------------
                                                        1997      1996    1995
                                                    ---------  -------  -------
Net earnings (loss) applicable to ordinary shares:
As reported                                         $ (9,296)  $21,624  $1,918
Pro forma                                            (16,802)   17,414    (587)

Basic earnings (loss) per ordinary share:
As reported                                         $  (0.26)  $  0.61  $ 0.05

Pro forma                                              (0.46)     0.48   (0.02)

Diluted earnings (loss) per ordinary share:
As reported                                         $  (0.25)  $  0.59  $ 0.05

Pro forma                                              (0.46)     0.47   (0.02)


</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 1997, 1996 and 1995: dividend
yield  of  0%;  expected  volatility  of 26.1%, 26.9% and 27.8%, respectively;
risk-free  interest rates of approximately 6%; and an expected life of five 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,  1997,  SARs covering 25,000 ordinary shares, with an exercise price of $8
per  share,  were  outstanding.

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

FAIR  VALUE  OF  FINANCIAL  INSTRUMENTS

At  December  31,  1997 and 1996, the Company's financial instruments included
cash,  cash  equivalents,  short-term  receivables,  marketable  securities,
long-term  receivables,  short-term  and  long-term debt, and financial market
transactions.    The  fair  value  of  cash,  cash  equivalents,  short-term
receivables  and  short-term  debt approximated carrying values because of the
short  maturities  of  these  instruments.    The fair values of the Company's
marketable  securities,  long-term  receivables  and  financial  market
transactions, based on broker quotes, quoted market prices and discounted cash
flows,  approximated  the  carrying  values.    The  estimated  fair  value of
long-term  debt,  based  on  quoted  market prices and market data for similar
instruments,  was  $596  million  (carrying  value  -   $574 million) and $433
million  (carrying  value  -  $417  million)  at  December  31, 1997 and 1996,
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.

In  anticipation  of  entering  into a forward oil sale, 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,
1997,  1996  and 1995, the Company recorded an unrealized gain (loss) of ($9.7
million),  $11 million and ($4.2 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.

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

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.

15.          OTHER  INCOME,  NET

Other  income,  net  is  summarized  as  follows:

<TABLE>
<CAPTION>


<S>                                              <C>        <C>       <C>
                                                   YEAR ENDED DECEMBER 31,
                                                 ----------------------------
                                                   1997      1996      1995
                                                 -------   --------  --------

  Change in fair market value of WTI
      benchmark call options                     $(9,689)  $ 10,987   $(4,171)
  Foreign exchange gain (loss)                     9,549       (561)    1,874
  Gain on sale of corporate asset                  1,414        ---       ---
  Proceeds from legal settlements                    765      7,624     7,222
  Gain on sale of shareholdings in Crusader          ---     10,417       ---
  Gain on the sale of Triton France                  ---        ---     3,496
  Gain on early redemption of Crusader's
      convertible notes                              ---        ---     2,899
  Loss provisions                                    ---     (3,193)   (1,058)
  Equity in earnings (loss) of affiliates, net       ---        118    (2,249)
  Other                                              833      1,969     1,372
                                                 --------  --------  --------
                                                 $ 2,872   $ 27,361  $  9,385
                                                 --------  --------  --------
</TABLE>



In  1997,  the  Company  recognized  a  foreign exchange gain of $9.6 million,
primarily  noncash  adjustments  to  deferred  tax  liabilities  in  Colombia
associated  with  devaluation  of  the  Colombian peso versus the U.S. dollar.

<PAGE>

16.          WRITEDOWN  OF  ASSETS

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.

17.          EARNINGS  PER  ORDINARY  SHARE

The  following  table  reconciles the numerators and denominators of the basic
and  diluted  earnings  per  ordinary  share  computation  for  earnings  from
continuing  operations.

