SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                                    FORM 10-K
(Mark One)
[ X ]    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
         EXCHANGE ACT OF 1934

For the fiscal year ended            December 31, 1997
                          ---------------------------------------

                                       OR

[    ]   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
         EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

For the transition period from                   to


Commission file number  1-3793

                         CANADA SOUTHERN PETROLEUM LTD.

             (Exact name of registrant as specified in its charter)

        NOVA SCOTIA, CANADA                                      98-0085412
    State or other jurisdiction of                            (I.R.S. Employer
    incorporation or organization                            Identification No.)

    Suite 1410, One Palliser Square
    125 Ninth Avenue, S.E.
    Calgary, Alberta   CANADA                                     T2G OP6
(Address of principal executive offices)                         (Zip Code)

Registrant's telephone number, including area code             (403) 269-7741

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

                                                        Name of each exchange on
      Title of each class                                    which registered

Limited Voting Shares, $1 (Canadian) per share           NASDAQ SmallCap Market
                                                         Pacific Stock Exchange
                                                         Boston Stock Exchange
                                                         Toronto Stock Exchange

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

                                (Title of Class)

                                      NONE

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the  preceding 12 months (or for such  shorter  period that the  registrant  was
required  to file  such  reports),  and  (2) has  been  subject  to such  filing
requirements for the past 90 days.                            |X| Yes |_| No




<PAGE>




          Indicate by check mark if disclosure of delinquent  filers pursuant to
Item 405 of Regulation S-K ss.229.405 of this chapter) is not contained  herein,
and will not be contained,  to the best of registrant's knowledge, in definitive
proxy or information  statements  incorporated  by reference in Part III of this
Form 10-K or any amendment to this Form 10-K.                          [ X ]

          The aggregate market value of the voting stock held by  non-affiliates
of the registrant was approximately U.S. $107,468,000 at March 23, 1998.


                   (APPLICABLE ONLY TO CORPORATE REGISTRANTS)


         Indicate the number of shares  outstanding of each of the  registrant's
classes of common stock, as of the latest practicable date.

         Limited Voting Shares, par value $1.00 (Canadian) per share, 14,234,740
shares outstanding as of March 23, 1998.


                       DOCUMENTS INCORPORATED BY REFERENCE


                  Proxy Statement of Canada Southern  Petroleum Ltd.  related to
the Annual Meeting of Shareholders  for the year ended December 31, 1997,  which
is incorporated into Part III of this Form 10-K.




<PAGE>



                                TABLE OF CONTENTS


                                                                            Page

                                     PART I

Item 1.   Business                                                            4

Item 2.   Properties                                                         15

Item 3.   Legal Proceedings                                                  22

Item 4.   Submission of Matters to a Vote of Security Holders                25

                                     PART II

Item 5.   Market for the Company's Limited Voting Shares and Related
          Stockholder Matters                                                26

Item 6.   Selected Financial Data                                            28

Item 7.   Management's Discussion and Analysis of Financial Condition
          and Results of Operations                                          29

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk         34

Item 8.   Financial Statements and Supplementary Data                        35

Item 9.   Changes in and Disagreements with Accountants
          on Accounting and Financial Disclosure                             56

                                    PART III

Item 10.  Directors and Executive Officers of the Company                    56

Item 11.  Executive Compensation                                             56

Item 12.  Security Ownership of Certain Beneficial Owners and Management     56

Item 13.  Certain Relationships and Related Transactions                     56

                                     PART IV

Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K    57


Unless  otherwise  indicated,  all dollar  figures  set forth are  expressed  in
Canadian currency. The exchange rate at March 23, 1998 was $1.00 Canadian = U.S.
$.7046.



<PAGE>



                                     PART I

Item 1.   Business

         The  nature of Canada  Southern  Petroleum  Ltd.'s  (the  "Company"  or
"Canada Southern")  business is described at Item 1(c) herein, and a description
of its principal oil and gas properties in Canada appears in Item 2 herein.  For
additional  information regarding the development of the Company's business, see
"Properties" and "Supplemental Information on Oil and Gas Activities".

         (a)  General Development of Business

Yukon Territory - The Kotaneelee Field

         The  Company's  principal  asset  is a  30%  carried  interest  in  the
Kotaneelee  gas field located on Ex-Permit 1007 (31,888 gross acres or 9,566 net
acres) in the extreme southeastern corner of the Yukon Territory. This partially
developed  field is connected to a major  pipeline  system.  Two wells have been
completed  to date that are  capable of an  estimated  output of in excess of 60
million cubic feet per day, the capacity of the field dehydration plant. Present
production is  approximately 40 million cubic feet ("mcf") per day. The operator
is Anderson  Exploration Ltd., which acquired all of Columbia Gas Development of
Canada's interests.  See "Legal Proceedings " for a discussion of the Kotaneelee
Litigation concerning this asset.

         Production  at  Kotaneelee  commenced  in February  1991.  According to
government  reports,  total  production  in billion  cubic feet ("bcf") from the
Kotaneelee gas field since 1991 has been as follows:

                      Calendar Year               Production (bcf)
                      -------------               ----------------
                           1991                          8.1
                           1992                         18.0
                           1993                         17.5
                           1994                         16.7
                           1995                         15.7
                           1996                         15.2
                           1997                         14.4

         In a 1989  application to the National Energy Board, a reserve study by
the operator estimated total gas in place at 1.6 trillion cubic feet with proved
and probable recoverable reserves of 781 BCF.



<PAGE>


         At  present,  the  Company  does not  receive  any cash  payments  from
production  but is credited with 30% of the gross  revenues until a like percent
of the working interest costs,  exclusive of any interest expense, are recovered
by the  operator.  The Company  will not receive  any  payment  from  production
revenues until its share of the working  interest costs are recovered.  When the
deferred  costs are recovered,  30% of gross  revenues (net of gross  overriding
royalties)  less  30% of  current  working  interest  costs  will be paid to the
Company.  Gross  overriding  royalties  amount  to 10% to the  Canadian  Federal
government  and 4.06% to certain  individuals.  The operator has reported to the
Company  development  costs  totaling  approximately  $88,043,000  and,  of that
amount,  approximately  $19,807,000  (Company share  $5,942,000)  remained to be
recovered at December 31, 1997.  The Company has  contested  the amount of costs
that have been charged to the carried interest account. It is estimated that the
Company will not begin to receive  proceeds from the Kotaneelee gas field before
the year 2000,  based  upon a price of $1.39 per mcf  (average  1997  price) and
current production rates. The period before payment to the Company begins may be
shorter or longer,  depending on prevailing market conditions and the results of
the Kotaneelee Litigation.

British Columbia Properties

         The  Company's  major  source of  income is from oil and gas  fields in
northeast  British Columbia.  These fields,  developed in the 1950's and 1960's,
produce revenue through both working and carried interest agreements.  The major
working  interests in these fields are  operated by Canadian  Natural  Resources
Ltd.  ("CNRL").  Petro  Canada had been the primary  operator  of the  Company's
carried interest lands in British Columbia.

         In addition  to the  producing  properties,  since 1988 the Company has
acquired a number of leases in northeast  British  Columbia by  participating in
British  Columbia land sales.  To date five wells have been drilled on the lands
resulting in three oil discoveries and two dry holes. Currently,  the Company is
defining the prospects by  geophysics.  Work  completed to date  indicates  that
seven of the prospects justify drilling. The Company estimates that the drilling
costs (excluding  completion  costs) of the seven prospects would be $1,625,000.
However, as most of these wells would be wildcat wells (exploratory  wells), the
Company plans to reduce its risk by selling or farming out part of its interest.
The timing of the  drilling is dependent  on the  availability  of funds and the
Company  anticipates  that its average net cost per well  (assuming a farmout or
sale) would be approximately  $75,000, or a total of $525,000,  for drilling and
completion costs.

         The  Company's  main  producing  properties  are  located in the Peejay
fields in British  Columbia.  Although these fields have been producing for over
20  years,  there  is  still  the  potential  for  additional   exploration  and
development.  The  1993  sale  of  the  field  by the  majority  owner  and  the
appointment of a new operator  resulted in new field  activity.  The most recent
developments  have included new work programs in the West Peejay and Peejay Unit
#3 areas, as well as, the nearby Beaverdam area.


<PAGE>


         At West Peejay a water flood was initiated in 1997 and three wells were
drilled  resulting in three new oil wells and one existing well was converted to
a water injector.  This will increase the allowable production in the field from
359 bpd to 503 bpd. The Company has an  approximate  14% interest in the oil and
gas production.

         The Peejay Unit #3 in which the Company has a 10.18%  interest has been
declining for several years and the operator has proposed  producing part of the
gas cap concurrent with the oil production.  One development well was drilled in
1997 and is now producing oil.

         In the  Beaverdam  area  the  operator  has  indicated  plans  to drill
additional  wells to  follow  up the 3 wells  drilled  in the  1993/1994  winter
drilling season.

         As of December  31,  1997,  the Company held approximately 18,732 gross
acres  (4,434  net  acres)  in  this  area.   The Company  owns  interest in the
following units:

                                       Unit                            Company
                                      Acreage                             %
Peejay Unit #1                         4,529                            3.1643
Weasel Unit #2                         1,569                           15.4136
Peejay Unit #3                         5,923                           10.1775

         The Company  also holds  interests in 10 oil wells (2.64 net wells) and
10 gas wells.  (2.28 net wells) not  included  in the above  units.  The Company
estimates that the capital costs for its interests in the West Peejay field will
aggregate approximately $200,000 for 1998.

         In the Paradise area, one well that was drilled and completed as an oil
well in 1997 proved to be  non-commercial.  Another oil well,  which was drilled
under a farmout arrangement,  is currently suspended. An additional farmout well
which was drilled in late 1997 has been plugged and abandoned.

         The Company also has interests at Buick Creek,  Wargen and Siphon.  The
Siphon and Wargen fields have new operators.  As these properties are held under
the  carried  interest  agreements,  the  Company  is not aware of any  proposed
exploration  and  development  plans for these  properties,  but anticipates the
change of  operator  will  cause new work to be done.  In late  1997,  there was
activity in the Siphon field, but the Company has no information on the results.



