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                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                             ----------------------


                                   FORM 10-KSB
                ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
                         COMMISSION FILE NUMBER 33-99978

                           ABACAN RESOURCE CORPORATION
           (Name of Small Business Issuer as Specified in its Charter)

         ALBERTA,  CANADA
  (State  or  other  Jurisdiction                         (I.R.S.  Employer
of  Incorporation  or  Organization)                    Identification  Number)


SUITE  699,  3050  POST  OAK  BLVD,  HOUSTON,  TEXAS          77056
(Address  of  Principal  Executive  Offices)               (Zip  Code)

(713)  479-9770
(Issuer's  Telephone  Number,  Including  Area  Code)


Securities registered under Section 12 (b) of the Exchange Act: None
Securities registered under Section 12 (g) of the Exchange Act: Common Stock,
                                                                without par
                                                                value
                                                                (Title of Class)

     Check  whether the Issuer (1) has filed all reports required to be filed by
Section  13 or 15 (d) of the Exchange Act during the past 12 months (or for such
shorter  period  that  the Issuer was required to file such reports) and (2) has
been  subject  to  such  filing
requirements  for  the  past  90  days.     Yes     X     No

     Check  if  there  is no disclosure of delinquent filers in response to Item
405  of  Regulation  S-B  contained  in  this  form,  and  no disclosure will be
contained,  to  the  best  of  the  Issuer's  knowledge,  in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-KSB
or  any  amendment  to  this  Form  10-KSB.     [X]

     The  Issuer's  revenues  for  the fiscal year ended December 31, 1998, were
$14,258,000.

     The  aggregate  market value of the voting and non-voting common stock held
by non-affiliates of the Issuer, computed by reference to the closing sale price
of  such  common  stock on the Nasdaq National Market as of February 1, 1999 was
$25,024,339.

     The  Issuer had 114,370,836 common shares of common stock outstanding as of
December  31,  1998.

<PAGE>
<TABLE>
<CAPTION>
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                      1998 ANNUAL REPORT (SEC  FORM 10-KSB)

                                      INDEX

                       Securities and Exchange Commission
                           Item Number and Description


<S>       <C>                                                        <C>

PART I

Item 1    Business                                                    1
Item 2    Properties                                                  8
Item 3    Legal Proceedings                                          22
Item 4    Submission of Matters to a Vote of Security Holders        23

PART II

Item 5    Market for the Company's Common Stock and Related
          Stockholder Matters                                        23
Item 6    Management's Discussion and Analysis or Plan of Operation  25
Item 7    Consolidated Financial Statements and Unaudited
          Supplemental Information                                   41
Item 8    Changes in and Disagreements with Accountants on
          Accounting and Financial Disclosure                        72

PART III

Item 9    Directors, Executive Officers, Promoters and Control
          Persons of the Issuer; Compliance With
          Section 16(a) of the Exchange Act                          72
Item 10   Executive Compensation                                     73
Item 11   Security Ownership of Certain Beneficial Owners and
          Management                                                 73
Item 12   Certain Relationships and Related Transactions             74

PART IV   AND SIGNATURES AND EXHIBIT INDEX

Item 13   Exhibits and Reports on Form 8-KSB                         75
          Signatures                                                 76
          Exhibit Index                                              77
</TABLE>

<PAGE>
                                     PART I

ITEM  1.       BUSINESS

CORPORATE  STRUCTURE

     Abacan  Resource  Corporation  ("Abacan")  is  a limited company subsisting
under  the  Business Corporations Act (Alberta) that was created on February 10,
1995  following  an  amalgamation  of five junior Canadian oil and gas companies
each  of  which,  prior  to  the  amalgamation,  held  certain rights to receive
production  revenues  and certain obligations to pay capital and operating costs
(collectively  referred to as "Participating Interests") in the same oil and gas
concession  properties  located  in the Federal Republic of Nigeria ("Nigeria").
Abacan  currently  has  14 wholly owned subsidiaries.  These subsidiaries either
hold  or,  prior  to  the  recent and ongoing restructuring of its affairs, held
certain  rights to receive petroleum production revenues and certain obligations
to  pay for exploration, development and operating costs (hereafter collectively
referred  to  as  "Participating  Interests")  in  Nigeria  and  the neighboring
Republic  of  Benin  ("Benin").  See  "Properties".

     At  the  end of the most recently completed fiscal year, neither Abacan nor
any  of  its  subsidiaries (collectively referred to hereafter as the "Company")
were  subject  to  any  bankruptcy or similar proceedings.  However, the Company
does  have  outstanding  debt obligations to secured and unsecured creditors and
may  be  in  default  of  certain  security  agreements.  In  1998,  the Company
initiated  a  restructuring  of its oil and gas operations and financial affairs
through:  (1)  the  disposition  of  a  number of its oil and gas properties and
related  production  facilities;  (2)  the  reduction  of operating, general and
administrative  expenses;  and  (3)  the reduction of a portion of the Company's
secured and unsecured debt.  This restructuring is ongoing and in the future may
include the sale, farmout or other disposition of some or all of its oil and gas
properties.  The Company currently has a significant working capital deficiency,
no  appreciable revenues or cash flow and limited cash reserves.  Therefore, the
Company  believes  that  it  must  successfully  attract new equity, debt, joint
venture  partners,  buyers, merger partners or a combination thereof in order to
remain  viable  and  continue  operations.  See  "History and Development of the
Business  -  Restructuring  of  Operations and Financial Affairs", "Management's
Discussion and Analysis of Financial Condition and Results of Operations - Risks
and  Uncertainties  -  Liquidity"  and  "-  Risks  and Uncertainties - Financing
Risks".

HISTORY  AND  DEVELOPMENT  OF  THE  BUSINESS

General
-------

     The  Company's current business relates primarily to the exploration of oil
and  gas  properties  located in West Africa.  To date, the Company's operations
have  included  the  acquisition of Participating Interests in concession blocks
located  in  both  Nigeria  and  Benin  and  the  exploration,  development  and
production  of oil and condensate from concession blocks located in Nigeria.  In
the  case  of  Nigeria, the Participating Interests of the Company relate to oil
prospecting  licences  ("OPL")  and oil mining leases ("OML") granted to several
different  Nigerian  companies  with  whom  the Company has a number of separate
joint  venture agreements.  In Benin, the Participating Interests of the Company
are  held  pursuant to production sharing contracts ("PSC") granted by the Benin
Government.

                                      -1-
<PAGE>
     Prior  to  a reorganization of its oil and gas operations in June 1998, the
Company's operations were focused in two distinct geological regions - the Niger
Delta, Nigeria's prolific oil producing region located in south-central Nigeria,
and  the Benin Basin, a largely unexplored area located in the coastal waters of
western Nigeria and Benin.  Recently, the Company has focused its efforts on its
large  Benin  Basin  holdings  where negotiations are currently underway for the
establishment in Benin of a natural gas powered electrical generation plant that
is  expected  to  utilize  the natural gas resources identified in the Company's
Benin  Basin  concessions.  The Company is also actively marketing the farm-out,
sale  or  other  disposition  of  its  properties  to industry partners which is
expected  will  provide the financial resources necessary to explore and develop
the  Company's  prospects in the region. The Company has not undertaken research
and  development  activities  during  the  past  two  fiscal  years.

Acquisition,  Exploration and Development of West African Oil and Gas Properties
--------------------------------------------------------------------------------

     In  December  1992,  the  Company  acquired  a Participating Interest in an
on-shore  concession  block  located  in  Benin  from  Wade  Cherwayko, a former
director  and  executive  officer  of  the Company who, until that time had been
involved  in  his  personal  capacity  in  identifying  opportunities to acquire
unallocated  oil  and  gas  concession  properties  in  West  Africa.  Prior  to
acquiring  this Participating Interest, the Company had been involved in oil and
gas  exploration  activities in western Canada and the western United States but
had  not  earned  any  ownership  interests  in  respect thereof.  Following the
purchase  of  the  Participating Interest in Benin from Mr. Cherwayko for common
stock, the Company initiated a program of additional acquisition and exploration
of  petroleum  properties  in  Nigeria  and  other  countries  in  West  Africa.

     In  June  1993, the Company acquired Participating Interests in Benin Basin
Concession  Block  OML  113  (formerly  OPL  309)  from Yinka Folawiyo Petroleum
Company  Limited  ("YFP")  and  Concession  Block  OPL 302 from another Nigerian
company.  YFP  is  a  company  that  is substantially owned by the father of Mr.
Tunde Folawiyo, a director of the Company.  In August 1993, the Company acquired
a  Participating  Interest  in  offshore  Concession Block OML 112 (formerly OPL
469).  The  Company  then  undertook  an  aggressive  campaign  to  expand  its
concession  acreage  in  West  Africa  through  the  addition  of  Participating
Interests in Niger Delta Concession Blocks OPL 237 (located adjacent to OML 112)
and  OPL  233,  Benin  Basin Concession Block OPL 310 in Nigeria and Benin Basin
Block  4  and  Block  1  in Benin.  See "- The Petroleum Industry in Nigeria and
Benin",  AProperties"  and  "Certain  Relationships  and  Related Transactions".

     In  February  1995,  in order to consolidate its Participating Interests in
Concession  Blocks  OML  112,  OML 113 and OPL 302, the Company amalgamated with
four  other  Canadian junior oil and gas companies, each of which at the time of
the amalgamation held Participating Interests in Blocks OML 112, OML 113 and OPL
302.  The  amalgamation  resulted  in  the  acquisition  of  the  Participating
Interests  of  the  amalgamating  junior  oil  and gas companies by the Company.

     Throughout  1994  and  1995,  the  Company  conducted  2-D  and 3-D seismic
programs  on  Blocks OML 112 and OPL 237 and a 2-D seismic program on Blocks OML
113  and  OPL  310.  The  Company's  first  off-shore  exploration  well  was
successfully  drilled  on  the  Ima  Field  on  Block OML 112 in September 1994.
Between  September  1994  and January 1997, the Company successfully drilled six
additional  wells  on  the  Ima  Field  and  completed  the  construction  and
installation  of  a mobile off-shore production facility capable of producing up
to 50,000 barrels of oil and condensate per day.  Commercial production of crude
oil  and  condensate  commenced  from the Ima Field in January 1997.  Production
levels  from  the  Ima  Field  peaked at approximately 27,500 gross (13,400 net)
barrels  of  oil and condensate per day from six producing wells.  In June 1996,
the  Company  signed  a  Crude  Oil  Sale  Agreement  pursuant  to which a large
international  crude  oil  marketing company agreed to market and sell the crude
production  from  the Ima Field.  A total of 6.1 million gross (2.9 million net)
barrels  of  crude  oil  were  produced  and sold during the fiscal period ended
December  31,  1997.  In  fiscal  1998 prior to the disposition of the Company's
interest  in June 1998, a total of 2.64 million gross (1.45 million net) barrels
of  crude  oil  were  produced  and  sold  from  the  Ima  Field.

                                      -2-
<PAGE>
     The Company drilled its first well in the Benin Basin on on-shore Block OPL
302  in  December  1993.  The  well  was  not  successful  and  the  Company's
Participating Interest in the concession was allowed to expire in 1997.  Between
November  1996  and  March  1997, the Company successfully drilled two off-shore
wells  on  the  Aje  Field  on  Benin Basin Concession Block OML 113.  The wells
tested maximum flow rates of 8,800 and 5,500 barrels of oil per day respectively
along  with  significant  volumes  of natural gas.  Both wells have been shut-in
following testing pending the financing and construction of a suitable off-shore
production  facility.  See "Properties - Benin Basin - Drilling, Development and
Future  Work  Commitments".

Restructuring  of  Operations  and  Financial  Affairs
------------------------------------------------------

     In  June 1997 production rates from the Ima Field began to decline.  It was
subsequently  determined  that  the  decline  in  production was attributable to
compartmentalization  of  the  main  producing zones and the absence of a strong
water  drive  for  the  Ima  Field.  In  February  1998,  Abacan appointed a new
President  and  Chief  Executive Officer.  A comprehensive reservoir analysis of
the  Ima  Field completed in the spring of 1998 suggested that the Ima Field was
no  longer  economically  producible.  The  Company  immediately  initiated  a
restructuring  strategy  in  respect of its oil and gas operations and financial
affairs which both management and the Board of Directors considered essential to
maintain  the  financial  viability of the Company.  The Company's restructuring
strategy,  which  is ongoing, was comprised of a series of steps which included:
(1)  the  disposition of the Company's Participating Interests in the Ima Field;
(2)  the  sale  or  disposition of the Company's mobile offshore production unit
("MOPU")  which  was then being utilized on the Ima Field; (3) the reduction and
extension  of  the  repayment  terms  of  the  Company's  secured  debt; (4) the
settlement  of  claims of trade and other unsecured creditors; (5) the reduction
of general and administrative expenses; and (6) the maximization of exploitation
opportunities with joint venture partners for the exploration and development of
the  Company's  large  acreage  position  in  the  Benin  Basin.

     On June 30, 1998, the Company concluded the first two phases of its overall
restructuring  strategy.  Under  the  terms of a settlement agreement (the "Amni
Settlement  Agreement")  reached  with  its Nigerian partner, Amni International
Petroleum  Development  Company  Limited  ("Amni"), the Company relinquished all
rights  and Participating Interests to the "shallow" zones of the Ima Field.  At
the  time  of  disposition,  the  "shallow" zones comprised all of the Company's
proved  developed  reserves  in  the  Niger  Delta  and  all  of  its  petroleum
production.  In  exchange,  Amni agreed: (1) to assume all outstanding unsecured
financial  claims  against  the  Company (including trade claims) related to the
development  of  the  Ima  Field;  (2)  to assume responsibility for ongoing and
future  lease  obligations with existing service providers to the Ima Field; (3)
to  release the Company from certain financial obligations due or accruing under
the terms of the joint venture agreements between the Company and Amni valued at
approximately  $20  million; and (4) to release the Company from any claims Amni
had to the MOPU.  The Company retained a 10% Participating Interest in the "Deep
Ima  Prospect"  which  is  located  below the producing shallow zones of the Ima
Field  and  which  prospect  was  previously  identified  in  1997 by one of the
Company's  exploration  wells.

                                      -3-
<PAGE>
     Concurrent  with concluding the terms of the Amni Settlement Agreement, the
Company  conveyed  its  interest  in  the  MOPU to a major international service
company  in  exchange  for  the extinguishment of approximately $18.8 million of
debt,  representing  all  of  the debt due from the Company to the international
service  company.  In  connection  with  this  settlement,  the  Company  also
restructured an existing secured loan (the "Secured Loan"). The Secured Loan had
been  previously  advanced  to  the  Company  in  August  1997 with the proceeds
therefrom being utilized to repay project financing used for the construction of
the MOPU and  a portion of the exploration and development costs associated with
the  Ima  Field.  The  restructuring  of  the  Secured  Loan  by the lender (the
"Secured Lender") enabled the Company to defer quarterly interest payments until
December  31,  1998 and to extend the maturity of approximately $20.1 million of
the  loan  until  June  30,  1999,  with  the  remainder of $10.6 million due on
December  31,  1999.  The  terms  of  its agreement with the major international
service  company,  provided  that  if a future sale price of the MOPU is above a
pre-determined  threshold,  a portion of the proceeds of sale will be applied to
reduce  the  Company's  obligations  under  its  existing  Secured  Loan.

     Subsequent to December 31, 1998, the Company received confirmation from the
Secured  Lender  that  the  interest  payment  due  December  31,  1998 had been
capitalized  and  that  the  first  payment  was amended to March 31, 1999.  The
Secured  Lender  has  since advised the Company that notwithstanding its written
extension,  payment  of  the  first  interest instalment was due on December 31,
1998.  The  Company  has  not  yet  made  this interest payment and is currently
negotiating with its Secured Lender regarding further relief from this and other
near-term  cash  interest payments. There is no assurance that such negotiations
will  be  successful.  See  "Management's  Discussion  and Analysis of Financial
Condition  and  Results  of  Operations  -  Risks  and Uncertainties - Financing
Risks".

     In  July  1997,  the  Company increased its participating position in Benin
Block  4  and  Block  1  to a 100% Participating Interest.  This acquisition was
followed  in  June  1998  with  the execution of a Letter of Intent with a major
international  natural  gas  and  electrical  power  generating  company and the
Government  of  Benin for the development, construction, financing and operation
of  a  natural  gas  powered  electrical generation power plant to be located in
Cotonou,  Benin.  Negotiations  are  ongoing  to finalize the details of a power
plant  that  is  expected  to  provide  electrical  energy  to  Benin  and  the
neighbouring  countries of Togo and Ghana.  Natural gas feedstock is expected to
be  supplied  from  the  Company's  Benin  Block 1 in Benin and the Aje Field in
Nigerian  Block  OML  113.  The  Company  has drilled and tested significant gas
resources  on  the  Aje Field that are awaiting development of a suitable market
before  being  classified as proved reserves.  The Company believes that it will
require an industry partner to fund the costs of developing a natural gas market
and  to  fund the costs of developing the natural gas resources contained in the
Aje Field.  See "Management's Discussion and Analysis of Financial Condition and
Results  of  Operations  -  Risks  and  Uncertainties  -  Liquidity".

THE  PETROLEUM  INDUSTRY  IN  NIGERIA  AND  BENIN

     All  of  the  Company's  oil  and gas properties are located in Nigeria and
Benin,  both  of  which are developing third world nations that have experienced
periods  of civil unrest and political and economic instability.  The regulation
of the petroleum industry has been and is expected to continue to be affected by
economic  and  political  events  that  occur  in each country.  Such events are
beyond the control of the Company and may adversely affect the future operations
of  the  Company.

Nigeria
-------

Overview

     Oil has been produced in Nigeria by multinational companies since 1958 with
only  limited  interruptions despite periods of civil and political unrest.  The
oil  industry constitutes the most important segment of the Nigerian economy and
accounts  for approximately 90% of the country's total exports and approximately
75%  of  total  government  revenue.

                                      -4-
<PAGE>
     The  Company  currently operates in Nigeria in conjunction with a number of
Nigerian  companies  (the  "Nigerian Partners") under a program (the "Indigenous
Program")  introduced  in  1990  by the Nigerian Ministry of Petroleum Resources
(the  "MPR")  in  an effort to increase production and domestic participation in
the  country's  oil  industry.  The  Indigenous  Program  provides  qualified,
privately  owned  Nigerian  companies  with  both  preferential treatment in the
allocation  of  available  petroleum  concession  blocks and favourable economic
terms  for the development of such blocks.  Participating Nigerian companies are
permitted  to  establish  revenue  and  cost  sharing  arrangements with foreign
companies  that  provide  the  technical  expertise,  operational  support  and
financial  resources  required  for  the  exploration  and  development  of  the
concession  blocks.  In  the  case  of  the Company, such arrangements have been
established  by  way  of  joint  venture  agreements between the Company and its
various  Nigerian  Partners.  As  part  of  the Indigenous Program, the Nigerian
government  receives  a combination of production royalties and taxes and is not
required  to  fund  any exploration or development costs.  The Nigerian National
Petroleum  Company  is  not  involved  in  concession  blocks  awarded under the
Indigenous  Program.  See  "Management's  Discussion  and  Analysis of Financial
Condition  and  Results  of  Operations  -  Risks  and  Uncertainties - Nigerian
Regulation  -  Dependence  Upon  the  Indigenous  Program".

Regulation

     All  phases of oil exploration, development and production are regulated by
the Nigerian government either directly, through the MPR or through the Nigerian
Department  of  Petroleum  Resources  ("DPR")  pursuant to the Petroleum Decree,
1969,  under  periodic  policy  statements issued by the Nigerian government and
through  administrative  practices  of  the DPR.  Areas of government regulation
include  restrictions  on petroleum production, price controls, export controls,
taxes and royalties, expropriation of property, environmental protection and rig
safety.  In  addition,  all petroleum drilling and production in Nigeria must be
approved  in  advance by the Nigerian government through the MPR or the DPR.  In
the  case  of the Company, any future operations to be conducted on its Nigerian
concessions,  including  the establishment of a production facility on Block OML
113  and  the  export  of natural gas to Benin will require MPR or DPR approval.
See  "Management's Discussion and Analysis of Financial Condition and Results of
Operations  -  Risks  and  Uncertainties  -  Nigerian  Regulation".

     Under  current Nigerian legislation, a petroleum concession is required for
a  party  to  conduct petroleum exploration and development.  Concessions may be
obtained  directly  from  the MPR or from an existing concession owner, provided
that  prior  MPR  approval  to an assignment is obtained.  Petroleum concessions
granted  by  the  MPR  consist  of  either  an  oil  exploration license, an oil
prospecting  licence  ("OPL") or an oil mining lease ("OML").  Concession Blocks
are  typically  designated on the basis of whether they are subject to an OPL or
OML.  An  OPL  gives  the holder the exclusive right to conduct both seismic and
exploratory drilling operations within a concession block and the right to carry
away  and  dispose  of petroleum produced during the term of the OPL.  An OML is
issuable to the holder of an OPL following testing or production of a minimum of
10,000  barrels  per  day and the fulfilment of a number of other conditions and
requirements  established  by  the  MPR  and  DPR.

     An  OML  provides the holder with an exclusive right to conduct exploration
and  development  drilling  operations  and  to export petroleum produced on the
concession  block  for  a  term  of  up to 20 years.  An OML may be renewed upon
application  to  the  MPR.  The  Petroleum Decree, 1969 contains provisions that
require  the  holder  of  an  OML  to  relinquish  50%  of  the  geographic area
encompassed  by the OML after 10 years upon the request of the MPR.  The acreage
to  be relinquished is identified by the holder of the OML and not the MPR.  The
Nigerian  government  may  also  elect,  during the currency of an OML or OPL to
directly participate in the concession, which could result in a reduction of the
Participating  Interest  of  the  Company.  The  Petroleum Decree, 1969 does not
specify  the  maximum  level  of  government  participation.  See " Management's
Discussion and Analysis of Financial Condition and Results of Operations - Risks
and  Uncertainties  -  Nigerian Regulation - Government Right of Participation".

                                      -5-
<PAGE>
     The  Company's current Participating Interests in Nigeria exist pursuant to
the  terms  of  joint  venture  agreements  between the Company and its Nigerian
Partners.  In the case of Concession Block OML 113, an OML was issued to YFP for
this  block  on July 3, 1998.  The OPL for Concession Block OPL 310 has expired,
however,  at the request of the Company's Nigerian Partner, the DPR confirmed in
February  1997  that the OPL was in good standing.  Nothing has been received by
the  Company  or  to the Company's knowledge, by its Nigerian Partner that would
indicate  that either the MPR or DPR consider OPL 310 not to be valid or in good
standing  at the current time.  See "Properties - Benin Basin" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations - Risks
and  Uncertainties  -  Nigerian Regulation - Assignment of Interests Under Joint
Venture  Agreements"  and  "Risks  and  Uncertainties  - Nigerian Title Issues".

     Revenues  generated  from  petroleum  operations are subject to a number of
tax/royalty  regimes.  Under  the Indigenous Program, the fiscal regime consists
of a production royalty and an adjusted profits tax.  The payment of the royalty
to  the Nigerian Government is dependant upon the levels of petroleum production
and is determined on the basis of the chargeable value of the crude oil produced
less  an  allowance  for oil used in the extraction process.  Royalty rates vary
depending  upon whether the concession is on-shore or off-shore and, in the case
of  off-shore  concession, the average water depth of the concession.  A royalty
of  20%  is  applicable  to  on-shore  concessions  reducing  to  no royalty for
concessions  situated  in  over 1000 metres of water.  The royalty applicable to
the  Company's  Nigerian  concessions  OML  113  and  OPL  310 have not yet been
formalized  but  are  expected  to  be  not  greater  than  15%.

     In  addition  to  the  royalty,  producers are subject to a tax on adjusted
petroleum  profits.  Adjusted  petroleum  profits  consist generally of revenues
from  petroleum  sales  less  operational  expenses  and  certain  capital costs
(including  drilling  costs).  The Petroleum Profits Tax Act, 1969, prescribes a
petroleum  profits  tax  rate  of  85%.  The  Company understands that a reduced
petroleum  profits tax rate may be applicable to concession blocks awarded under
the  Indigenous  Program.  Any  changes  to  the  current  royalty regime or the
Petroleum Profits Tax Act, 1969 or their applicability to the Indigenous Program
will affect the Company.  See "Management's Discussion and Analysis of Financial
Condition  and  Results  of  Operations  -  Risks  and  Uncertainties - Nigerian
Regulation  -  Uncertainty  Regarding  Tax  and  Royalty  Arrangements".

Benin
-----

     The  Benin petroleum industry is less developed than the Nigerian petroleum
industry.  Petroleum  exploration  started in Benin in 1964 and has been focused
primarily  in  the off-shore area of the Benin Basin.  The country's first major
discovery  occurred  in  1982  with  the  discovery  of  the  Seme Field located
off-shore  near  the  Nigerian  border.  There  has been a number of significant
off-shore  discoveries  made  recently  on  the Nigerian side of the Benin Basin
(including  the Company's discovery on OML 113) which has heightened interest in
Benin's  petroleum  sector  in  recent  years.

Regulation

     Responsibility  for the regulation and control of the petroleum industry in
Benin  rests  with the national government pursuant to the Petroleum Code of the
Republic  of  Benin  and  the  administrative decrees and ordinances established
thereunder  (collectively,  the  "Benin  Petroleum  Code").  Regulation  of
exploration,  exploitation,  title,  transportation,  marketing  and taxation of
petroleum  rests  with  the Ministry of Energy, Mines and Hydraulics (the "Benin
Oil  Ministry").  All  drilling and production and other petroleum operations in
Benin  require  prior  approval  of  the  Benin Oil Ministry.  Consequently, any
future  operations  to  be  conducted  on  its  Benin concessions, including the
drilling  of  exploration  wells  on Block 1 and Block 4, will require the prior
approval  of  the  Benin  Oil  Ministry.

                                      -6-
<PAGE>
     The  Company's  current  Participating Interests in Benin exist pursuant to
separate  Production  Sharing  Contracts  for  Block  1  and Block 4 between the
Company and the Government of Benin.  Each of the PSC's establish a minimum work
commitment that must be met by the Company.  In the case of Block 1, the minimum
work  commitment  includes  the  drilling  of  one  well and the completion of a
seismic program by the end of February 1999.  The requisite work commitments for
Block  1  were  not  satisfied  by  the  February 1999 deadline.  The Company is
currently  negotiating  an  extension  with the Benin Oil Ministry and risks the
loss  of  its  Participating  Interest  in  Block  1  should an extension not be
secured.  In  the  case of Block 4, the minimum work commitment includes and the
completion  of  a  seismic program which has been satisfied, and the drilling of
one  exploratory well by the end of February 2002.  The Company believes that it
will  require an industry partner to fund the requisite minimum work commitments
associated  with  Blocks  1 and 4.  See "Management's Discussion and Analysis of
Financial  Condition  and  Results  of  Operations  - Risks and Uncertainties  -
Liquidity"  and  A  -  Risks  and  Uncertainties  -  Benin  Title  Issues".

COMPETITIVE  AND  INDUSTRY  CONDITIONS

     The  oil  and  gas  industry  is intensely competitive and the Company will
continue  to  compete with a substantial number of other companies, many of whom
have  greater technical, financial and other resources.  Many such companies not
only  explore  for  and  produce  crude  oil  and natural gas, but also carry on
refining  operations  and  market  oil,  natural  gas  and  other  products on a
worldwide  basis.