<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 before extraordinary item                $     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>




<PAGE>

<TABLE>
<CAPTION>



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


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

YEAR ENDED DECEMBER 31, 1995:

  Earnings from continuing operations              $       6,541
  Less: Preference share dividends                          (802)
                                                   --------------
  Earnings available to ordinary shareholders              5,739
  Basic earnings per ordinary share                                          35,147    $      0.16
                                                                                       -----------
  Effect of dilutive securities
  Stock options                                              ---                690
  Convertible debentures                                     ---                113
                                                   --------------     -------------
  Earnings available to ordinary shareholders and
     assumed conversions                           $       5,739
                                                   --------------
  Diluted earnings per ordinary share                                        35,950    $      0.16
                                                                     --------------    -----------


</TABLE>


At December 31, 1997, 218,285 shares of 5% preference shares were outstanding.
Each preference share is convertible any time into one ordinary share, subject
to  adjustment  in certain events.  The preference shares were not included in
the  computation  of diluted earnings per ordinary share because the effect of
assuming  conversion  of  preference  shares  was  antidilutive.

At  December  31,  1995,  the Company's proportionate shares owned by Crusader
were  not  included  in the computation of diluted earnings per ordinary share
because  the  effect  of assuming conversion of these shares was antidilutive.

18.  STATEMENTS  OF  CASH  FLOWS

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

<TABLE>
<CAPTION>


<S>                                       <C>                       <C>  <C>       <C>     <C>     <C>
                                          YEAR ENDED DECEMBER 31,
                                          ------------------------
                                            1997      1996    1995
                                          -------    ------  ------
Cash paid during the year for:
   Interest (net of amount capitalized)  $133,265    $  ---  $  ---
   Income taxes                             4,666       200     920

Noncash financing acivities:
   Conversion of preference shares into
       ordinary shares                   $  1,004    $5,594  $3,867

</TABLE>



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, $19.5
million  and $7.7 million in the years ended December 31, 1997, 1996 and 1995,
respectively.

19.  CERTAIN  FACTORS  THAT  COULD  AFFECT  FUTURE  OPERATIONS

Certain  statements in this report, including  expectations, intentions, plans
and  beliefs  of  the  Company and management, including those contained in or
implied  by  "Management's  Discussion and Analysis of Financial Condition and
Results  of  Operations" and these Notes to Consolidated Financial Statements,
are  forward-looking  statements,  as defined in Section 21D of the Securities
Exchange  Act  of  1934,  that  are  dependent  on  certain  events, risks and
uncertainties  that  may  be  outside  the  Company's  control.    These
forward-looking  statements  include  statements  of  management's  plans  and
objectives  for  the  Company's  future  operations  and  statements of future
economic  performance;  information regarding drilling schedules and schedules
for  the  start-up of production facilities; expected or planned production or
transportation  capacity;  when the Fields might become self-financing; future
production  of  the  Fields;  the  negotiation  of  a  heads of agreement to a
gas-sales  contract and a gas-sales contract and commencement of production in
Malaysia-Thailand;  the  Company's  capital  budget  and  future  capital
requirements;  the  Company's  meeting its future capital needs; the amount by
which  production  from  the  Fields  may  increase  or  when  such  increased
production  may commence; 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; and proven
oil  and  gas reserves and discounted future net cash flows therefrom; and the
assumptions  described  in  this  report  underlying  such  forward-looking
statements.    Actual  results  and  developments could differ materially from
those  expressed  in or implied by such statements due to a number of factors,
including  those  described in the context of such forward-looking statements,
as  well  as  those  presented  below.

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 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, 1997,
including  capitalized  costs  by  geographic  area,  is set forth in note 21.

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.  Subsequent to
yearend,  the  price  of oil declined significantly which will have a negative
effect on earnings and cash flows in the first-quarter of 1998.

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  and  completion  of  the production facilities currently
under  construction.   The Company expects that the production facilities will
be  completed  in  1998.    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 in
1997,  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.  In 1998, the President of the United States
announced  that  Colombia  would  not be certified, but was granted a national
interest waiver.  There can be no assurance that, in the future, Colombia will
receive certification or a 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  upper  Malay  Basin  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  early planning stages but is expected to take several
years  and  require  the  drilling of additional wells and the installation of
production  facilities,  which  will  require  significant  additional capital
expenditures,  the  ultimate  amount  of which cannot be predicted.  Pipelines
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 Thailand and Malaysia,
including  the  Thai  national oil company's monopoly of transportation within
Thailand  and  its  territorial  waters.