<PAGE>


Arctic Islands

         As of December 31, 1997,  the Company held working  interests in 45,100
gross  acres  (1,817 net acres) and  carried  interests  in 133,260  gross acres
(37,255 net acres) in the Sverdrup  Basin,  located in the Arctic  Islands.  The
Hecla, Whitefish,  Drake Point, Roche Point,  Kristoffer,  Romulus and Bent Horn
fields have been designated  significant discovery lands ("SDL" ) by the Federal
Government.  The  Company's  interests in the SDL's have been  retained  pending
development.

         Panarctic  Oils Ltd.  ("Panarctic"),  the  operator,  received  Federal
government  regulatory  approvals for a pilot project to move shipments of crude
oil from the Bent Horn field by tanker through the Northwest Passage to southern
Canada in 1985. Through December 31, 1996,  approximately 2.7 million barrels of
Bent Horn crude had been sold with  deliveries  being made at northern  Canadian
and  European  markets as well as the  eastern  seaboard  market.  In 1996,  the
operator  decided  to shut down  production  from the field  and  dismantle  the
production  facilities because of economic  uncertainties.  The Company has a 5%
carried interest in the area which has not yet reached payout status. The timing
of any payout is uncertain.

Northwest Territories Properties

         The Company has a 45% carried interest in the Northwest  Territories in
the Celibeta  field  designated as  Significant  Discovery  Lands ("SDL") by the
Federal  Government  (1,594  gross  acres and 717 net  acres).  The gas field is
presently shut-in.

Alberta

         In 1997,  the Company  participated  in 19 wells on the  Alberta  lands
which resulted in 11 oil wells, 4 gas wells, 2 water disposal wells, 1 suspended
well and 1 dry hole.

         In 1994,  the Company  purchased a 5% working  interest in the Kitscoty
heavy oil field and the  related  facilities.  Oil  recovery  from this field is
being  enhanced  by steam  injection.  Two  horizontal  holes were  drilled  for
production with the steam being injected through vertical holes.

         In 1996, the Company purchased an additional 5% working interest in the
Kitscoty field.  Three more wells were drilled in 1996, two horizontal wells and
one  vertical  well.  All the wells  encountered  oil and were  completed as oil
wells.  One well  also  discovered  three  potential  gas  zones  which  will be
evaluated for future use as fuel for the steam generation  needed to enhance the
oil production.  Scheduled remedial work programs have been postponed pending an
increase in the current low  netbacks on heavy oil.  Additional  work at the new
Lloydminister  heavy oil discovery at 16-2-51-2 W4M has also been  postponed for
this reason.


<PAGE>


         During 1997,  the Company  joined in drilling 11 additional  horizontal
wells to  develop  a  glauconite  heavy  oil  (14(degree)  API)  project  in the
Atlee/Majestic  area. A multitude of production  problems  occurred which caused
numerous delays.  By year end,  although only 8 of 13 wells were on-stream,  the
field was  producing  1,000 bpd. In addition,  the Company  participated  in two
stratigraphic  tests to  calibrate  and verify the 3D seismic.  These wells were
later completed as water disposal wells. New production facilities are scheduled
for  completion  in April 1998  which  should  resolve  the  current  production
problems.

         At year end, the Company and its partner, Probe Exploration, Inc., were
negotiating to purchase additional prospective lands in the Atlee/Majestic area.

         At Leduc in 1996,  three wells were drilled of which two were completed
as oil and gas  wells  and one well was a dry  hole.  One well  encountered  two
potential producing zones and is currently producing at the allowable rate of 68
bpd.  The Company has a 15% working  interest in these  wells.  In 1997, a three
well  program  resulted  in 2 gas wells and 1 dry hole.  The two gas wells  were
recently tied in at 1 Mmcf/d each.

         The  Company  also  acquired a 10-20%  working  interest in over 12,000
acres in four other areas of Alberta. These lands were purchased on the basis of
seismic  work  which  showed  a number  of  promising  prospects.  Subsequently,
additional seismic work has confirmed the potential of those prospects.  One was
drilled in 1997 and completed as a potential gas well. A second well was drilled
in early 1998 and completed as an oil well.

         In Alberta,  the Company  currently has working  interests ranging from
10% to 100% in a total of 5,690 gross (729 net) developed acres and 31,514 gross
(7,989 net) undeveloped acres.

Saskatchewan

         The  Company  has  a  3.75%  working   interest  in  five  sections  in
Saskatchewan.  During 1997, three wells were drilled on the lands resulting in 2
dry holes and 1 shut-in gas well.

Australia

         Effective  November 1, 1997, the Company sold its .08% working interest
in 115,596 gross (90 net) acres in the Amadeus  Basin in the Northern  Territory
in  Australia  for $3,000 to  Magellan  Petroleum  Australia  Limited  ("MPAL").
Because of the limited potential of the only remaining  property,  the Dingo gas
field,  the interest was written down to a nominal value in 1992.  The Dingo gas
field is a shut-in gas field which is not connected to a gas pipeline.


<PAGE>


United States

         Texas

         In 1996 and 1997, the Company  participated  in the drilling of 4 wells
in Texas  resulting  in 4 potential  oil wells.  Two wells are  shut-in  pending
remedial  work and two wells are  currently  producing.  Based on the results of
these  wells  in which it has a  relatively  small  interest,  the  Company  has
commenced a leasing  program  and has  acquired 4 leases on which it plans to do
seismic in 1998.  The Company  will have a 100%  working  interest  initially in
these leases.

         California

         During March 1998,  the Company  agreed to  participate  with two other
companies in a heavy oil recovery project in California.  The field is estimated
to have  approximately  12 million  barrels of oil in place with only 13% of the
oil recovered to date.  The initial  purchase price for a 90% (75% APO) interest
in the  project  is  $200,000  (Company  share 30% -  $60,000).  There is also a
commitment  to spend  $600,000  to  perform  remedial  work on the  field and to
complete a pilot  stream  flood  program  during  the first year of the  project
(Company  share  $180,000).  If the total  amount of  expenditures  is less than
$600,000,  the  participants'  interests will be reduced  proportionately  to an
amount which is not less than 10% (Company share - 3%).

         (b)      Financial Information about Industry Segments

         Since the Company is primarily  engaged in only one  industry,  oil and
gas exploration and development, this item is not applicable to the Company. See
Item 8 for general financial information concerning the Company.

         (c)      (1)      Narrative Description of the Business

                  The  Company  was   incorporated  in  1954  under  the  Canada
Corporations   Act.  In  1979,  it  became  subject  to  the  Canadian  Business
Corporations Act and in 1980, was continued under the Nova Scotia Companies Act.

         The Company is,  either in its own right,  or through  other  entities,
engaged in the  exploration  for and  development  of  properties  containing or
believed to contain recoverable oil and gas reserves and the sale of oil and gas
from these properties.  Although many of the properties in which the Company has
interests are undeveloped,  all properties with proved reserves are partially or
fully  developed.  The  Company's  interests  in  exploratory  ventures  are  on
properties located in Alberta,  British Columbia, the Northwest Saskatchewan and
Yukon  Territories and the Arctic Islands in Canada and in the United States.  A
principal  asset of the  Company is its 30% carried  interest in the  Kotaneelee
field, a partially  developed gas field (See Item 3 - "Legal  Proceedings".) The
Company  also has  interests  in producing  properties  in British  Columbia and
Alberta.  Most of this acreage is covered by carried interest agreements,  which
provide that revenues are not payable to the Company until  expenditures  by the
carrying  partners  have  been  recouped  from  production,  and that  operating
decisions are made by the carrying partners.  Generally, the Company may, at any
time,  as to each  block or  economic  unit,  elect to  convert  from a  carried
interest  position  to a working  interest  position  by paying its share of the
unrecouped  expenditures  for the unit,  i.e.,  expenditures  not recouped  from
production  revenues.  At December 31, 1997,  the Company's  share of unrecouped
expenditures were as follows:

         British Columbia:
           Ex-permit 149                                              $3,186,000

         Yukon and Northwest Territories:
           Ex-permit 1007 (Kotaneelee)*                               $5,942,000
           Ex-permit 2713 (Celibeta)                                    $321,000

         *See Item 3 - Legal Proceedings

                          (i)      Principal Products

                                   The majority of the  Company's  interests are
carried  interests.  The Company also participates in the production and sale of
crude  oil,  natural  gas and  natural  gas  liquids  derived  from its  working
interests.

                          (ii)     Status of Product or Segment

                                   At present,  some of the  properties in which
the Company has interests are undeveloped and/or nonproducing.

<PAGE>

                          (iii)    Raw Materials

                                   Not applicable.

                          (iv)     Patents, Licenses, Franchises and Concessions
                                   Held

                                   Permits and concessions are important  to the
Company's operations, since they allow the search for and extraction of any oil,
gas and minerals discovered on the areas covered.  See the  detailed schedule of
properties under Item 2, "Properties."

                          (v)      Seasonality of Business

                                   The  Company's  business   is  not  seasonal,
except  that  sales  of  natural gas  peak during  the  winter  heating  season.
Exploration  and  development  activities  are  restricted in certain areas on a
seasonal basis because extreme weather conditions affect  transportation and the
ability to pursue these activities.

                          (vi)     Working Capital Items

                                   Not applicable.

                          (vii)    Customers

                                   Substantially  all  oil  production  from the
Company's properties for the current year was purchased by CNRL, the operator of
the majority of the producing properties.  Most of the natural gas produced from
Company properties was sold by the operator, Petro Canada, to a company owned by
certain British  Columbia gas producers,  CanWest Gas Supply Inc. The production
from the Kotaneelee gas field is also being sold to CanWest Gas Supply, Inc.

                          (viii)   Backlog

                                   Not applicable.

                          (ix)     Renegotiation of Profits or Termination of
                                   Contracts or Subcontracts at the Election of
                                   the Government

                                   Not applicable.

                          (x)      Competitive Conditions in the Business

                                   The exploration for and production of oil and
gas are highly  competitive  operations,  both internally within the oil and gas
industry and externally with producers of other types of energy.  The ability to
exploit a discovery of oil or gas is dependent upon  considerations  such as the
ability to  finance  development  costs,  the  availability  of  equipment,  and
engineering and construction  delays and difficulties.  The Company must compete
with companies which have  substantially  greater  resources  available to them.
Because the majority of Company interests are in remote areas,  operation of its
properties is more difficult and costly than in more accessible areas.