     The  Company  does  not  currently  own  production  facilities or refining
operations  and  will  rely upon other parties to produce, market and refine any
future  petroleum  production.  Due to the changes in the affairs of the Company
arising  out  of  its  recent  restructuring,  the  Company  will have to secure
adequate sources of funding to retain the services of such parties.  In the case
of  the  Benin Basin Concessions, there is currently no market for the Company's
natural  gas  resources.  Subject  to completion, the establishment of a natural
gas  electrical  generation  project  currently  being negotiated is expected to
create  a  market.  The  electrical generation project has not yet been formally
approved,  financed or constructed.  There is no assurance that the project will
be  approved,  or  if  approved,  that  it  will  be successfully completed.  If
completed, the project will rely upon an electrical distribution network that is
owned  by  the  governments  of  Benin,  Togo  and  Ghana as well as other third
parties.  If  a sustainable market for the Company's natural gas is created, the
Company  will  have to finance and construct or rely on other parties to finance
and  construct  a  suitable  production facility and natural gas pipeline to the
natural gas electrical generation project.  There are currently other sources of
electricity which may affect the amounts that can be generated and sold which in
turn  will  affect  demand  for  the  Company's  natural  gas  resources.  See
"Management's  Discussion  and  Analysis  of  Financial Condition and Results of
Operations  -  Risks  and  Uncertainties  -  Benin  Regulation".

ENVIRONMENTAL  PROTECTION

     The  Company's  operations  are and will continue to be affected in varying
degrees  by  legislation  intended  to ensure the protection of the environment.
Much  of  Nigeria's and Benin's environmental legislation is administered by the
DPR  and the Benin Oil Ministry, respectively.  These government departments may
require  environmental impact assessments prior to granting approval for certain
larger  scale or environmentally sensitive activities or may impose restrictions
or  prohibitions on releases or emissions of various substances generated by the
Company's  oil  and  gas operations or any future electrical generation project.
Compliance  with  such  legislation  or  administrative requirements may require
significant  expenditures  and the breach of such requirements may result in the
imposition of material fines and penalties.  Guidelines and regulations continue
to  be  developed  and  implemented  by  the  DPR,  Benin Oil Ministry and other
government  ministries  in  areas  of  waste  management,  contaminated  sites,
environmental  impact  assessments  and  habitat  protection.

                                      -7-
<PAGE>
     The  Company  believes  that  its Nigerian and Benin operations have at all
times  complied  in  all  material  respects  with applicable Nigerian and Benin
legislation and administrative requirements relating to safety and environmental
protection.  The  costs  of  such compliance has been included as either capital
expenditures or operating costs.  The Company intends to continue conducting its
operations  in  both  Nigeria  and  Benin  in  a  manner  that  complies  with
environmental  standards  imposed  by the DPR and the Benin Oil Ministry and all
applicable  legislation.

EMPLOYEES

     At  December  31,  1998,  the  Company  had  7 employees and consultants in
Houston,  3  consultants  in Calgary and 22 employees and consultants in London,
Benin  and Nigeria.  None of the Company's employees or consultants are party to
a  collective  bargaining  agreement.

ITEM  2.          PROPERTIES

OVERVIEW

     Between  1993  and  1997,  the  Company acquired Participating Interests in
eight  oil and gas concession blocks in the Benin Basin and Niger Delta.  In the
case  of  its  Nigerian  concession  blocks,  the Participating Interests of the
Company  are  held  pursuant  to  joint  venture  agreements  with the Company's
indigenous  Nigerian  Partners  who  in  turn  have  been issued oil prospecting
licences  or  oil mining leases from the MPR.  In the case of its two concession
blocks  located  in  Benin,  the Participating Interests of the Company are held
pursuant  to  two  separate  production  sharing  contracts directly between the
Company and the national Government of Benin.  Participating Interests in two of
the  Company's  Nigerian concession blocks have been subsequently surrendered or
released  by  the  Company.  Consequently,  at  the  end  of  the  most recently
completed  financial  year,  the  Company  held  Participating  Interests in six
concession  blocks,  two  of  which  were located in the Niger Delta and four of
which  were located in the Benin Basin.  See "Niger Delta - Cost Obligations and
Revenue  Interests"  and "Benin Basin - Cost Obligations and Revenue Interests".

NIGER  DELTA

Recent  Events

     Prior  to  June  1998,  all of the Company's proven reserves and all of its
production  came from the Ima Field located in Niger Delta Concession Blocks OML
112  and  OPL  237.  In  June  1998,  following  an  assessment that the shallow
producing  zones  of the Ima Field were no longer economic, the Company began to
restructure  its  oil  and  gas  operations  and  in  so  doing,  relinquished
substantially  all  of its Participating Interest in Nigerian Blocks OML 112 and
OPL  237.  The  only  interest  retained  in  the blocks by the Company is a 10%
Participating  Interest  in  the  Deep Ima Prospect located beneath the existing
producing  zones  of the Ima Field.  There are no reserves allocated to the Deep
Ima  Prospect.  In  January  1998,  the  Company  cancelled  its  joint  venture
agreement  in  respect  of  Concession  Block  OPL  233.

     As  a  consequence  of  this  ongoing restructuring, at the end of the most
recently completed financial year, the Company has no Participating Interests or
production  from the Niger Delta with the exception of a 10% working interest in
the  Deep  Ima  Prospect.  PERSONS  READING  THIS  DOCUMENT SHOULD NOTE THAT THE
PARTICIPATING  INTERESTS  ATTRIBUTABLE  TO  THE  COMPANY  IN THE NIGER DELTA AND
DISCUSSED  IN  THIS  SECTION WERE DISPOSED OF AND THAT WITH THE EXCEPTION OF THE
INTEREST  HELD IN THE DEEP IMA PROSPECT, ARE NO LONGER HELD BY THE COMPANY.  See
"Business  -  History  and  Development  of  the  Business  -  Restructuring  of
Operations  and  Financial  Affairs".

                                      -8-
<PAGE>
Location

     Prior  to  the disposition of its Participating Interests on June 30, 1998,
the  Company  held  Participating  Interests in adjoining Niger Delta Concession
Blocks  OML  112 and OPL 237.  Concession Blocks OML 112 and OPL 237 are located
approximately six miles off the coast of south-central Nigeria, cover an area of
approximately  150,000  acres,  and are in the vicinity of a number of Nigeria's
largest  oil  producing  fields, including Mobil's Oso and Kpono Fields; Shell's
Bonny,  Opobo  and  Kalaekule  Fields;  and  Elf  Aquitaine's  Ameram  Field.

     Prior  to  the cancellation of its joint venture agreement in early January
1998,  the  Company also held a Participating Interest in Niger Delta Concession
Block  OPL 233.  Concession Block OPL 233 covers an area of approximately 30,000
acres  and  is  located  along  the  Nigerian  coastline  100 miles northwest of
Concession  Blocks  OML  112  and  OPL 237 in the vicinity of Texaco's producing
Middleton,  North  Apoi  and  Pennington  Fields.

Participating  Interests

     An  oil prospecting licence for Concession Block OPL 237 was granted by the
MPR  to  Amni  in  December 1994.  An OML for Concession Block OML 112 (formerly
Concession  Block OPL 469) was issued to Amni in February 1998 following a prior
grant  of  an OPL for the concession block in August 1993.  The Company acquired
its Participating Interests in Concession Blocks OML 112 and OPL 237 pursuant to
joint  venture  agreements  signed  with  Amni  in August 1993 and December 1994
respectively.  On  June  30,  1998,  the  existing  joint venture agreements for
Blocks OML 112 and OPL 237 were terminated with the consent of Amni and replaced
by  a  new  joint  venture  agreement  (the "June 1998 JVA") which granted a 10%
Participating  Interest  to  the  Company  restricted  to the Deep Ima Prospect.

     An  OPL  for  Concession  Block OPL 233 was granted by the MPR to Petroleum
Products  Company  Limited  ("PPCL")  in  August  1993.  The  Company acquired a
Participating  Interest  in  Concession  Block  OPL  233 through a joint venture
agreement  with  PPCL  signed in November 1996.  The joint venture agreement was
terminated  by  mutual  consent  of the Company and PPCL in January 1998 with no
work  having  been  performed  by  the  Company  on  the  block.

Drilling,  Development  and  Production

     Prior to the disposition of its Participating Interests in the Niger Delta,
the Company had drilled 10 exploratory and development wells in the region.  The
following  table  provides  a  summary of the wells drilled and completed by the
Company  in  the  Niger  Delta:

                                      -9-
<PAGE>
<TABLE>
<CAPTION>
                                             TOTAL VERTICAL DEPTH
CONCESSION BLOCK  WELL NAME  DATE COMPLETED         (FEET)
----------------  ---------  --------------  ---------------------
<S>               <C>        <C>             <C>
OML 112           NGO #3     September 1994                 11,400
OML 112           NGO #4     November 1994                  11,400
OML 112           NGO #5     March 1995                     11,450
OPL 237           Ima #1     May 1995                       11,600
OPL 237           Ima #2     November 1995                  11,400
OPL 237           Ima #6     June 1997                      12,350
OPL 237           Ima #7     August 1997                    10,735
OML 112           Ima #8     October 1997                   11,380
OML 112           Ima #9     February 1998                  12,940
OPL 237           Ima #10    April 1998                     10,765
----------------  ---------  --------------  ---------------------
</TABLE>

     The  Company commenced commercial production of oil and condensate from the
Ima  Field  in  January 1997.  During the most recently completed fiscal year, a
total  of  approximately  2.64  million  gross  (1.45  million net) barrels were
produced  from  the  Ima  Field  prior  to  the  disposition  of  the  Company's
Participating  Interest  in June 1998.  Production levels from the Ima Field for
1998  prior  to  the disposition averaged approximately 14,600 gross (8,050 net)
barrels  of  oil  per  day.

     The  following  table  sets  forth  the  average  sales  price  (including
transfers)  and the average production cost per barrel of oil produced since the
commencement  of  production in January 1997 to the disposition of the Company's
Participating  Interest  in  the  Ima  Field  on  June  30,  1998.

<TABLE>
<CAPTION>
                                                   Year Ended
                                    -----------------------------------------
                                    December 31, 1997   December 31, 1998(1)
                                    ------------------  ---------------------
<S>                                 <C>                 <C>
Average Sales Price per Barrel      $            17.56  $               12.22
Average Production Cost per Barrel  $            13.61  $               14.94
<FN>
----------------------------------
(1)     Reflects  production  to  June  30,  1998
</TABLE>

     Oil and condensate produced from the Ima Field was lifted and sold pursuant
to  a Crude Oil Sale Agreement signed in August 1996 (amended July 1997) between
the  Company,  Amni  and a large international crude oil marketing company.  The
sale price under the Crude Oil Sale Agreement was linked to world markets prices
for  crude oil and was payable in U.S. dollars outside of Nigeria through a bank
in  Europe.  As  part  of  the  restructuring,  the Crude Oil Sale Agreement was
terminated  effective  June  30, 1998.  See "- Marketing and Sale of Petroleum".

Cost  Obligations  and  Revenue  Interests

     The  Company's Participating Interests in Concession Blocks OML 112 and OPL
237, (both before and after the disposition of its Participating Interest in the
shallow  zones  of  the  Ima  Field)  are held by subsidiaries and consist of an
obligation  to pay for exploration and development costs ("Cost Obligation") and
an  entitlement  to  receive  revenues  from  the  sale  of production ("Revenue
Interest").  Prior  to  the  signing  of  the  June 1998 JVA with Amni, the Cost
Obligation  and  Revenue  Interest  of the Company varied depending upon whether
Payout  has  been reached on the applicable concession block.  The June 1998 JVA
establishes  the same Cost Obligation and Revenue Interest both before and after
Payout.

                                      -10-
<PAGE>
     A  summary  of  the  Company's  Cost Obligation and Revenue Interest in its
Niger  Delta  concessions  both  before  and  after  the  disposition  of  its
Participating  Interests  in  June  1998 is outlined in the tables below. In all
cases, the Revenue Interest is after giving effect to gross overriding royalties
(or their equivalent) payable to third parties.  Royalties are payable on Blocks
OML  112  and OPL 237 to a company controlled by Wade Cherwayko, a former senior
executive officer and director of the Company.  A royalty is also payable on all
of the Niger Delta concessions to YFP, a company substantially controlled by the
father  of  Tunde  Folawiyo,  a  current  director of the Company.  See "Certain
Relationships  and  Related  Transactions".

Prior  to  June  30,  1998

<TABLE>
<CAPTION>
                                       BEFORE PAYOUT                       AFTER PAYOUT
                           -----------------------------------  -----------------------------------
CONCESSION        COUNTRY  REVENUE INTEREST   COST OBLIGATION   REVENUE INTEREST   COST OBLIGATION
----------------  -------  -----------------  ----------------  -----------------  ----------------
<S>               <C>      <C>                <C>               <C>                <C>
Block OML 112     Nigeria           49.7%(2)            100.0%           25.3%(2)             40.0%
Block OPL 237     Nigeria           48.7%(2)            100.0%           24.8%(2)             40.0%
Block OPL 233(1)  Nigeria           48.5%(3)            100.0%           24.1%(3)             40.0%
</TABLE>

Subsequent  to  June  30,  1998

<TABLE>
<CAPTION>
                                       BEFORE PAYOUT                       AFTER PAYOUT
                           -----------------------------------  -----------------------------------
CONCESSION        COUNTRY  REVENUE INTEREST   COST OBLIGATION   REVENUE INTEREST   COST OBLIGATION
----------------  -------  -----------------  ----------------  -----------------  ----------------
<S>               <C>      <C>                <C>               <C>                <C>
Block OML 112(4)  Nigeria           10.0%(5)             10.0%           10.0%(5)             10.0%
Block OPL 237(4)  Nigeria           10.0%(5)             10.0%           10.0%(5)             10.0%
<FN>
----------------------------------
(1)     Reflects  Cost  Obligation and Revenue Interest to January 30, 1998 at which time the Joint
Venture  Agreement  between  the  Company  and  PPCL was terminated by mutual consent.  No work was
performed  or  expenditures  incurred  by  the  Company  on  Concession  Block  OPL  233.
(2)     Revenue  Interest  gives effect to (i) the interest of the Company's Nigerian Partner, (ii)
combined  government  royalties and taxes of 30% both before and after Payout and (iii) a number of
gross  overriding royalties that vary from concession to concession and range between approximately
6.4%  and  5.3%  before  Payout  and  3.2%  and  2.6%  after  Payout.  A portion of the total gross
overriding  royalties are held by a company controlled by Wade Cherwayko, a former senior executive
officer and director of the Company and by YFP, a company substantially controlled by the father of
Tunde  Folawiyo,  a  director  of the Company.  Tunde Folawiyo is also an executive officer of YFP.
(3)     The  Revenue  Interest  shown  gives  effect  to  the  Company's proportionate share of (i)
combined  government  royalties  and taxes of 30% both before and after payout and (ii) a number of
gross  overriding  royalties  equal  to  approximately 6.5% before Payout and 3.9% after Payout.  A
portion  of  the  total  gross  overriding  royalties  is  payable  to  YFP.
(4)     The  joint  venture  agreements  governing  the  Company's participation in its Niger Delta
concessions  reserve  to  the  Nigerian government the right to acquire a Participating Interest in
each  of  the  respective concession blocks.  If the Nigerian government elects to participate, the
Company's after-Payout Revenue Interest could be reduced to approximately 8.0% after accounting for
the  interests  of  others.  In  such  an  event,  there  would be a corresponding reduction in the
Company's  after-Payout  Cost  Obligation.  See  "Management's Discussion and Analysis of Financial
Condition  and  Results of Operations - Risks and Uncertainties - Nigerian Regulation  - Government
Right  of  Participation".
(5)     Excludes  applicable  gross  overriding  royalties  or  their  equivalent payable to others
(including  YFP  and  a  company  controlled  by  Wade  Cherwayko).  The  level of the royalties is
currently  under  review  by  the  Company  as a result of the signing of the June 1998 JVA and the
Company  anticipates  re-negotiating  the  levels  of  royalties  held  by royalty-holders prior to
commencing  any  further  operations  on  the  Deep  Ima  Prospect.
</TABLE>

BENIN  BASIN

Location

     The  Benin  Basin  is  a  large geological region located along the western
coastal region of Nigeria and much of offshore Benin.  In Nigeria, the Company's
Benin  Basin concessions consist of adjoining offshore Concession Blocks OML 113
and  OPL  310.  In  Benin,  the  Company's  Benin  Basin  concessions consist of
offshore Concession Block 1 and Block 4, located adjacent to Nigerian Concession
Block  OML  113.  Concession  Block  1 encompasses the area around and below the
producing zones of the Seme Field.  Concession Block 4, located further offshore
than  Concession  Block 1 spans from the Nigerian border on the east to the Togo
border  on  the  west.

                                      -11-
<PAGE>
Participating  Interests

     In  Nigeria,  an  OML  for  Concession Block OML 113 (formerly OPL 309) was
issued  to  YFP  in  July  1998  following  the  prior  grant  of an OPL for the
concession  block  in  June  1991.  YFP  is  a  company  that  is  substantially
controlled  by  the  father of Tunde Folawiyo, a director of the Company.  Tunde
Folawiyo  is  also an executive officer of YFP.  An OPL for Concession Block OPL
310  was granted to Optimum Petroleum Development Limited ("Optimum") by the MPR
in February 1992.  The Company acquired its Participating Interest in Concession
Block OML 113 in June 1993 pursuant to a joint venture agreement with YFP and in
Concession  Block OPL 310 in December 1996 pursuant to a joint venture agreement
with  Optimum.  The  OPL  for Block OPL 310 expired in February 1997 however, at
the  request  of  Optimum, the DPR confirmed in February 1997 (subsequent to the
expiry  date)  that the OPL continued to be in good standing notwithstanding the
expiry  of its formal term.  Nothing has been received by the Company or, to the
knowledge  of  the  Company,  by  Optimum subsequent to February 1997 that would
indicate  that  the  MPR  or  DPR  consider  OPL  310 not to be valid or in good
standing  at  the  current  time.  To  maintain  its  Participating  Interest in
Concession Block OPL 310, the Company is required to satisfy certain future work
commitments.  See  "Management's  Discussion and Analysis of Financial Condition
and  Results  of  Operations - Risks and Uncertainties - Nigerian Title Issues -
Expiration  or  Cancellation  of  Nigerian  Oil  Prospecting  Licences".

     In  Benin,  the  Company  and Addax Petroleum Benin Limited ("Addax Benin")
executed a Production Sharing Contract in respect of Benin Block 1 (the "Block 1
PSC")  and Benin Block 4 (the "Block 4 PSC") in February 1997.  On September 30,
1997,  the  Company  acquired all of Addax Benin's Participating Interest in the
Block  1 PSC and Block 4 PSC.  To maintain its Participating Interest in Block 1
and Block 4, the Company is required to satisfy certain future work commitments.
See  "Management's Discussion and Analysis of Financial Condition and Results of
Operations  -  Risks  and  Uncertainties  -  Benin  Title  Issues".

     The Company has paid total acquisition fees of approximately $9.125 million
for  its  Participating  Interests  in  the  Benin  Basin concessions.  With the
conversion  of  OPL 309 into OML 113 in July 1998, an additional $5.0 million in
acquisition  fees  is  payable to YFP out of a portion of the Company's share of
future  production  revenues.  YFP is a company that is substantially controlled
by  the  father of Tunde Folawiyo, a director of the Company.  Tunde Folawiyo is
also  an executive officer of YFP.  On Concession Block OPL 310, $1.0 million is
payable to Optimum within nine months following testing of the first exploration
well  and  $2.0  million  following  commencement  of  production.

Drilling,  Development  and  Future  Work  Commitments

      The following table provides a summary of the wells drilled by the Company
on  its  Benin  Basin  concessions  since  1996:

<TABLE>
<CAPTION>
CONCESSION                             TOTAL VERTICAL DEPTH
  BLOCK     WELL NAME  DATE COMPLETED         (FEET)          FLOW RATE (BOPD)(1)
----------  ---------  --------------  ---------------------  -------------------
<S>         <C>        <C>             <C>                    <C>
OML 113     AJE #1     November 1996                   7,605                5,500
OML 113     AJE #2     March 1997                     11,551                8,800
<FN>
----------------------------------
(1)     Flow  rate  results  are  from  testing  only  and  are  not  necessarily
indicative  of  flow rates that may be realized during production.  Results shown
include  oil  and condensate but not natural gas.  Testing and compilation of the
test  results  from  the  Company's  wells  was  conducted  by  Schlumberger.
</TABLE>

                                      -12-
<PAGE>
     The  Company  has  fulfilled  its  minimum  work  obligations in respect of
Concession  Block  OML  113.  However,  significant additional expenditures will
have  to  be  incurred  by  the  Company  under  the  terms of its joint venture
agreement with YFP in order to produce the petroleum resources identified in OML
113.  Most  notably,  the  Company will have to establish or secure a market for
the  natural gas identified in the Aje Field of Block OML 113, secure a suitable
floating  off-shore  production  facility  and  finance,  construct  or  lease a
pipeline  to  an  on-shore market.  There is no assurance that the Company will,
by  itself  or  with  others,  be  able  to  establish a suitable market for the
petroleum  resources contained in the Aje Field of Block OML 113 or that it will
be  able  to  secure  a production facility or construct a pipeline necessary to
produce  such  resources.  See  "  - Cost Obligations and Revenue Interests" and
"Management's  Discussion  and  Analysis  of  Financial Condition and Results of
Operations  -  Risks  and  Uncertainties  -  Liquidity".

     On  Concession Block OPL 310, the Company is required to complete a minimum
work program consisting of three wells and a seismic program.  The obligation of
the  Company to initiate expenditures towards the minimum work program commences
after  receipt of applicable government approval for the joint venture agreement
between  the  Company  and  Optimum.  The  OPL  for Concession Block OPL 310 has
expired  and  Optimum has not yet secured an extension or replacement OPL or the
requisite  government  approval  for  the  joint venture agreement.  Optimum has
advised  the  Company  that it wishes the Company to proceed with fulfilling its
minimum work commitment in advance of receipt of requisite government approvals.

     In  Benin,  the  work commitments of the Company are set out in the Block 1
PSC  and  Block 4 PSC.  In the case of Block 1, the Company is required to drill
one  well  and  complete  a  seismic  program  by the end of February 1999.  The
requisite  work  commitment  for Block 1was not satisfied by this deadline.  The
Company  is currently negotiating an extension with the Benin Ministry and risks
the  loss  of  its  Participating  Interest  in  Block  1 if an extension is not
secured.  In  the case of Block 4, the Company is required to drill one well and
complete  a  seismic  program  by  February 2002.  The Company has satisfied the
seismic  commitment  but  not  the  drilling  commitment.  See  "Management's
Discussion and Analysis of Financial Condition and Results of Operations - Risks
and  Uncertainties  -  Benin  Title  Issues"  and  "-  Risks and Uncertainties -
Liquidity".

     In June 1998, the Company entered into a Letter of Intent with a subsidiary
of  a  major international natural gas producing and electrical power generating
company and the Government of Benin for the development, financing, construction
and  operation of an electrical generation power plant to be located in Cotonou,
Benin.  Under  the  terms of the Letter of Intent, natural gas feedstock for the
project  is  expected  to  be  supplied from the Company's Aje Field natural gas
resources  identified  on  Nigerian  Block  OML  113  and from Block 1 in Benin.
Negotiations  are  continuing towards the signing of a definitive Power Purchase
Agreement.  See "Management's Discussion and Analysis of Financial Condition and
Results  of  Operations  -  Risks  and  Uncertainties  -  Benin  Regulation".

Cost  Obligations  and  Revenue  Interests

     The  Company's  Participating Interests in the Benin Basin, consisting of a
Cost  Obligation and Revenue Interest, are held by the Company pursuant to joint
venture  agreements  with  its  Nigerian Partners in Nigeria and pursuant to the
Block  1 PSC and Block 4 PSC in Benin.  The Cost Obligation and Revenue Interest
of the Company vary based upon whether Payout has been reached on the applicable
concession  block.

                                      -13-
<PAGE>
     The  joint  venture agreements with the Nigerian Partners generally provide
that,  as part of its Cost Obligation, the Company must fund all exploration and
development  costs  before  Payout  and  40%  of  all  such  costs after Payout.
Provided there is production from a concession block, the Company is entitled to
55%  of revenues before Payout and 28% after Payout (before accounting for gross
overriding  royalties  or  their  equivalent payable to others).  The balance of
revenues before Payout is payable as to 30% to the Nigerian government for taxes
and  royalties  and  as  to  15%  to  the Nigerian Partner.  There is a pro-rata
adjustment  mechanism  in place should applicable government royalties and taxes
be less than 30% of total revenues.  The Company's Nigerian Partner on Block OML
113  is YFP, a Company substantially controlled by the father of Tunde Folawiyo,
a  director  of  the  Company.

     In  Benin,  the  PSC's  with the Government of Benin require the Company to
fund  100% of all exploration and development costs of a prescribed minimum work
program.  Petroleum  costs  (to  a  prescribed  maximum)  are recoverable out of
future  production  sale  proceeds after payment of a 12.5% crude oil production
royalty  to the Benin Government.  Remaining crude is subject to a sliding scale
allocation  between  the  Company  and  the  Benin  Government  based upon daily
production.  The Company is also subject to a tax on corporate profits and to an
export  revenue  tax.

     A  summary of the Company's Revenue Interest and Cost Obligation in each of
its  Benin  Basin  concessions  is  set  forth  below.

<TABLE>
<CAPTION>
                                      BEFORE PAYOUT                      AFTER PAYOUT
                           -----------------------------------  -----------------------------------
CONCESSION        COUNTRY  REVENUE INTEREST   COST OBLIGATION   REVENUE INTEREST   COST OBLIGATION
----------------  -------  -----------------  ----------------  -----------------  ----------------
<S>               <C>      <C>                <C>               <C>                <C>
Block OML 113(1)  Nigeria           52.5%(2)            100.0%              26.7%             40.0%
Block OPL 310(1)  Nigeria              48.5%            100.0%              24.7%             40.0%
Block 1/Seme      Benin          69.0%(3)(5)      100.0%(3)(5)           50.0%(5)      100.0%(3)(5)
Block 4           Benin          75.0%(4)(5)      100.0%(4)(5)        50.0%(4)(5)      100.0%(4)(5)
<FN>
----------------------------------
(1)     The  agreements governing the Company's participation in Blocks OML 113 and OPL 310 reserve
to  the Nigerian government the right to acquire a Participating Interest in each of the respective
concession  blocks.  If  the  Nigerian government elects to participate, the Company's after-Payout
Revenue  Interest  could be reduced to 20.0% after accounting for the interests of others.  In such
an  event,  there would be a corresponding reduction in the Company's after-Payout Cost Obligation.
See  "Management's  Discussion  and  Analysis  of  Financial  Condition and Results of Operations -
Management's  Discussion  and Analysis of Financial Condition and Results of Operations - Risks and
Uncertainties  -  Government  Right  of  Participation."

(2)     The Revenue Interest set forth above gives effect to (i) the interest held by the Company's
Nigerian  Partner,  (ii)  government  royalties  and taxes both before and after Payout and (iii) a
number of gross overriding royalties that vary from concession to concession and range from 6.4% to
2.5%  before Payout and 3.2% to 1.3% after Payout.  Certain of these gross overriding royalties are
held  by  a  company wholly owned by Wade Cherwayko, a former executive officer and director of the
Company.