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.

<PAGE>

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.

20. COMMITMENTS  AND  CONTINGENCIES

Development  of  the Fields, including drilling and construction of additional
production  facilities,  will  require  further  capital  outlays.    Further
exploration  and development activities on Block A-18 in the Malaysia-Thailand
Joint  Development  Area  in  the  Gulf  of  Thailand,  as well as exploratory
drilling  in  other  countries, also will require substantial capital outlays.
The  Company's  capital  budget  for  the  year  ending  December 31, 1998, is
approximately  $176  million,  excluding  capitalized  interest,  of  which
approximately $103 million relates to the Fields, $23 million relates to Block
A-18,  and  $50  million relates to the Company's activities in other parts of
the  world.    The  1998  capital  budget  includes  funding  requirements for
committed  activities  only.   Substantial capital requirements for Block A-18
are  expected  prior  to  the  first deliveries of gas, which are estimated to
occur  between  30-36  months  after  signing  of  a  heads  of agreement to a
gas-sales  contract.

The  Company expects to fund capital expenditures and repay debt in the future
with  a  combination  of  some or all of the following: asset sales (which may
involve  interests  in  material assets), cash flow from operations (including
additional  proceeds  of  $30  million  from the 1995 forward oil sale), cash,
credit facilities and additional facilities to be negotiated, and the issuance
of  debt  and  equity  securities.    See  note  22  -  Subsequent  Events.

As  of  yearend  1997,  under  the  most restrictive covenant in the Company's
existing  credit  facilities,  the  Company  generally  could not permit total
indebtedness  (as  defined  in the various agreements) to exceed $650 million.
The  limitation  on  total indebtedness will increase to $725 million once the
Fields  achieve  a  production  rate  of  340,000  barrels  per  day.

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  Block A-18  in  the Gulf of Thailand discussed above, will be met without
any  material,  adverse  effect  on  the  Company's operations or consolidated
financial  condition.

The  Company leases office space, other facilities and equipment under various
operating  leases expiring through 2011.  Total rental expense was $2 million,
$2  million  and  $1.9 million for the years ended December 31, 1997, 1996 and
1995,  respectively.  At December 31, 1997, the minimum payments required over
the  next  five  years  are  as  follows:   1998 -- $2.4 million; 1999 -- $2.2
million;  2000  --  $1.2 million; 2001 -- $.3 million; 2002 --$.2 million; and
thereafter  --  $1.1  million.

GUARANTEES

At  December  31, 1997, the Company had guaranteed loans of approximately $3.7
million for a Colombian pipeline company in which the Company has an ownership
interest.   The Company also guaranteed performance of $32.3 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.   Also, the Company may remain liable for certain environmental matters
that may arise from formerly owned fuel businesses.  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.

<PAGE>

LITIGATION

The  Company and subsidiaries or former subsidiaries of the Company were among
numerous defendants in a lawsuit brought in the Superior Court of the State of
California,  County of Los Angeles, by Travelers Indemnity Company arising out
of  a 1988 tidal wave at King Harbor in Redondo Beach, California. The lawsuit
alleged,  among  other  things, that the defendants' negligence contributed to
the  collapse  of  a hotel and the flooding of a restaurant in the tidal wave.
This  lawsuit  was  settled  in  1998.

During  the quarter ending September 30, 1995, the United States Environmental
Protection  Agency ("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 subsidiary has a formal
period  of  negotiation  regarding performing the final remediation design for
the  clean-up of the site, and demanded reimbursement for certain unpaid costs
that  have  been incurred. The government estimates the aggregate amount being
negotiated  as  $217 million  to be allocated  among  the 280 known operators.
The  subsidiary's  share    would    be  approximately $1 million based upon a
volumetric  allocation.    The  Company  has  been advised that the government
expects  defendants  such  as  the  subsidiary will be given an opportunity to
settle  some  time  in  the second half of 1998.  At that time, it is expected
that an allocation will be made as to such defendants, which may be greater or
less  than  the  estimated  volumetric  allocation.