                                   Furthermore,  competitive  conditions  may be
substantially  affected by various  forms of energy  legislation  which may have
been or may be proposed  in the United  States and  Canada;  however,  it is not
possible to predict the nature of any such  legislation  which may ultimately be
adopted or its effects upon the future operations of the Company.  For a further
discussion of Canadian  governmental  regulation of the petroleum industry,  see
Item 1(d)(2).

                          (xi)     Research and Development

                                   Not applicable.



<PAGE>


                          (xii)    Environmental Regulation

                                   In the  exploration  for  and  development of
natural   resources,   the  Company  is  required  to  comply  with  significant
environmental laws and regulations which add to the expense of those activities.
The Company has not been required to spend significant sums to comply with clean
up laws and regulations.  Compliance by the Company with governmental provisions
regulating the discharge of materials to the  environment or otherwise  relating
to the protection of the  environment are not expected to have a material effect
on the capital  expenditures,  earnings or competitive  position of the Company.
(xiii) Number of Persons Employed by Company

                                   The  Company  currently  has three  full time
employees, all of whom are located in Canada. The Company also relies to a great
extent on consultants  (approximately 10) for technical,  legal,  accounting and
administrative  services.  The Company uses consultants  because it is more cost
effective than employing a larger full time staff.

         (d)      Financial Information about Foreign and Domestic Operations
                  and Export Sales

                  (1)      Identifiable Assets

                           Substantially all of the Company's  operating  assets
and revenues are attributable to its operations in Canada.

                  (2)      Risks Attendant to Foreign Operations

                           The properties in which the Company has interests are
located  primarily  in Canada and are subject to certain  risks  involved in the
ownership  and  development  of such  foreign  property  interests.  These risks
include  but  are not  limited  to  those  of:  nationalization;  expropriation;
confiscatory  taxation;  native rights;  changes in foreign  exchange  controls;
currency  revaluation;  burdensome  royalty  terms;  export sales  restrictions;
limitations on the transfer of interests in exploration licenses; and other laws
and regulations  which may adversely  affect the Company's  properties,  such as
those providing for conversion, proration, curtailment, cessation or other forms
of limiting or  controlling  production of, or  exploration  for,  hydrocarbons.
Thus, an  investment in the Company  represents an exposure to risks in addition
to those inherent in petroleum exploratory ventures.

Governmental Regulation of the Canadian Oil and Natural Gas Industry

         The oil and  natural  gas  industry  in Canada is subject to  extensive
controls and  regulations  imposed by various  levels of government  relating to
land  tenure,   production,   production  facilities,   pricing  and  marketing,
royalties,  environmental protection and other matters.  Outlined below are some
of the more significant  aspects of the legislation,  regulations and agreements
governing the oil and natural gas industry in Canada. All current legislation is
a matter of public  record  and the  Company is unable to  predict  whether  any
additional legislation or amendments may be enacted.


<PAGE>

Land Tenure

         Crude oil and natural gas  located in the  western  provinces  is owned
predominantly by the respective provincial  governments.  Provincial governments
grant  rights to explore for and produce oil and natural gas pursuant to leases,
licenses  and  permits  for  varying  terms  from two  years  and on  terms  and
conditions set forth in provincial legislation including requirements to perform
specific work or make  payments.  Oil and natural gas located in such  provinces
can also be  privately  owned and rights to explore for and produce such oil and
natural  gas are  granted  by  lease  on such  terms  and  conditions  as may be
negotiated.  The term of both Crown and freehold leases will generally  continue
as long as oil or natural gas is produced from the property.

         Oil and natural gas rights on federal lands outside of the provinces is
generally  regulated  by the  Government  of Canada  unless  authority  has been
delegated by agreement to the  territorial  government or the  government of the
province  adjacent to the federal  offshore  area. In May 1993, the Canada Yukon
Oil and Gas Accord  was signed  which  allows for the  transfer  to the Yukon of
authority to administer  and control oil and natural gas  resources  within that
territory and for the  establishment  of an Oil and Gas Management  Regime.  The
National  Energy Board ("NEB") is working with Yukon officials to facilitate the
transfer of oil and natural gas regulatory  responsibilities  in accordance with
the Yukon Accord Implementation Agreement.

Production and Production Facilities

         The Governments of Canada,  Alberta,  British Columbia and Saskatchewan
have enacted statutory  provisions  regulating the production of oil and natural
gas. These regulations may restrict the maximum allowable production from a well
based on reservoir engineering and/or conservation  practices.  The construction
and  operation of facilities to recover and process oil and natural gas are also
subject to regulation.

Pricing and Marketing - Oil

         In Canada, producers of oil negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of oil. Certain
purchasers  periodically  advertise  for  volumes  of oil they are  prepared  to
purchase and the price being offered for such volumes. The price depends in part
on oil quality,  prices of competing fuels,  distance to market and the value of
refined  products.  Oil exports may be made  pursuant to export  contracts  with
terms not exceeding  one year in the case of light crude,  and not exceeding two
years in the case of heavy  crude,  provided  that an order  approving  any such
export has been  obtained  from the NEB. Any oil export to be made pursuant to a
contract of longer  duration  requires  an exporter to obtain an export  license
from the NEB and the  issue  of such a  license  requires  the  approval  of the
Governor in Council.



<PAGE>


Pricing and Marketing - Natural Gas

         In  Canada,  the price of  natural  gas is  determined  by  negotiation
between buyers and sellers, with the result that the market determines the price
of natural gas. Natural gas exported from Canada is subject to regulation by the
NEB and the  Government of Canada.  Exporters  are free to negotiate  prices and
other terms with purchasers, provided that the export contracts must continue to
meet certain criteria  prescribed by the NEB and the Government of Canada. As is
the case with oil, natural gas exports for a term of less than two years must be
made pursuant to an NEB order, or, in the case of exports for a longer duration,
pursuant to an NEB license and Governor in Council approval.

         The  Governments of Alberta,  British  Columbia and  Saskatchewan  also
regulate the volume of natural gas which may be removed from those provinces for
consumption   elsewhere   based  on  such   factors  as  reserve   availability,
transportation arrangements and market considerations.

Royalties and Incentives

         The royalty regime is a significant  factor in the profitability of oil
and natural gas  production.  Royalties  payable on production  from lands other
than Crown lands are  determined by  negotiations  between the mineral owner and
the  lessee,  although  production  from  such  lands  may  also be  subject  to
provincial taxes and  regulations.  Crown royalties are determined by government
regulation  and are  generally  calculated  as a percentage  of the value of the
gross production, and the rate of royalties payable generally depends in part on
prescribed  reference prices, well productivity,  geographical  location,  field
discovery date and the type or quality of the product produced. The value of the
gross  production  for royalty  purposes  may be based on a deemed value for the
product rather than the actual value received by the interest holder.

         From time to time the Governments of Canada, Alberta,  British Columbia
and Saskatchewan have established incentive programs which have included royalty
rate reductions, royalty holidays and tax credits for the purpose of encouraging
natural gas and oil exploration or enhanced  recovery  projects.  Incentives are
intended to enhance the  existing  cash flow of the oil and natural gas industry
and to improve the economics of finding and  developing  new and more costly oil
and natural gas reserves.  Oil royalty  holidays for specific  wells and royalty
reductions  reduce the amount of Crown  royalties paid by the interest holder to
the  respective  government.  Tax  credit  programs  provide  a rebate  on Crown
royalties paid.



<PAGE>


Environmental Regulation

         The oil and natural gas industry is subject to environmental regulation
pursuant to local, provincial and federal legislation. Environmental legislation
provides for restrictions  and prohibitions on spills,  releases or emissions of
various  substances  produced in  association  with  certain oil and natural gas
industry  operations.  An  environmental  assessment  and review may be required
prior  to  initiating   exploration  or  development   projects  or  undertaking
significant changes to existing projects. In addition, legislation requires that
well and facility  sites be abandoned and reclaimed to the  satisfaction  of the
appropriate  authorities.  A  breach  of  such  legislation  may  result  in the
imposition of fines or penalties.  Federal environmental  regulations also apply
to the use and transport of certain  restricted and prohibited  substances.  The
Company is committed to meeting its  responsibilities to protect the environment
wherever  it  operates  and  believes  that it is in  material  compliance  with
applicable environmental laws and regulations. The Company has not been required
to  spend  significant  sums to  comply  with  clean  up laws  and  regulations.
Compliance by the Company with governmental  provisions regulating the discharge
of materials to the  environment or otherwise  relating to the protection of the
environment  are  not  expected  to  have  a  material  effect  on  the  capital
expenditures, earnings or competitive position of the Company.

         (3)      Data which Are Not Indicative of Current or Future Operations

                  Not applicable.

Item 2.  Properties

         (a)  The principal asset of the Company is its 30% carried  interest in
the Kotaneelee  field, a partially  developed gas field in the Yukon  Territory.
See Item 3. "Legal  Proceedings."  The Company  also has  interests in producing
properties in British Columbia and Alberta and in several exploration prospects.
These  interests are in exploratory  ventures in properties  located in Alberta,
Saskatchewan,  the Northwest Territories and the Arctic Islands in Canada and in
the United  States.  Geophysical,  geological and drilling work on the Company's
properties  is conducted by the  operators  under  various  agreements  with the
Company.  The  results  of this  work are  reviewed  by  Company  personnel  and
consultants retained by the Company.

         (b)  (1)  The  information  regarding  reserves,  costs  of oil and gas
activities,  capitalized costs,  discounted future net cash flows and results of
operations  is  contained in Item 8.  "Financial  Statements  and  Supplementary
Data."



<PAGE>











The following  graphic  presentation  has been  omitted,  but the following is a
description of the omitted material:




                  Map of Canada showing key Company properties


<PAGE>











The following  graphic  presentation  has been  omitted,  but the following is a
description of the omitted material:




          Map of N.E. British Columbia and Yukon, Northwest Territories
                         showing Company interest lands


<PAGE>











The following  graphic  presentation  has been  omitted,  but the following is a
description of the omitted material:




                        Map showing the Kotaneelee Field


<PAGE>











The following  graphic  presentation  has been  omitted,  but the following is a
description of the omitted material:




                         Map of the Arctic Island Fields
                       showing the Company interest lands


<PAGE>


(2)      Reserves Reported to Other Agencies

         Not applicable.