(3)     Under  the  terms  of  the  Block  1  PSC,  the  Company  is responsible for payment of all
exploration  and  development costs of a prescribed minimum work program.  Petroleum costs incurred
by  the Company are recoverable out of future proceeds of production after payment of a 12.5% crude
oil production royalty.  In any particular year, cost recovery is limited to 69% of total crude oil
sale  proceeds.  The  balance  of  crude  oil sale proceeds ("Profit Oil") is allocated between the
Company  and  the  Government  of  Benin  based  upon total daily production in accordance with the
following  progressive  scale:

AVERAGE DAILY
------------------
PRODUCTION (BOPD)   GOVERNMENT SHARE   COMPANY SHARE
------------------  -----------------  --------------
0 to 5,000                        50%             50%
5,001 to 10,000                   55%             45%
10,001 to 20,000                  60%             40%
20,001 to 50,000                  65%             35%
50,000 to 100,000                 70%             30%
Over 100,000                      75%             25%

(4)     Under  the  terms  of  the  Block  4 PSC, the Company is responsible for
payment  of  all  exploration and development costs of a prescribed minimum work
program.   Petroleum costs incurred by the Company are recoverable out of future
proceeds  of  production  after payment of a 12.5% crude oil production royalty.
In  any particular year, cost recovery is limited to 75% of total crude oil sale
proceeds.  The  balance  of  crude oil sale proceeds ("Profit Oil") is allocated
between  the  Company  and  the  Government  of  Benin  based  upon  total daily
production  in  accordance  with  the  following  progressive  scale:

                                      -14-
<PAGE>
Oil

AVERAGE DAILY
-----------------
PRODUCTION (BOPD)  GOVERNMENT SHARE   COMPANY SHARE
-----------------  -----------------  --------------
0 to 100,000                     50%             50%
over 100,000                     55%             45%

     Condensate

AVERAGE DAILY
-----------------
PRODUCTION (BOPD)  GOVERNMENT SHARE   COMPANY SHARE
-----------------  -----------------  --------------
0 to 100,000                     45%             55%
over 100,000                     50%             50%

(5)     The  Company  may  also be subject to a 55% tax on profits received from
the  sale of petroleum (after full cost recovery including capital and operating
costs).  An  export  revenue tax of 3.12% of the FOB value of the petroleum sold
is  also  applicable  to  petroleum  exported  to  a  location outside of Benin.
</TABLE>

RESERVES

Niger  Delta
------------

     The  following table sets forth certain summary information at December 31,
1997  contained  in  the Reserve Report prepared by Gilbert Laustsen dated April
13,  1998 of the gross and the Company's net oil and condensate reserves and the
Present  Value  of  such  reserves  on  a  constant  price  and cost basis after
adjustment  for  applicable  Nigerian  taxes and royalties, as understood by the
Company and gross overriding royalties or their equivalent and interests held by
the  Company's Nigerian Partners.  ALL OF THE RESERVES REFERENCED IN THE RESERVE
REPORT  WERE  DISPOSED OF BY THE COMPANY ON JUNE 30, 1998 AS PART OF THE ONGOING
REORGANIZATION  OF  ITS  OIL  AND  GAS  OPERATIONS.

     All of the Company's reserves reflected in the Reserve Report relate to the
Ima  Field located on Concession Blocks OML 112 and OPL 237.  The Reserve Report
also  identified  natural  gas  reserves,  however,  such reserves have not been
assigned  economic  value  as no market currently exists.  No Reserve Report has
been  filed  by  the Company with any U.S. or Canadian Federal regulatory agency
since  the  beginning  of  the  last  fiscal  year.

     The  Reserve  Report  revises  previous reserve reports prepared by Gilbert
Laustsen  dated August 1, 1995, November 15, 1995, September 1, 1996 and May 13,
1997.  The  forecasts  shown  in  the  Reserve Report reflect updated production
facility capital, lease and operating expenditures, change in the constant price
per  barrel  of  oil  and  the commencement of production on the Ima Field.  The
reserve  information,  including Present Value, have been prepared in accordance
with  SEC  Present  Value  Criteria  which  differs  in  some  respects from the
requirements  of Canadian National Policy No. 2-B.  The Present Values set forth
in  the  Reserve  Report do not necessarily reflect the fair market value of the
reserves  evaluated.  THE  INFORMATION  RESPECTING  THE  COMPANY'S  RESERVES ARE
PRESENTED  TO  COMPLY  WITH  APPLICABLE  SECURITIES REGULATIONS.  THE COMPANY NO
LONGER  HOLDS  ANY  INTEREST  IN  THE  RESERVES  SHOWN.

                                      -15-
<PAGE>
                 BASED ON CONSTANT PRICE AND COST ASSUMPTIONS(1)

<TABLE>
<CAPTION>
                                                      AT DECEMBER 31, 1997
                                 -----------------------------------------------------------------
                                                                                     TOTAL PROVED
                                   PROVED    PROVED NON-     TOTAL       50% OF        AND 50%
                                 PRODUCING    PRODUCING     PROVED      PROBABLE     PROBABLE OF
                                  RESERVES     RESERVES    RESERVES   RESERVES(2)      RESERVES
                                 ----------  ------------  ---------  ------------  --------------
<S>                              <C>         <C>           <C>        <C>           <C>
Oil and Condensate
  Gross Reserves(3)(MMB)                3.8          18.3       22.1           6.5            28.6
                                 ----------  ------------  ---------  ------------  --------------

  Company's Net Reserves (4)(5)         2.8            13       15.8           4.7            20.5
                                 ----------  ------------  ---------  ------------  --------------

Present Value of Company's Net
Reserves (in $millions) (1)(6)
  Undiscounted                   $     11.7  $       65.6  $    77.1  $       41.9  $        119.0
  Discounted at 10%                    11.4          53.1       64.5          30.7            95.2
  Discounted at 15%                    11.2          48.4       59.6          26.5            86.1
-------------------------------  ----------  ------------  ---------  ------------  --------------
<FN>
-------------------------------
(1)     Utilizing SEC Present Value criteria based on a constant price of $16.20 per barrel (being
the  price  in effect on December 31, 1997).  The SEC Present Value differs from the Present Value
utilized  under  Canadian  National Policy 2-B in that the SEC Present Value is based upon a price
per  barrel  on the date the SEC Present Value is calculated.  The Canadian Present Value is based
upon  an  estimated  average  price per barrel of oil for the year following the date the Canadian
Present  Value  is  calculated.
(2)     A  risk  factor  of  50% has been applied to Probable Reserves and to the future estimated
cash  flow  from  Probable  Reserves to account for the geological and engineering risk associated
with  these  reserves.
(3)     Gross  Reserves  reflects  total  cumulative  reserves  held  by  all  participants.
(4)     Net  Reserves  reflects  reserves  attributable  to  the  Company  after adjustment of the
Company's  understanding  of  applicable  Nigerian  taxes  and  royalties,  and  gross  overriding
royalties  or  their  equivalent  and  interests  held  by  the  Company's  Nigerian  Partners.
(5)     The total proved production forecast reflected in the Reserve Report is developed based on
the  following  assumptions:
   -  Based  on  the  inclusion of two wells forecast to be placed on production in April 1998 and
January  1999,  respectively.
   -  Gas  injection  is  increased  to  a  minimum  of  40  MMCFD  into  the  Upper  C-1  Zone.
   -  With  pressure maintenance, production from three existing wells is stabilized at 6,200 bopd
until  the  end  of  1999  and  then  forecast  to  decline to depletion of the assigned reserves.
   -  Pressure  maintenance  is  implemented  in  the  Lower  C-1 Zone by January 1, 1999 with gas
injection  at 65 million cubic feet per day or water injection at 50,000 barrels of water per day.
   -  With pressure maintenance, production from three existing wells is forecast to be stabilized
at  6,500  bopd  until  mid-year  2000  and  then  decline thereafter to depletion of the assigned
reserves.
     The  total  proved  plus  probable  production  forecast  includes  the  following additional
assumptions:
   -  Two  wells are forecast to be placed on production in the first half of 1999 with production
at  a  rate  of  2,500  bopd  per  well.
   -  The  flat  life  production  period  of  the  Upper  C1  zone  is  extended  by  one  year.
   -  Place  the  D  zone  on  production  from  one  additional  well.
(6)     The  economic  parameters  used  to  determine  the  present  value  are  as  follows:
   -  Constant  crude  oil  price  of  $16.20/barrel
   -  Operating  cost  of  $32.3  million  per  year
   -  Overhead  cost  of  $7.2  million  per  year
   -  Government  tax/royalty  of  18.5%
   -  Indigenous  company  royalty/carried  interest  of  10.0%
   -  Drilling  cost  of  $7.3  million  per  well
</TABLE>

Benin  Basin
------------

                                      -16-
<PAGE>
     Between November 1996 and March 1997, the Company drilled and completed two
off-shore  wells  on  the Aje Field of Nigerian Block OML 113.  The wells tested
maximum flow rates of 5,500 and 8,800 barrels of oil per day, respectively, with
associated  natural  gas.  Subsequent  analysis  of log results and seismic data
indicate that, in addition to oil, significant natural gas resources are located
in  the  Aje Field.  Although identified by exploration drilling, no reserves or
Present  Value  has  been  assigned to the Aje Field on the basis that no market
currently  exists  for  the  Aje  Field's natural gas resources.  The Company is
currently  negotiating  with  a  major  international  natural gas producing and
electrical  power  generating  company  and  the  Government  of  Benin  for the
development,  financing  and  construction  of  a natural gas powered electrical
generation  power  plant  which is anticipated will provide electrical energy to
Benin and the neighboring countries of Togo and Ghana.  Natural gas feedstock is
expected  to  be  supplied  from the natural gas resources identified in the Aje
Field  and  from  Benin Block 1.  The completion of a power plant is expected to
establish  a  market for the Company's natural gas resources.  See "Management's
Discussion and Analysis of Financial Condition and Results of Operations - Risks
and Uncertainties - Liquidity" and "Risks and Uncertainties - Benin Regulation".

RESERVE  RECONCILIATION

     The  following  table  contains  a  reconciliation  of Proved Reserves on a
constant  price  basis  from  December 31, 1996 to June 30, 1998 when all of the
Company's  Proved  Reserves  were  disposed  of.

<TABLE>
<CAPTION>
                                                      PROVED RESERVES (MMBBLS)(1)(5)
                                                    ----------------------------------
                                                    GROSS RESERVES(2)  NET RESERVES(3)
                                                    -----------------  ---------------
<S>                                                 <C>                <C>
PROVED RESERVES AT DECEMBER 31, 1996(4)                         47.7             23.5 
                                                    -----------------  ---------------

Add:
               Discoveries, additions, extensions                  -                - 
               Purchases and Sales                                 -                - 
               Economic/Technical Revisions                    (19.5)            (4.3)

Subtract:
               Production                                       (6.1)            (3.4)
                                                    -----------------  ---------------

PROVED RESERVES AT DECEMBER 31, 1997                            22.1             15.8 

Add:
               Discoveries, additions, extensions                  -                - 
               Purchases                                           -                - 
               Economic/Technical Revisions                        -                - 

Subtract:
               Production and Sales                             22.1             15.8 
                                                    -----------------  ---------------

PROVED RESERVES AT DECEMBER 31, 1998(5)                            -                - 
                                                    =================  ===============
<FN>
-------------------------------
(1)     Proved  Reserves  are  those  reserves  estimated as recoverable under current
technology  and existing economic conditions, from that portion of the reservoir which
can  be  reasonably  evaluated  as economically productive on the basis of analysis of
drilling,  geological,  geophysical  and  engineering  data,  including reserves to be
obtained  by  enhanced  recovery processes demonstrated to be economic and technically
successful  in  the  subject  reservoir.  Includes  oil  and  condensate.
(2)     Gross  Reserves  reflect  total  cumulative reserves held by all participants.
(3)     Net  Reserves reflect reserves attributable to the Company after adjustment of
the  Company's  understanding  of  applicable  Nigerian  taxes  and  royalties,  gross
overriding  royalties or their equivalent and interests held by the Company's Nigerian
Partner.
(4)     Based  on  a  May  13,  1997  reserve  report  prepared  by  Gilbert Laustsen.
(5)     All  of  the  Proved  Reserves of the Company are situated in the Niger Delta.
These reserves were disposed of in June 1998.  See "Business - History and Development
of  the  Business  -  Restructuring  of  Operation  and  Financial  Affairs".
</TABLE>

CAPITAL  EXPENDITURES

     The  following  table  is a summary of the capital expenditures made by the
Company  on  acquisition, exploration, drilling and production activities on its
oil  and  gas  properties  for  the fiscal periods indicated.  In all cases, the
total  capital  expenditures  on the Company's oil and gas properties includes a
provision  for decline in property values.  For the twelve months ended December
31,  1997,  a  total  of  $110.9  million was spent on the Company's oil and gas
properties  compared  to  capital  expenditures  of $15.2 million for the twelve
months  ended  December  31,  1998.

                                      -17-
<PAGE>
<TABLE>
<CAPTION>
                                                    TWELVE MONTHS ENDED
                                              --------------------------------
                                               DEC. 31    DEC. 31     DEC. 31      TOTAL TO
                                                1996        1997       1998     DEC. 31 1998(1)
                                              ---------  ----------  ---------  ---------------
<S>                                           <C>        <C>         <C>        <C>
                                                                                         ($000)

NIGER DELTA CONCESSIONS
   Land and Data Acquisitions                 $      -   $   1,200          -           10,211 
   Exploration, Drilling and Seismic            11,128      61,497     13,222          132,068 
   Production Facilities                        93,670       2,862          -          102,177 
   Administration and Capitalized Interest       1,896           -          -            9,461 
   Acquisition of Royalty Interest                   -      13,536          -           13,536 
   Acquisition by Plan of Arrangement                -           -          -           28,038 
   Depreciation, Depletion and Amortization          -     (28,159)    (4,244)         (32,452)
   Provision for Decline in Property Values          -    (206,019)         -         (206,019)
   Disposition of Niger Delta Concessions(2)         -           -    (57,020)         (57,020)
                                              ---------  ----------  ---------  ---------------

   TOTAL NIGER DELTA                           106,694    (155,083)   (48,042)               - 
                                              ---------  ----------  ---------  ---------------

BENIN BASIN CONCESSIONS

   Land and Data Acquisitions                      600       1,525      2,000            9,125 
   Exploration, Drilling and Seismic            52,136      24,311          -           78,469 
   Administration and Capitalized Interest         687           -          2            2,782 
   Acquisition of Royalty Interest                   -       6,036          -            6,036 
   Provision for Decline in Property Values          -      (3,981)         -           (3,981)
                                              ---------  ----------  ---------  ---------------

   TOTAL BENIN BASIN                            53,423      27,891      2,002           92,431 
                                              ---------  ----------  ---------  ---------------

   TOTAL BENIN BASIN/NIGER DELTA              $160,117   $(127,192)  $(46,040)          92,431 
                                              =========  ==========  =========  ===============
<FN>
-------------------------------
(1)     The  total includes all expenditures since the Company initiated oil and gas operations
in  Nigeria  and  Benin.
(2)     See  "Business  - History and Development of the Business - Restructuring of Operations
and  Financial  Affairs".
</TABLE>

OIL  AND  GAS  DRILLING  ACTIVITIES

     All  of  the  Company's drilling activities have been in Nigeria.  No wells
have  been  drilled  to date by the Company in the Republic of Benin.  The table
that  follows  sets  out  the  gross  and net number of productive and dry wells
drilled  and  completed  in  the  periods  indicated.

                                      -18-
<PAGE>
<TABLE>
<CAPTION>
                                   FOR THE 12          FOR THE 12       FOR THE 12 MONTHS
                                  MONTHS ENDED        MONTHS ENDED           ENDED            CUMULATIVE TO
                                DEC. 31, 1996(1)    DEC. 31, 1997(1)    DEC. 31, 1998(1)      DEC. 31, 1998
                               ------------------  ------------------  ------------------  ------------------
                                GROSS      NET      GROSS      NET      GROSS      NET      GROSS      NET
LOCATION OF WELLS              WELLS(2)  WELLS(3)  WELLS(2)  WELLS(3)  WELLS(2)  WELLS(3)  WELLS(2)  WELLS(3)
-----------------------------  --------  --------  --------  --------  --------  --------  --------  --------
<S>                            <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>

NIGER DELTA CONCESSIONS:
Productive Oil and
Condensate                            -         -       3.0       1.4       2.0       1.0      10.0      4.78

Dry and Abandoned                     -         -         -         -         -         -         -         -
                               --------  --------  --------  --------  --------  --------  --------  --------

Total Drilled Wells                   -         -       3.0       1.4       2.0       1.0      10.0      4.78
                               --------  --------  --------  --------  --------  --------  --------  --------


BENIN BASIN CONCESSIONS:
Productive Oil and Condensate
                                    1.0       0.5       1.0       0.5         -         -       2.0       1.0

Dry and Abandoned                     -         -         -         -         -         -       1.0      0.51
                               --------  --------  --------  --------  --------  --------  --------  --------

Total Drilled Wells                 1.0       0.5       1.0       0.5         -         -       3.0      1.51
                               --------  --------  --------  --------  --------  --------  --------  --------


TOTAL DRILLED WELLS                 1.0       0.5       4.0       1.9       2.0       1.0      13.0      6.29
                               ========  ========  ========  ========  ========  ========  ========  ========
<FN>
-----------------------------
(1)     "Reflect  wells  completed  in  the  periods  indicated.
(2)     Gross  Wells"  are  the  total  number  of  wells in which the Company  has a Participating Interest.
(3)     "Net  Wells"  are  the  aggregate of the percentage of Revenue Interest of the Company in each of the
Gross Wells.  In all cases, the Revenue Interest shown is before payout.  The Revenue Interest of the Company
declines  after payout.  See "-The Niger Delta - Cost Obligations and Revenue Interests" and "- Benin Basin -
Cost  Obligations  and  Revenue  Interests".
</TABLE>

AREA  HOLDINGS

     As  at  December  31,  1998, following the disposition of its Participating
Interest in the shallow zones of Ima Field, the Company's crude oil, natural gas
and  natural gas liquids holdings consisted of approximately 148,000 gross acres
and  14,800  net  acres  in  the Niger Delta and approximately 3.5 million gross
acres and 2.1 million net acres in the Benin Basin.  Pursuant to the disposition
of  its  Participating  Interest in the Niger Delta in June 1998, the Company no
longer  holds  proved  or  unproved  acreage  in  the  Niger Delta.  Rather, the
Company's  net  acreage  position is restricted to 10% Participating Interest in
the  Deep  Ima  Prospect  in  respect  of  which there is currently no proved or
probable  reserves.

                                      -19-
<PAGE>
<TABLE>
<CAPTION>
     The  following  table  summarized the Company's land holdings as of December 31, 1998.

       CONCESSION          ACQUIRED   PARTNER  PROVED ACREAGE(1)(2)   UNPROVED ACREAGE(1)(3)
------------------------  ----------  -------  --------------------  ------------------------
                                                GROSS       NET         GROSS         NET
                                               ACRES(4)   ACRES(5)    ACRES(4)     ACRES(5)
                                               --------  ----------  ----------  ------------
<S>                       <C>         <C>      <C>       <C>         <C>         <C>

NIGER DELTA
Block OML 112 (6)         Aug. 1993   Amni            -           -     134,100     13,410(7)
Block OPL 237 (6)         Dec. 1994   Amni            -           -      14,335      1,433(7)
                          ----------  -------  --------  ----------  ----------  ------------
      Total Niger Delta                               -           -     148,435       14,843 
                          ----------  -------  --------  ----------  ----------  ------------


BENIN BASIN
Block OML 113             June 1993   YFP             -           -     410,000      215,250 
Block OPL 310             Dec. 1996   Optimum         -           -     490,000      237,650 
Block 1                   Sept. 1997        -         -           -     720,000    434,700(8)
Block 4                   Sept. 1997        -         -           -   1,900,000  1,246,800(8)
                          ----------  -------  --------  ----------  ----------  ------------
     Total Benin Basin                                -           -   3,520,000    2,134,400 
                          ----------  -------  --------  ----------  ----------  ------------


TOTAL AREA HOLDINGS                                   -           -   3,668,435    2,149,243 
                          ==========  =======  ========  ==========  ==========  ============
<FN>
------------------------
(1)     As  at  December  31,  1998
(2)     "Proved  Acreage"  means  the  acreage  to  which  the  Company has assigned Proved
Reserves  at  December  31,  1998.
(3)      "Unproved  acreage"  refers  to  the  acreage to which the Company has assigned no
Proved  Reserves.
(4)     "Gross  Acres" means all acreage in which the Company has a Participating Interest.
(5)     "Net  Acres" means Gross Acres after deducting interests of all other participants.
In  each  case,  the Net Acres is shown before Payout.  The Net Acres position will decline
after Payout is achieved.  See "- Niger Delta - Cost Obligations and Revenue Interests" and
"-  Benin  Basin  -  Cost  Obligations  and  Revenue  Interests".
(6)     The  Company  released  its  Participating Interest in the shallow zones of the Ima
Field  located on this concession block in June 1998.  Acreage references are restricted to
the  Deep  Ima  Prospect  only.
(7)     Reflects  interest  in  the  Deep  Ima  Prospect  only.
(8)     Net Acres calculated based upon Cost Oil Recovery attributable to the Company after
giving  effect  to  a 12.5% crude oil production tax payable on gross production.  Does not
account  for an additional sliding scale royalty that becomes payable by the Company to the
Benin  government  based  upon  average  daily  production  rate.
</TABLE>

OPERATIONS  AND  PRESENT  ACTIVITIES

     Historically,  operations  in  Nigeria  have  been conducted jointly by the
Company,  as  technical  partner  and  the applicable Nigerian Partner, as named
operator.  In the Niger Delta, the Company is no longer the technical partner on
blocks  OML 112 or OPL 237.  In the Benin Basin, the Company continues to be the
technical partner for Concession Block OML 113 and OPL 310.  The Company is also
the  operator  of  Block  1  and  Block  4  in  Benin.  The Company is currently
evaluating  the  sale/farmout  of  part or all of its Participating Interests in
these  concessions.  The  role  of the Company as operator is dependant upon the
outcome  of  future  farm-out  arrangements.

     Due  to  the  restructuring of its affairs in June 1998, the Company is not
currently conducting drilling activities nor does it currently own production or
refining  facilities.  The  ability  of  the  Company to drill or participate in
future  wells  or  to  secure  or  construct  a  suitable production or refining
facility  to  produce  any  discoveries  is  dependant upon the Company securing
sufficient  financial  resources  or  a  suitable industry partner.  There is no
assurance  that  the  Company  will  be  able to attract new equity, debt, joint
venture  partners,  buyers, merger partners or a combination thereof in order to
remain  viable  and  continue  operations.  See  "Management's  Discussion  and
Analysis  of  Financial  Condition  and  Results  of  Operations  -  Risks  and
Uncertainties  -  Liquidity".

                                      -20-
<PAGE>
PRODUCTION  FACILITY

Components
----------

     On  June  30,  1998,  the  Company conveyed its entire interest in the MOPU
situated  on  the Ima Field to a major international service company in exchange
for  the extinguishment of approximately $18.8 million of debt, representing all
of  the  debt  due  from  the  Company  to  the  international  service company.
Consequently,  the MOPU ceased to be a material asset of the Company at its most
recently  completed  year  end.  See  "Business - History and Development of the
Business  -  Restructuring  of  Operations  and  Financial  Affairs"

Financing
---------

     In  order  to  fund a portion of the capital and installation costs for the
MOPU  and  the  drilling of certain wells on the Ima Field, the Company and Amni
entered into a $30.0 million credit facility (the "European Bank Facility") with
two European banks in August 1996.  In July 1997, the Company received a Secured
Loan  of  $35.0 million under a crude oil pre-payment agreement, the proceeds of
which  were  used  to fully repay the European Bank Facility and for exploration
and  development costs on the IMA Field.  On June 30, 1998, the Secured Loan was
restructured  as  part  of  the  Company's overall financial restructuring.  The
restructuring  of  the Secured Loan by the Secured Lender enabled the Company to
defer  quarterly  interest  payments  until  December 31, 1998 and to extend the
maturity  of  approximately  $20.1 million of the loan until June 30, 1999, with
the  remainder  of  $10.6  million  due  on December 31, 1999.  The terms of its
agreement  with  the  major  international  service  company, provided that if a
future  sale price of the MOPU is above a pre-determined threshold, a portion of
the  proceeds  of sale will be applied to reduce the Company's obligations under
its  existing  Secured  Loan.

     Subsequent to December 31, 1998, the Company received confirmation from the
Secured  Lender  that  the  interest  payment  due  December  31,  1998 had been
capitalized  and  that  the  first  payment  was amended to March 31, 1999.  The
Secured  Lender  has since advised the Company that, notwithstanding its written
extension,  payment  of  the  first  interest instalment was due on December 31,
1998.  The  Company  has  not  yet  made  this interest payment and is currently
negotiating with its Secured Lender regarding further relief from this and other
near-term  cash  interest payments. There is no assurance that such negotiations
will  be  successful.  See  "Management's  Discussion  and Analysis of Financial
Condition  and  Results  of  Operations  -  Risks  and Uncertainties - Financing
Risks".

     The  Company  has  granted security to the Secured Lender in respect of its
repayment  obligations  under  the  Secured  Loan.  Included  as security to the
Secured  Lender  are  (1)  a  pledge  of  all  of  the  common  shares  of those
subsidiaries  that hold Participating Interests in the Company's Niger Delta and
Benin Basin Concessions; (2) a series of debentures granting a security interest
against  the Company's Participating Interest in its Niger Delta and Benin Basin
Concessions; and (3) a guarantee of Abacan for all outstanding amounts under the
Secured  Loan.  See "Management's Discussion and Analysis of Financial Condition
and  Results  of  Operations  -  Risks  and  Uncertainties  -  Financing Risks".

MARKETING  AND  SALE  OF  PETROLEUM

     Prior to the relinquishment of its Participating Interest in the Ima Field,
the Company sold its crude oil production to a major international oil marketing
company  pursuant  to  the  terms of a Crude Oil Sale Agreement dated August 29,
1996.  The  Crude Oil Sale Agreement was terminated in June 1998 concurrent with
the restructuring of the Company's oil and gas operations and financial affairs.
Consequently,  the  Company  has  no  existing  crude  oil delivery commitments.

                                      -21-
<PAGE>
INSURANCE,  OPERATING  HAZARDS  AND  UNINSURED  RISKS

     Prior  to the restructuring of its oil and gas operations and as protection
against  operating  hazards,  the  Company maintained insurance coverage against
some,  but  not  all,  potential  losses.  Following  the  disposition  of  its
Participating  Interest  in  the Ima Field the Company cancelled all policies of
insurance that related to its involvement as an operator and producer of oil and
condensate.  The  Company  anticipates  that  it  will  obtain  future insurance
coverage, as is prudent for the Company, based upon the nature and extent of the
exploration  and  development activities being conducted by the Company.  Losses
could, however, occur for uninsurable or uninsured risks or in amounts in excess
of  any  existing or future insurance coverage.  The occurrence of an event that
is not fully covered by insurance or that is uninsured could have a material and
adverse  impact  on the Company's financial condition and results of operations.
See  "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Risks and Uncertainties - Oil and Gas Exploration,  Development and
Production".

ITEM  3.     LEGAL  PROCEEDINGS

     As  at December 31, 1998, the Company is not involved in any lawsuits where
the  claim  for  damages  for  any  such lawsuit exceeds 10% of the value of the
Company's  current  assets  except  as  indicated  below:

1.     Weatherford  Enterra  U.S.  L.P.  v.  Abacan Resource Corporation et. al.
       -------------------------------------------------------------------------

Action commenced by Weathorford Enterra U.S.  L.P. (the "Plaintiff") in 1998  in
the  61st  Judicial District Court, Harris County, Texas against Abacan and four
of  its  affiliates  alleging  breach  of  contract  and unjust enrichment. Amni
International  Development  Company  Limited ("amni") and a subsidiary of Abacan
were  parties  to  a  Joint  Venture  Agreement  relating to oil exploration and
development  of  Nigerian  Concession  Blocks  OPL  237  and OML 112 (the "Joint
Venture").  The Plaintiff's claims arose out of transactions with respect to the
Joint Venture. The Plaintiff seeks an unspecified amount of actual damages, plus
interest,  costs and legal fees. Abacan has denied the Plaintiff's claim. Abacan
is  also  indemnified  by  Amni  for any of the Plaintiff's claims. Amni and the
Plaintiff  have  signed a settlement agreement however, the Company is not aware
if  the  settlement  terms have been performed by Amni. On January 19, 1999, the
Plaintiff  filed  a  non-suit  of  the  case,  without  prejudice.

2.     Global  Marine  International  Services  Corporation  v. Abacan Technical
       -------------------------------------------------------------------------
Services  Ltd.
--------------

Action  commenced  by  Global  Marine  International  Services  Corporation (the
"Plaintiff")  in the 125th Judicial District Court, Harris County, Texas against
Abacan Technical Services Ltd. ("Abacan Technical"), a subsidiary of the Company
on  March  25,  1998 alleging breach of contract arising out of the provision of
services  to Abacan Technical. The Plaintiff seeks damages of $1,963,148.80 plus
interest,  costs  and  legal  fees.  Abacan Technical has denied the Plaintiff's
claims.