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

<PAGE>




21. GEOGRAPHIC  DATA

Information  about  the  Company's  operations  by  geographic  area  follows:

<TABLE>
<CAPTION>


<S>                                  <C>         <C>         <C>      <C>          <C>       <C>        <C>          <C>
                                                 MALAYSIA-                         UNITED
                                     COLOMBIA    THAILAND    FRANCE   INDONESIA    STATES    OTHER      CORPORATE    TOTAL
                                     ----------  ----------  -------  -----------  --------  ---------  -----------  ----------
YEAR ENDED DECEMBER 31, 1997:
Sales and other operating revenues   $  145,419  $     ---   $   ---  $      ---   $   ---   $  4,077   $      ---   $  149,496
Operating profit (loss)                  59,719       (536)      ---         ---       ---     (6,312)     (20,167)      32,704
Trade and other receivables              54,758      2,047       ---         ---       ---      7,665          655       65,125
Identifiable assets                     712,512    148,780       ---         ---       ---    110,561      126,186    1,098,039

YEAR ENDED DECEMBER 31, 1996:
Sales and other operating revenues   $  127,071  $     ---   $   ---  $    1,856   $ 5,050   $    ---   $      ---   $  133,977
Operating profit (loss)                  70,874       (509)      ---        (340)    3,400    (47,158)     (23,489)       2,778
Trade and other receivables              56,647        494       ---          53       ---      3,212          120       60,526
Identifiable assets                     629,978    113,364       ---       2,592       ---     55,257      113,333      914,524

YEAR ENDED DECEMBER 31, 1995:
Sales and other operating revenues   $   89,851  $     ---   $ 9,206  $    4,531   $ 3,884   $    ---   $      ---   $  107,472
Operating profit (loss)                  49,086       (239)    1,123        (858)     (230)    (2,669)     (22,897)      23,316
Trade and other receivables              19,823        366       ---         785       717        730          766       23,187
Identifiable assets                     487,472     50,867       ---       1,744    23,261     63,159      197,664      824,167
</TABLE>



At  December  31,  1997,  corporate  assets  were  principally  cash  and cash
equivalents,  the  U.S.  deferred  tax  asset  and  other fixed assets.  Other
identifiable assets included $26.2 million, $21.4 million and $17.3 million of
capitalized  costs  relating to exploration activities in Guatemala, China and
Italy,  respectively.

Other 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.

22.  SUBSEQUENT  EVENTS

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  an aftertax gain of $50.2 million, which will be recorded in the
first  quarter  of  1998.

<PAGE>


In conjunction with the sale of TPC, the Company entered into a five-year
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 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.  Upon a sale by the Purchaser of the TPC shares,
the Company will receive from the Counterparty, or make a cash payment 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.  The equity swap will be carried in
the Company's financial statements at fair value during the five-year term.
Fluctuations in the fair value of the equity swap will affect other income as
noncash adjustments.

In  February  1998,  the  Company  used  the proceeds from the sale of the TPC
shares  and  borrowings  under  other unsecured credit facilities to repay and
terminate  its  $125  million  unsecured  credit  facility.

23. QUARTERLY  FINANCIAL  DATA  (UNAUDITED)

<TABLE>
<CAPTION>


<S>                                               <C>        <C>       <C>       <C>
                                                                QUARTER
                                                  --------------------------------------
                                                   FIRST     SECOND    THIRD     FOURTH
                                                  --------  --------  --------  --------
 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)

 YEAR ENDED DECEMBER 31, 1996:
  Sales and other operating revenues              $ 35,781 $  31,170  $ 30,780  $ 36,246
  Gross profit (loss)                               19,839    15,885    15,936   (22,937)
  Net earnings (loss) before extraordinary item     11,351    12,696    19,549   (19,791)
  Net earnings (loss)                               11,351    12,262    18,787   (19,791)
  Basic earnings (loss) per ordinary share:
        Before extraordinary item                     0.30      0.36      0.53     (0.54)
        Net earnings (loss)                           0.30      0.35      0.51     (0.54)
  Diluted earnings (loss) per ordinary share:
        Before extraordinary item                     0.29      0.34      0.52     (0.54)
        Net earnings (loss)                           0.29      0.33      0.50     (0.54)


</TABLE>



Gross  profit  (loss)  comprises  of  sales  and other operating revenues less
operating  expenses,  depreciation, depletion and amortization, and writedowns
pertaining  to  operating  assets.