(3)      Production

         Average  sales price per unit and average  production  cost for oil and
gas produced during the periods shown below are as follows:


                 Average Sales Price                Average Production Costs
Year      Oil (per bbl.)     Gas (per mcf.)    Oil (per bbl.)     Gas (per mcf.)
                ($)                ($)               ($)                ($)
1997           22.50               2.31              8.70               1.30
1996           25.47               1.64              8.67                .79
1995           22.39               1.30             10.08                .77

(4)      Productive Wells and Acreage

         Productive wells and acreage on working and carried interest properties
as of December 31, 1997:

              Gross Wells                                       Net Wells
         Oil               Gas                            Oil              Gas
         90                89                            14.43            15.71

                                            Gross and Net Developed Acres
                                       Gross Acres                   Net Acres

          Alberta                          5,690                         729
          Saskatchewan                       640                          24
          British Columbia                67,058                      11,729
          Yukon Territory                  3,350                       1,005
          Arctic Islands                   3,060                         153
          Texas, USA                         160                          33
                                          ------                      ------
                                          79,958                      13,673
                                          ======                      ======



<PAGE>


(5)      Undeveloped Acreage

         Total  developed  and  undeveloped  acreage  in which the  Company  has
interests is summarized by geographic area in the table below:

             Gross and Net Petroleum Acreage as of December 31, 1997
                                     Developed Acres         Undeveloped Acres
                                  ---------------------   ----------------------
                                   Gross     Net            Gross     Net
                                   Acres    Acres    %      Acres    Acres    %
                                   -----    -----           -----    -----
Canada:
  British Columbia:
    Carried Interests             28,592    6,043  21.1     6,415    1,363  21.2
    Working Interests             20,266    4,897  24.2    39,347   13,239  33.6
    Overriding royalty interest   18,200      789   4.3     2,189       30   1.4
                                  ------   ------         -------   ------
  Total British Columbia          67,058   11,729          47,951   14,632
                                  ------   ------         -------   ------

  Saskatchewan:
    Working Interests                640       24   3.8     2,560       96   3.8
                                  ------   ------         -------   ------

  Alberta:
    Working Interests              4,410      715  16.2    30,874    7,906  25.6
    Overriding Royalty Interest    1,280       14   1.1       640       83  13.0
                                  ------   ------         -------   ------
  Total Alberta                    5,690      729          31,514    7,989
                                  ------   ------         -------   ------

  Yukon & Northwest Territories:
    Carried Interests              3,350    1,005  30.0    31,726    9,757  30.8

  Arctic Islands:
    Carried Interests              3,060      153   5.0   128,670   37,027  28.8
    Working Interests                  -        -          45,100    1,817   4.0
                                  ------   ------         -------   ------
  Total Arctic Islands             3,060      153         173,770   38,844
                                  ------   ------         -------   ------

  Total Canada                    79,798   13,640         287,521   71,318

Texas, USA                           160       33  20.6         -        -
                                  ------   ------         -------   ------

               TOTAL              79,958   13,673         287,521   71,318
                                  ======   ======         =======   ======

(6)      Drilling activity

         Productive and dry net wells drilled during the following periods:

                                Gross                               Net
                       ---------------------             -----------------------
         Year          Productive        Dry             Productive          Dry
         1997              25             2                3.606            .250
         1996              10             2                1.044            .150
         1995               1             3                 .033            .258


<PAGE>


(7)      Present Activities

         There was one well drilling at December 31, 1997.

(8)      Delivery Commitments

         None.

Item 3.  Legal Proceedings

         The  Company,  which has a 30%  interest in the  Kotaneelee  gas field,
believes  that the  working  interest  owners in the field  have not  adequately
pursued the  attainment of contracts for the sale of Kotaneelee  gas. In October
1989 and in March 1990,  the Company  filed  statements of claim in the Court of
Queens  Bench of Alberta,  Judicial  District of  Calgary,  Canada,  against the
working interest partners in the Kotaneelee gas field. The named defendants were
Amoco Canada  Petroleum  Corporation,  Ltd.,  Dome Petroleum  Limited (now Amoco
Canada Resources Ltd.), and Amoco Production  Company  (collectively  the "Amoco
Dome Group"),  Columbia Gas Development of Canada Ltd.  ("Columbia"),  Mobil Oil
Canada Ltd.  ("Mobil") and Esso Resource of Canada Ltd.  ("Esso")  (collectively
the "Defendants").

         The  Company  claims  that the  Defendants  breached  either a contract
obligation  or a  fiduciary  duty owed to the  Company  to  market  gas from the
Kotaneelee  gas field when it was  possible to so do. The Company  asserts  that
marketing  the  Kotaneelee  gas was  possible  in 1984 and  that the  Defendants
deliberately failed to do so. The Company seeks money damages and the forfeiture
of the  Kotaneelee  gas field.  The  Company  expects to argue at trial that the
money damages sustained by the Company are at least $86 million.

         In  addition,  the  Company  has  claimed  that the  Company's  carried
interest  account  should be reduced  because of the negligent  operation of the
field and improper  charges to the carried  interest  account by the Defendants.
The Company claims that when the Defendants in 1980  suspended  production  from
the field's gas wells, they failed to take  precautionary  measures necessary to
protect and maintain the wells in good operating condition. The wells thereafter
deteriorated,  which caused unnecessary  expenditures to be incurred,  including
expenditures  to  redrill  one  well.  In  addition,  the  Company  claims  that
expenditures made to repair and rebuild the field's dehydration plant should not
have been necessary had the facilities been properly  constructed and maintained
by the Defendants.  The expenditures,  the Company claims, were  inappropriately
charged to the field's  carried  interest  account.  The effect of an  increased
carried  interest  account is to extend the period  before  payout begins to the
carried interest account owners.


<PAGE>


         The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million.  The Company  claims  that by 1993 at least $34 million of  unnecessary
expenses  had been  wrongfully  charged to the  carried  interest  account.  The
Company's 30% share of these expenses would be approximately $10.2 million.  The
Company  further  claims that if production  had commenced in 1984,  the carried
interest  account  would have been paid off in  approximately  two years and the
Company would have begun to receive revenues from the field in 1986. At present,
the Company does not expect to receive revenues before the year 2000, based on a
price of Cdn. $1.39 per mcf and current production rates.

         Columbia has filed a counterclaim  against the Company seeking,  if the
Company is  successful in its claim for the  forfeiture of the field,  repayment
from the  Company of all sums  Columbia  has  expended on the  Kotaneelee  lands
before the Company is entitled to its interest.

         The parties to the litigation have conducted  extensive discovery since
the filing of the claims.  The trial began on  September 3, 1996 and is ongoing.
Based upon recently  discovered  evidence,  the Company has petitioned the court
for leave to amend its  complaint to add a claim that the  Defendants  failed to
develop the field in a timely manner. The Company is unable to estimate the time
necessary to conclude the litigation.

Matters Ancillary to Kotaneelee Litigation

         In its 1989  statement  of  claim,  the  Company  sought a  declaratory
judgment regarding two issues:

         (1)      whether interest accrued on the carried interest account; and

         (2)      whether  expenditures  for  gathering  lines  and  dehydration
                  equipment are expenditures  chargeable to the carried interest
                  account or whether the Company  will be assessed a  processing
                  fee on gas throughput.

         With respect to the first issue, the Company maintains that no interest
should  accrue  on the  account  and the  Defendants  have  not  contested  this
position.  With  regard to the second  issue,  the  Company  maintains  that the
expenditures are chargeable to the carried  interest  account.  Mobil,  Esso and
Columbia have essentially  agreed to the Company's position while the Amoco Dome
Group continues to contest this issue.



<PAGE>


         On January 22, 1996, the Company settled two claims outstanding against
the Company in the Court of Queens Bench, Calgary,  Alberta,  which related to a
suit brought against  AlliedSignal  Inc.  ("AlliedSignal")  in Florida which was
dismissed on the basis that Canada was the appropriate forum for the litigation.
AlliedSignal  had sought  additional  relief  against  the  Company in Canada to
preclude  other  types of suits by the  Company  and to recover the costs of the
defense of the initial  action.  The settlement bars  AlliedSignal from making a
claim  against  the  Company  for any costs in  connection  with the  Kotaneelee
Litigation.  The Company agreed not to bring any action against  AlliedSignal in
connection  with the  Kotaneelee  gas field.  Neither  party  made any  monetary
payment to the other party.

         In 1991,  Anderson  Exploration  Ltd.  acquired  all of the  shares  in
Columbia and changed its name to Anderson Oil & Gas Inc. ("Anderson").  Anderson
is now the sole operator of the field and is a direct  defendant in the Canadian
lawsuit.  Columbia's  previous parent, The Columbia Gas System,  Inc., which was
reorganized in a bankruptcy  proceeding in the United States,  is  contractually
liable to Anderson in the legal proceeding described above.

         The working  interest  owners have reported that they have been selling
Kotaneelee gas since February 1991.

         Under  Canadian  law certain  costs  (known as "taxable  costs") of the
litigation  may be  assessed  against the  nonprevailing  party.  Taxable  costs
consist  primarily of attorney's and expert witness fees during trial. The trial
is presently scheduled to last twelve months, therefore,  taxable costs could be
substantial. While taxable costs are not now determinable, the Company estimates
that taxable costs,  assuming a twelve month trial,  could be approximately $1.5
million.  However,  a judge in complex and lengthy  trials has the discretion to
increase  an award of  taxable  costs.  There are no  assurances  however,  that
taxable costs will not exceed this amount or that the duration of the trial will
not  exceed  twelve  months.  The  actual  trial  time  through  March  1998  is
approximately  5 months.  During 1997,  the Company was  assessed  approximately
$110,000 in taxable  costs  payable to the  Defendants  in  connection  with the
Company's motion to disqualify Amoco's legal counsel which was denied.
The amount is included in 1997 legal expenses.

         There is no assurance  whatever  that the Company will be successful on
the merits of its claims, which have been vigorously defended by the Defendants.
There is also no  assurance  that the Company  will be awarded any  damages,  or
that,  if damages are  awarded,  the Court will apply the measure of damages the
Company claims should be applied.



<PAGE>


Item 4.  Submission of Matters to a Vote of Security Holders

         Not applicable.

Executive Officers of the Company

         The following information with respect to the executive officers of the
Company is furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.

                                               Length of         Other Positions
                                                Service             Held with
       Name       Age      Office           in this Office           Company

M. A. Ashton      62       President      Since June 4, 1997         Director

         All  officers  of the  Company  are  elected  annually  by the Board of
Directors and serve at the pleasure of the Board of Directors.