Abacan  Technical  has  filed an interlocutory appeal of the trial court's order
denying  its  special  appearance, which disputes that Texas has jurisdiction of
the Plaintiff's claims. That appeal is pending. In late December 1998, the trial
court  granted the Plaintiff's Motion for Partial Summary Judgement for the full
amount  of its claim, excluding legal fees, plus interest. However, the order is
subject  to  appeal.  Pending  the  appeal,  the  Plaintiff  is  precluded  from
finalizing proceedings in the trial court or undertaking any collection efforts.
The  date  of  the hearing of the appeal or its disposition is uncertain at this
time.

                                      -22-
<PAGE>
3.     SBM  Offshore  Contractors  v.  Amni  International Petroleum Development
       -------------------------------------------------------------------------
Company  Limited, Liberty Technical Services Ltd. and Abacan Resources (Nigeria)
--------------------------------------------------------------------------------
Ltd.
----

SBM  Offshore  Contractors  (the "Plaintiff") has commenced action against Amni,
Liberty  Technical Services Ltd. ("Liberty") and Abacan Resources (Nigeria) Ltd.
("Abacan  Nigeria")  in  a  suit filed in the United Kingdom. Liberty and Abacan
Nigeria are subsidiaries of Abacan. The Plaintiff claims the that the Defendants
owe  it approximately $1.8 million for alleged past due invoices. The defendants
have  denied  the  claims.  Amni  has  indemnified  the  Company  for any of the
Plaintiff's  claims.  Amni  has  received authorization to conduct the action on
behalf  of  all  of  the  defendants.

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

     The  Company had no matters requiring a vote of security holders during the
fourth  quarter  of  fiscal  1998.

                                     PART II

ITEM  5.     MARKET  FOR  THE  COMPANY'S  COMMON  STOCK  AND  RELATED
             STOCKHOLDER  MATTERS

MARKET  INFORMATION

     The  Common  Shares of Abacan Resource Corporation commenced trading on The
Toronto  Stock  Exchange  (the  "TSE") on June 14, 1995 under the trading symbol
"ABC",  and  on  the Nasdaq National Market ("NASDAQ") on December 4, 1995 under
the  trading  symbol  ABACF.  The  following  table  sets forth the high and low
closing  sale  prices  of  Abacan's  Common  Shares  as  reported by the TSE (in
Canadian  dollars)  and  by  NASDAQ (in U.S. dollars) for the periods indicated.

<TABLE>
<CAPTION>
                        NASDAQ                 TSE
                ------------------------  --------------
                        (US $)             (Canadian $)
                  High          Low        High    Low
                ---------  -------------  ------  ------
<S>             <C>        <C>            <C>     <C>
1997
First Quarter   $ 11.7500  $      7.8125  $15.65  $10.75
Second Quarter     9.0000         1.8125   12.45    2.50
Third Quarter      4.0000         2.4375    5.50    3.35
Fourth Quarter     3.5156         1.5625    4.85    1.38

1998
First Quarter      2.6250         1.4062    3.64    1.75
Second Quarter     1.6250         0.3438    2.25    0.52
Third Quarter      0.9375         0.2188    1.38    0.34
Fourth Quarter     0.5625         0.1562    0.88    0.27

1999
January            0.4375         0.2188    0.67    0.36
February           0.2812         0.1562    0.40    0.23
March 1-20         0.2500         0.1562    0.38    0.25
</TABLE>

                                      -23-
<PAGE>
     The  Company  has  received  notice  from  The  Nasdaq  Stock  Market  Inc.
("Nasdaq")  that  its common shares are not in compliance with the $1.00 minimum
bid  price requirement for ongoing listing on the Nasdaq National Market System.
In  order  to endeavor to achieve compliance, the Company's shareholders will be
asked  to consider and approve at a Shareholders Meeting scheduled for March 29,
1999,  a  resolution  authorizing  the  directors,  in their discretion, to give
effect to a reverse stock split of the Company's common stock.  In the event the
Company's  common stock does not satisfy the $1.00 minimum bid price requirement
(which  is  the  only requirement it does not currently comply with) by April 7,
1999,  the  Company's  common  shares  will  be de-listed from Nasdaq's National
Market  System.  The  Company must also meet all other Nasdaq requirements on an
on-going  basis.  The  Company's  common  shares  are not currently eligible for
listing  on  the  Nasdaq  Smallcap  Market.

     There  is  no  assurance that shareholders' approval will be obtained for a
reverse-stock  split  or  if  obtained,  that  the directors will proceed with a
reverse  stock  split.  There  is  no assurance that if a reverse stock split is
completed  that  the minimum bid price will rise above or be sustained above the
$1.00  minimum  bid  requirement  or that the Company's common stock will not be
delisted  for some other reason.  A delisting of the Company's common stock from
the Nasdaq National Market System will be materially adverse to the liquidity of
the  Company's  common  stock.

     The  Company has received notification from The Toronto Stock Exchange that
it  does  not  currently  meet the TSE's requirements for a reverse stock split.
Consequently,  if  the  Company  elects  to proceed with the reverse stock split
without  meeting  the  applicable  TSE  requirements,  its common shares will be
delisted  from  the TSE immediately prior to the completion of the reverse stock
split. A delisting of the Company's common shares from the TSE may be materially
adverse  to  the  liquidity  of  the  Company's  shareholders,  particularly
shareholders  who reside in Canada.  If the Company's common shares are delisted
from  the TSE, Canadian residents would have to trade their shares on the Nasdaq
National  Market System (provided the Company meets all Nasdaq continued listing
requirements referenced above).  Quotations on the Nasdaq National Market System
are  in  U.S.  dollars.  Consequently  all  purchases and sales of the Company's
common shares would be in U.S. rather than Canadian currency.  See "Management's
Discussion and Analysis of Financial Condition and Results of Operations - Risks
and  Uncertainties  -  Stock  Market  Maintenance  Requirements".

HOLDERS

     As  of  December  31, 1998, there were approximately 1997 record holders of
the  Abacan's  Common  Stock.

DIVIDENDS

     Abacan  has  not previously paid any cash dividends on its Common Stock and
does  not  anticipate or contemplate paying dividends on the Common Stock in the
foreseeable  future.  It  is  the present intention of management to utilize all
available funds for the development of the Company's business.  In addition, the
Company may not pay any dividends on common equity unless and until all dividend
rights  on  outstanding preferred stock, if any,  have been satisfied.  The only
other  restrictions  that limit the ability to pay dividends on common equity or
that are likely to do so in the future, are those restrictions imposed by law or
by  certain  credit  agreements.

                                      -24-
<PAGE>
SALE  OF  NON-REGISTERED  SECURITIES

     In  connection with the restructuring of the Company's Secured Loan in June
1998,  the  Company  agreed to issue options to acquire 600,000 common shares to
the  Secured  Lender.  The exercise price of the options is Cdn $0.91 per common
share  expiring  June 30, 2000.  The common shares issuable upon exercise of the
options  were  exempt  from  registration  requirements of the Securities Act of
1933.

ITEM  6.     MANAGEMENT'S  DISCUSSION  AND  ANALYSIS  OF FINANCIAL CONDITION AND
             RESULTS  OF  OPERATIONS

     The following discussion should be read in conjunction with the information
contained  in the Company's audited consolidated financial statements, including
related  notes,  for  the  years  ended December 31, 1997 and 1998 and its other
public  filings.  References  herein  to  the  Company  include  Abacan Resource
Corporation  and  its  subsidiaries.

OVERVIEW  OF  1998

     The  Company  underwent several changes during 1998 including discontinuing
its  uneconomic  oil  and gas operations, significantly reducing its liabilities
and  ongoing  obligations, streamlining its administrative overhead expenses and
focusing  efforts to optimize the potential value of its Benin Basin oil and gas
concessions.

SALE  OF  IMA  FIELD

     A comprehensive reservoir analysis of the Ima Field completed in the spring
of  1998 suggested that the Ima Field was no longer economically producible.  On
June  30,  1998,  the  Company  reached a settlement agreement with its Nigerian
partner,  Amni  International  Petroleum  Development  Company Limited ("Amni"),
regarding  the  Company's interests in Nigerian Concession OML 112 (formerly OPL
469),  OPL  237 and the mobile offshore production unit ("MOPU") used to produce
the  Ima  Field.  Under  the  agreement, the Company relinquished all rights and
interests  in  Concession  Blocks OML 112 and OPL 237, including its interest in
the  "shallow"  zones  of  the Ima Field.  The Company retained an interest in a
deep  hydrocarbon  prospect  (the  "Deep  Ima Prospect") located beneath the Ima
Field.  As  consideration  for the cancellation of the Company's rights on these
blocks,  Amni  assumed  all  of  the  Company's  Ima  Field  related  claims and
liabilities  valued at approximately $47 million, extinguished approximately $20
million  of  claims it had against the Company and released any claims it had to
the  Ima  Field MOPU.  The shallow zones encompassed all of the Company's proved
developed  reserves  and  production.

SALE  OF  THE  MOBILE  OFFSHORE  PRODUCTION  UNIT

     Concurrent with its agreement with Amni, the Company exchanged its interest
in  the  topside  equipment  on the MOPU which was being used to produce the Ima
Field, to a major international service company in return for the extinguishment
of  all  of  the  major  service  company's  debt  valued at approximately $18.8
million.  Subject  to  a  sale  or  disposition  price of the MOPU being above a
pre-determined  threshold,  a portion of the proceeds of sale will be applied to
reduce  the  Company's  obligations  under  its  existing  senior  secured loan.

                                      -25-
<PAGE>
RESTRUCTURING  OF  SECURED  LOAN

     Concurrent  with  the above transactions, the Company also restructured its
existing senior secured loan (the "Secured Loan").  In June 1998, at the time of
the  restructuring,  the  Company  owed  its senior secured lender (the "Secured
Lender")  approximately  $30.7  million  under  the secured loan agreement.  The
restructuring  enabled  the  Company  to defer quarterly interest payments until
December  31, 1998 and extend the maturity of approximately $20.1 million of the
loan  until  June 30, 1999, with the remainder of $10.6 million due December 31,
1999.  Subsequent  to  December  31,  1998,  the  Company  received  written
confirmation  from  its Secured Lender that the first quarterly interest payment
due  December  31,  1998  had  been capitalized and that interest payments would
commence  on  March  31,  1999.  The  Secured  Lender  has  since  advised  that
notwithstanding  its  written extension, the first interest instalment continued
to  be  due  on  December  31,1998.  The  Company has not yet made this interest
payment  and  is currently negotiating with its Secured Lender regarding further
relief from this payment and from other near-term cash interest payments.  There
is  no  assurance that such negotiations will be successful and that the Company
will  be  able  to  successfully  defer  its  principal  and  interest  payment
obligations  until  a  future date.  Failure of the Company to pay the principal
and  interest  amounts  to  its  Secured Lender when due constitutes an event of
default  which could result in a loss of part or all of the Company's assets and
render  it  insolvent.

NEW  INITIATIVES

     Since  the  sale  of  the  Ima  Field, the Company has turned its attention
towards  its  significant  Benin  Basin acreage.  The Company is focusing on two
initiatives:  (1) the Benin Power Project, which is expected to be supplied fuel
from  the  Company's  Block  OML 113 and Benin Block 1 gas reserves; and (2) the
exploration of its sizeable Benin Basin Concessions (Block OML 113 and Block OPL
310  in  Nigeria  and  Block  4,  offshore  Benin).

Benin  Power  Project
---------------------

     On May 27, 1998, the Company entered into a Letter of Intent ("LOI") with a
subsidiary  of a major international natural gas and electrical power generating
company  and  the Government of Benin for the development of an electrical power
plant to be located in Cotonou, Benin.  Under the terms of the LOI, the required
natural gas feedstock for the project is expected to come from the Company's Aje
Field  natural gas resources identified on Nigerian Block OML 113 and from Block
1  in  Benin.  Negotiations  are  continuing towards the signing of a definitive
Power  Purchase  Agreement.

Exploration  of  Additional  Benin  Basin  Acreage
--------------------------------------------------

     The  Company  continues  to hold a significant position in the Benin Basin.
However, it does not currently have the financial resources necessary to explore
and  develop  its prospects and therefore will be reliant on third-party funding
sources  to  provide  the  necessary capital to do so.  The Company continues to
explore  various  options  with  respect  to  securing  a  partner.  Types  of
relationships  that  are  currently  being  contemplated  are  joint  venture
transactions,  farm-outs,  sales  of  interests  or  a  merger.  The  Company is
actively marketing the farm-out, sale or other disposition of its concessions to
industry  participants.

LIQUIDITY,  OPERATING  AND  CAPITAL  REQUIREMENTS  AND  FUNDING  ALTERNATIVES

                                      -26-
<PAGE>
     The  Company  has  a  serious  liquidity  problem that casts doubt upon the
ability  of the Company to continue operations in the foreseeable future.  As of
December  31,  1998, the Company had cash on hand of approximately $3.3 million,
current  debt  of approximately $30.7 million, accounts payable of approximately
$9.7  million and royalties payable of approximately $5.4 million.  The decrease
in the Company's long term debt and working capital deficiency from December 31,
1997  to  December  31,  1998  is due principally to the Ima Field restructuring
described  above.  As  a  consequence of the sale of its producing properties in
June  1998,  the  Company  does  not  currently have revenues or cash flow.  The
Company  does  not  anticipate  generating  revenues  or  cash  flow  until  the
completion  of  the  Benin  Basin  electrical  generation project or the sale or
farm-out  of  part  or  all of its existing properties.  The Company has limited
cash  reserves  and,  despite  a  significant reduction in operational costs, is
continuing  to  incur general, administrative and other related expenses.  Based
upon  current  expenditure  levels, the cash reserves of the Company will not be
sufficient  to  sustain  the  operations of the Company at current levels.  That
being  the  case,  the  Company's  ability  to  continue  as  a going concern is
dependent  on  the  following:

1.     The  development  of  the natural gas resources in Benin Basin Concession
Blocks  OML 113 and OPL 310 including the development of a commercial market for
the  natural  gas  produced  in  this  area;

2.     Obtaining  financing in the form of equity, debt or a combination thereof
in  order  to continue the development of the natural gas resources in the above
referenced  concession  blocks;

3.     Negotiating a joint venture for the continued exploration and development
of  the  West  African  acreage  position;

4.     Continuing  to  finance general and administrative expenses from existing
cash  or financing in the form of equity, debt or combination thereof until such
time  as  the  above  negotiations  and  financing  are  complete;

5.     Negotiations  with  certain  suppliers  to settle current liabilities and
forbearance  of  the  Company's  secured  and  unsecured  creditors;

     The  Company  has  received  an  indication  from a major shareholder that,
subject  to  the  fulfillment  of  certain conditions, additional funding may be
available  to  the  Company.  However,  there  is no assurance any such funding,
joint  venture  transactions  or  asset  sales will be available to the Company.

SENIOR  SECURED  LOAN

     A  Secured  Loan  was  initially  advanced  to  the  Company in August 1997
pursuant  to  a  Crude  Oil Prepayment Agreement between the Company and a major
international oil marketing company.  The proceeds of the Secured Loan were used
at  that  time to repay outstanding project financing incurred by the Company in
constructing the MOPU located on the Ima Field and for Ima Field exploration and
development  costs.  The $30.7 million Secured Loan was restructured on June 30,
1998.  As  restructured,  repayment of $20.1 million was deferred until June 30,
1999  with  the  balance  of  $10.6  million due on December 31, 1999.  Interest
payments  were  to  commence  quarterly  on  December  31,  1998.  Subsequent to
December  31,  1998,  the Company received written confirmation from the Secured
Lender  that the first quarterly interest payment due December 31, 1998 had been
capitalized  and  that  interest payments would commence on March 31, 1999.  The
Secured Lender has since advised that notwithstanding its written extension, the
first  interest instalment continued to be due on December 31,1998.  The Company
has  not  yet  made  this interest payment and is currently negotiating with the
Secured  Lender regarding relief from this payment and from other near-term cash
interest  payments.

                                      -27-
<PAGE>
ACCOUNTS  PAYABLE

     As  at  December  31,  1998,  the Company had approximately $9.7 million in
unsecured  trade debt primarily related to its Aje Field exploration activities.
Two  creditors  hold approximately $8.0 million of this debt, with the remainder
held  by  numerous  other  entities.  The  Company  continues  to  work to reach
settlement arrangements with its creditors.  In addition to the trade creditors,
the  Company  continues to have a contingent liability with respect to the debts
assumed by Amni under the Ima Field restructuring.  In consideration of the sale
of  the  Ima  Field,  Amni  agreed to assume all of the Company's trade payables
specifically  related  to  the  development of the field and has indemnified the
Company  in  respect of such obligations.  The Company understands that Amni has
settled  a majority of the claims of the large creditors.  However, there can be
no assurance that the remaining creditors will not seek redress from the Company
should  Amni be unable to pay or otherwise settle their claims.  Until the Benin
Basin  initiatives  begin  to  generate  cash  flow  to the Company, the Company
anticipates  it  will  not  be  in a position to settle any remaining creditor's
claims.

ROYALTIES  PAYABLE

     As  at  December  31,  1998,  royalties  payable included an amount of $1.0
million  owed  to  Abacan International Resource Management Inc. ("Airmi"), $1.4
million  to Yinka Folawiyo Petroleum Company Limited ("YFP") and $2.9 million to
several  other  unrelated  companies.  All  of  the  royalties relate to the Ima
Field.  AIRMI  is  a  company wholly owned by Wade G. Cherwayko, a former senior
executive  officer and director of the Company.  YFP is substantially controlled
by the father of Mr. Tunde Folawiyo, a director of the Company.  Mr. Folawiyo is
also an executive officer of YFP.  Until such time as the Company generates cash
flow,  it  will  be  unable  to make cash settlements of its outstanding royalty
obligations.

FUTURE  WORK  COMMITMENTS

     The  Company  has  fulfilled  its  minimum  work  obligations in respect of
Nigerian  Block OML 113.  However, significant additional expenditures will have
to  be incurred in order to produce the resources contained in the Aje Field and
elsewhere  in  OML  113  and  to  establish  a  market for such resources.  Most
notably, the Company will have to secure a suitable offshore production facility
as  well  as  construct  a  pipeline  to  an electrical generation project to be
located  on-shore  Benin.  An  electrical  generation  project, which is not yet
constructed,  will  have  to  be  completed  and  tied  into  the  West  African
electricity grid in order for there to be a market for the Company's natural gas
resources.  The  Company  believes  that  it will require an industry partner to
fund  the commercial development of its resources.  The Company has a commitment
to  YFP  to  pay  $5  million  to  be  paid  out  of net cash flow out of future
production  of  Block  OML  113.

     Under  the  terms  of  its  Block  OPL 310 joint venture agreement with its
Nigerian partner, Optimum Petroleum Development Company ("Optimum"), the Company
is  obligated to complete a minimum work program consisting of three wells and a
seismic program.  The obligation of the Company to initiate expenditures towards
the  minimum  work  program  commences  after  receipt  of applicable government
approval  for  the joint venture agreement between the Company and Optimum.  The
oil  prospecting  licence  for  OPL  310  expired in February 1997, however, the
Nigerian Department of Petroleum Resources confirmed shortly after the expiry of
the OPL to Optimum that the OPL remains in good standing.  Subsequently, nothing
has  been  received  by  the Company, or to the Company's knowledge, by Optimum,
that  would indicate that the Nigerian authorities do not consider OPL 310 to be
valid  and  in  good  standing.

                                      -28-
<PAGE>
     Optimum  has  not  yet  secured  an  extension or renewal of the OPL or the
requisite  joint  venture  agreement  approval  from  the  Nigerian  Ministry of
Petroleum  Resources.  Despite  this,  Optimum  has  advised the Company that it
wishes  the  Company  to  proceed  on the minimum work program in advance of the
required  extension  or  renewal and receipt of requisite government approval to
the  joint  venture  agreement.

     In  the  Republic of Benin, the work commitments of the Company are set out
in  separate  Production Sharing Contracts for Block 1 and Block 4.  In the case
of  Block  1, the minimum work requirements include the drilling of one well and
the  completion of a seismic program by the end of February 1999.  The requisite
work  commitment  was  not satisfied by this deadline.  The Company is currently
negotiating  an  extension  with  the  Benin  Ministry and risks the loss of its
interest in Block 1 should an extension not be secured.  In the case of Block 4,
the minimum work requirements include the drilling of one well and completion of
a  seismic  program by February 2002.  The Company believes that it will require
an  industry partner to fund the requisite work commitments of Block 4 and Block
1.

CAPITALIZED  COSTS  OF  PETROLEUM  AND  NATURAL  GAS  PROPERTIES  AND  EQUIPMENT

     Through  to  December  31,  1998  the  Company  had  expended  a  total  of
approximately  $392  million  on the acquisition, exploration and development of
its  concession  blocks, including approximately $296 million in the Niger Delta
and  $96 million in the Benin Basin.  This compares to the total expenditures of
$376  million  as  at  December 31, 1997.  The capital spending in 1998 totaling
approximately  $15  million  included  the  acquisition of additional concession
interests in the Benin Basin at a cost of $2.0 million and the drilling, testing
and  placing  on  production  of  the  Ima  #9  and  Ima  #10 wells at a cost of
approximately  $13  million.

     In  1997,  the Company recorded a provision for the decline in value of the
Niger  Delta  properties  of  approximately $206 million.  With the 1998 sale of
Blocks  OML  112  and OPL 237, the Company disposed of its remaining interest in
the Niger Delta properties and equipment, including the hydrocarbon reserves and
related  production  equipment.  This disposition resulted in a reduction of the
petroleum  and  natural  gas  property  costs  by  approximately  $57  million.

OIL  AND  GAS  RESERVES

     With  the sale of its interest in OPL 237 and OML 112, the Company sold all
of  its  proved  producing  and  developed  hydrocarbon  reserves.  The  Company
conducted  a  2-D seismic program on Nigerian Blocks OML 113 and OPL 310 in 1994
and  1996.  Following  the evaluation or the data from this program, the Company
drilled  two  wells  on Block OML 113 that tested cumulative flow rates of 5,500
and  8,800  barrels  per day of oil and condensate, with associated natural gas.
Based  on  the  results  of  the Company's first two wells, the Company believes
that, in addition to oil and condensate, the Benin Basin has significant natural
gas.  Based  on  these  results,  the  Company also believes there is sufficient
natural gas resources in the Aje Field to supply the electrical generation power
project  in  Benin.

RESULTS  OF  OPERATIONS

     The  Company  discontinued its hydrocarbon production operations due to the
sale of the Ima Field in June 1998.  The tables below illustrate the significant
components  of  its  1997  and  1998 production operations up until the point of
sale.

                                      -29-
<PAGE>
Production  and  Sales
----------------------

     The Company recognized petroleum revenues for its oil and condensate at the
time  of production at the then prevailing market rate for the Company's oil and
condensate.  The  Company  produced oil and condensate and stored its production
in  a  floating  storage  tanker  ("FSO")  until  sufficient  quantities  were
inventoried for transfer to a crude tanker.  Any difference between the value of
crude oil and condensate recorded at production and the amount actually realized
from  the  sale  was  recorded  by  the  Company  as  income  in  the  period of
realization.

     The  following  table sets forth the average daily gross and net production
levels  (in  barrels)  for  the  periods  indicated.

<TABLE>
<CAPTION>
                Gross              Net       
              Production      Production(1)
           ----------------  ----------------
            1997     1998     1997     1998
           -------  -------  -------  -------
<S>        <C>      <C>      <C>      <C>
January    10, 141  18, 207   5, 578  10, 014
February   12, 842  15, 358   7, 068   8, 447
March       16,880  14, 262   9, 284   7, 844
April      23, 995  14, 799  13, 197   8, 139
May        21, 483  13, 202  11, 816   7, 261
June       18, 447  11, 963  10, 146   6, 580
July       12, 668  N/A       6, 967  N/A
August     18, 896  N/A      10, 393  N/A
September  20, 079  N/A      11, 043  N/A
October    16, 782  N/A       9, 230  N/A
November   20, 664  N/A      11, 365  N/A
December    9, 376  N/A       5, 157  N/A
<FN>
----------------
(1)  Net figures reflect the Company's pre-payout participation before royalties
</TABLE>

     The  following  table  sets  forth  information pertaining to the quarterly
production  and  liftings  on a gross and net basis as well as quarterly revenue
and  operating  cost  information  for  the Company prior to the sale of the Ima
Field  on  June  30,  1998.

<TABLE>
<CAPTION>
                         Three Months   Three Months
                             Ended          Ended
                           March 31        June 30
                         -------------  -------------
<S>                      <C>            <C>
Gross Production (bbls)      1,436,583        686,461
Net Production (bbls)          790,121        377,554

Gross Sales (bbls)           1,528,753        592,561
Net Sales (bbls)               840,814        325,909

Average Price            $       12.75  $       13.57
Net Revenue              $       9,986  $       4,272
Operating Costs          $       8,041  $       9,390
</TABLE>

                                      -30-
<PAGE>
Operating  Costs
----------------

     The  majority  of the Company's operating costs relates to the operation of
the  MOPU and FSO located on the Ima Field.  Such costs were fixed on a per diem
basis.  Following  the  sale  of  the  Ima  Field,  the  Company ceased to incur
operating  costs.

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

     General  and  Administrative expenses for the year ending December 31, 1998
were  approximately  $4.6 million versus approximately $3.9 million for the year
ending  December  31,  1997.  Since  the sale of the Ima Field in June 1998, the
Company  has  made  significant  strides towards reducing its overhead expenses.
The  Company  has  closed  or  is  in  the process of closing three offices, has
reduced  staff  levels  and  has  out-sourced  several  of  its  administrative
functions.  Offsetting  these changes, however, has been a significant amount of
additional legal and accounting expenses incurred related to the sale of the Ima
Field  and  the  Company's ongoing restructuring process.  Critical to continued
existence  of the Company is the continued reduction and re-alignment of general
and  administrative  expenses  to better reflect the Company's current situation
and  future  prospects.  The  Company  currently has no revenue or cash flow and
limited  cash  reserves.  Accordingly,  the  Company  will  require  additional
financing  in the near term in order to sustain its current level of operations.

Interest  and  Other  Financial  Expense
----------------------------------------

     For  the  year ending December 31, 1998, the Company incurred approximately
$3.0  million  in  interest  and other financial expenses versus $4.3 million in
1997.  These  charges  are primarily related to the Secured Lender both prior to
and  following  its  restructuring.  The  December  31,  1998 quarterly interest
payment  was  not  made.  Subsequent to December 31, 1998,  the Company received
written  confirmation  from the Secured Lender that the first quarterly interest
payment  had been capitalized and that interest payments would commence on March
31,  1999. The Secured Lender has since advised that notwithstanding its written
extension,  the  first  interest  instalment continued to be due on December 31,
1998.  The  Company  has  not  yet  made  this interest payment and is currently
negotiating  with the Secured Lender regarding relief from this payment and from
other  near-term  cash  interest  payments.

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

     For  the  year  ended December 31, 1998, the Company incurred approximately
$4.2  million  in  depletion, depreciation and amortization versus approximately
$28.2  million  in 1997.  The decline in 1998 expense is primarily attributed to
the  1997 write down in costs associated with the Ima Field and its sale in June
1998.

1997  Provision  for Decline in Value of Petroleum Properties in the Niger Delta
--------------------------------------------------------------------------------

     As a result of the application of the ceiling test and other considerations
related  to  the  Company's intention to sell its production assets, the Company
recorded  a  provision  for  decline  in  the value of its Niger Delta petroleum
properties  in  1997  of  approximately  $206  million.  Application  of  this
write-down  resulted  in  a  remaining  Niger  Delta  petroleum  cost balance of
approximately  $47  million  at  December  31,  1997.