In  the  second quarter of 1997, the Company incurred 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.

In the fourth quarter of 1996, the Company recorded a writedown of $43 million
($37.9  million net of tax) related to oil and gas properties and other assets
in  Argentina.

24. OIL  AND  GAS  DATA  (UNAUDITED)

The  following  tables  provide additional information about the Company's oil
and  gas  exploration  and  production  activities.   Equity affiliate amounts
reflect  only the Company's proportionate interest in Crusader, which was sold
in  1996.

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>      <C>       <C>
                                                                           UNITED             TOTAL
                                        COLOMBIA    FRANCE    INDONESIA    STATES   OTHER    WORLDWIDE
                                        ----------  -------  ----------   -------  --------  ---------
   YEAR ENDED DECEMBER 31, 1997:
          Revenues                      $  145,419  $   ---  $      ---   $   ---  $    ---   $145,419
          Costs:
            Production costs                51,357      ---         ---       ---       ---     51,357
            General operating expenses       2,886      ---         ---       ---       ---      2,886
            Depletion                       30,729      ---         ---       ---       ---     30,729
            Writedown of assets                ---      ---         ---       ---       ---        ---
            Income taxes                    22,167      ---         ---       ---       ---     22,167
                                        ----------  -------  -----------  -------  ---------  --------
          Results of operations         $   38,280  $   ---  $      ---   $   ---  $    ---   $ 38,280
                                        ----------  -------  -----------  -------  ---------  --------
  YEAR ENDED DECEMBER 31, 1996:
          Revenues                      $  127,071  $   ---  $    1,856   $ 5,050  $    ---   $133,977
          Costs:
            Production costs                34,822      ---       1,510       322       ---     36,654
            General operating expenses       1,909      ---         553       774       ---      3,236
            Depletion                       18,515      ---          49       554       ---     19,118
            Writedown of assets                ---      ---         ---       ---    42,960     42,960
            Income taxes                    25,766      ---         ---       ---       ---     25,766
                                        ----------  -------  -----------  -------  ---------  --------
          Results of operations         $   46,059  $   ---  $     (256)  $ 3,400  $(42,960)  $  6,243
                                        ----------  -------  -----------  -------  ---------  --------


</TABLE>



<PAGE>

<TABLE>
<CAPTION>


<S>                                     <C>         <C>      <C>          <C>      <C>      <C>
                                                                           UNITED             TOTAL
                                        COLOMBIA    FRANCE   INDONESIA     STATES   OTHER   WORLDWIDE
                                        ----------  -------  ----------   -------  -------  --------
     YEAR ENDED DECEMBER 31, 1995:
          Revenues                      $   89,851  $ 9,206  $    4,531   $ 3,884  $   ---  $107,472
          Costs:
            Production costs                24,942    5,460       4,422       452      ---    35,276
            General operating expenses         740    1,061         726     1,030      ---     3,557
            Depletion                       14,776    1,562         241     1,950      ---    18,529
            Writedown of assets                ---      ---         ---       ---      ---       ---
            Income taxes                    17,395      374         ---       ---      ---    17,769
                                        ----------  -------  -----------  -------  -------  --------
          Results of operations         $   31,998  $   749  $     (858)  $   452  $   ---  $ 32,341
                                        ----------  -------  -----------  -------  -------  --------



</TABLE>



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

The  Company's  equity  share of Crusader's results of operations for oil- and
gas-producing  activities  follows:

<TABLE>
<CAPTION>


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

                   AUSTRALIA   CANADA   OTHER     TOTAL
                   ----------  -------  --------  ------

December 31, 1996  $    1,243  $   ---  $   ---   $1,243
                   ----------  -------  --------  ------

December 31, 1995  $    2,998  $   269  $(1,401)  $1,866
                   ----------  -------  --------  ------