         The Company is aware of no  arrangement  or  understanding  between the
individual named above and any other person pursuant to which any individual was
selected as an officer.



<PAGE>


                                     PART II

Item 5.  Market for the Company's Limited Voting Shares and Related
         Stockholder Matters

         (a)      Principal Markets

         The Company's  Limited  Voting Shares,  par value $1.00 per share,  are
traded on The Toronto Stock Exchange and the Pacific and Boston Stock Exchanges,
and in the NASDAQ SmallCap market.

         The quarterly high and low closing prices (in Canadian  dollars) on The
Toronto Stock Exchange during the calendar periods indicated were as follows:

1996          1st quarter       2nd quarter        3rd quarter       4th quarter
----          -----------       -----------        -----------       -----------
High            11.25             11.50              11.55              10.25
Low              7.75              8.00               8.50               8.50


1997          1st quarter       2nd quarter        3rd quarter       4th quarter
----          -----------       -----------        -----------       -----------
High            11.00             12.50              16.60              15.00
Low              8.50              7.50              12.25              10.75

         The quarterly high and low closing prices (in United States dollars) on
the  Pacific  Stock  Exchange  during the  calendar  periods  indicated  were as
follows:

1996          1st quarter       2nd quarter        3rd quarter       4th quarter
----          -----------       -----------        -----------       -----------
High             8 1/8             8 1/4              8 1/2             7 5/8
Low                6               6 1/8              6 3/8             6 1/2


1997          1st quarter       2nd quarter        3rd quarter       4th quarter
----          -----------       -----------        -----------       -----------
High               8                 9              11 15/16              11
Low              6 1/2             5 3/4             8 13/16             7 1/4



<PAGE>


         (b)      Approximate Number of Holders of Limited Voting
                  Shares at March 23, 1998

                                                              Approximate
         Title of Class                                Number of Record Holders

      Limited Voting Shares, par value
      $1.00 per share.                                           6,100

         (c)      Dividends

         The Company has never paid a dividend on its Limited Voting Shares. Any
future  dividends  will  be  dependent  on  the  Company's  earnings,  financial
condition, and business prospects. The Company is legally restricted from paying
any  dividend  or making  any other  payment to  shareholders  (except by way of
return of capital) on the Limited  Voting Shares until its  accumulated  deficit
($21,142,464 at December 31, 1997) is eliminated.

         Current  Canadian law does not restrict the  remittance of dividends to
persons not resident of Canada.  Under  current  Canadian tax law and the United
States-Canada tax treaty, any dividends paid to U.S.  shareholders are currently
subject to a 15% Canadian withholding tax.



<PAGE>


Item 6.           Selected Financial Data

         The following selected consolidated financial information (in thousands
except per share and exchange rate data) of the Company insofar as it relates to
each  of the  fiscal  periods  shown  has  been  extracted  from  the  Company's
consolidated financial statements.

<TABLE>
<CAPTION>
                                                                         Year ended December 31,
                                         -------------------------------------------------------------------------------------------
                                            1997               1996                1995               1994               1993
                                            ----               ----                ----               ----               ----
                                             ($)                ($)                ($)                 ($)                ($)

<S>                                         <C>                <C>                <C>                 <C>                <C>
Operating revenues                           2,120              1,755              1,657               1,691              1,915
                                            ======             ======             ======              ======             ======

Total revenues                               2,515              2,228              1,793               1,942              2,103
                                            ======             ======             ======              ======             ======

Net loss                                    (1,758)            (1,461)            (1,162)             (1,210)              (977)
                                            ======             ======             ======              ======             ======

Net loss per share                           (.12)              (.11)              (.09)               (.10)              (.08)
                                            ======             ======             ======              ======             ======

Working capital                              5,573              8,403              1,510               2,417              3,890
                                            ======             ======             ======              ======             ======

Total assets                                20,956             20,375             12,380              13,390             14,484
                                            ======             ======             ======              ======             ======

Shareholders' Equity:
     Capital stock                          40,489             38,888             29,635              29,513             29,513
     Deficit                               (21,143)           (19,385)           (17,923)            (16,762)           (15,552)
                                            ------             ------             ------              ------             ------
                                            19,346             19,503             11,712              12,751             13,961
                                            ======             ======             ======              ======             ======
Average number of
  shares outstanding                        14,084             13,362             12,622              12,613             12,453
                                            ======             ======             ======              ======             ======

Exchange rates:
     Year-end                               .6992              .7297              .7329               .7129              .7554
                                            =====              =====              =====               =====              =====

     Average for the period                 .7224              .7335              .7289               .7324              .7757
                                            =====              =====              =====               =====              =====

     Range                               .6947-.7482        .7234-.7520        .7026-.7480         .7098-7634         .7436-.8045
</TABLE>

U.S. GAAP Information

Under U.S. generally accepted accounting principles ("GAAP"), the above selected
information  would be as follows (See Note 6 in Notes to Consolidated  Financial
Statements):

<TABLE>
<CAPTION>
<S>                                       <C>                <C>                 <C>               <C>                    <C>
Net loss                                  (1,588)            (1,236)             (1,001)           (1,140)                (673)
                                          =======            =======             =======           =======                =====
Net loss per share                         (.11)              (.09)               (.08)             (.09)                 (.05)
                                           =====              =====               =====             =====                 =====
</TABLE>

<PAGE>


Item 7.  Management's Discussion and Analysis of Financial Condition
         and Results of Operations

(1)      Liquidity and Capital Resources

         Statements   included  in  Management's   Discussion  and  Analysis  of
Financial Condition and Results of Operations which are not historical in nature
are intended to be, and are hereby  identified as, "forward looking  statements"
for  purposes  of the  "Safe  Harbor"  Statement  under the  Private  Securities
Litigation Reform Act of 1995. The Company cautions readers that forward looking
statements  are  subject to certain  risks and  uncertainties  that could  cause
actual results to differ  materially from those indicated in the forward looking
statements.

         At December 31,  1997,  the Company had  approximately  $5.5 million of
cash and securities  available.  These funds are expected to be used for general
corporate  purposes,  including  exploration and development and to continue the
Kotaneelee field litigation.  The Company estimates that it has adequate working
capital for 1998 and 1999 and may be required to raise  additional funds through
the sale of  properties  or other  means in  order to  complete  the  Kotaneelee
Litigation.

         Cash  flow  used in  operations  during  1997  increased  to  $1,003,00
compared to $775,000  during the  1996  period.  The $228,000 difference between
the periods was caused primarily by the following:

                  Increase in loss from operations            $(311,000)
                  Increase in accounts receivable and other    (433,000)
                  Net change in current liabilities             516,000
                                                              ----------
                  Difference in net cash used in operations   $(228,000)
                                                              ==========

         A  significant  proportion  of the  Company's  property  interests  are
covered by carried interest agreements,  which provide that expenditures made by
the operator are recouped solely out of revenues from production.  Major capital
expenditures  made by the operators  have an impact on the  Company's  cash flow
from  operations as no revenues are reported or received until the capital costs
have been  recovered by the  operator.  Properties  in the Fort Nelson,  British
Columbia  area in which the Company has carried  interests  have reached  payout
status.  Proceeds  from  these  carried  interests  plus oil and gas sales  from
working interest properties are the Company's major sources of working capital.

         The Company is currently evaluating and expects to continue to evaluate
oil and gas properties and may make  investments  in such  properties  utilizing
cash on hand. The Company  anticipates  that its capital  expenditures  for land
acquisitions and drilling for the year 1998 will be approximately  $750,000.  In
addition,  substantial  continuing  expenses  are  expected  to be  incurred  in
connection  with the Kotaneelee  Litigation.  During 1997, the Company  expended
approximately  $1.8 million in connection with the Kotaneelee  Litigation  which
has been the principal cause of the Company's losses since 1991.

<PAGE>

         The Company has established a reserve for its potential share of future
site  restoration  costs.  The  estimated  amount of these  costs,  which  total
$804,000,  is being  provided on a unit of production  basis in accordance  with
existing legislation and industry practice.

         The Company has determined  that the year 2000 century change will have
no material impact on the Company's  internal  operations or financial  results.
However,  it will be dependent on its suppliers,  partners and customers to make
their systems year 2000 compliant.

(2)      Results of Operations

1997 vs. 1996

          The net loss  for the  year 1997  was  $1,671,164,  ($.12  per  share)
compared to a net loss of  $1,461,283  ($.11 per share) for the 1996  period.  A
summary of revenue and expenses during the periods is as follows:

                                   1997              1996            Net Change
                                   ----              ----            ----------
Revenues                        $2,514,978        $2,228,393          $286,585
Costs and expenses              (4,272,642)       (3,689,676)         (582,966)
                                -----------       -----------         ---------
Net loss                       $(1,757,664)      $(1,461,283)        $(296,381)
                               ============      ============        ==========

         Oil  sales  increased  by  46%  due  primarily  to an 85%  increase  in
production which was partially offset by a 12% decrease in the average prices of
oil sold.  There was also a 184% increase in royalties paid by the Company.  Oil
unit sales in barrels  ("bbls")  (before  deducting  royalties)  and the average
price per barrel sold during the periods indicated were as follows:

<TABLE>
<CAPTION>
                                        1997                                             1996
                                    Average price                                    Average price
                        bbls           per bbl            Total          bbls           per bbl            Total

<S>                    <C>             <C>             <C>              <C>             <C>               <C>
Oil sales              63,783          $22.50          $1,436,000       34,565          $25.47            $880,000
Royalties paid                                           (315,000)                                        (111,000)
                                                       -----------                                        ---------
Total                                                  $1,121,000                                         $769,000
                                                       ==========                                         ========
</TABLE>

         Gas sales  increased 33%. There was a 41% increase in the average price
for gas and a 2%  increase  in  number of units  sold.  In  addition,  gas sales
include royalty income which increased 35% in 1997. The volumes in million cubic
feet ("mmcf") and the average price of gas per thousand  cubic feet ("mcf") sold
during the periods indicated were as follows:


<PAGE>



<TABLE>
<CAPTION>
                                        1997                                             1996
                                    Average price                                    Average price
                        mmcf           per mcf            Total          mmcf           per mcf            Total

<S>                     <C>             <C>              <C>             <C>             <C>              <C>
Gas sales               200             2.31             $462,000        197             $1.64            $323,000
Royalty income                                            146,000                                          108,000
Royalties paid                                            (85,000)                                         (36,000)
                                                         ---------                                        ---------
Total                                                    $523,000                                         $395,000
                                                         ========                                         ========
</TABLE>

         Proceeds under carried  interest  agreements  decreased 20% to $476,000
during 1997 compared to $591,000 in 1996. The operator of the Company's  carried
interest  properties  increased  its  development  activities  during late 1996,
thereby incurring additional capital costs which were deducted in 1997. Proceeds
under carried interest agreements are derived from net production revenues after
payout of capital costs.