                                      -31-
<PAGE>
1998  Gain  on  Sale  of  Assets
--------------------------------

     At  the  time  of  the  sale  of  the  Ima Field and the related production
facility transaction with a major international service company, the Niger Delta
petroleum properties remaining cost balance was approximately $57 million.  As a
result  of  the  above transactions, approximately $86 million in debt and other
liabilities  were  either  extinguished  or  assumed  by  other  entities.  This
resulted  in  the  Company  realizing  a  book  gain  on  the  sale of assets of
approximately  $29 million.  Though these transactions resulted in a significant
book  gain  for  the Company, no cash was received by the Company as a result of
any  of  the  transactions.

OUTLOOK

     The  continuing  corporate financial restructure is a critical priority and
the  Company  is exploring opportunities to raise additional capital, reduce the
level  of total liabilities and reduce overhead costs.  In addition, the Company
is  exploring  various  options  that  allow  for  external  funding for further
development  of  its  remaining  Benin  Basin  concession  blocks,  including  a
farm-out,  sale  of  interests or merger.  Should the Company be unable to raise
additional  capital,  either  directly  or  through  a  combination of a sale or
farm-out  of  assets,  or  a  business combination, it will be required to cease
operations.

YEAR  2000  ISSUE

     The  Year  2000 problem arises with the change in century and the potential
inability  of  information  systems  to  correctly  "rollover"  dates to the new
century.  To save on computer storage space, many systems were programmed with a
two-digit century (ie. December 31, 1999 would appear as 12/31/99) assuming that
all  years  would be part of the 20th century.  On January 1, 2000, systems with
this  programming  will  default  to  01/01/1900  instead  of  01/01/2000,  and
calculations  using  or  reporting  the date will not be correct and errors will
arise.  To  prevent  this from occurring, information systems need to be updated
to  ensure  they  recognize  the  Year  2000.

     The  Company  began  its  Year  2000  strategy  by  compiling a list of all
computerized  equipment  and  making  a  determination  of  how,  if at all, the
software  will  be  affected  by  the  Year  2000 problem.  All of the Company's
hardware  and  software were recently acquired and are Year 2000 compliant.  All
of  the  data  related to the Company's royalty fees, consulting fees, and other
payment  obligations  related  to  its  properties  are  stored  on its computer
systems.  The  Company has and will continue to back up all of its financial and
business  records,  property data and engineering data to ensure that no loss of
information  will  occur in the event that its systems are affected by Year 2000
problems.

     The  Company  also  requested  all of its principal consultants, engineers,
advisors  and  joint  venture  partners  to  conduct  similar  reviews  of their
computerized equipment, software and operating systems to determine the risk, if
any,  that  the  Year  2000  problem  poses  to the Company.  The Company has no
knowledge  of any material risks that will result from the Year 2000 problem and
does not believe its business will be impacted as a result of Year 2000 problems
related  to  such  third  parties.

     The  Company  does  not  anticipate  it  will  commence  drilling  or other
exploration  activities  that  will  be  affected by the Year 2000 problem.  The
Company  intends  to engage only established contractors, consultants, engineers
and  advisors  for  work  related  to  its  properties and intends to source its
exploration  and  development equipment and information systems from established
vendors who have designed Year 2000 compliant systems.  The Company also intends
to  locate  alternative  sources  for  exploration and development equipment and
information  systems  in  the  event  it  primary  suppliers  cannot  meet  the
requirements  of  the  Company  in  a  timely  manner.


                                      -32-
<PAGE>
     In  the event the Year 2000 problem affects the exploration and development
equipment  and  operating  systems  of  the  Company's  third party consultants,
engineers,  advisors  and  joint  venture  partners, the cost of exploration and
development  of the Company's properties may increase and the Company's business
and  results of operations may be adversely affected.  There can be no assurance
that  the  Year  2000  problem  will  not  cause  delay  in  the exploration and
development  of  the  Company's  properties  or that the Company will be able to
resolve  a  Year 2000 problem on acceptable terms.  Any delay in exploration and
development  of  the Company's properties will have a material adverse effect on
the  Company's  business  and  results  of  operations.

     The  Company  intends to monitor the Year 2000 problem as it relates to the
oil  and  gas industry and the Company's properties and to implement contingency
plans  as  required.  Management does not anticipate incurring significant costs
in  this  regard.

SUBSEQUENT  EVENTS

Announcement  of  Listing  Status
---------------------------------

     On  January  26,  1999, Abacan announced that it had been advised by NASDAQ
that  the trading prices for Abacan's Common Stock was below the $1.00 per share
minimum  established by the NASDAQ National Market for continued listing on that
market.  Subject to a further extension, unless the minimum trading price is met
(during  a  ten day period) beginning March 22, 1999, Abacan's Common Stock will
be  delisted  from  the  NASDAQ  National  Market.  Abacan  expects to meet this
requirement  by implementing a reverse stock split that will be submitted to its
shareholders  at  Abacan's  Annual  Meeting  of Shareholders.  Any reverse stock
split  will  also  be subject to approval of the Toronto Stock Exchange.  Abacan
has  been  advised  that  it does not meet the applicable requirements for stock
consolidation  approval  by The Toronto Stock Exchange.  If the requirements are
not  met  and  Abacan  proceeds with the reverse stock split, its shares will be
delisted  from  The  Toronto  Stock  Exchange.

Insurance  claim  on  Ima  #9  /  Major  Creditor  Settlements
--------------------------------------------------------------

     During February 1999, settlement agreements were reached with a majority of
the  large  creditor claims assumed by Amni in the Ima Field restructuring.  The
proceeds  used  to  settle  these claims were derived by a lump sum cash payment
Amni  and  the  Company  negotiated  with respect to the Ima #9 well underground
blowout  claim.

RISKS  AND  UNCERTAINTIES

Liquidity
---------

     The  Company  has  a  serious  liquidity  problem that casts doubt upon the
ability  of  the Company to continue operations in the foreseeable future. As of
December  31,  1998, the Company had cash on hand of approximately $3.3 million,
current  debt  of approximately $30.7 million, accounts payable of approximately
$9.7  million  and royalties payable of approximately $5.4 million. The decrease
in the Company's long term debt and working capital deficiency from December 31,
1997  to  December  31,  1998  is due principally to the Ima Field restructuring
described  above.

                                      -33-
<PAGE>
     As a consequence of the disposition of its Participating Interest in Blocks
OML  112  and  OPL  237  in  June  1998, the Company does not currently have any
revenues  or  cash flow.  The Company does not anticipate generating revenues or
cash  flow until the completion of the Benin Basin electrical generation project
or  the  sale or farm-out of part or all of its existing properties. The Company
has  limited  cash  reserves and, despite a significant reduction in operational
costs,  is  continuing  to  incur  general,  administrative  and  other  related
expenses.  The  Company's ability to continue as a going concern is dependent on
the  following:

1.     The  development  of  the natural gas resources in Benin Basin Concession
Blocks  OML 113 and OPL 310 including the development of a commercial market for
the  natural  gas  produced  in  this  area;

2.     Obtaining  financing in the form of equity, debt or a combination thereof
in  order  to continue the development of the natural gas resources in the above
referenced  concession  blocks;

3.     Negotiating a joint venture for the continued exploration and development
of  the  West  African  acreage  position;

4.     Continuing  to  finance general and administrative expenses from existing
cash  or financing in the form of equity, debt or combination thereof until such
time  as  the  above  negotiations  and  financing  are  complete;

5.     Negotiations  with  certain  suppliers  to settle current liabilities and
forbearance  of  the  Company's  secured  and  unsecured  creditors;

     There  is no assurance that the Company will be able to achieve part of all
of  the  elements  required to continue operations prior to fully exhausting its
current  cash reserves.  Should the Company not be able to secure new sources of
funding  in  the  very near term, it will be required to wind up its affairs and
cease  operations.

     The  Company  will  not  be  able to meet its payment obligations under the
Secured  Loan  or the contractual commitments on its existing properties without
additional  capital.  There  is  no  assurance  that  additional capital will be
available or, if it is available, that the Company would not have to sell all or
substantially  all  of  its properties or assets to access such capital.  Should
the  Company  be  unable to access additional capital through capital markets or
otherwise,  or  should the Company be unable to further restructure its existing
secured  loan  and extend the time pursuant to which it must commence operations
in  its  existing  properties,  the  Company  may  lose all of its Participating
Interests  in  some or all of its remaining properties which would be materially
adverse  to  the  financial  condition  of  the  Company.

Stock  Market  Maintenance  Requirements
----------------------------------------

     The  Company  has  received  notice  from  The  Nasdaq  Stock  Market  Inc.
("Nasdaq")  that  its common shares are not in compliance with the $1.00 minimum
bid  price requirement for ongoing listing on the Nasdaq National Market System.
In  order  to endeavor to achieve compliance, the Company's shareholders will be
asked  to consider and approve at a Shareholders Meeting scheduled for March 29,
1999,  a  resolution  authorizing  the  directors,  in their discretion, to give
effect to a reverse stock split of the Company's common stock.  In the event the
Company's  common stock does not satisfy the $1.00 minimum bid price requirement
(which  is  the  only requirement it does not currently comply with) by April 7,
1999,  the  Company's  common  shares  will  be de-listed from Nasdaq's National
Market  System.  The  Company must also meet all other Nasdaq requirements on an
on-going  basis.  The  Company's  common  shares  are not currently eligible for
listing  on  the  Nasdaq  Smallcap  Market.

                                      -34-
<PAGE>
     There  is  no  assurance that shareholders' approval will be obtained for a
reverse-stock  split  or  if  obtained,  that  the directors will proceed with a
reverse  stock  split.  There  is  no assurance that if a reverse stock split is
completed  that  the minimum bid price will rise above or be sustained above the
$1.00  minimum  bid  requirement  or that the Company's common stock will not be
delisted  for some other reason.  A delisting of the Company's common stock from
the Nasdaq National Market System will be materially adverse to the liquidity of
the  Company's  common  stock.

     The  Company has received notification from The Toronto Stock Exchange that
it  does  not  currently  meet the TSE's requirements for a reverse stock split.
Consequently,  if  the  Company  elects  to proceed with the reverse stock split
without  meeting  the  applicable  TSE  requirements,  its common shares will be
delisted  from  the TSE immediately prior to the completion of the reverse stock
split. A delisting of the Company's common shares from the TSE may be materially
adverse  to  the  liquidity  of  the  Company's  shareholders,  particularly
shareholders  who reside in Canada.  If the Company's common shares are delisted
from  the TSE, Canadian residents would have to trade their shares on the Nasdaq
National  Market System (provided the Company meets all Nasdaq continued listing
requirements referenced above).  Quotations on the Nasdaq National Market System
are  in  U.S.  dollars.  Consequently  all  purchases and sales of the Company's
common  shares  would  be  in  U.S.  rather  than  Canadian  currency.

     If  the  Company proceeds with the reverse stock split and thereafter fails
to  meet  Nasdaq's  continued listing requirements, it risks the loss of listing
status  on  both  of  its  current  stock  markets.

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

     All  of  the  Company's operations are currently being conducted in Nigeria
and  Benin.  International  operations  are  subject  to political, economic and
other  uncertainties,  including,  among others, risk of war, revolution, border
disputes,  expropriation,  renegotiation  or modification of existing contracts,
import,  export  and  transportation regulations and tariffs, taxation policies,
including  royalty  and  tax  increases  and  retroactive  tax  claims, exchange
controls,  limits  on  allowable  levels  of  production, currency fluctuations,
labour  disputes  and  other  uncertainties  arising  out  of foreign government
sovereignty  over  the  Company's  international operations.  Certain regions of
Africa  have  a history of political and economic instability.  Such instability
could  result  in  new  governments  or  the adoption of new policies that might
assume  a  substantially more hostile attitude toward foreign investment.  In an
extreme  case,  such a change could result in voiding pre-existing contracts and
concession  agreements  and/or  expropriation  of  foreign-owed  assets  without
compensation.  The  Company's  international  operations  may  also be adversely
affected  by laws and policies of the United States and Canada affecting foreign
trade,  taxation and investment.  Furthermore, in the event of a dispute arising
from  international  operations,  the  Company  may  be subject to the exclusive
jurisdiction  of  foreign  courts or may not be successful in subjecting foreign
persons  to  the  jurisdiction  of  courts  in  Canada.

     Nigeria  is  a developing third world national that has experienced periods
of  civil  unrest  and  political  and  economic instability.  In June 1998, the
country  experienced  a significant political change with the death of Col. Sani
Abacha  and the appointment of Col. Abdulsalem Abubakar as President of Nigeria.
Under  Col.  Abubakar,  political  and  social change has been initiated.  These
changes  included  the  release of a number of prominent political prisoners and
the  holding  of  democratic  elections in early March 1999.  As a result of the
elections,  Olusegan  Obasanjo  was  elected  to become the new President of the
country.  Mr. Obasajo's government is scheduled to assume power on May 29, 1999.

                                      -35-
<PAGE>
     Despite  these  recent  events,  Nigeria's  membership  in  the  British
Commonwealth  of  Nations remains suspended.  Pending the appointment of the new
government,  the  imposition  of  trade  sanctions  continues  to  be  under
consideration  by  a  number  of  western countries including Canada, the United
States  and  the  United  Kingdom.  The implementation of trade sanctions may be
dependent,  in large part, on the outcome of future democratic elections and the
appointment  of  a  democratically  elected  government.  If trade sanctions are
imposed,  and  if  they  significantly  reduce  the amount of oil purchased from
Nigeria or impede the ability of producers in Nigeria to market their production
or  receive  market  prices  for such production, such sanctions could adversely
affect  Nigeria's oil producers and the country's overall economy.  There can be
no assurance that actions taken by the international community, future political
unrest  or  actions  by  companies  doing  business  in  Nigeria will not have a
materially  adverse  effect  on  Nigeria and in turn, on the Company's financial
condition  or  future  results  of  operations.  The  Company  has no ability to
control  the  factors  that  may  lead  to  such  events.

     Benin  is  a  developing third world nation that has experienced periods of
civil  unrest  and  political  and economic instability.  Future civil unrest or
political  and economic instability is beyond the control of the Company and may
adversely  affect  any  future  operations  of  the Company in the country.  The
ability  of the company to successfully operate in Benin will, in large part, be
dependent  upon its maintaining good relations with the Benin government and the
Benin  Oil  Ministry.  See  "-  Benin  Regulation".

Nigerian  Regulation
--------------------

     All  phases  of  oil exploration, development and production in Nigeria are
regulated  to  varying  degrees  by  the Nigerian government, either directly or
through  the MPR and the DPR, under the provisions of the Petroleum Decree, 1969
and  under  various  policy  statements  issued  by  the Nigerian government and
administrative  practices  followed  by  the  DPR.  Such  government  regulation
includes  matters relating to restrictions on production, price controls, export
controls,  income taxes, expropriation of property, environmental protection and
rig  safety.  All  drilling and production programs and operations undertaken or
to  be  undertaken  by  the Company (including petroleum export permits) must be
approved  by the Nigerian government through the MPR or the DPR.  If the Company
is  unable  to  obtain  the  requisite approvals from the DPR or the MPR for its
ongoing  operations,  such  operations  could be suspended or delayed until such
approvals  are  granted.  In  addition,  the  Company  must, either directly, or
through  its Nigerian Partners, maintain satisfactory working relationships with
the  Nigerian  government,  the MPR and the DPR.  Any suspension or delay in the
Company's  operations  or failure to maintain satisfactory working relationships
could  materially  and  adversely  affect  the financial condition or results of
operations  of  the  Company.

Dependence  Upon  the  Indigenous  Program

     All  of the Company's Participating Interests in Nigeria have been acquired
under  the  Indigenous  Program.  The Indigenous Program is not formally written
into  the  Petroleum Decree, 1969, or any other law of Nigeria but exists solely
pursuant  to an oral policy statement (the "1990 Policy") issued by the Nigerian
Government  in  1990.  Should  the  Company's  or  its  Nigerian  Partners'
interpretation  of  the  1990  Policy  prove  incorrect,  or should the Nigerian
Government  change  this  policy,  the  Company  and  its  Nigerian  Partners'
Participating  Interests,  business  and future results of operations in Nigeria
could  be  materially  and  adversely  affected.

     The  Company  relies  on  its  Nigerian  Partners  for  compliance with all
requirements of Nigerian law, the 1990 Policy and all dealings with the Nigerian
Government.  If  either  the  relationship  between the Company and its Nigerian
Partners  or  that  between  the  Company's  Nigerian  Partners and the Nigerian
Government  deteriorates  for  any  reason or if the Company's Nigerian Partners
cannot  meet  their  obligations  to  the Company or the Nigerian Government for
financial  or  other  reasons,  the Company's financial condition and results of
operations  may  be  adversely  affected.  Additionally,  the  Company  does not
control  its  Nigerian Partners and may be adversely affected by the detrimental
activities  of  any  of  its  Nigerian  Partners  or  the  principals  thereof.

                                      -36-
<PAGE>
Uncertainty  Regarding  Nigerian  Tax  and  Royalty  Arrangements

     The  Company  has  negotiated  tax/royalty  arrangements  with its Nigerian
Partners  on each of the Niger Delta concessions and the Benin Basin concessions
in  Nigeria.  These  tax/royalty  arrangements,  included  in  the joint venture
agreements between the Company and its Nigerian Partners, provide for a combined
tax/royalty  payment to the Nigerian Government equal to a maximum of 30% of the
gross  production  revenues,  both before and after Payout.  Notwithstanding the
tax/royalty  arrangements contained in the joint venture agreements, the Company
has  subsequently  learned  and  currently  believes that the tax/royalty regime
applicable  to  blocks  awarded  under  the  Indigenous  Program are the same as
applicable  to  the  tax/royalty  regime  applicable  generally  to  petroleum
production  in  Nigeria.  To  date,  the  Company has paid royalties of 18.5% of
production  from its Ima Field to the Nigerian government in accordance with the
existing  royalty  regime.  The  Company  has  not generated taxable profits and
consequently, no petroleum profits taxes have been or are expected to be paid to
the  Nigerian  Government.  Should  the Nigerian Government audit the operations
conducted  on  the  Ima  Field and disagree with the level of royalties or taxes
paid  by  the  Company, the Company may become liable for additional payments to
the  Nigerian  Government.

     There  is no assurance that the Nigerian Government will not alter or amend
the  existing  royalty  structure  or definition of taxable profits.  Any future
amendments  of  changes  in the interpretation of the current fiscal regime that
imposes  and  increased  royalty or tax rate upon the Company will be materially
adverse  to  the  Company's  business,  financial position and future results of
operations.

Assignment  of  Interests  Under  Joint  Venture  Agreements

     The  1990  Policy  prohibits  the assignment of an interest in a concession
block  without  MPR approval and also prohibits the assignment to the Company of
an  interest  in a concession that is greater than 40% of the Nigerian Partner's
interest.  The  Company's  Participating Interests in Nigerian concession blocks
OML  112  and  OPL  237  were,  prior  to  the reorganization of its oil and gas
operations,  governed  by  the  terms  of joint venture agreements that had been
approved  by  the  MPR.  As  a  consequence  of  the reorganization, a new joint
venture  agreement reflecting a reduced Participating Interest restricted to the
Deep  Ima  Prospect  was executed between the Company and Amni.  MPR approval of
the  new  joint  venture agreement and the revised Participating Interest of the
Company  has  not  yet  been  obtained.  Although  the  Company has no reason to
believe  that  the  applicable  MPR  approval will not be received in the normal
course,  there  is  no  assurance  the  MPR  will grant the requisite approvals.
Failure  to  obtain  MPR approval to the new joint venture agreement could bring
into question the level of the Participating Interest of the Company, if any, in
the  Deep  Ima Prospect, which in turn could have a materially adverse affect on
the  future  results  of  operations  of  the  Company.

     The  joint  venture  agreements  between  the Company and YFP in respect of
Block  OML  113  and  Optimum  in respect of OPL 310, allocate to the Company an
approximate  55%  beneficial  interest  in gross revenues prior to Payout and an
approximate 28% beneficial interest in gross revenues after Payout (before gross
overriding royalties or their equivalent payable by the Company to others).  YFP
is  a  company  substantially  controlled  by  the  father  of Tunde Folawiyo, a
director  of  the  Company.  Tunde Folawiyo is also an executive officer of YFP.
The  allocation  to  the  Company  of  55% of revenues before Payout could be an
assignment  that  exceeds the maximum allocation of revenues permitted under the
1990  Policy,  notwithstanding  that  the MPR has approved the allocation.  As a
result, the Company could have its entitlement to production revenues reduced or
its interests in the concessions blocks terminated, either of which would have a
materially  adverse  affect  on  the  financial  condition and future results of
operations  of  the  Company.

                                      -37-
<PAGE>
Governmental  Right  of  Participation

     Under  the  Petroleum Decree, 1969, the Nigerian Government is entitled, at
any  time,  to take a Participating Interest in any concession block in Nigeria.
Neither the Petroleum Decree, 1969 nor any subsequent correspondence between the
MPR  and  any of the Company's Nigerian Partners addresses either the payment to
the  Company or its Nigerian Partner of a proportionate share of future costs or
the  reimbursement  of  past  costs by the Nigerian Government.  If the Nigerian
Government  exercises  its right to participate in any of the Company's existing
concession  blocks, the Revenue Interest of the Company would be reduced and the
financial  position and results of operations of the Company could be materially
affected.  Under  the  terms of its joint venture agreements for the Benin Basin
concessions,  should  the Nigerian government choose to participate, the Company
does  not  believe  its  Revenue  Interest  would  be reduced to less than a 20%
post-Payout  Revenue  Interest,  after  deducting  existing gross overriding and
other  royalty  interests.  While the Company is not aware of any efforts on the
part of the Nigerian Government to participate directly in any concession blocks
awarded under the Indigenous Program, the government has, in all cases, reserved
the  right  to  do  so.

Nigerian  Title  Issues
-----------------------

Expiration  or  Cancellation  of  Nigerian  Oil  Prospecting  Licenses

     The  Company's  primary  Nigerian assets are its Participating Interests in
oil  and  gas concession blocks OML 113 and OPL 310.  The Participating Interest
of  the  Company  is  held pursuant to Joint Venture Agreements in place for the
applicable  concession  blocks.  Such Agreements operate for the life of the OPL
and  any resulting OML.  In the case of Block OML 113, the Company believes that
the  economic  life  of any reserves contained in such blocks will expire before
the expiration of the 20 year term of the OML.  In the event that the productive
life  of  reserves  exceeds  the  current  term of the OML, a successful renewal
application  will  have to be made to the MPR by YFP, failing which ownership of
the  block  reverts  to  the  Nigerian government.  The Joint Venture Agreements
between  the  Company  and its Nigerian Partners impose certain obligations upon
the  Company, failing which the Company could forfeit its interest as prescribed
by the Joint Venture Agreement.  Failure of the Company to meet such obligations
(which  includes  an  obligation  that  the  Company at all times be and remains
solvent)  could  allow  the  Nigerian  Partner to terminate the applicable Joint
Venture  Agreement  and  extinguish the Participating Interest of the Company in
the  affected  concession  block.  In  view  of  the Company's current financial
circumstances,  there  is no assurance that one or more of its Nigerian Partners
will  not  endeavour  to terminate its Joint Venture Agreement with the Company.

     The  formal  five  year  term  of the OPL 310 expired in February 1997.  In
February  1997,  subsequently to the expiry date, the Company's Nigerian Partner
received  written  confirmation  from the MPR that OPL 310 was in good standing.
The  Petroleum Decree, 1969 does not contemplate or authorize the term of an OPL
(inclusive  of  extensions)  extending  beyond five years.  The Company believes
that  the written confirmation issued on behalf of the MPR confirming OPL 310 to
be  in  good  standing  reflects  an administrative practice that supersedes the
provisions of the Petroleum Decree, 1969 respecting the term of the OPL.  Should
the  Company's  interpretation  of the DPR written confirmation be incorrect, or
should  neither  the  DPR  nor  the  MPR  have  the jurisdiction to implement an
administrative  practice  inconsistent  with  the terms of the Petroleum Decree,
1969,  or should the DPR or MPR change their position respecting the standing of
Block  OPL  310,  the  Company  and  its Nigerian Partner may be prohibited from
continuing  and  pursuing  future  operations  on Concession Block OPL 310.  The
Company  also  could  lose  its entire investment and  Participating Interest in
Concession  Block  OPL  310  without  compensation.

                                      -38-
<PAGE>
Benin  Regulation
-----------------

     Responsibility  for the regulation and control of the petroleum industry in
Benin  rests  with  the  national  government  of  Benin  pursuant  to the Benin
Petroleum  Code.  Specific  regulation  of  petroleum  exploration, exploitation
title,  transportation,  marketing  and production taxation rests with the Benin
Oil  Ministry.  The  regulation of general business operations, income taxes and
import/export licences and levies rests with a number of other ministries within
the  national government of Benin.  All drilling, production and other petroleum
operations  in  Benin require the prior approval of the Benin Oil Ministry.  The
import  and  export  of  natural  gas and electricity and the construction of an
electrical  generation  power  plant will also require the prior approval of the
Benin Oil Ministry and a number of other ministries within the Benin Government.

     In  order  to  produce  and/or  import natural gas, construct an electrical
generation power plant and generate, transmit, sell and export electrical power,
the  Company and any future partners will require the prior approval of a number
of  Government  Ministries  and  government  and privately owned companies.  The
Company  and  its  partners  will  also  require  the  approval of other foreign
governments,  ministries  and departments if it exports power generated from the
electrical  generation power plant outside of Benin.  There is no assurance that
the  Company or its partners will be able to obtain all of the consents, permits
or  authorizations necessary to import natural gas from the Aje Field or produce
natural  gas  from  Block  1,  construct an electrical generation power plant or
produce,  transmit, sell or export electrical energy.  Failure of the Company to
obtain  all  necessary approvals or permits will materially and adversely affect
its  financial  condition and future results of operations.  See " - Liquidity".

Benin  Title  Issues
--------------------

     The  Company's  current  Participating Interests in Benin exist pursuant to
two  separate  production  sharing contracts between subsidiaries of the Company
and the Nigerian Government.  The PSC's set out certain obligations that must be
fulfilled  by  the  Company.  Failure  to  fulfill  the  requisite  obligations
constitutes  an event of default and subject the affected PSC to cancellation by
the  government  without  compensation.

     Included  as  part  of  the  Company's obligations are certain minimum work
commitments.  In  the case of Block 1, the Company is required to drill one well
and  complete a seismic program by the end of February 1999.  The requisite work
commitment  for  Block  1was  not  satisfied by the February 1999 deadline.  The
Company  is  currently  negotiating  an  extension  with the Benin Oil Ministry.
There  is  no  assurance  that  the  Company  will  secure  an extension that is
satisfactory  to it, or at all.  If the Company fails to secure an extension, it
could  lose  its  entire Participating Interest in Block 1 without compensation.
In the case of Block 4, the Company is required to drill one well and complete a
seismic  program by February 2002. The Company has completed the seismic program
requirement.  The  Company  currently does not and, without securing a financial
partner  or  other  form  of financing, will not have the financial resources to
drill  the  requisite  well on Block 4 by February 2002.  Failure to comply with
the minimum work requirements could result in the cancellation or termination of
the  Company's Participating Interest in Block 4.  The loss of its Participating
Interest in Benin Blocks 1 and 4 would have a material and adverse affect on the
Company.

Labour  Relations  and  Interruptions
-------------------------------------

     Nigerian  and  Benin  laws  require  that foreign companies involved in the
petroleum  industry hire and train indigenous personnel in petroleum operations.
Nigerian  oil workers are organized into a number of labour unions.  In the fall
of 1994, these labour unions called a general strike to protest against a number
of  the political changes that had occurred within Nigeria.  This general strike
ultimately  affected  the  Company's  oil  and  gas  operations  by delaying its
drilling  program.  There  is no assurance that there will not be strikes in the
future in countries where the Company operates.  Any future labour interruptions
could  adversely  affect  the  Company's  ongoing  operations and its ability to
explore  for,  produce,  market  and  sell  its  oil  and  condensate  reserves.