</TABLE>


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>         <C>      <C>      <C>
                                                    MALAYSIA-                      UNITED             TOTAL
                                       COLOMBIA     THAILAND  FRANCE   INDONESIA   STATES   OTHER    WORLDWIDE
                                       ----------  ---------  -------  ----------  -------  -------  --------
     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
                                       ----------  ---------  -------  ----------  -------  -------  --------

</TABLE>



<PAGE>

<TABLE>
<CAPTION>


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


                                                   MALAYSIA-                       UNITED             TOTAL
                                       COLOMBIA    THAILAND   FRANCE   INDONESIA   STATES    OTHER   WORLDWIDE
                                       ---------  ---------  -------  ----------  --------  -------  --------

    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        ---      ---        0.52      5.59      ---      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
                                       ---------  ---------  -------  ----------  --------  -------  --------

  DECEMBER 31, 1995:
    Costs incurred:
          Property acquisition         $   1,101  $     ---  $   ---  $      ---  $    ---  $   250  $  1,351
          Exploration                     45,961     25,948      ---         ---       ---   28,480   100,389
          Development                     48,419        ---      ---         299       ---      ---    48,718
      Depletion per equivalent
          barrel of production              2.67        ---     3.14        0.95      6.05      ---      2.81

      Cost of properties at year-end:
          Unevaluated                  $  59,087  $  46,282  $   ---  $      ---  $  9,202  $58,490  $173,061
                                       ---------  ---------  -------  ----------  --------  -------  --------

          Evaluated                    $ 260,058  $     ---  $   ---  $   47,301  $190,379  $ 8,667  $506,405
                                       ---------  ---------  -------  ----------  --------  -------  --------

          Support equipment and
           facilities                  $  87,289  $     ---  $   ---  $      ---  $    ---  $   ---  $ 87,289
                                       ---------  ---------  -------  ----------  --------  -------  --------
      Accumulated depletion and
        depreciation at year-end       $  17,355  $     ---  $   ---  $   47,153  $180,574  $ 8,667  $253,749
                                       ---------  ---------  -------  ----------  --------  -------  --------

</TABLE>


A  summary  of  costs  excluded  from  depletion at December 31, 1997, by year
incurred  follows:

<TABLE>
<CAPTION>


<S>                     <C>            <C>                       <C>      <C>      <C>
                                                          DECEMBER 31,
                                       --------------------------------------------------
                            TOTAL          1997         1996       1995    1994 AND PRIOR
                        -------------  ------------   --------  ---------  --------------

  Property acquisition  $       5,292  $      3,128   $    600  $     250  $        1,314
  Exploration                 202,483        70,738     77,149     35,203          19,393
  Capitalized interest         37,095        17,558     10,259      3,981           5,297
                        -------------  ------------    -------    -------  --------------
      Total worldwide   $     244,870  $     91,424    $88,008  $  39,434  $       26,004
                        -------------  ------------    -------    -------  --------------
</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 $144.6 million ($114.3 million and $30.3
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  heads  of  agreement  to  a gas-sales contract.  Additionally,
excluded  costs  include exploration costs of $23.3 million, $18.2 million and
$15.4  million  in  Guatemala,  China and Italy, respectively.  The balance of
excluded  costs  represents exploration work in other countries, none of which
is material.  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.

The  Company's  equity  share  of  costs  incurred  by  Crusader  follows:

<TABLE>
<CAPTION>


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

                                AUSTRALIA   CANADA   OTHER   TOTAL
                                ----------  -------  ------  ------
Cost of property acquisition,
  exploration and development:

      December 31, 1996         $    2,105  $   ---  $  ---  $2,105
                                ----------  -------  ------  ------

      December 31, 1995         $    1,187  $   507  $  541  $2,235
                                ----------  -------  ------  ------
</TABLE>




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 all proved reserves in the Fields in Colombia
were  prepared  by the Company's independent petroleum engineers, DeGolyer and
MacNaughton.    The estimates for all 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, 1997, 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 reserves attributable to such interest, the Company assumed that
production  from the interest would be sold at natural-gas prices derived from
what  the  Company believed to be the most comparable market price at December
31,  1997.    There  can be no assurance that the price established in any gas
contract  would  be  equal  to  the  price used in the Company's calculations.