         Interest  and  other  income  decreased  17% in 1997.  Interest  income
increased  from  $259,000  to  $336,000  in 1997  due to the  increase  in funds
available for investment from the June 1996 rights offering to shareholders.  In
addition, the 1997 period includes proceeds from the sale of seismic data in the
amount of $59,000 compared to $215,000 from such sales in 1996.

         General and  administrative  costs  increased 23% in 1997 to $1,105,000
from  $895,000 in 1996.  Capital  taxes,  which are based on the  Company's  net
worth,  increased  $48,000 in 1997.  Directors'  fees increased  $44,000 in 1997
because four nonemployee  directors are being paid fees in 1997 compared to 1996
when only two directors  were paid fees.  Geological  and  engineering  expenses
increased $23,000 in 1997 because of the Company's active  exploration  program.
Shareholders'  expenses  increased  $32,000 in 1997  compared to 1996 because of
increased  printing and mailing costs.  Salaries  increased $39,000 in 1997 with
the addition of a new employee.

         Legal  expenses  increased  18% during 1997 to  $1,898,000  compared to
$1,610,000  during 1996. These expenses are related primarily to the cost of the
Kotaneelee  litigation.  During 1997, the Company  presented a major part of its
case against the working interest partners.  The 1997 costs represent both legal
fees and the  cost of  various  Company  experts  who  testified  or were  being
prepared for testimony.

         Lease  operating  costs increased 68% from $477,000 in 1996 to $799,000
in the 1997 period.  The increased costs are relative to the 85% increase in oil
production.  Although the revenue on these  properties also increased during the
period,  the costs are not yet  proportional  to revenue because some of the new
wells are awaiting installation of production facilities.



<PAGE>


         A foreign  exchange  gain of $231,000 was recorded in 1997,  contrasted
with a gain of $25,000 on the Company's  U.S.  investments in 1996. In 1997, the
gain was  attributable to a strengthening  of the U.S. dollar as compared to the
Canadian dollar on the Company's U.S. investments.

         Income taxes. No provision for income taxes is required for the current
period.

1996 vs. 1995

         The net loss  for  the year  1996  was  $1,461,283,  ($.11  per  share)
compared to a net loss  of $1,161,763  ($.09 per share)  for the 1995 period.  A
summary of revenue and expenses during the periods is as follows:

                                 1996                 1995            Net Change
                                 ----                 ----            ----------
Revenues                      $2,228,393           $1,793,112          $435,281
Costs and expenses             3,689,676            2,954,875           734,801
                               ---------            ---------          --------
Net loss                     $(1,461,283)         $(1,161,763)        $(299,520)
                             ============         ============        ==========


         Oil sales  increased  by 38% due  primarily  to a 14%  increase  in the
average price of oil sold with an 18% increase in  production.  There was also a
13%  increase in  royalties  paid.  Oil unit sales in barrels  ("bbls")  (before
deducting  royalties)  and the average  price per barrel sold during the periods
indicated were as follows:

<TABLE>
<CAPTION>
                                        1996                                             1995
                                    Average price                                    Average price
                        bbls           per bbl             Total         bbls           Per bbl            Total

<S>                    <C>             <C>               <C>            <C>             <C>               <C>
Oil sales              34,565          $25.47            $880,000       29,198          $22.39            $654,000
Royalties paid                                           (111,000)                                         (98,000)
                                                         ---------                                        ---------
Total                                                    $769,000                                         $556,000
                                                         ========                                         ========
</TABLE>

         Gas sales  increased  8%. There was a 26% increase in the average price
for gas which was partially offset by a 22% decrease in units sold. In addition,
gas sales include  royalty  income which  increased 17% in 1996.  The volumes in
million cubic feet ("mmcf") and the average price of gas per thousand cubic feet
("mcf") sold during the periods indicated were as follows:


<PAGE>



                                         <TABLE>
<CAPTION>
996                                           1995
                                    Average price                                   Average price
                        mmcf           per mcf              Total       mmcf           per mcf             Total

<S>                      <C>            <C>               <C>            <C>            <C>              <C>
Gas sales                197            $1.64             $323,000       252            $1.30            $327,000
Royalty income                                             108,000                                         92,000
Royalties paid                                             (36,000)                                       (52,000)
                                                          ---------                                      ---------
Total                                                     $395,000                                       $367,000
                                                          ========                                       ========
</TABLE>

         Proceeds under carried  interest  agreements  decreased 20% to $591,000
during 1996 compared to $734,000 in 1995. The operator of the Company's  carried
interest  properties  increased  its  development  activities  during late 1996,
thereby  incurring   additional   expenses.   Proceeds  under  carried  interest
agreements  are derived  from gross  production  revenues  after payout of these
expenses.

         Interest  and other  income was 247%  higher in 1996.  Interest  income
increased  from  $90,000  to  $259,000  in 1996  due to the  increase  in  funds
available for investment from the June 1996 rights offering to shareholders.  In
addition, the 1996 period includes proceeds from the sale of seismic data in the
amount of $215,000 compared to $46,000 in 1995.

         General and administrative costs decreased 10% in 1996 to $895,000 from
$988,000 in 1995. The 1995 period  included  higher salary  expenses  related to
retired  personnel.  In addition,  accounting and  administrative  expenses also
decreased in 1996 due to cost reduction efforts.

         Lease  operating costs decreased 5% from  $504,000 to $477,000 in 1996.
The  decrease  represents  lower  charges  by  the  operators  of  the Company's
properties during 1996.

         Legal expenses increased 83% to $1,610,000 from $880,000 in 1995. These
expenses are related  primarily to the cost of the Kotaneelee  litigation  which
increased  as a result of trial  preparation  and the actual  costs of the trial
which began on September 3, 1996.

         Depletion,  depreciation and amortization expense increased 31% in 1996
to $655,000 from $500,000 in 1995.  The increase in depletion is the result of a
decrease in gas reserves and an increase in estimated capital costs.

         Provision for  restoration  costs increased to $24,600 in 1996 compared
to $16,800 in 1995. During 1996, a charge of $81,000 was made to the future site
restoration  costs  account  for  certain  abandonments  costs.  The Company has
re-evaluated its potential liability and accordingly increased its provision for
restoration costs.


<PAGE>

         A foreign  exchange  gain of $25,000 was  recorded in 1996,  contrasted
with a loss of $14,000 on the Company's  U.S.  investments in 1995. In 1996, the
gain was  attributable to a strengthening  of the U.S. dollar as compared to the
Canadian dollar on the Company's U.S. investments.

         Income taxes. No provision for income taxes is required for the current
period.

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

         The information  required by this item is not applicable to the Company
until the fiscal year ending December 31, 1998.



<PAGE>


Item 8.  Financial Statements and Supplementary Data



                         REPORT OF INDEPENDENT AUDITORS




To the Shareholders of
Canada Southern Petroleum Ltd.


We have audited the accompanying  consolidated balance sheets of Canada Southern
Petroleum Ltd. as at December 31, 1997 and 1996, and the consolidated statements
of operations and deficit,  cash flows and limited voting shares and contributed
surplus for each of the years in the three year period ended  December 31, 1997.
These financial  statements are the responsibility of the Company's  management.
Our responsibility is to express an opinion on these financial  statements based
on our audits.

We  conducted  our  audits  in  accordance  with  generally   accepted  auditing
standards.  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, the consolidated  financial statements referred to above present
fairly,  in all material  respects,  the financial  position of Canada  Southern
Petroleum  Ltd.  as at  December  31,  1997  and  1996  and the  results  of its
operations  and the changes in its  financial  position for each of the years in
the three year period ended  December 31, 1997,  in accordance  with  accounting
principles generally accepted in Canada.




Calgary, Canada                                            ERNST & YOUNG
March 20, 1998                                             Chartered Accountants


<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.
                  (Incorporated under the laws of Nova Scotia)

                           CONSOLIDATED BALANCE SHEETS
                         (Expressed in Canadian dollars)


                                                              December 31,
                                                           1997         1996
                                                       -----------  -----------
          Assets

Cash and cash equivalents (Note 2)                     $ 2,129,156  $ 2,709,597
Marketable securities (Note 3)                           3,373,334    3,404,213
Accounts receivable (Note 4)                             1,226,086      635,223
Prepaid insurance and other                                             227,368
Other assets                                               242,278            -
                                                       -----------  -----------
Total current assets                                     6,970,854    6,976,401
                                                       -----------  -----------

Marketable securities (Note 3)                                   -    2,048,573
                                                       -----------  -----------

Oil and gas properties and equipment
  (full cost method) (Note 4)                           13,984,771   11,349,945
                                                       -----------  -----------
Total assets                                           $20,955,625  $20,374,919
                                                       ===========  ===========

          Liabilities and Shareholders' Equity

Current liabilities
  Accounts payable                                     $ 1,120,521  $   439,837
  Accrued liabilities (Notes 10 and 11)                    277,715      182,104
                                                       -----------  -----------
Total current liabilities                                1,398,236      621,941
                                                       -----------  -----------

Future site restoration costs                              210,974      250,274
                                                       -----------  -----------

Contingencies (Note 8)                                           -            -

Shareholders' Equity
  Limited Voting Shares, par value
    $1 per share (Note 5)
  Authorized - 100,000,000 shares
  Outstanding - 14,234,740 (1996 - 13,956,540) shares   14,234,740   13,956,540
  Contributed surplus                                   26,254,139   24,930,964
                                                       -----------  -----------
Total capital                                           40,488,879   38,887,504
                                                       -----------  -----------

Deficit                                                (21,142,464) (19,384,800)
                                                       -----------  -----------
Total shareholders' equity                              19,346,415   19,502,704
                                                       -----------  -----------
Total liabilities and shareholders' equity             $20,955,625  $20,374,919
                                                       ===========  ===========


                             See accompanying notes.