Oil  and  Gas  Exploration,  Development  and  Production
---------------------------------------------------------

     Oil  and  gas  exploration  involves  a high degree of risk and there is no
assurance  that  expenditures  made  on future exploration by the Company on its
properties will result in new discoveries of oil, condensate or natural gas that
are  commercially  or  economically  producible.  It is difficult to project the
costs  of  implementing  an  exploratory  drilling  program  due to the inherent
uncertainties  of  drilling  in  unknown  formations,  the costs associated with
encountering  various  drilling conditions such as overpressured zones and tools
lost  in  the  hole,  and changes in drilling plans and locations as a result of
prior  exploratory wells or additional seismic data and interpretations thereof.
Production  and  development  of  offshore  oil,  condensate  and  natural  gas
properties  also  involve  an  increased  degree of risk relative to on-shore or
close-to-shore  production  and  development  primarily due to greater technical
obstacles.

                                      -39-
<PAGE>
     The  Company's  operations  are  subject  to  the  risks  of  exploration,
development  and operation of oil, condensate and natural gas properties and the
drilling  of  wells  thereon,  including  encountering  unexpected formations or
pressures,  premature  declines  of  reservoirs, blow-outs, craterings, sour gas
releases,  fires  and  spills.  Losses  resulting  from the occurrence of any of
these  risks could have a materially adverse affect on the Company.  The Company
may  become subject to liability for pollution, blow-outs or other hazards.  The
payment  of  such liabilities would reduce the funds available to the Company or
could  result  in  the  total  loss  of  the  Company's Participating Interests.

Depletion  of  Reserves;  Necessity  of  Successful  Exploration and Development
--------------------------------------------------------------------------------

     Producing  oil  and  natural  gas reservoirs generally are characterized by
declining  production  rates  that vary depending upon reservoir characteristics
and  other  factors.  The  Company's  future  oil  and  natural gas reserves and
production,  and, therefore, cash flow and income, are highly dependent upon the
Company's  success  in  economically  finding  additional  reserves  that  are
economically  recoverable.  There  can  be no assurance that the Company will be
able  to  find,  finance,  develop  or  acquire  additional  reserves.

Uncertainty  of  Reserve  Estimates
-----------------------------------

     There  are  numerous  uncertainties  inherent  in  estimating quantities of
reserves  and the present value of net cash flows attributable to such reserves.
Such  estimates  represent  subjective judgments based on available data and the
quality  of such data.  Different reserve engineers may make different estimates
of  reserve  quantities  and the present value of net cash flows attributable to
the  production  of  such  quantities.  Substantial  revisions  to  the  reserve
quantities and present value estimates may be necessary due to numerous factors,
including  the  results  of  drilling, testing and production and changes in the
assumptions regarding decline and production rates, taxes, royalties, prices and
costs made after the date of a reserve estimate.  The reserve estimates included
and  incorporated  by  reference  in this document could be materially different
from  the  quantities  and  values  ultimately  realized.

Prices,  Markets  and  Marketing  of  Crude  Oil  and  Condensate
-----------------------------------------------------------------
     Oil, condensate and natural gas are commodities whose prices are determined
based  on  world  demand,  supply and other factors, all of which are beyond the
control  of  the  Company.  World  prices for oil and condensate have fluctuated
widely  in  recent  years  and,  most  recently  have  been  characterized  by a
significant  decline  in  value.  Future  price fluctuations in world oil prices
will  have  a significant impact upon the economics of the Company's undeveloped
properties  and  the  projected  revenue  of  the  Company.

Financing  Risks
----------------

     On  June 30, 1998, the Company restructured its financial affairs including
its  Secured  Loan.  The  Company  has granted security to the Secured Lender in
respect  of  its repayment obligations under the Secured Loan.  The Secured Loan
includes  a  number of events of default.  In the event of the Company's default
under  the  terms  of  the  Secured  Loan,  the Secured Lender may call upon the
Company to immediately pay the outstanding principal or interest due thereunder,
or  take  title  to,  sell  or  otherwise  dispose  of  the  common  shares  of
substantially  all  of  the  Company's  subsidiaries.  Should the Secured Lender
become entitled to realize upon their security, the Company may lose part or all
of its Participating Interest in part of all of its oil and gas properties.  The
Company  may  currently  be in default of one or more terms of the Secured Loan.

ITEM  7.     CONSOLIDATED  FINANCIAL  STATEMENTS  AND  UNAUDITED

     SUPPLEMENTARY  DATA

U.S.  GAAP  RECONCILIATION

     The Company's Audited Consolidated Financial Statements for the fiscal year
ended  December 31, 1998 (the "1998 Financial Statements") have been prepared in
accordance  with  generally  accepted  accounting  principles  in  Canada. These
principles  differ  in some respects to generally accepted accounting principles
in the United States.  The Company's 1998 Financial Statements include "Comments
by  Auditors  for  U.S.  Readers  on  Canada  -  U.S. Reporting Difference" as a
supplement to the Auditors' Report.  In addition, a detailed discussion entitled
"Differences  in Generally Accepted Accounting Principles Between Canada and the
United  States"  is  included  as Note 12 of the 1998 Financial Statements.  See
"Consolidated  Financial  Statements  and  Unaudited  Supplementary  Data".

                                      -40-
<PAGE>
                                AUDITORS' REPORT

To  the  Shareholders  of
ABACAN  RESOURCE  CORPORATION:

We  have  audited the consolidated balance sheets of ABACAN RESOURCE CORPORATION
as  at  December 31, 1998 and 1997 and the consolidated statements of operations
and  deficit and changes in cash flow for the years then ended.  These financial
statements  are  the  responsibility  of  the  Company's  management.  Our
responsibility  is  to  express  an  opinion  on  these  consolidated  financial
statements  based  on  our  audits.

We conducted our audits in accordance with auditing standards generally accepted
in  Canada.  Those standards require that we plan and perform an audit to obtain
reasonable  assurance  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.  An audit also includes
assessing  the  accounting  principles  used  and  significant estimates made by
management,  as well as evaluating the overall financial statement presentation.

In  our  opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 1998
and  1997,  the  results of operations and changes in its financial position for
the years then ended in accordance with accounting principles generally accepted
in  Canada.



Calgary,  Alberta                                   /s/  Deloitte  &  Touche LLP
February  17,  1999                                 Chartered  Accountants

Note:  See  separate  Comments  by  Auditors  for  U.S.  Readers  on Canada-U.S.
Reporting  Difference

                      COMMENTS BY AUDITORS FOR U.S. READERS
                       ON CANADA-U.S. REPORTING DIFFERENCE

In  the  United States, reporting standards for auditors require the addition of
an  explanatory  paragraph  (following the opinion paragraph) when the financial
statements  are affected by conditions and events that cast substantial doubt on
the Company's ability to continue as a going concern, such as those described in
Note  1  to  the  consolidated  financial  statements.  Our  report  to  the
shareholders,  dated  February 17, 1999 is expressed in accordance with Canadian
reporting  standards  which  do  not  permit  a  reference  to  such  events and
conditions  in  the  auditors' report when these are adequately disclosed in the
financial  statements.



Calgary,  Alberta                                   /s/  Deloitte  &  Touche LLP
February  17,  1999                                 Chartered  Accountants

                                      -41-
<PAGE>
<TABLE>
<CAPTION>
                                ABACAN RESOURCE CORPORATION
                                CONSOLIDATED BALANCE SHEETS
                                     AS AT DECEMBER 31
                                (Thousands of U.S. Dollars)
                                         (Note 1)

                                                                       1998        1997
                                                                    ----------  ----------
<S>                                                                 <C>         <C>
                                                                    ----------  ----------
ASSETS
CURRENT
    Cash                                                            $   3,305   $   1,813 
    Accounts Receivable                                                    31      15,267 
    Inventory                                                               -         627 
                                                                    ----------  ----------
                                                                        3,336      17,707 

Petroleum and natural gas properties
    (utilizing the full cost method of accounting) (Notes 1 and 3)     92,431     138,471 
Deposits and other                                                         42       3,204 
                                                                    ----------  ----------
                                                                    $  95,809   $ 159,382 
                                                                    ==========  ==========

LIABILITIES
CURRENT
    Accounts payable                                                $   9,663   $  64,047 
    Current portion of capital lease obligations (Note 5)                   -       1,353 
    Royalties payable (Note 3)                                          5,373       3,537 
    Due to joint venture partner                                            -      14,658 
    Current portion of long term debt (Note 4)                         30,702      15,121 
                                                                    ----------  ----------
                                                                       45,738      98,716 


Long term debt (Note 4)                                                     -      19,879 
Capital lease obligations (Note 5)                                          -       5,213 
                                                                    ----------  ----------
                                                                       45,738     123,808 
                                                                    ----------  ----------

Contingency (Notes 1 and 10) and Commitments (Note 8)

SHAREHOLDERS' EQUITY
    Share Capital (Note 6)                                            276,750     274,750 
    Deficit                                                          (226,679)   (239,176)
                                                                    ----------  ----------
                                                                       50,071      35,574 
                                                                    ----------  ----------
                                                                    $  95,809   $ 159,382 
                                                                    ==========  ==========
</TABLE>

Approved  by  the  Board:
/s/  Timothy  Stephens                Director  -  Tim  Stephens

/s/  James  Harvie                    Director  -  James  Harvie


                                      -42-
<PAGE>
<TABLE>
<CAPTION>
                                ABACAN RESOURCE CORPORATION
                      CONSOLIDATED STATEMENT OF OPERATIONS AND DEFICIT
                              FOR THE YEARS ENDED DECEMBER 31
                                (Thousands of U.S. Dollars)
                                          (Note 1)

                                                                        1998        1997
                                                                     ----------  ----------
<S>                                                                  <C>         <C>
REVENUE
    Petroleum revenue (net of foreign taxes)                         $  14,258   $  59,702 
    Royalties                                                           (1,994)     (6,704)
    Interest and other                                                     181         528 
                                                                     ----------  ----------
                                                                        12,445      53,526 
                                                                     ----------  ----------

EXPENSES
    Operating                                                           17,431      46,276 
    General and administrative                                           4,623       3,934 
    Interest and other financial expense                                 3,022       4,333 
    Depletion, depreciation and amortization                             4,244      28,159 
    Provision for decline in value of petroleum properties (Note 3)          -     210,000 
                                                                     ----------  ----------
                                                                        29,320     292,702 
                                                                     ----------  ----------

LOSS BEFORE GAIN ON SALE OF ASSETS                                     (16,875)   (239,176)

GAIN ON SALE OF ASSETS (NOTE 1)                                         29,372           - 
                                                                     ==========  ==========

NET EARNINGS (LOSS) FOR THE YEAR (NOTE 7)                               12,497    (239,176)

DEFICIT, BEGINNING OF YEAR                                            (239,176)          - 
                                                                     ----------  ----------

DEFICIT, END OF YEAR                                                 $(226,679)  $(239,176)
                                                                     ==========  ==========

BASIC EARNINGS (LOSS) PER SHARE                                      $    0.11   $   (2.13)

FULLY DILUTED EARNINGS (LOSS) PER SHARE                              $    0.11   $   (2.13)
</TABLE>

                                      -43-
<PAGE>
<TABLE>
<CAPTION>
                            ABACAN RESOURCE CORPORATION
                 CONSOLIDATED STATEMENT OF OPERATIONS AND DEFICIT
                          FOR THE YEARS ENDED DECEMBER 31
                            (Thousands of U.S. Dollars)
                                     (Note 1)

                                                               1998        1997
                                                             ---------  ----------
<S>                                                          <C>        <C>

CASH PROVIDED BY (USED IN):

OPERATING ACTIVITIES
Net earnings (loss) for the year                             $ 12,497   $(239,176)
Items not affecting cash:
    Gain on sale of assets (Note 1)                           (29,372)          - 
    Provision for decline in value of petroleum properties          -     210,000 
    Depletion, depreciation and amortization                    4,244      28,159 
                                                             ---------  ----------
                                                              (12,631)     (1,017)
Changes in non-cash working capital items                      22,123       6,432 
                                                             ---------  ----------
                                                                9,492       5,415 
                                                             ---------  ----------

FINANCING ACTIVITIES
Issue of share capital
    Exercise of options                                             -       1,624 
    Acquisition of petroleum and natural
        gas properties                                          2,000           - 
    Acquisition of royalty interest                                 -      19,572 
Long term debt                                                 (4,298)     35,000 
Bank debt                                                           -     (20,100)
Capital lease obligations                                      (6,566)    (35,342)
                                                             ---------  ----------
                                                               (8,864)        754 
                                                             ---------  ----------

INVESTING ACTIVITIES
Expenditures on petroleum and natural
    gas properties                                            (15,224)   (110,967)
Disposition of assets (Note 1)                                 86,392           - 
Changes in non-cash working
    capital items                                             (73,466)     43,770 
Other                                                           3,162      (1,204)
                                                             ---------  ----------
                                                                  864     (68,401)
                                                             ---------  ----------

INCREASE (DECREASE) IN CASH                                     1,492     (62,232)

CASH, BEGINNING OF YEAR                                         1,813      64,045 

CASH, END OF YEAR                                            $  3,305   $   1,813 
                                                             =========  ==========
</TABLE>

                                      -44-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

1.     BASIS  OF  PRESENTATION

Continuation  of  business

The  consolidated  financial  statements  have  been  presented using accounting
principles  applicable  to  a going concern, which assumes that the Company will
continue  operations in the foreseeable future and be able to realize assets and
satisfy  liabilities  in  the  normal  course  of  business.  The  Company has a
liquidity  problem  which  casts  doubt  upon  the  validity of this assumption.

The Company has incurred a net loss from operations of $16,875,000 for the year.
The cash flows from operations for the year amounted to a net outflow of cash of
$12,631,000.  At  December  31,  1998, the Company has a deficit of $226,679,000
and  a  net  working  capital  deficiency  of $42,402,000.  Accounts payable and
royalties  payable  are  past  due in terms of normal payment terms and the long
term  debt  described  in Note 4 is repayable as to $20,100,000 on June 30, 1999
and  the  remainder  of  $10,602,000  on  December 31, 1999.  As a result of the
disposition of the Company's interests as disclosed below, the Company no longer
has  any  revenue  generating  properties  but  is  still  incurring general and
administrative  costs.

In  addition,  on  June  30, 1998, the Company's wholly-owned subsidiary Liberty
Technical  Services  Ltd.  ("Liberty")  reached  a settlement agreement with its
Nigerian  partner,  Amni  International  Petroleum  Development  Company Limited
("Amni"),  regarding the Ima Field and Liberty's interest in Nigerian Concession
OML  112  (formerly  OPL  469)  and  OPL  237.  Under  the  agreement,  Liberty
relinquished all rights and interests in the "shallow" zones of the Ima Field in
exchange  for  Amni  (1)  assuming  all  outstanding Ima Field related financial
claims  (including  trade  creditor  claims);  (2)  assuming  responsibility for
ongoing  and  future  lease  obligations  in  respect  of the Ima Field; and (3)
releasing Liberty from certain outstanding financial obligations under the terms
of  joint  venture  agreements  between  Liberty and Amni.  Although the Company
expects  Amni  will settle all the liabilities it has assumed, if Amni is unable
to settle all liabilities the Company may be held liable to settle the remaining
liabilities.  Concurrent  with  its  agreement  with  Amni,  Liberty  and  Amni
exchanged  their  interest  in  the  topside  equipment  of  the mobile offshore
production  unit  with  a  major international service company in return for the
extinguishment  of  all  outstanding debt due to that company.  As a result, the
Company  has  severed  its  operational responsibilities and associated overhead
related to the Ima Field and removed $86,392,000 of liabilities from its balance
sheet.

The  details  of  the  assets  and  facilities  disposed  of  are  as  follows:

Petroleum  and  natural  gas  properties           $      57,020,000
Assumption  of  liabilities  and  obligations            (86,392,000)
                                                   ==================
Gain  on  sale  of  assets                         $     (29,372,000)
                                                   ==================

                                      -45-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

1.     BASIS  OF  PRESENTATION  -  CONTINUED

The  Company's  ability  to  continue  as  a going concern is dependent upon the
following  factors  which  outline  management's  plan:

i)     the  development  of  the  natural  gas  reserves  in  the  Benin  Basin
Concessions OML113 (formerly OPL 309) and OPL 310 including the development of a
market  for  the  produced  natural  gas  in  this  area;

ii)    obtaining  financing in the form of equity, debt or a combination thereof
in  order  to  continue the development of the natural gas reserves in the above
mentioned  Concessions.

iii)   negotiating a joint venture for the continued exploration and development
of  the  West  African  acreage  position;

iv)    continuing  to  finance general and administrative expenses from existing
cash  or financing in the form of equity, debt or combination thereof until such
time  as  the  above  negotiations  and  financing  are  complete.

v)     negotiations  with  certain  suppliers  to settle current liabilities and
forbearance  of  the  creditors;

If  the  going  concern  assumption  were  not  appropriate  for these financial
statements,  then adjustments would be necessary in the carrying value of assets
and  liabilities,  the  reported  net  earnings  (loss)  and  the  balance sheet
classifications  used.

Reporting  currency

The  principal  costs  incurred  in  conducting  the  business operations of the
Company  are  almost  exclusively  transacted  in U.S. dollars and revenues were
generated  in  that  currency, therefore the Company has adopted U.S. dollars as
its reporting currency for financial presentation.  All dollar amounts set forth
in  these  financial  statements,  including the notes thereto, are expressed in
U.S.  dollars,  except  where  indicated  otherwise.

2.     SIGNIFICANT  ACCOUNTING  POLICIES

     Generally  accepted  accounting  standards

These  financial  statements  have  been  prepared in accordance with accounting
principles  generally accepted in Canada which differ from accounting principles
generally  accepted  in  the  United  States  as  described  in  Note  12.

                                      -46-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

2.     SIGNIFICANT  ACCOUNTING  POLICIES  -  CONTINUED

     Consolidation

These  financial statements include the accounts of Abacan Resource Corporation,
a  Canadian  corporation  incorporated in the Province of Alberta and its wholly
owned  subsidiaries,  ("the  Company").

     Revenue  recognition

     Revenue  from  crude  oil  is  recognized once it is produced and processed
ready  for  shipment.

     Petroleum  and  natural  gas  properties

The Company follows the full cost method of accounting for petroleum and natural
gas  properties  whereby all costs of exploring for and developing petroleum and
natural gas reserves are capitalized on a country by country basis.  Capitalized
costs  included  land acquisition costs, geological and geophysical costs, costs
of drilling wells, production equipment, related overhead costs, and capitalized
interest.  As  commercial  production  commenced in Nigeria effective January 1,
1997,  the  Company  recorded  depletion  from  that  date  and  to  the date of
disposition  on  June  30,  1998  on  capitalized  costs,  excluding undeveloped
projects,  using  the  unit of production method based upon estimated proved net
reserves  as  determined  by  the  Company  and  reviewed  yearly by independent
consulting  engineers,  converted  to  a  common  unit of measure using relative
energy  content.  The  remaining  full  cost  pool  in  Benin  is not subject to
depletion  until  such  time  as  its  projects  are  developed  and  commercial
production  has  commenced.

The Company periodically performs an impairment test relative to the capitalized
cost  of  undeveloped properties.  A ceiling test was employed at least annually
to ensure costs of developed properties accumulated by the Company do not exceed
estimated  future  cash  flows  from proven reserves and the cost of undeveloped
properties.  For  the  purposes  of  this test, future cash flows are determined
using  year-end  prices and costs, including deductions for applicable overhead,
financing  and  income  tax  expenses.

All  the  Company's  petroleum  and  natural  gas  exploration,  development and
production  activities  are  conducted  jointly with others.  These consolidated
financial  statements  reflect only the Company's proportionate interest in such
activities.

                                      -47-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

2.     SIGNIFICANT  ACCOUNTING  POLICIES  -  CONTINUED

     Foreign  Exchange

Foreign  currency  transactions  and  balances of the Company and its integrated
foreign  subsidiaries  are  translated  using  the  temporal method.  Under this
method,  monetary  assets  and liabilities are translated at year end rates, and
non-monetary  assets  and  liabilities  at  rates  prevailing at the transaction
dates.  Expenses  are  translated  at  the  average exchange rate for the month.
Foreign  exchange  gains  or losses on long term monetary assets and liabilities
are  deferred  and  amortized  over  the  remaining  term.

     Estimates

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  at the date of the
financial  statements  and  the reported amounts of revenues and expenses during
the  reporting  period.  Actual  results  may  differ  from  those estimates and
assumptions.

     Earnings  per  share

The  basic  earnings  per  share  has been calculated using the weighted average
number  of  shares outstanding during the year. Fully diluted earnings per share
are  calculated  taking  into  account  all  dilutive  options.


3.     PETROLEUM  AND  NATURAL  GAS  PROPERTIES

As  at  January  1,  1998, the Company had working interests in seven concession
blocks  in  West  Africa  in two geologically distinct areas; the Niger Delta in
South  Eastern  Nigeria  and the Benin Basin along the Nigeria/Republic of Benin
border.  Five  concessions  are  located  in  Nigeria and two are located in the
Republic  of  Benin.

In January 1998, the Company cancelled its joint venture agreement in respect of
the  Nigerian  Concession  Block  OPL 233, and consequently holds no interest in
this  property.

As  disclosed  in  Note  1,  the  Company  has  relinquished  all its rights and
interests  in  the  "shallow"  zones  of  the Ima Field and its interests in the
Nigerian  Concession  OML  112  (formerly  OPL  469)  and  OPL  237.

                                      -48-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

3.     PETROLEUM  AND  NATURAL  GAS  PROPERTIES  -  CONTINUED

Costs accumulated to date for acquisitions, seismic, exploration and development
and production equipment net of depletion and provision for decline in value are
as  follows:

<TABLE>
<CAPTION>
                                                     1998       1997
                                                   (000's)    (000's)
                                                   --------  ----------
<S>                                                <C>       <C>
Producing
Niger Delta
    Concessions Blocks OML 112 (formerly OPL 469)
        /OPL 237                                   $      -  $ 281,513 
    Concession Block OPL 233                              -        135 
    Less accumulated depletion                            -    (28,022)
    Less provision for decline in value                   -   (206,019)
                                                   --------  ----------
                                                          -     47,607 
                                                   --------  ----------

Non-producing
Benin Basin
    Concession Block OPL 302                              -      3,981 
    Less provision for decline in value                   -     (3,981)
    Concession Block OML 113 (formerly OPL 309)      81,285     82,152 
    Concession Block OPL 310                          6,024      3,973 
    Benin Republic Blocks I & IV                      5,010      4,304 
                                                   --------  ----------

                                                     92,319     90,429 


Corporate assets                                        112        435 
                                                   --------  ----------

                                                     92,431     90,864 
                                                   --------  ----------

                                                   $ 92,431  $ 138,471 
                                                   ========  ==========
</TABLE>

As  a  result  of  the  application of the ceiling test and other considerations
related  to  the  Company's intention to sell its production assets, the Company
recorded  a  provision  for  decline in value of petroleum properties in 1997 of
$210,000,000.

Working  Interest  -  Nigerian  Concessions

While  the  "shallow"  Ima Field encompassed all of the Company's production and
revenue  streams,  the Company retained a 10% working interest in the Ima "deep"
prospect  which is currently undrilled.  The Company continues to hold a working
interest  in  Nigerian  Block  OML  113  (formerly  OPL  309)  and  OPL  310.

                                      -49-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

3.     PETROLEUM  AND  NATURAL  GAS  PROPERTIES  -  CONTINUED

The  working  interests  of the Company in these two concessions are as follows:

<TABLE>
<CAPTION>
                Before Payout    After Payout
               ---------------  ---------------
               Revenue   Cost   Revenue   Cost
               --------  -----  --------  -----
<S>            <C>       <C>    <C>       <C>
Block OML 113     52.5%   100%     26.7%    40%
Block OPL 310     48.5%   100%     24.7%    40%
</TABLE>

The  Company's  Nigerian  partner  in  Block OML 113 is Yinka Folawiyo Petroleum
Company  ("YFP"),  which  is  owned by the father of one of the directors of the
Company.  That  director  is also an executive officer and director of YFP.  YFP
is  entitled  to 15% of all revenues before payout and 28% after payout.  YFP is
not  responsible  for any capital or operating costs until payout, at which time
it  becomes responsible for 60% of the capital and operating costs.  As a result
of  the  conversion  of Concession Block OPL 309 to Concession Block OML113, the
Company  has  a commitment to YFP in the amount of $5,000,000, to be paid out of
net  cash flow from the future production of Concession Block OML 113.  All work
commitments under the original license with the Government of Nigeria related to
this  Concession  have  been  completed.

The  Oil  Prospecting  License  ("OPL")  for Block 310 expired in February 1997,
however,  the  Nigerian  Department  of  Petroleum  Resources  confirmed shortly
following  the  expiry  of  the  OPL  to the Company's Nigerian partner, Optimum
Petroleum  Company  Limited  ("Optimum") that the OPL remained in good standing.
Subsequently,  nothing  has been received by the Company, or to the knowledge of
the Company, by Optimum that would indicate that the Nigerian authorities do not
consider  OPL  310  to  be  valid  and  in  good  standing.  The  Company has an
obligation to pay $1,000,000 to Optimum within nine months of the testing of its
first  exploration  well  and an additional $2,000,000 following commencement of
production.  In  addition,  the Company is required under the OPL to drill three
wells  and  complete  a  seismic  program  on  the  Block.  These  minimum  work
commitments  do  not become effective until the OPL is confirmed by the Nigerian
authorities.  Despite  this,  Optimum has advised the Company that it wishes the
Company  to  proceed  on  the  minimum  work  program in advance of the required
extension  or  renewal and receipt of requisite government approval to the joint
venture  agreement.

Prior to June 30, 1998 the Company's economic participation in concession blocks
in Nigeria was calculated on a before and after payout basis and on a concession
by  concession  basis.  Though  royalties  applicable  to  the Company's working
interest  varied  from  concession to concession, general economic terms were as
follows:

                                      -50-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

3.     PETROLEUM  AND  NATURAL  GAS  PROPERTIES  -  CONTINUED

<TABLE>
<CAPTION>
                            Before Payout             After Payout
                      ------------------------  ------------------------
                                    Operating                 Operating
                        Revenue        Cost       Revenue        Cost
                      ------------  ----------  ------------  ----------
<S>                   <C>           <C>         <C>           <C>
Participation before
   Royalties                   55%        100%           28%         40%

Royalties              6.5% - 2.5%                3.3 - 1.6%

Net Concession
   Participation      48.5 - 52.5%        100%  24.7 - 26.4%         40%
</TABLE>

Abacan International Resources Management Inc. ("AIRMI"), a company wholly owned
by  a  former  president  and director of the Company, holds royalty interest in
three  of  the  Company's  Nigerian concessions with rates ranging from 1.65% to
0.85%  before payout and 0.82% to 0.42% after payout.  The Company's interest in
the  concessions  exists  through joint venture agreements between the Company's
subsidiaries  and  its  Nigerian  partner  corporations.

At December 31, 1998, royalties payable included an amount of $1,059,000 (1997 -
$794,000)  owed to AIRMI and $1,427,000 (1997 - $921,000) to YFP.  The remaining
balance  of  royalties  payable  of  $2,887,000  (1997  - $1,822,000) is due the
Company's  other  Nigerian  partner  corporations.  All  of  the royalty payable
amounts  are  currently  due  and  beyond  normal  repayment  terms.

Working  Interests  -  Benin  Republic  Concessions

In  July 1997, the Company increased its position in Benin Republic Blocks 1 and
4 to a 100% Participating Interest.  Under separate production sharing contracts
with  the  Government  of  Benin,  the  Company  is required to fund 100% of all
exploration  and  development  costs of a prescribed minimum work program and is
entitled  to  receive  approximately 69% of revenue from Block 1/Seme and 75% of
revenue from Block 4, subject to a sliding scale royalty that becomes applicable
after  a  prescribed  level  of  cost  recovery  is  achieved  by  the  Company.