<PAGE>
<TABLE>
<CAPTION>


<S>                             <C>       <C>           <C>      <C>
                                      COLOMBIA         MALAYSIA-THAILAND
                                --------------------   ------------------
                                OIL        GAS           OIL      GAS
                                ---------  ---------   -------  ---------
PROVED DEVELOPED AND
  UNDEVELOPED RESERVES:
AS OF DECEMBER 31, 1994          104,393    14,721         ---        ---
    Revisions                        ---       ---         ---        ---
    Sales                        (10,434)      ---         ---        ---
    Extensions and discoveries    32,556     1,127         ---        ---
    Production                    (5,089)     (158)        ---        ---
                                ---------  --------    -------  ---------

AS OF DECEMBER 31, 1995          121,426    15,690         ---        ---
    Revisions                        270      (403)        ---        ---
    Sales                           (548)     (338)        ---        ---
    Extensions and discoveries    19,900       ---      24,700    871,100
    Production                    (5,738)     (298)        ---        ---
                                ---------  --------    -------  ----------
AS OF DECEMBER 31, 1996          135,310    14,651      24,700     871,100
    Revisions                     14,157       770      (2,000)     (7,600)
    Sales                            ---       ---         ---         ---
    Extensions and discoveries     2,308       ---       7,100     360,300
    Production                    (5,776)     (802)        ---         ---
                                ---------  --------     -------  ---------

AS OF DECEMBER 31, 1997          145,999    14,619      29,800   1,223,800
                                ---------  --------    -------   ---------




</TABLE>
<TABLE>
<CAPTION>


<S>                               <C>               <C>      <C>     <C>         <C>
                                FRANCE   INDONESIA   UNITED STATES       TOTAL WORLDWIDE
                                -------  ----------  --------------  ---------------------
                                   OIL       OIL      OIL    GAS       OIL        GAS
                                -------  ----------  -----  -------   --------  ----------
PROVED DEVELOPED AND
  UNDEVELOPED RESERVES:
AS OF DECEMBER 31, 1994           6,244         402    596   7,197    111,635      21,918
    Revisions                       ---          23    119     967        142         967
    Sales                        (5,746)        ---    ---     ---    (16,180)        ---
    Extensions and discoveries      ---         ---    ---     ---     32,556       1,127
    Production                     (498)       (255)  (121) (1,207)    (5,963)     (1,365)
                                -------  ----------  -----  -------   --------  ----------

AS OF DECEMBER 31, 1995             ---         170    594   6,957    122,190      22,647
    Revisions                       ---         ---    ---     ---        270        (403)
    Sales                           ---         (75)  (574) (6,482)    (1,197)     (6,820)
    Extensions and discoveries      ---         ---    ---     ---     44,600     871,100
    Production                      ---         (95)   (20)   (475)    (5,853)       (773)
                                -------  ----------  -----  -------   --------  ----------
AS OF DECEMBER 31, 1996             ---         ---    ---     ---    160,010     885,751
    Revisions                       ---         ---    ---     ---     12,157      (6,830)
    Sales                           ---         ---    ---     ---        ---         ---
    Extensions and discoveries      ---         ---    ---     ---      9,408     360,300
    Production                      ---         ---    ---     ---     (5,776)       (802)
                                 ------  ----------  -----  -------   --------  ----------

AS OF DECEMBER 31, 1997             ---         ---    ---     ---    175,799   1,238,419
                                 ------  ----------  -----  -------   --------  ----------





</TABLE>



<TABLE>
<CAPTION>


<S>                            <C>       <C>                <C>     <C>        <C>        <C>  <C>        <C>    <C>
                                    COLOMBIA        MALAYSIA-THAILAND  FRANCE  INDONESIA  UNITED STATES  TOTAL WORLDWIDE
                               -------------------  -----------------  ------  ---------  -------------  ---------------
                                OIL        GAS        OIL     GAS        OIL      OIL     OIL   GAS       OIL    GAS
                               --------  ---------  ------  ---------  ------  ---------  ---  -----     ------  ------

PROVED DEVELOPED RESERVES AT:
DECEMBER 31, 1995                65,856     10,515     ---        ---     ---        170  594  6,957     66,620  17,472
                               --------  ---------  ------  ---------  ------  ---------  ---  -----     ------  ------

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

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


</TABLE>





The  Company's  proportional  equity  interest  in Crusader's estimated proved
developed  and  undeveloped oil and gas reserves at December 31, 1995, was 3.3
million  barrels  of  oil  and  60.9  billion  cubic  feet  of  gas.