<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

                Consolidated Statements of Operations and Deficit
                         (Expressed in Canadian dollars)


<TABLE>
<CAPTION>
                                                                      Year ended December 31,
                                                          1997                  1996                   1995
                                                      ------------          ------------           ------------
Revenues:
<S>                                                   <C>                   <C>                    <C>
  Oil sales                                           $  1,120,789          $    768,576           $    555,894
  Gas sales                                                523,433               395,068                366,700
  Proceeds under carried
      interest agreements                                  475,697               590,935                734,066
  Interest and other income                                395,059               473,814                136,452
                                                      ------------          ------------           ------------
    Total revenues                                       2,514,978             2,228,393              1,793,112
                                                      ------------          ------------           ------------

Costs and expenses:
  General and administrative                             1,104,535               894,766                988,395
  Legal (Note 9)                                         1,897,506             1,610,477                879,821
  Lease operating costs                                    799,372               476,562                503,648
  Depletion, depreciation,
      and amortization                                     623,600               654,982                499,630
  Foreign exchange (gains)                                (231,457)              (24,693)                13,915
  Provision for future site
      restoration costs                                     21,500                24,600                 16,800
  Rent                                                      57,586                52,982                 52,666
                                                      ------------          ------------           ------------
    Total costs and expenses                             4,272,642             3,689,676              2,954,875
                                                      ------------          ------------           ------------

  Loss before income taxes                              (1,757,664)           (1,461,283)            (1,161,763)
  Income taxes (Note 6)                                          -                     -                      -
                                                      ------------          ------------           ------------
Net loss                                                (1,757,664)           (1,461,283)            (1,161,763)
  Deficit - beginning of period                        (19,384,800)          (17,923,517)           (16,761,754)
                                                      -------------         -------------          -------------
  Deficit - end of period                             $(21,142,464)         $(19,384,800)          $(17,923,517)
                                                      =============         =============          =============

Net loss per share (Basic & Diluted)                     $(.12)                $(.11)                 $(.09)
                                                         ======                ======                 ======

Average number of shares
  Outstanding (Basic & Diluted)                        14,084,294            13,362,410             12,621,560
                                                       ==========            ==========             ==========
</TABLE>



                             See accompanying notes.



<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

                      Consolidated Statements of Cash Flows
                         (Expressed in Canadian dollars)

<TABLE>
<CAPTION>
                                                                                  Year ended
                                                                                 December 31,
                                                              1997                   1996                   1995
                                                          -----------            -----------            -----------
 Cash flows from operating activities:
<S>                                                       <C>                    <C>                    <C>
     Net loss                                             $(1,757,664)           $(1,461,283)           $(1,161,763)
     Adjustments to reconcile net loss
        to net cash provided by
       (used in) operating activity:
     Depreciation, depletion and
       amortization                                           623,600                654,982                499,630
     Future site restoration costs (net)                      (39,300)               (56,454)                16,800
   Change in assets and liabilities:
     Accounts and interest receivable                        (590,863)              (284,625)               (64,491)
     Other assets                                             (14,910)               112,074                (85,775)
     Accounts payable                                         680,684                314,328                (38,583)
     Accrued liabilities                                       95,611                (54,228)                51,620
                                                          -----------            -----------            -----------
 Net cash used in operations                               (1,002,842)              (775,206)              (782,562)
                                                          -----------            -----------            -----------

 Cash flows from investing activities:
   Additions to oil and gas properties (net)               (3,258,426)            (1,496,308)              (383,519)
   Sale (purchase) of marketable securities                 2,079,452             (5,452,786)                     -
                                                          -----------            -----------            -----------
 Net cash used in investing activities                     (1,178,974)            (6,949,094               (383,519)
                                                          -----------            -----------            -----------

 Cash flows from Financing Activities:
   Sale of common stock less expenses                               -              9,019,609                      -
   Exercise of stock options                                1,601,375                232,707                121,780
                                                          -----------            -----------            -----------
 Net cash from financing activities                         1,601,375              9,252,316                121,780
                                                          -----------            -----------            -----------

 Increase (decrease) in cash
   and cash equivalents                                      (580,441)             1,528,016             (1,044,301)
 Cash and cash equivalents at the
   beginning of period                                      2,709,597              1,181,581              2,225,882
                                                          -----------            -----------            -----------
 Cash and cash equivalents at the
   end of period (Note 2)                                 $ 2,129,156            $ 2,709,597            $ 1,181,581
                                                          ===========            ===========            ===========
</TABLE>


                             See accompanying notes.

<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

                CONSOLIDATED STATEMENTS OF LIMITED VOTING SHARES
                             AND CONTRIBUTED SURPLUS
                         (Expressed in Canadian dollars)



<TABLE>
<CAPTION>
                                                           Limited
                                        Number          Voting Shares        Contributed
                                      of shares         $1 par value           surplus            Total
                                      ----------        ------------         -----------       -----------

<S>                                   <C>                <C>                 <C>               <C>
Balance at December 31, 1994          12,612,791         $12,612,791         $16,900,617       $29,513,408

  Exercise of stock options               33,000              33,000              88,780           121,780
                                      ----------         -----------         -----------       -----------

Balance at December 31, 1995          12,645,791          12,645,791          16,989,397        29,635,188

Sale of common stock                   1,268,549           1,268,549           7,751,060         9,019,609
Exercise of stock options                 42,200              42,200             190,507           232,707
                                      ----------         -----------         -----------       -----------

Balance at December 31, 1996          13,956,540          13,956,540          24,930,964        38,887,504

Exercise of stock options                278,200             278,200           1,323,175         1,601,375
                                      ----------         -----------         -----------       -----------

Balance at December 31, 1997          14,234,740         $14,234,740         $26,254,139       $40,488,879
                                      ==========         ===========         ===========       ===========
</TABLE>



                             See accompanying notes.



<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         (Expressed in Canadian dollars)
                                December 31, 1997

1.       Summary of significant accounting policies

Accounting principles

         The  Company  prepares  its  accounts  in  accordance  with  accounting
principles  generally  accepted in Canada which,  except as described in Note 6,
conform  in  all  material  respects  with  United  States  generally   accepted
accounting principles ("U.S. GAAP").

Consolidation

         The consolidated financial  statements  include the  accounts of Canada
Southern Petroleum Ltd. and its  wholly-owned subsidiaries, Canpet Inc. and C.S.
Petroleum Limited.

Use of Estimates

         The preparation  of financial  statements in  conformity with generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions that  affect the  amounts reported  in the  financial statements and
accompanying notes.  Actual results could differ from those estimates.

Cash and cash equivalents

         For the purposes of the statement of cash flows, the Company  considers
all highly liquid investments with a maturity of three months or less to be cash
equivalents.

Oil and gas properties and equipment

         The  Company,   which  is  engaged  primarily  in  one  industry,   the
exploration for and the  development of oil and gas  properties,  principally in
Canada,  follows the full cost method of accounting for oil and gas  properties,
whereby all costs associated with the exploration for and the development of oil
and gas reserves are capitalized.

         The Company  periodically reviews the costs associated with undeveloped
properties  and  mineral  rights  to  determine  whether  they are  likely to be
recovered.  When such  costs  are not  likely to be  recovered,  such  costs are
transferred to the depletable pool of oil and gas costs.


<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         (Expressed in Canadian dollars)
                                December 31, 1997

1.       Summary of significant accounting policies (Cont'd)

         The net  carrying  cost of the  Company's  oil  and gas  properties  in
producing  cost  centers is limited to an  estimated  recoverable  amount.  This
amount is the  aggregate  of future net  revenues  from proved  reserves and the
costs of  undeveloped  properties,  net of  impairment  allowances,  less future
general and administrative  costs,  financing costs and income taxes. Future net
revenues  are  calculated  using  year  end  prices  that are not  escalated  or
discounted.

         The costs of the Company's 30% carried  interest in the  Kotaneelee gas
field are  included  in oil and gas  properties  and in the cost  center for the
purpose of computing  depletion.  In addition,  the Company's share of estimated
net reserves  after payout are also  included in the proved oil and gas reserves
base for the purpose of computing depletion. However, no revenue production data
will be reported for financial  statement purposes until the Company is entitled
to participate in the field's revenue after payout status is achieved.

         Gains or losses  are not  recognized  upon  disposition  of oil and gas
properties unless crediting the proceeds against  accumulated costs would result
in a change in the rate of depletion of 20% or more.

         Depletion is provided on costs  accumulated  in producing  cost centers
including well equipment  using the unit of production  method.  For purposes of
the  depletion  calculation,  gross proved oil and gas reserves as determined by
outside  consultants  are  converted to a common unit of measure on the basis of
their approximate relative energy content.

         Depreciation   has  been  computed  for  equipment,   other  than  well
equipment,  on the straight-line  method based on estimated useful lives of four
to ten years.

         Substantially   all  of  the  Company's   exploration  and  development
activities  related  to oil  and gas  are  conducted  jointly  with  others  and
accordingly the  consolidated  financial  statements  reflect only the Company's
proportionate interest in such activities.

Revenue recognition

         The Company recognizes revenue on its working interest  properties from
the production of oil and gas in the period the oil and gas are sold.

         Revenue  under  carried  interest  agreements is recorded in the period
when the proceeds become  receivable.  The Company is entitled to participate in
oil and gas net  revenues  after the  repayment  of  exploration,  drilling  and
completion  expenses to the party or parties  bearing  these costs.  The carried
interest  accounts  are subject to  independent  audits  which are  performed in
subsequent  years. In the past,  these audits have resulted in both positive and
negative  adjustments.  For these reasons,  the proceeds under carried  interest
agreements may fluctuate each year  depending on both capital  expenditures  and
any audit adjustments.


<PAGE>


1.       Summary of significant accounting policies (Cont'd)

Earnings per share

         Earnings per common share is based upon the weighted  average number of
common and common equivalent shares  outstanding  during the period. In February
1997, the FASB issued Statement No. 128,  Earnings per Share ("EPS"),  which the
Company  adopted   retroactively  in  1997.  The  Company's  basic  and  diluted
calculations of EPS are the same for both U.S. and Canadian GAAP.