As  part  of  the  prescribed work program, the Company is required to drill one
well in Block 1/ Seme by February 1999 and one well in Block 4 by February 2002.
In addition, the Company is required to complete a seismic program on Block 4 by
February  2002.  As the Company has not commenced the Block 1/Seme well, it will
at  the end of February 1999 not be in compliance with the minimum work program.
As  a result, under the production sharing contract, the Company's Participation
interest  in-Block 1 would be subject to cancellation at that date.  The Company
is  in  the  process  of  negotiating  an  extension  of  this  requirement.

                                      -51-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

4.     LONG  TERM  DEBT

During  1997,  the  Company entered into a Crude Oil Prepayment Agreement in the
amount  of  $35,000,000  to be repaid out of a portion of the proceeds of future
crude oil deliveries from the Company's share of crude oil produced from the Ima
Field  commencing  in February, 1998.  The original agreement specified that the
minimum  amount  by  which  the  prepayment  was  to  be repaid from the monthly
delivery  payment  of  the  marketer  is $2,916,667 plus accrued interest at the
London  Inter-Bank  offered  rate  ("LIBOR")  plus 2.5% during a six month grace
period,  changing  to  LIBOR  plus  0.5%  beginning  with  the  first  principal
repayment.  A  portion  of  the  proceeds  from  this loan was used to repay the
Company's  bank  indebtedness  that  existed  at  that  time.

On  June 30, 1998, concurrent with the settlement agreement disclosed in Note 1,
the  prepayment  sums  of  approximately  $30,702,000 then outstanding under the
Crude Oil Prepayment Agreement were converted into a credit facility.  Under the
terms  of the facility, interest is payable on the outstanding principal balance
of  the  facility  at  a  maximum  rate  equal  to  Libor plus 4% per annum.  As
restructured, repayment of $20,100,000 was deferred until June 30, 1999 with the
balance  of  $10,602,000  due  on  December 31, 1999.  Interest payments were to
commence  quarterly  on December 31, 1998.  Subsequent to December 31, 1998, the
Company  received written confirmation that the first quarterly interest payment
due  December  31,  1998  had  been capitalized and that interest payments would
commence  on  March  31,  1999.  The  Company  has  since  been  advised  that
notwithstanding  its  written extension, the first interest instalment continued
to  be  due  on  December  31, 1998.  The Company has not yet made this interest
payment and is currently negotiating regarding relief from this payment and from
other  near-term  cash  interest  payments.

The  Company  has granted security in respect of its repayment obligations under
the facility.  Included as security are (1) a pledge of all of the common shares
of  those  subsidiaries that hold Participating Interests in the Company's Niger
Delta  and  Benin  Basin  Concessions;  (2)  a  series  of debentures granting a
security  interest  against  the  Company's  Participating Interest in its Niger
Delta  and  Benin  Basin Concessions; and (3) a guarantee of the Company for all
outstanding  amounts  under  the  Loan.

                                      -52-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

5.     LEASE  OBLIGATIONS

The Company had entered into various leases relating to the production facility.
Leases  are  classified  as  capital or operating leases.  Leases which transfer
substantially  all  of  the benefits and risks incident to ownership of property
were  accounted  for  as capital leases.  All other leases were accounted for as
operating  leases.  As  part  of  the restructuring and disposition of assets on
June  30,  1998  all  lease  obligations related to the production facility were
assumed  by  Amni.

The  Company  has  entered into a lease for the office premises in Houston.  The
lease  has  18  months remaining.  The minimum lease payments under the terms of
this  lease  are  $41,200  per  year.


6.     SHARE  CAPITAL

a)     Common  Shares
     Authorized
   Unlimited  number  of  common  shares and preferred shares issuable in series
Issued
   Common  shares

<TABLE>
<CAPTION>
                                                 Number of       $
                                                  Shares      (000's)
                                                -----------  ---------
<S>                                             <C>          <C>
Balance, December 31, 1996                      109,413,504  $ 253,554
----------------------------------------------  -----------  ---------

Issued on exercise of options                       862,500      1,624
Issued on exercise of share
   purchase warrants                                358,152          -
Issued on acquisition of royalty interest         2,247,680     19,572
                                                -----------  ---------

Balance, December 31, 1997                      112,881,836    274,750

Issued on acquisition of petroleum and natural
   gas properties                                 1,489,000      2,000
                                                -----------  ---------

Balance, December 31, 1998                      114,370,836  $ 276,750
                                                ===========  =========
</TABLE>

                                      -53-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

6.     SHARE  CAPITAL  -  CONTINUED

     b)     Stock  Options

At  December  31, 1998 the Company has options outstanding to acquire 12,356,200
common  shares by officers, directors, consultants and employees of the Company.
These  options  may  be exercised at prices ranging from CDN $0.28 to CDN $12.15
per  common  share  and  expire  at  various  times  to  October  23,  2003.

     c)     Warrants  Outstanding

On  June 30, 1998, in connection with the restructuring of its loan, the Company
agreed  to  issue 600,000 options at a price of CDN$0.91 per share expiring June
30,  2000.  At  December  31,  1998,  all  of  the  options  were  outstanding.

On  November  6,  1996 the Company completed a public issue of 12,500,000 common
shares at a price of $7.50 per common share.  On November 19, 1996 an additional
1,875,000  common  shares  were issued in conjunction with the underwriters over
allotment  option.  The  Company  received  net  proceeds  of  $100,987,000.  In
connection  with  this  offering,  the  placement  agent was granted warrants to
purchase  100,000  common  shares  of  the  Company.  The warrants, which can be
exercised  after one year from the issue date, have a term of five years and are
exercisable  at  a price of $7.50 per share.  At December 31, 1998, all of these
warrants  remain  unexercised.

On April 19, 1996, there were warrants granted to purchase 500,000 Common Shares
of  the  Company  for advisory services to an investment banker.  These warrants
have a term of five years and are exercisable at a price of $3.40 per share.  At
December  31,  1998,  all  of  these  warrants  remain  unexercised.

     d)     Acquisition  of  Royalty  Interests

In  February  1997,  the  Company  acquired  a  portion  of the gross overriding
royalties  on  Niger  Delta Concession Block OML 112/OPL 237 from YFP by issuing
643,840 Common Shares valued at $6,036,000.  The Company also acquired a portion
of  the  gross overriding royalties on Benin Basin Concession Block OML 113 from
YFP  by  issuing  643,840  Common  Shares  of  the Company valued at $6,036,000.

On April 1, 1997, the Company acquired a further portion of the gross overriding
royalties  on  Concession Block OML 112/OPL 237 from YFP on Concession Block OML
113  by  issuing  960,000  Common  Shares  valued  at  $7,500,000.

                                      -54-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

6.     SHARE  CAPITAL  -  CONTINUED

     e)     Acquisition  of  Participating  Interest

In  April  1998,  the  Company  issued  1,489,000  shares of its common stock to
Optimum  in  consideration  for  financial  obligations  of  $2,000,000 owing to
Optimum  to  secure the Company's interest in Concession Block OPL 310.  Optimum
is the indigenous Nigerian company which owns the rights to Concession Block OPL
310  and  is partner to the Company in Concession Block OPL 310, as discussed in
Note  3.

7.     INCOME  TAXES

Due  to  the  nature of the Company's structure and operations, the Company will
not  have  a tax liability resulting from the current gain on the sale of assets
,and  accordingly  has  not recorded a tax provision.  At December 31, 1998, the
Company  had approximately CDN $26,854,000 of non-capital losses available to be
applied  against  taxable  income  of  the  future  years  on the portion of its
operations  which  are  subject  to  Canadian income taxes.  These losses expire
between  1999  and 2004.  The Company also had available for deduction, at rates
allowed  under  the Income Tax Act, CDN $17,012,000 of oil and gas expenditures.
The  potential  future  benefit  of  these  losses  and deductions have not been
reflected  in  the  consolidated  financial  statements.

8.     COMMITMENTS

The  Company  entered  into  an  agreement for the sale of the Company's and its
Nigerian partner's entitlement to crude oil and condensate produced from the Ima
Field located in Concession Block OML 112 for a period of one year from the date
of the first lifting which occurred on February 21, 1997.  The price payable for
each  barrel of crude oil and condensate was based upon a range of quoted prices
for  Bonny  Quesbo  crude  oil less a new crude oil discount.  This discount was
calculated  based  upon  the  volume  of  cargo  lifted  at  each  lifting.

At  July  29,  1997, the Company entered into a second agreement for the sale of
the  Company's  entitlement  to  crude  oil and condensate produced from the Ima
Field.  The  duration  of this second agreement was to be one year commencing on
February  22,  1998.

                                      -55-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

8.     COMMITMENTS  -  CONTINUED

Upon  relinquishment  by  the  Company  of its participating interest in the Ima
Field  at June 30, 1998, the above mentioned agreements were terminated, and the
loan  was  restructured  as  disclosed  in  Note  4.

The  Company has further commitments with respect to its participating interests
in  the  Concessions,  as  disclosed  in  Note  3.

9.     FINANCIAL  INSTRUMENTS

The  carrying  value  of  the  financial instruments of the Company approximates
their  estimated  fair  value.

10.     CONTINGENCIES

While the Company is defending various lawsuits, there are two lawsuits in which
the  claims  are  significant,  which  relate  to  liabilities  assumed by Amni.
Although  Amni has agreed to assume liability for any claims against the Company
in respect of oil and gas operations on the Ima Field, the Company will continue
to  be  liable to trade and other creditors until settlement arrangements can be
established.  The  total amounts claimed in the two lawsuits (exclusive of costs
and  interest)  is  approximately  $3,700,000. The management of the Company has
determined  that  the  Company does not have any material exposure in any of the
lawsuits.

11.     UNCERTAINTY  DUE  TO  THE  YEAR  2000  ISSUE

The  Year  2000  Issue  arises  because many computerized systems use two digits
rather  than  four  to identify a year. Date-sensitive systems may recognize the
year 2000 as 1900 or some other date, resulting in errors when information using
year  2000  dates  is processed. In addition, similar problems may arise in some
systems  which  use  certain  dates  in 1999 to represent something other than a
date. The effects of the Year 2000 Issue may be experienced before, on, or after
January  1,  2000, and, if not addressed, the impact on operations and financial
reporting may range from minor errors to significant systems failure which could
affect  the  Company's  ability to conduct normal business operations. It is not
possible  to  be  certain  that all aspects of the Year 2000 Issue affecting the
Company,  including  those  related  to  the efforts of customers, suppliers, or
other  third  parties,  will  be  fully  resolved.

                                      -56-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

12.     DIFFERENCES  IN  GENERALLY  ACCEPTED  ACCOUNTING  PRINCIPLES  BETWEEN
        CANADA  AND  THE  UNITED  STATES

The  consolidated  financial  statements  have  been prepared in accordance with
generally  accepted  accounting  principles  (GAAP)  in  Canada.  The  primary
difference  between  Canadian  and  US  GAAP  affecting  the Company's financial
statements  are  as  discussed  below:

     Deferral  of  General  and  Administrative  Costs

Under Canadian GAAP, general and administrative costs, net of interest and other
revenue  prior  to  the  period  in  which  commercial  production commenced are
deferred  and  added  to  the  carrying  value  of  petroleum  and  natural  gas
properties.  Under  US  GAAP,  deferral  costs  of this type would be treated as
expenses  in  the  year  incurred.

The effect of this difference is to create a statement of loss and deficit which
would  include  such revenues and expenses and to reduce the amounts included in
petroleum  and  natural  gas  properties  as  follows:

<TABLE>
<CAPTION>
                                                  1998        1997       1996
                                               ----------  ----------  ---------
<S>                                            <C>         <C>         <C>

Net income (loss) as reported                  $  12,497   $(239,176)  $      - 
Net oil production revenue                             -           -      1,300 
Interest revenue                                       -           -      1,050 
General and administrative expense                     -           -     (2,603)
Adjustment to provision for decline in value
 of petroleum properties (US GAAP)                     -       3,000          - 
Adjustment to gain on sale of assets                (715)          -          - 
                                               ----------  ----------  ---------
Net earnings (loss)                               11,782    (236,176)      (253)

Deficit, beginning of period                    (238,461)     (2,285)    (2,032)
                                               ----------  ----------  ---------

Deficit, end of period as adjusted
 to US GAAP                                    $(226,679)  $(238,461)  $ (2,285)
                                               ----------  ----------  ---------

Petroleum and natural gas properties
 as reported                                   $  92,431   $ 138,471   $265,551 
Increase (decrease)                                    -         715     (2,285)
                                               ----------  ----------  ---------

As adjusted to US GAAP                         $  92,431   $ 139,186   $263,266 
                                               ==========  ==========  =========
</TABLE>

                                      -57-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

12.     DIFFERENCES  IN  GENERALLY  ACCEPTED  ACCOUNTING  PRINCIPLES  BETWEEN
        CANADA  AND  THE  UNITED  STATES  -  CONTINUED

     Earnings  per  share

The methodology for computing fully diluted earnings per share is not consistent
between  the  two  countries.  For Canadian purposes, the proceeds from dilutive
securities  are  used to reduce debt in the calculation.  US GAAP, Statements of
Financial  Accounting  Standards  ("SFAS")  No.  128  requires the proceeds from
dilutive  securities  be  used  to  repurchase  common  shares.

     Statement  of  Changes  in  Cash  Flow

Under  Canadian  GAAP,  certain  financing  and  investing  activities  such  as
acquiring petroleum and natural gas properties in exchange for share capital are
treated  as  a cash inflow followed by a cash outflow.  As a result, these types
of  transactions  are  included  in  the  consolidated statements of cash flows.
Under  US GAAP, non-cash transactions of a financing or investing nature are not
included  in consolidated statements of cash flows.  These types of transactions
are disclosed as supplementary disclosure to the consolidated statements of cash
flows.  Accordingly  for US GAAP purposes, financing and investing activities in
the  statement  of  change  in  cash flow would be lower by $2,000,000, in 1998,
$19,572,000  in  1997  and  $600,000  in  1996  as the Company had issued common
shares  in  exchange  for  petroleum  and  natural  gas  properties  or  royalty
interests.

For  US GAAP purposes, the disposition of assets as outlined in Note 1 would not
be  shown  on  the  consolidated  statements of cash flow as the Company did not
receive  any  cash  as  part  of  the transaction.  Accordingly, cash flows from
financing  activities  are  lower  and  investing  activities  will be higher by
$6,094,000.

In  addition, for US GAAP purposes, changes in working capital are by definition
an  operating  activity.  For  Canadian GAAP purposes, change in working capital
that  relate  to investing activities such as purchases of equipment are treated
as  an  investing activity.  Accordingly, the net cash from operations in the US
GAAP  consolidated statements of cash flows would increase in 1998 by $9,994,000
(1997 - $43,770,000 and 1996 - $12,057,000) from the net cash from operations in
the  Canadian  GAAP consolidated statements of cash flows.  Investing activities
are  reduced  by  the  identical  amount  in  each  year.

Foreign  currency  translation

Under  Canadian GAAP, non-monetary assets and liabilities denominated in foreign
currencies are translated at exchange rates prevailing at the transaction dates.
Under  US  GAAP,  those  assets  and liabilities would be translated at year-end
rates.  As  the  majority  of  the  assets  and  liabilities are denominated and
reported in US dollars, this difference would not have material effect on either
the  financial  position  of  the  results  of  operations  on  the  Company.

                                      -58-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                             YEARS ENDED DECEMBER 31

12.     DIFFERENCES  IN  GENERALLY  ACCEPTED  ACCOUNTING  PRINCIPLES  BETWEEN
        CANADA  AND  THE  UNITED  STATES  -  CONTINUED

     Deferred  income  taxes

Under  Canadian GAAP, the Company would record a deferred tax asset related to a
tax  loss  carry  forward only if the Company was virtually certain of realizing
the benefit associated with the tax loss carry forward.  Under US GAAP, SFAS No.
109  requires that the Company record all deferred income tax assets and make an
estimate  of  the  likely  recoverability of the asset by recording a provision.
The  provision  would  reduce  the  recorded  deferred  tax  asset to the amount
expected  to  be  recovered.  The  Company  is  of the opinion that the benefits
related  to the tax loss carry forwards will not be realized for the foreseeable
future.  Accordingly,  the provision that the Company would record under US GAAP
would  reduce  the  recorded deferred tax asset to a nil balance.  As no benefit
has  been  realized  for  Canadian GAAP, there is no difference in the financial
position  or  the  results  of  operations  of  the  Company.

     Comprehensive  income

SFAS  No.  130 "Reporting Comprehensive Income" became effective as of the first
quarter  of  1998.  The  statement  requires  companies  to  report  and display
comprehensive  income  and  its  components.  Comprehensive  income includes all
changes  in  equity  during  a period except those resulting from investments by
shareholders  or  distributions to shareholders.  For the Company, comprehensive
income  is  the  same  as  net income reported in the consolidated statements of
operations  and  deficit, since there are no other items of comprehensive income
for  the  years  presented.

     Recently  issued  Accounting  Standards

SFAS 131, "Disclosures About Segments of an Enterprise and Related Information,"
is  effective  for the year ended December 31, 1998.  This statement establishes
standards  for  defining  and  reporting  business  segments.  As  the financial
statements  disclose  the operations of the Company in the various countries, no
additional  disclosure  is  needed.

SFAS  132,  "Employer's  Disclosures  about  Pensions  and Other Post-retirement
Benefits,"  revises  existing  rules  for  disclosure  of  pensions  and  other
post-retirement  benefit  plans.  As  the  Company does not have any pensions or
other  post-retirement  benefit  plans,  no  additional  disclosure  is  needed.

SFAS  133,  "Accounting  for  Derivative Instruments and Hedging Activities," is
effective  for  fiscal  years  beginning  after  June  15,  1999.  This standard
requires  that  all derivatives be recognized as either assets or liabilities in
the  balance  sheet  at  their  fair  market  values and that accounting for the
changes  in  their  fair  values  is  dependent  upon  the  intended  use of the
derivative  and  its  resulting designation.  The new standard will supersede or
amend  existing standards which deal with hedge accounting and derivatives.  The
Company has not yet determined the effect of adopting this standard will have on
its  financial  statements.

                                      -59-
<PAGE>
The consolidated statements of operations and accumulated deficit and statements
of  cash flows prepared using US GAAP are presented as supplemental information:

<TABLE>
<CAPTION>
                                      ABACAN RESOURCE CORPORATION
                        CONSOLIDATED STATEMENTS OF LOSS AND ACCUMULATED DEFICIT
                     (PREPARED USING U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES)
                                        YEARS ENDED DECEMBER 31
                                  (Thousands of U.S. Dollars - Note 1)

                                                                 1998           1997           1996
                                                             -------------  -------------  ------------
<S>                                                          <C>            <C>            <C>
Revenue
    Petroleum revenue (net of royalties and foreign taxes)   $     12,264   $     52,998   $     1,300 
    Interest and other                                                181            528         1,050 
                                                             -------------  -------------  ------------
                                                                   12,445         53,526         2,350 
                                                             -------------  -------------  ------------

Expenses
    Operating                                                      17,431         46,276             - 
    General and administrative                                      4,623          3,934         2,603 
    Interest and other financial expense                            3,022          4,333             - 
    Depletion, depreciation and amortization                        4,244         28,159             - 
    Provision for decline in value of petroleum properties              -        207,000             - 
                                                             -------------  -------------  ------------
                                                                   29,320        289,702         2,603 
                                                             -------------  -------------  ------------

Net loss before gain on sale of assets                            (16,875)      (236,176)         (253)

Gain on sale of assets                                             28,657              -             - 
                                                             -------------  -------------  ------------

Net earnings (loss)                                                11,782       (236,176)         (253)

Deficit, beginning of period                                     (238,461)        (2,285)       (2,032)
                                                             -------------  -------------  ------------

Deficit, end of period                                       $   (226,679)  $   (238,461)  $    (2,285)
                                                             =============  =============  ============

Basic earnings (loss) per Common share                       $       0.10   $      (2.11)  $      0.00 
                                                             =============  =============  ============

Fully diluted earnings (loss) per common share               $       0.10   $      (2.11)  $      0.00 
                                                             =============  =============  ============

Weighted average number of shares outstanding                 113,942,486    112,029,272    92,899,595 
                                                             =============  =============  ============
</TABLE>

                                      -60-
<PAGE>
<TABLE>
<CAPTION>
                                              ABACAN RESOURCE CORPORATION
                                         CONSOLIDATED STATEMENTS OF CASH FLOWS
                            (PREPARED USING U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES)
                                                YEARS ENDED DECEMBER 31
                                         (Thousands of U.S. Dollars - Note 1)

                                                                                       1998        1997        1996
                                                                                     ---------  ----------  ----------
<S>                                                                                  <C>        <C>         <C>
NET INFLOW (OUTFLOW) OF CASH RELATED TO THE FOLLOWING ACTIVITIES

OPERATING
Net earnings (loss)                                                                  $ 11,782   $(236,176)  $    (253)
Items not affecting cash:
    Gain on sale of assets                                                            (28,657)          -           - 
    Provision for decline in value of petroleum properties                                  -     207,000           - 
    Depletion, depreciation and amortization                                            4,244      28,159           - 
Changes in non-cash working capital items                                              32,117      50,202      12,057 
                                                                                     ---------  ----------  ----------

                                                                                       19,486      49,185      11,804 
                                                                                     ---------  ----------  ----------

FINANCING
Issue of share capital
    Common shares and warrants                                                              -           -     104,449 
    Exercise of options                                                                     -       1,624       5,237 
Long term debt                                                                         (4,298)     35,000           - 
Bank debt                                                                                   -     (20,100)     20,100 
Capital lease obligations                                                                (472)    (35,342)     41,909 
Issue of convertible debentures                                                             -           -       7,806 
                                                                                     ---------  ----------  ----------

                                                                                       (4,770)    (18,818)    179,501 
                                                                                     ---------  ----------  ----------

INVESTING
Expenditures on petroleum properties and equipment                                    (13,224)    (91,395)   (159,263)
Maturity settlement of short term investments                                               -      15,000     (15,000)
Other                                                                                       -      (1,204)     (1,750)
                                                                                     ---------  ----------  ----------

                                                                                      (13,224)    (77,599)   (176,013)
                                                                                     ---------  ----------  ----------

NET CASH INFLOW (OUTFLOW)                                                               1,492     (47,232)     15,292 

CASH AND SHORT-TERM INVESTMENTS,
   BEGINNING OF YEAR                                                                    1,813      49,045      33,753 
                                                                                     ---------  ----------  ----------

CASH AND SHORT-TERM INVESTMENTS,
   END OF YEAR                                                                       $  3,305   $   1,813   $  49,045 
                                                                                     =========  ==========  ==========

Supplemental Non-Cash
    Acquisition of petroleum and natural gas properties for common shares
                                                                                     $  2,000   $  19,572   $     600 
                                                                                     ---------  ----------  ----------

Supplemental Disclosure of Cash Flow
    Interest paid                                                                    $   2663   $   2,833   $     895 
                                                                                     ---------  ----------  ----------
    Operating lease payments                                                         $ 11,242   $  23,940   $       - 
                                                                                     ---------  ----------  ----------
    Conversion of convertible debentures
       including accrued interest                                                    $      -   $       -   $  13,056 
                                                                                     ---------  ----------  ----------
</TABLE>

                                      -61-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                         FOR THE YEARS ENDED DECEMBER 31
                           (Thousands of U.S. Dollars)
                                    (Note 1)

-     SUPPLEMENTAL  INFORMATION

Following  is a summary of stock option activity during the years ended December
31,  1998,  1997  and  1996  (weighted  average  prices  are  in  $CDN):

<TABLE>
<CAPTION>
                                              -----1998-----          -----1997-----          -----1996-----
                                                       Weighted                Weighted                Weighted
                                                        Average                 Average                 Average
                                            Number       Price      Number       Price      Number       Price
                                          -----------  ---------  -----------  ---------  -----------  ---------
<S>                                       <C>          <C>        <C>          <C>        <C>          <C>
Outstanding at the beginning of the year
                                          10,461,750   $    4.72   6,768,000   $    3.52   4,485,000   $    2.70

Granted                                    5,710,250        0.93   4,946,250        6.16   5,498,300        6.55
Terminated                                (3,815,800)       9.81    (390,000)       5.12     (50,000)       5.00
Exercised                                          -           -    (862,500)       2.58  (3,165,300)       2.26
Expired                                            -           -           -           -           -           -
                                          -----------  ---------  -----------  ---------  -----------  ---------

Outstanding at the
end of the year                           12,356,200   $    3.63  10,461,750   $    4.72   6,768,000   $    3.52
                                          ===========  =========  ===========  =========  ===========  =========

Options exercisable
at the end of the year                     9,764,117   $    2.25   5,033,750   $    4.39   4,407,000   $    2.22
                                          ===========  =========  ===========  =========  ===========  =========
</TABLE>

Options  outstanding  as  of  December  31,  1998:

<TABLE>
<CAPTION>
                                             Weighted
                                 Weighted    Average                 Weighted
                      Options     Average   Remaining   Exercisable   Average
                    Outstanding    Price    Life (yrs)    Options      Price
                    -----------  ---------  ----------  -----------  ---------
<S>                 <C>          <C>        <C>         <C>          <C>
Exercise price of:

    $0.28 - $1.00     4,710,000  $    0.44        4.62    4,710,000  $    0.44
    $1.01 - $6.00     7,293,900  $    3.65        2.97    4,877,867  $    3.65
    $6.01 - $12.15      352,500  $   12.15        3.09      176,250  $   12.15
</TABLE>

                                      -62-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                         FOR THE YEARS ENDED DECEMBER 31
                           (Thousands of U.S. Dollars)
                                    (Note 1)

13.     SUPPLEMENTAL  INFORMATION  -  CONTINUED

In 1996, the United States Financial Accounting Standards Board issued Statement
of  Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based
Compensation."  With  regard  to  its stock option plan, the Company applies ABB
Opinion  No.  25  as  allowed  under  SFAS  123  in accounting for this plan and
accordingly  no compensation cost has been recognized.  Had compensation expense
been  determined based on the fair value at the grant dates for the stock option
grants  consistent with the method of SFAS No. 123, the Company's net income and
net  income  per  common  share should have been reduced to the pro forma amount
indicated  below:

<TABLE>
<CAPTION>
                                                               1998       1997       1996
<S>                                                           <C>      <C>         <C>

Net Income (Loss)
As Reported                                                    11,782   (236,176)      (253)
Pro forma                                                       8,510   (253,047)   (14,437)

Net Income (Loss) Per Share
As Reported
    Basic                                                        0.10      (2.11)         - 
    Fully Diluted                                                0.10          -          - 

Pro forma
    Basic                                                        0.07      (2.26)     (0.16)
    Fully Diluted                                                0.07          -          - 
------------------------------------------------------------  -------  ----------  ---------

Stock options issued during period (thousands)                  5,710      4,946      5,498 
Weighted average exercise price                               $  0.93  $    6.18   $   6.55 
Average per option compensation value of options granted (a)     0.85       4.77       3.52 
Compensation cost (thousands $U.S.)                           $ 3,272  $  16,871   $ 14,184 
------------------------------------------------------------  -------  ----------  ---------
<FN>
(a)  Calculated  in  accordance  with  the  Black-Scholes  option  pricing  model, using the
following  assumptions:  expected  volatility  computed  using, as of the date of grant, the
prior  year  monthly  average  of  the Common Shares as listed on the TSE, which ranged from
53.5%  to  148%; expected dividend yield - 0%; expected option term - 5 years; and risk-free
rate of return as of the date of grant which ranged from 5.4% to 7.4%, based on the yield of
five-year  Canadian  treasury  securities.
</TABLE>

                                      -63-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                         FOR THE YEARS ENDED DECEMBER 31
                           (Thousands of U.S. Dollars)
                                    (Note 1)

13.     SUPPLEMENTAL  INFORMATION  -  CONTINUED

     Capitalized  costs  (unaudited)

The  following  tables  summarize  the  costs  incurred  in  oil and natural gas
property  acquisition,  exploration  and  development  activities.  Property
acquisition  costs  are  those  costs  incurred to purchase, lease, or otherwise
acquire property.  Exploration costs include costs of identifying areas that may
warrant  examination and in examining specific areas that are considered to have
prospects  containing  oil and natural gas reserves, including costs of drilling
exploratory  wells,  geological  and  geophysical  costs  and  carrying costs on
undeveloped  properties.  Development  costs  are  incurred  to obtain access to
proved  reserves,  including  the  cost  of  drilling  development wells, and to
provide  facilities  for extracting, treating, gathering and storing the oil and
natural  gas.