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 yearend prices of oil and gas
relating  to the Company's proved reserves to the estimated yearend quantities
of  those  reserves.    As  of  December  31, 1997, 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 natural-gas prices derived from
what  the  Company believed to be the most comparable market price at December
31, 1997.  Future price changes were considered only to the extent provided by
contractual  agreements  in  existence  at  yearend.    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 yearend 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  considerably.

<TABLE>
<CAPTION>


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

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


<TABLE>
<CAPTION>



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



<PAGE>

<TABLE>
<CAPTION>



<S>                                        <C>         <C>        <C>         <C>      <C>
                                                       MALAYSIA-              UNITED     TOTAL
                                           COLOMBIA    THAILAND   INDONESIA   STATES   WORLDWIDE
                                           ----------  ---------  ----------  -------  ----------
DECEMBER 31, 1995:
      Future cash inflows                  $2,321,424  $     ---  $    2,909  $19,076  $2,343,409
      Future production and
        development costs                     730,139        ---       2,250    2,037     734,426
                                           ----------  ---------  ----------  -------  ----------
      Future net cash inflows before
        income taxes                       $1,591,285  $     ---  $      659  $17,039  $1,608,983
                                           ----------  ---------  ----------  -------  ----------

      Future net cash inflows before
        income taxes discounted at 10%
        per annum                          $  803,665  $     ---  $      626  $11,150  $  815,441
      Future income taxes discounted at
        10% per annum                         173,745        ---         ---      ---     173,745
                                           ----------  ---------  ----------  -------  ----------
      Standardized measure of discounted
        future net cash inflows            $  629,920  $     ---  $      626  $11,150  $  641,696
                                           ----------  ---------  ----------  -------  ----------

</TABLE>



Subsequent  to  yearend,  the  price  of  oil declined significantly.  Each $1
decrease  in  oil  prices  would  have  reduced  the  standardized  measure of
discounted  future  net  cash  inflows  (aftertax) in Colombia at December 31,
1997,  by  $58  million.    The  Company's  proportional  equity  interest  in
Crusader's  standardized  measure  of  discounted  future net cash inflows was
$30.4  million  at  December  31,  1995.

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

<TABLE>
<CAPTION>


<S>                                              <C>             <C>          <C>
                                                             DECEMBER 31,
                                                 ---------------------------------------
                                                          1997         1996        1995
                                                 --------------  -----------  ----------
Total worldwide, excluding equity share:
  Beginning of year                              $   1,292,195   $  641,696   $ 499,670
  Sales, net of production costs                       (94,062)     (97,323)    (67,471)
  Sales of reserves                                        ---      (10,473)   (144,361)
  Revisions of quantity estimates                       75,253        2,617       2,348
  Net change in prices and production costs           (552,863)     228,349      42,044
  Extensions, discoveries and improved recovery         42,918    1,125,733     339,413
  Change in future development costs                    (5,936)    (652,902)   (102,323)
  Development and facilities costs incurred             53,199       92,856      28,068
  Accretion of discount                                160,406       80,672      62,188
  Changes in production rates and other                 (3,089)      19,088      22,917
  Net change in income taxes                           101,322     (138,118)    (40,797)
                                                 --------------  -----------  ----------
  End of year                                    $   1,069,343   $1,292,195   $ 641,696
                                                 --------------  -----------  ----------
</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, 1995:
   Allowance for doubtful
       receivables         $       897  $       ---   $      41  $      (128)  $    810
                           -----------  ------------  ---------  ------------  --------

   Allowance for deferred
       tax asset           $    87,518  $   (33,472)  $     ---  $       ---   $ 54,046
                           -----------  ------------  ---------  ------------  --------

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
                           -----------  ------------  ---------  ------------  --------
</TABLE>





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