The  Company  has  capitalized property acquisition, exploration and development
costs  pertaining  to  its  oil  and  gas  producing  operations  as  follows:

<TABLE>
<CAPTION>
                                 1998       1997       1996
<S>                             <C>      <C>         <C>
Property
    Proved                      $     -  $ 279,859   $203,013
    Unproved                     92,431     94,535     60,253
                                -------  ----------  --------

                                 92,431    374,394    263,266

Accumulated depreciation,
    depletion and amortization        -   (235,208)         -
                                -------  ----------  --------

Capitalized Costs               $92,431  $ 139,186    263,266
                                =======  ==========  ========
</TABLE>

                                      -64-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                         FOR THE YEARS ENDED DECEMBER 31
                           (Thousands of U.S. Dollars)
                                    (Note 1)

13.     SUPPLEMENTAL  INFORMATION  -  CONTINUED

     Costs  incurred  for  property  acquisition and exploration activities on a
calendar  year  basis

<TABLE>
<CAPTION>
                               Total
                              (000's)
<S>                          <C>

1998
Property Acquisition
    Proved                   $       -
    Unproved                     2,000
Exploration and Development     13,224
                             ---------

                             $  15,224
                             ---------

1997
Property Acquisition
    Proved                   $  20,772
    Unproved                     1,525
Exploration and Development     88,670
                             ---------

                             $ 110,967
                             ---------

1996
Property Acquisition
    Proved                   $     600
    Unproved                         -
Exploration and Development    159,249
                             ---------

                               159,849
                             ---------
</TABLE>

Depletion  Expenses  (unaudited)

The  Company  has  recorded  depletion  on  a  per  barrel  basis  as  follows:

                         1998      1997     1996

                       $  2.92  $   8.33  $     -
                       =======  ========  =======

                                      -65-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                         FOR THE YEARS ENDED DECEMBER 31
                           (Thousands of U.S. Dollars)
                                    (Note 1)

14.     SUPPLEMENTAL  RESERVE  INFORMATION  (UNAUDITED)

Net  proved  oil  and  natural  gas  reserve  estimates were prepared by Gilbert
Lausten  Jung  Associates  Ltd.,  independent  petroleum  engineers  located  in
Calgary, Alberta.  Oil and natural gas prices in effect as of the reserve report
date were used without escalation.  Operating costs and future development costs
were  based  on  current  costs  with  no  escalation.

There  are  numerous  uncertainties  inherent in estimating quantities of proved
reserves  and  in  projecting  future  rates  of  production  and  the timing of
development  expenditures.  The following reserve data represents estimates only
and should not be construed as being exact.  Moreover, the present values should
not  be  construed  as  the  market  value  of the Company's oil and natural gas
reserves  or  the  costs  that  would be incurred to obtain equivalent reserves.

<TABLE>
<CAPTION>
Estimated quantities of proved reserves    Year ended    Year ended     Year ended
(mmbbls)                                  December 31,  December 31,   December 31,
                                              1998          1997           1996
                                          ------------  -------------  -------------
<S>                                       <C>           <C>            <C>

Balance, beginning of year                        15.8          23.5           21.8 
    Reserve additions                                -             -              - 
    Economic revisions                               -          (4.3)           1.8 
    Production and sale                           15.8          (3.4)          (0.1)
                                          ------------  -------------  -------------

Balance, end of year                                 -          15.8           23.5 
                                          ============  =============  =============
</TABLE>

Standardized  measure of discounted future cash flows relating to proved oil and
gas  reserve  quantities

In  calculating  the  standardized  measure of discounted future net cash flows,
prices and costs in effect at year end were assumed to be constant, were applied
to  proved  reserves  and  provision  was  made for estimated future development
expenditures  that  will be required to produce the Company's reserves.  Royalty
deductions  were based on laws, regulations and contracts existing at the end of
the  fiscal year.  The discounted future net cash flows were derived by applying
a 10% discount factor, as required by SFAS No. 69, to the future net cash flows.

Management  believes that this information does not reflect the current economic
value  of  the  oil  and gas properties or the present value of estimated future
cash  flows since no economic value is attributed to potential reserves, the use
of  a  10% discount rate is arbitrary and prices change constantly from year end
levels.

                                      -66-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                         FOR THE YEARS ENDED DECEMBER 31
                           (Thousands of U.S. Dollars)
                                    (Note 1)

14.     SUPPLEMENTAL  RESERVE  INFORMATION  (UNAUDITED)  -  CONTINUED

<TABLE>
<CAPTION>
                                                        (000's)
<S>                                                     <C>

December 31, 1998
    Future cash inflows                                 $     - 
    Future capital lease payments                             - 
    Future gross overriding royalties                         - 
    Future production and development costs                   - 
                                                        --------


10% annual discount for estimated timing of cash flows        - 
                                                        --------

Standardized measure of future net cash flows           $     - 
                                                        ========

Changes in standardized measure
    December 31, 1997                                   $  64.5 
    Purchases of reserves in place                            - 
    Sales of reserves in place                            (64.5)
    Net changes in prices and costs                           - 
                                                        --------

December 31, 1998                                       $     - 
                                                        ========


December 31, 1997
    Future cash inflows                                 $ 357.8 
    Future capital lease payments                           6.6 
    Future gross overriding royalties                     (35.8)
    Future production and development costs              (251.5)
                                                        --------

                                                           77.1 

10% annual discount for estimated timing of cash flows    (12.6)
                                                        --------

Standardized measure of future net cash flows           $  64.5 
                                                        ========

Changes in standardized measure
    December 31, 1996                                   $ 268.2 
    Purchases of reserves in place                            - 
    Production                                           (203.6)
    Net changes in prices and costs                        (.01)
                                                        --------


December 31, 1997                                       $  64.5 
                                                        ========
</TABLE>

                                      -67-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
                         FOR THE YEARS ENDED DECEMBER 31
                           (Thousands of U.S. Dollars)
                                    (Note 1)

14.     SUPPLEMENTAL  RESERVE  INFORMATION  (UNAUDITED)  -  CONTINUED

<TABLE>
<CAPTION>
                                                        (000's)
                                                        --------
<S>                                                     <C>
December 31, 1996
    Future cash inflows                                 $ 537.4 
    Future capital lease payments                          38.1 
    Future gross overriding royalties                     (55.8)
    Future production and development costs              (217.4)
                                                        --------

                                                          302.3 

10% annual discount for estimated timing of cash flows    (34.1)
                                                        --------

Standardized measure of future net cash flows           $ 268.2 
                                                        ========


Changes in standard measure
    December 31, 1995                                   $ 152.0 
    Purchases of reserves in place                            - 
    Sales of reserves in place                                - 
    Net changes in prices and costs                       116.2 
                                                        --------

    December 31, 1996                                   $ 268.2 
                                                        ========
</TABLE>

U.S.  GAAP  RECONCILIATION

     The Company's Audited Consolidated Financial Statements for the fiscal year
ended  December 31, 1998 (the "1998 Financial Statements") have been prepared in
accordance  with  generally  accepted  accounting  principles  in  Canada. These
principles  differ  in some respects to generally accepted accounting principles
in the United States.  The Company's 1998 Financial Statements include "Comments
by  Auditors  for  U.S.  Readers  on  Canada  -  U.S. Reporting Difference" as a
supplement to the Auditors' Report.  In addition, a detailed discussion entitled
"Differences  in Generally Accepted Accounting Principles Between Canada and the
United  States"  is  included  as Note 12 of the 1998 Financial Statements.  See
"Consolidated  Financial  Statements  and  Unaudited  Supplementary  Data".

                                      -68-
<PAGE>
                           ABACAN RESOURCE CORPORATION
                          INDEPENDENT AUDITOR'S CONSENT



We consent to the inclusion of our report dated February 17, 1999 (which express
an  unqualified  opinion  and  for  U.S.  Readers  had  a  Canada-U.S. reporting
difference  which  would  require  the  addition  of  an  explanatory  paragraph
(following  the opinion paragraph) relating to the Company's ability to continue
as  a  going  concern), with respect to the consolidated financial statements of
Abacan  Resource  Corporation  appearing  in the Annual Report on Form 10-KSB of
Abacan  Resource  Corporation  for  the  year  ended  December  31,  1998.



Deloitte  &  Touche  LLP


/s/  Deloitte  &  Touche  LLP
Chartered  Accountants
Calgary,  Alberta

March  26,  1999

                                      -69-
<PAGE>



                                      -70-
<PAGE>



                                      -71-
<PAGE>
ITEM  8.     CHANGES  IN  AND  DISAGREEMENTS  WITH ACCOUNTANTS ON ACCOUNTING AND
             FINANCIAL  DISCLOSURE

     There  are  not and have not been any disagreements between the Company and
its accountants on any matter of accounting principles or practices or financial
statement  disclosure.

                                    PART III

ITEM  9.     DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS OF THE
             ISSUER;  COMPLIANCE  WITH  SECTION  16(a)  OF  THE  EXCHANGE  ACT

DIRECTORS  AND  EXECUTIVE  OFFICERS

     The following is a list of the names of the Company's current directors and
executive  officers,  their  jurisdiction  of  residence  and  their  principal
occupation  for  the past five years.  Each of the named directors has agreed to
stand for re-election at the upcoming Annual and Special Meeting of Shareholders
scheduled  for  March  29,  1999  in  Houston,  Texas.

<TABLE>
<CAPTION>
NAME                       AGE          POSITION                        PRINCIPAL OCCUPATION WITHIN LAST FIVE YEARS
-------------------------  ---  ------------------------  ------------------------------------------------------------------------
<S>                        <C>  <C>                       <C>
Timothy T. Stephens         46  Chairman, President, CEO  President, Chief Executive Officer and Director since February 1998 and
Houston, Texas                  and Director              Chairman since February 1999; prior thereto, between March 1995 and
                                                          May 1997, the President and a Director of Seven Seas Petroleums Inc.
                                                          (TSE and NASDAQ); prior thereto, between July 1991 and March 1995,
                                                          a Vice President of Enron Capital and Trade Resources Inc.

James S. Harvie (1)         49  Director                  Director since June 1997 and Chief Operating Officer between June 1997
Calgary, Alberta                                          and February 1999; prior thereto, between June 1994 and August 1996,
                                                          the Executive Vice President of Midland Walwyn Capital Inc.; prior
                                                          thereto, President of Deacon Barclay's Canada; former Governor of The
                                                          Toronto Stock Exchange.

T. B. ("Tunde") Folawiyo    39  Director                  Director since December 1993. Executive Director of Yinka Folawiyo
Lagos, Nigeria                                            Petroleum Co. Ltd. (a private Nigerian oil company) and Executive
                                                          Director of Yinka Folawiyo Group of Companies (an international business
                                                          conglomerate).

James A. Kishpaugh (1)      58  Director                  Director since February 8, 1999. Chairman and CEO of Merlon Petroleum
Houston, Texas                                            Company, a private company, since 1997.  Chairman and CEO of Texas
                                                          International Company (NYSE) and Phoenix Resources Company
                                                          (NASDAQ) from 1978 to 1990.

Kenneth C. Rutherford (1)   45  Director                  Director since February 8, 1999. Vice President and CFO of Scorpion
Calgary, Alberta                                          Energy Corporation (TSE) from 1998 to present; President of Captiva
                                                          Resource Corporation, a private oil and gas financial, investment and
                                                          administrative services company, from 1993 to present; Vice President
                                                          Finance and CFO of Arakis Energy Corporation (NASDAQ) from
                                                          December 1996 to September 1997 and a Director of Arakis from
                                                          July 1997 to October 1998.
<FN>
_________
(1)     Indicates  member  of  the  Company's  Audit  Committee.
</TABLE>

     During  the  fiscal  year  ended December 31, 1998, the Corporation paid no
cash  compensation  (including  salaries,  director's fees, commissions, bonuses
paid  for  services  rendered,  bonuses paid for services rendered in a previous
year,  and  any  compensation  other  than  bonuses  earned by the directors for
services  rendered) to the directors for services rendered as such. Compensation
has  been  paid  by  the  Corporation to certain directors or companies owned or
controlled  by directors where such directors have provided ongoing professional
consulting  or  employment  services  to  the  Corporation  or its subsidiaries.
Executive  officers  of  the  Corporation  who  also  act  as  directors  of the
Corporation, do not receive any additional compensation for services rendered in
their  capacity  as  directors,  other  than  as paid by the Corporation to such
executive  officers  in  their  capacity  as  executive  officers.

                                      -72-
<PAGE>
     During  the fiscal year ended December 31, 1998, a total of 4,999,500 stock
options  were  granted  to the directors of the Corporation (including directors
who  were  executive  officers).

SIGNIFICANT  EMPLOYEES

     The  following  persons, who are not directors or executive officers of the
Company, are expected to make a significant contribution to the ongoing business
affairs  of  the  Company.

<TABLE>
<CAPTION>
       NAME        AGE   POSITION                PRINCIPAL OCCUPATION WITHIN LAST FIVE YEARS
-----------------  ---  ----------  ----------------------------------------------------------------------
<S>                <C>  <C>         <C>
Wade G. Cherwayko   35  Consultant  Consultant to the Company since February 1998; President and Chief
Lagos, Nigeria                      Executive Officer of the Corporation between May 1993 and February
                                    1998; Director between November 1992 and February 1999; prior thereto,
                                    an independent international petroleum consultant.
</TABLE>

FAMILY  RELATIONSHIPS

     There  are  no  family  relationships  among  the  Company's  directors  or
executive  officers.

INVOLVEMENT  IN  CERTAIN  LEGAL  PROCEEDINGS

     None  of  the  Company's directors or executive officers have been involved
during the past five years in any legal proceedings material to an evaluation of
such  persons  ability  or  integrity.

COMPLIANCE  WITH  SECTION  16(A)  OF  THE  EXCHANGE  ACT

     Section 16(a) of the Securities Exchange Act of 1934 requires the Company's
officers  and  directors,  and  persons  who  own  more  than  10 percent of the
Company's  common  stock  to  file reports of ownership and changes in ownership
with  the  Securities and Exchange Commission ("SEC").  Officers, directors, and
greater  than 10 percent shareholders are required by SEC regulations to furnish
the  Company  with  copies  of  all  Section  16(a)  forms they file. Management
believes  all  such  individuals were in compliance with Section 16(a) as of the
effective  date  hereof.

ITEM  10.     EXECUTIVE  COMPENSATION

     Information  in  respect  of  this  item  appears  on  Pages  6 - 14 of the
Company's  Definitive  Proxy  Statement  filed  March  5, 1999 under the heading
"Compensation of Directors and Executive Officers" and is incorporated herein by
reference.

ITEM  11.     SECURITY  OWNERSHIP  OF  CERTAIN  BENEFICIAL OWNERS AND MANAGEMENT

     Information in respect of this item appears on Pages 2 - 5 of the Company's
Definitive  Proxy Statement filed March 5, 1999 under the heading "Voting Shares
and  Principal  Holders  Thereof"  and  is  incorporated  herein  by  reference.

                                      -73-
<PAGE>
ITEM  12.     CERTAIN  RELATIONSHIPS  AND  RELATED  TRANSACTIONS

     There  are  no material interests, direct or indirect, of directors, senior
officers, or any shareholder who beneficially owns, directly or indirectly, more
than 5% of the outstanding Common Shares or any known associate or affiliates of
such  persons,  in  any  transaction  within the last two fiscal years or in any
proposed  transaction  which  has materially affected or would materially affect
the  Company  other  than  as  disclosed  below:

TRANSACTIONS

(1)     On  April  5,  1995,  Liberty  Technical  Services  Ltd.  ("Liberty") (a
subsidiary  of  the  Company)  granted  Yinka Folawiyo Petroleum Company Limited
("YFP")  a  2.40879%  before  Payout  (1.26%  after  Payout) royalty interest in
respect  of  all  petroleum substances produced from Concession Block OPL 237 in
consideration  of  YFP's  assistance  in  enabling  the  Company  to  acquire  a
Participating  Interest  in  the concession. On March 31, 1997, YFP sold 0.9554%
before  Payout  and  0.4863%  after Payout of its royalty interest to Liberty in
consideration  of  the  payment  of  $3,767,495  from  Liberty  to  YFP.  The
consideration  for  the purchased royalty interest was based upon the discounted
future  value  of  the  royalty  interest  based  upon  the  proved  reserves on
Concession  Block  OPL  237  at  the  time  of purchase.  The purchase price was
determined  based  upon  the  purchase  price  paid by the Company for a royalty
interest  acquired  by  it from an unrelated third party.  Payment was satisfied
through  the  issuance  of 482,239 common shares of Abacan at a price of $7.8125
per  common  share.  YFP  is  a  company that is substantially controlled by the
father  of  Mr.  Tunde  Folawiyo, a director of the Company. Tunde Folawiyo is a
director  and  senior  officer  of  YFP.

(2)     On  February  23,  1994,  Liberty  granted  YFP a 2.45775% before Payout
(1.2611%  after  Payout) royalty interest in respect of all petroleum substances
produced  from  Concession  Block OML 112 (formerly OPL 469) in consideration of
YFP's  assistance in enabling the Company to acquire a Participating Interest in
the  concession. On March 31, 1997, YFP sold 0.86125% before Payout and 0.43841%
after  Payout of its royalty interest to Liberty in consideration of the payment
of  $3,732,505  from Liberty to YFP. The consideration for the purchased royalty
interest  was  based  upon  the  discounted future value of the royalty interest
based  upon  the  proved  reserves  on  Concession  Block OPL 469 at the time of
purchase.  The  purchase price was determined based upon the purchase price paid
by  the  Company  for  a royalty interest acquired by it from an unrelated third
party.  Payment  was  satisfied through the issuance of 477,761 common shares of
Abacan  at  a  price  of  $7.8125  per  common  share.

(3)     On  March  8, 1992, the Company and YFP signed a Joint Venture Agreement
for  the  exploration  of Nigerian Concession Block OPL 309.  Under the terms of
the Joint Venture Agreement, the Company was responsible, inter alia, to pay YFP
a  conversion fee of $5.0 million upon the conversion of the OPL into an OML. On
July  3,  1998,  OPL 309 was converted into OML 113.  Consequently, a payment of
$5.0  million  is due from the Company to YFP.  Payment of this amount will come
from a portion of the Company's net cash flow from future production on OML 113.

MATERIAL  INTERESTS

1.     Pursuant  to a Royalty Agreement between Liberty and Abacan International
Resource  Management Inc. ("AIRMI") dated December 2, 1994, AIRMI holds a 1.501%
Pre-Payout  (0.764%  After Payout) royalty interest in  respect of all petroleum
substances  produced  from  Concession  Block OPL 237. AIRMI is a company wholly
owned  by  Wade  G.  Cherwayko,  a former President, CEO and director of Abacan.

                                      -74-
<PAGE>
2.     Pursuant  to  a  Royalty Agreement between Liberty and AIRMI dated August
19,  1993,  AIRMI  holds  a  0.825%  before  Payout (0.42% after Payout) royalty
interest  in  respect of all petroleum substances produced from Concession Block
OML  112.

3.     Pursuant  to a Royalty Agreement between Liberty and AIRMI dated March 8,
1992, AIRMI holds a 1.65% before Payout (0.84% after Payout) royalty interest in
respect  of  all  petroleum  substances  produced from Concession Block OML 113.

4.     Pursuant  to  a  Participation/Royalty  Agreement between Liberty and YFP
dated April 5, 1995 (amended pursuant to a Sale Agreement dated March 31, 1997),
YFP  holds  a 1.61146% before Payout (0.82037% after Payout) royalty interest in
respect  of  all  petroleum  substances  produced from Concession Block OML 112.

5.     Pursuant  to  a  Participation/Royalty  Agreement between Liberty and YFP
dated  February  23,  1994 (amended pursuant to a Sale Agreement dated March 31,
1997),  YFP  holds  a  1.59650%  before  Payout  (0.81269% after Payout) royalty
interest  in  respect of all petroleum substances produced from Concession Block
OML  112.

6.     YFP  is  the indigenous Nigerian concession owner of Concession Block OML
113.  Under the terms of the Joint Venture Agreement between the Company and YFP
dated  March  8, 1992, the Company is responsible for paying 100% of all capital
and  operating  costs  before  to Payout reducing to 40% of all such costs after
Payout.  After  accounting  for  royalties and taxes, the Company is entitled to
52.525%  of  all  revenues earned before Payout and 26.74% of all revenues after
Payout.  YFP  is  not responsible for any costs before Payout but is entitled to
15.0% of all revenues before Payout. After Payout, YFP is responsible for 60% of
all  capital  and  operating  costs  and  is entitled 28.0% of all revenues.  In
addition  to  the  foregoing,  the  Company is responsible for a payment of $5.0
million  to  YFP as a result of the conversion of the oil prospecting licence to
an oil mining lease in respect of Block OML 113.  Payments are to be paid out of
a  portion  of  the  Company's net cash flow from future production of Block OML
113.

ITEM  13.     EXHIBITS  AND  REPORTS  ON  FORM  8-KSB

(3)     Exhibits:  See  the  Exhibits  Index  on  Page  77.

(4)     Reports  on  Form  8-KSB: No reports on Form 8-KSB were filed during the
last  quarter  of  fiscal  1998.

                                      -75-
<PAGE>
SIGNATURES

     Pursuant  to  the  requirements  of  Section  13  or  Section  15(d) of the
Securities  Exchange  Act of 1934, the Registrant has duly caused this report to
be  signed  on  its  behalf  by  the  undersigned,  thereunto  duly
authorized,  on  March  1,  1999.

ABACAN  RESOURCE  CORPORATION
(Registrant)

By: /s/ Timothy T. Stephens
______________________________
Timothy T. Stephens
Chairman of the Board , President and
Chief  Executive Officer
(Principal Executive
Officer)

By: /s/ James S. Harvie
______________________________
James S. Harvie
Director

     Pursuant  to  the requirements of the Securities Exchange Act of 1934, this
report  has  been signed below by the following persons in the capacities and on
the  dates  indicated:

<TABLE>
<CAPTION>
Signature                Title                                 Date
<S>                      <C>                                   <C>

/s/ Timothy T. Stephens  Chairman of the Board, President,
Timothy T. Stephens      Chief Executive Officer and Director  March 1, 1999

/s/ James S. Harvie      Director                              March 1, 1999
James S. Harvie

/s/ James Kishpaugh      Director                              March 1, 1999
James Kishpaugh

/s/ Ken Rutherford       Director                              March 1, 1999
Ken Rutherford

/s/ Tunde Folawiyo       Director                              March 1, 1999
Tunde Folawiyo
</TABLE>

                                      -76-
<PAGE>
<TABLE>
<CAPTION>
                                 ABACAN RESOURCE CORPORATION

                                       EXHIBITS INDEX


Exhibit
Number                                       Description
-------  -----------------------------------------------------------------------------------
<S>      <C>

3.1      Certificate of Amendment and Articles of Amalgamation dated February 10, 1995

3.2      Articles of Amendment dated June 20, 1997

3.3      By-Laws dated January 20, 1995

4.1      Description of Common Stock

10.1     Termination, Settlement and Release Agreement dated June 30, 1998 between Amni
         and Liberty, and first supplement agreement

10.2     Termination, Settlement and Release Supplemental Agreement dated June 30, 1998
         between Amni and Liberty

10.3     Joint Venture Agreement  dated June 30, 1998 in respect of the Deep Ima Prospect
         between Amni and Liberty

10.4     Joint Operating Agreement dated June 30, 1998 in respect of the Deep Ima Prospect
         between Amni and Liberty

10.5     Debenture dated June 30, 1998 in respect of the Deep Ima Prospect between Amni
         and Liberty

10.6     Consent Agreement dated June 30, 1998 between Amni and Liberty

10.7     Termination Agreement dated June 30, 1998 in respect of the MOPU between
         Abacan Technical Services Ltd. ("Abacan Technical"), Liberty, Amni,
         Schlumberger and Sedco

10.8     Facility Agreement dated June 30, 1998 between Abacan Resource
         Corporation ("Abacan"), Dahomey Resource Corporation ("Dahomey"), Liberty and CSFB

10.9     Security Trust Deed dated June 30, 1998 between Abacan, Dahomey, Liberty,
         Abacan Resources (Benin) Limited ("Abacan Benin"), West African Resource
         Corporation, Agbara Resources Limited, Abacan Power (Benin) Limited, Abacan-
         Addax Benin Consortium S.A., Abacan Resources (Nigeria) Ltd., Angus
         International Resources Ltd., Profile International Ltd. and CSFB

10.10    Royalty Agreement dated March 8, 1992 in respect of Nigerian Concession Block
         OML 113 (formerly OPL 309) between Liberty and Abacan
         International Resource Management Inc. ("Airmi")

10.11    Royalty/Revenue Interest Sale Agreement dated March 31, 1997 in respect
         of Nigerian Block OML 112 (formerly OPL 469) between Liberty and Yinka
         Folawiyo Petroleum Company Limited ("YFP")

                                      -77-
<PAGE>
10.12    Royalty Agreement dated August 19, 1993  in respect of Nigerian Concession
         Block OML 112 (formerly OPL 469) between Liberty and Airmi

10.13    Royalty/Revenue Interest Sale Agreement dated March 31, 1997 in respect
         of Nigerian Block OPL 237 between Liberty and YFP

10.14    Royalty Agreement dated December 2, 1994 in respect of Nigerian
         Concession Block OPL 237 between Liberty and Airmi

10.15    Joint Operating Agreement dated March 8, 1992 in respect of Nigerian
         Concession Block OML 113 between Liberty and YFP

10.16    Joint Operating Agreement dated March 8, 1992 in respect of Nigerian
         Concession Block OML 113 between Liberty and YFP

10.17    Project Management Agreement dated March 8, 1992 in respect of
         Nigerian Concession Block OML 113 between Liberty, YFP and Airmi

10.18    Technical Assistance Agreement dated March 8, 1992 in respect of
         Nigerian Concession Block OML 113 between Liberty and YFP

10.19    Joint Venture Agreement dated November 27, 1996 in respect of
         Nigerian Concession Block OPL 310 between Liberty and Optimum Petroleum
         Development Limited ("Optimum")

10.20    Technical Assistance Agreement dated November 27, 1996 in respect of
         Nigerian Concession Block OPL 310 between Liberty and Optimum

10.21    [intentionally left blank]

10.22    Oil Exploration and Exploitation Contract - Offshore Block No. 4 dated February
         1, 1997 between Addax Petroleum Benin Limited ("Addax"), Abacan Resources
         (Benin) Limited and the Government of the Republic of Benin (English language
         translation of French language original).

10.23    Oil Exploration and Exploitation Contract - Offshore No. 1 and Seme Bloc dated
         February 1, 1997 between Addax Petroleum Benin Limited ("Addax"), Abacan
         Resources (Benin) Limited and the Government of the Republic of Benin (English
         language translation of French language original).

10.24    Purchase and Sale Agreement dated July 31, 1997 in respect of Benin Block 4
         and Block 1 between Addax and Abacan Benin

10.25    Conveyance Agreement dated July 31, 1997 in respect of Benin Block 4 and
         Block 1 between Addax and Abacan Benin

                                      -78-
<PAGE>
10.26    Consulting Services Agreement dated July 18, 1996 between Texada Holdings
         Ltd. and Liberty

10.27    Employment Services Agreement dated February 10, 1998 between
         Timothy Stephens and  Abacan

10.28    Stock Option Plan dated June 20, 1997 and standard form of Stock
         Option Agreement

11.1     Statement re: Computation of Per Share Earnings

21.1     Subsidiaries

27.1     Summary Financial Information
</TABLE>

                                      -79-
<PAGE>