Future site restoration costs

         Estimated  future  site  restoration  costs which are  estimated  to be
$804,000 are being  provided on a unit of  production  basis.  The  provision is
based on current  costs of  complying  with  existing  legislation  and industry
practice  for  site   restoration  and   abandonment.   At  December  31,  1997,
approximately $598,000 in such costs have not been accrued.

Deferred income taxes

         The Company  follows the deferral  method of tax allocation  accounting
whereby  the income tax  provision  is based on pre-tax  income  reported in the
accounts.  Under this method,  full provision is made for deferred  income taxes
resulting  from  claiming  deductions  at the  rates  permitted  by  income  tax
legislation, which may differ from those used in the accounts.

Foreign currency translation

         Transactions  for settlement in U.S. dollars  have been  translated  at
average monthly exchange rates. Assets and liabilities in U.S. dollars have been
translated at the year end exchange  rates.  Exchange gains or losses  resulting
from these adjustments are included in costs and expenses.

Financial instruments

         The carrying value for cash and cash equivalents,  accounts receivable,
marketable  securities  and accounts  payable  approximates  fair value based on
anticipated cash flows and current market conditions.



<PAGE>


1.       Summary of significant accounting policies (Cont'd)

Comprehensive income

         In 1997, the Financial Accounting Standards Board issued FASB Statement
No. 130,  Reporting  Comprehensive  Income. As the Company has no items of other
comprehensive  income,  the net loss for all periods  presented  is equal to the
comprehensive loss.

2.       Cash and cash equivalents

         The Company  considers  all highly liquid short term  investments  with
maturities  of  three  months  or  less  at  date  of  acquisition  to  be  cash
equivalents.  Cash  equivalents  are carried at cost which  approximates  market
value.

                                                    1997                 1996
                                                 ----------           ----------
Cash                                             $  436,030           $  319,616
Canadian bankers acceptances (2.9%)                 988,437            1,441,170
U.S. Treasury Bills (5.6%)                          704,689              948,811
                                                 $2,129,156           $2,709,597
                                                 ==========           ==========

3.       Marketable Securities

         At  December 31,  1997  and  1996,   the  Company  held  the  following
marketable securities which were expected to be held until maturity:

<TABLE>
<CAPTION>
                                                        1997
                  Security                       Par value        Maturity Date       Amortized Cost      Fair value
                  --------                       ----------       -------------       --------------      ----------
<S>                                              <C>              <C>                   <C>               <C>
U.S. Federal Home Bank Note                      $  143,021       Mar. 6, 1998          $  140,418        $  141,247
U.S. Federal Home Bank Note                         286,041       Apr. 6, 1998             278,324           280,925
U.S. Federal Farm Credit Bank Note                  143,021       May 4, 1998              139,600           139,469
U.S. Treasury Note                                2,145,309       May 31, 1998           2,137,934         2,149,321
U.S. Federal Home Loan Bank Note                    715,103       Jun. 19, 1998            677,058           683,411
                                                 ----------                             ----------        ----------
Total                                            $3,432,495                             $3,373,334        $3,394,373
                                                 ==========                             ==========        ==========

                                                        1996

U.S. Treasury Bill                               $  822,256       Mar. 27, 1997         $  801,637       $   812,570
U.S. Treasury Bill                                  685,213       Apr. 3, 1997             657,599           676,271
U.S. Treasury Bill                                2,055,639       Jun. 26, 1997          1,944,977         2,004,289
                                                 ----------                             ----------        ----------
Total short term                                  3,563,108                              3,404,213         3,493,130
                                                 ----------                             ----------        ----------

U.S. Treasury Bill                                2,055,639       Jun. 26, 1998          2,048,573         2,056,914
                                                 ----------                             ----------        ----------
Total                                            $5,618,747                             $5,452,786        $5,550,044
                                                 ==========                             ==========        ==========
</TABLE>


<PAGE>


4.       Oil and gas properties and equipment

<TABLE>
<CAPTION>
                                                                                  Accumulated
                                                                                Provisions and        Net Book
                                                                 Cost             Writedowns            Value
                                                             -----------          ----------         -----------
Balance December 31, 1997
<S>                                                           <C>                  <C>                <C>
Oil and gas properties - developed                            21,192,037           7,854,066          13,337,971
Oil and gas properties (U.S.) - undeveloped                      616,980                   -             616,980
Seismic data                                                     112,000             112,000
                                                             -----------          ----------         -----------
                                                                                                               -
                                                              21,921,017           7,966,066          13,954,951
Equipment                                                         67,769              37,949              29,820
                                                             -----------          ----------         -----------
                                                             $21,988,786          $8,004,015         $13,984,771
                                                             ===========          ==========         ===========

Balance December 31, 1996
Oil and gas properties-developed                             $18,555,130          $7,227,874         $11,327,256
Oil and gas properties-undeveloped                                     1                   -                   1
Seismic data                                                     112,000             112,000
                                                             -----------          ----------         -----------
                                                                                                               -
                                                              18,667,131           7,339,874          11,327,257
Equipment                                                         62,172              39,484              22,688
                                                             -----------          ----------         -----------
                                                             $18,729,303          $7,379,358         $11,349,945
                                                             ===========          ==========         ===========
</TABLE>


         Substantially  all gas sales  were made to  CanWest Gas Supply Inc. and
oil sales were made to  Canadian  Natural  Resources Ltd. and Probe Exploration,
Inc. ("Probe").  At  December 31, 1997,  a cash call  in the amount  of $616,000
from Probe is included in accounts receivable.

5.       Limited voting shares and stock options

         The Memorandum of Association  (Articles of Continuance) of the Company
provides that no person (as defined) shall vote more than 1,000 shares.

         Under the terms of the Company's 1985 and 1992 stock option plans,  the
Company is authorized to grant certain key employees and consultants  options to
purchase limited voting shares at prices based on the market price of the shares
as determined  on the date of the grant.  The options are  exercisable  for five
years from the date of grant.

         On January 27, 1998, the Company's Board of Directors  approved a stock
option  plan  that  permits  the  granting  of  both  stock  options  and  stock
appreciation  rights.  Under the plan,  which must be approved by the  Company's
shareholders  at the June 1998  Annual  Meeting,  a total of 700,000  shares are
being authorized.

         In 1996,  the Company sold 1.3 million  shares to its  shareholders  at
$7.50 per share.  The  proceeds to the  Company  from the rights  offering  were
$9,019,609 after deducting the $494,509 cost of the offering.


<PAGE>


5.       Limited voting shares and stock options (Cont'd)

         Following  is  a  summary  of  option   transactions   which   reflects
adjustments of the stock option prices and the number of shares subject to stock
options as discussed above:

Options outstanding                         Number of shares      Option Prices
                                                                       ($)
December 31, 1994                                 494,700          3.45 - 7.00
  Exercised                                       (33,000)         3.45 - 4.06
                                                  -------
December 31, 1995                                 461,700
                                                  =======
  Canceled                                       (137,000)         3.45 - 7.00
  Exercised                                       (42,200)         3.45 - 8.75
  Granted                                         150,700          3.15 - 6.37
  Granted                                          12,500             8.75
                                                  -------
December 31, 1996                                 445,700
                                                  =======
  Exercised                                      (278,200)         3.70 - 8.75
  Granted                                          35,000             13.50
December 31, 1997                                 202,500         6.37 - 13.50
                                                  =======

Options reserved for future grants                212,134

         On July 8, 1996,  137,000 options to purchase  limited voting shares of
the Company which were previously  granted were canceled and reissued to reflect
the June 1996 rights offering.

         For U.S. GAAP, the Company has elected to follow Accounting  Principles
Board Opinion No. 25,  "Accounting  for Stock Issued to Employees"  (APB No. 25)
and related  interpretations  in accounting  for its stock  options  because the
alternative  fair value  accounting  provided  under  FASB  Statement  No.  123,
"Accounting  for Stock Based  Compensation,"  requires  use of option  valuation
models that were not developed for use in valuing stock  options.  Under APB No.
25, because the exercise price of the Company's  stock options equals the market
price of the underlying  stock on the date of grant, no compensation  expense is
recognized.

          Pro forma  information  regarding net income and earnings per share is
required  by  Statement  123,  and has been  determined  as if the  Company  had
accounted for its stock  options under the fair value method of that  Statement.
The fair value for these  options  was  estimated  at the date of grant  using a
Black-Scholes option pricing model.

          Option  valuation  models  require  that  input of  highly  subjective
assumptions including the expected stock price volatility.  The assumptions used
in the 1996 valuation model were: risk free interest rate - 6.7%,  expected life
- 5 years and  expected  volatility  - .396.  The  assumptions  used in the 1997
valuation  model were:  risk free interest rate - 5.7%,  expected life - 5 years
and expected volatility - .459.


<PAGE>


5.       Limited voting shares and stock options (Cont'd)

          Because the Company's stock options have characteristics significantly
different from those of traded  options,  and because  changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion,  the  existing  models do not  necessarily  provide a  reliable  single
measure of the fair value of its stock options.

          For the purpose of pro forma disclosures,  the estimated fair value of
the  stock  options  is  expensed  in the year of grant  since the  options  are
immediately exercisable. The Company's pro forma information follows:

                                                       Amount          Per Share
Net loss as reported - December 31, 1996             $(1,461,283)        $(.11)
Stock option expense                                      49,373            -
                                                     ------------        ------
Pro forma net loss - December 31, 1996               $(1,510,656)        $(.11)
                                                     ============        ======

Net loss as reported - December 31, 1997             $(1,757,664)        $(.12)
Stock option expense                                     225,400          (.02)
                                                     ------------        ------
Pro forma net loss - December 31, 1997               $(1,983,064)        $(.14)
                                                     ============        ======

6.        Income taxes

          Income  taxes vary from the amounts that would be computed by applying
the Canadian federal and provincial income tax rates as follows:


<TABLE>
<CAPTION>
                                                                        1997              1996             1995
                                                                     ---------         ---------         ---------
                                                                       44.84%            44.84%           44.84%
                                                                       ======            ======           ======
Provision for income taxes based on combined
<S>                                                                  <C>               <C>               <C>
 basic Canadian federal and provincial income tax                    $(788,137)        $(655,239)        $(520,935)
Nondeductible crown charges                                            154,463            61,599            60,354
Resource allowance                                                     232,922                 -                 -
Other                                                                   21,106               478               948
Nontaxable portion of capital gain                                     (20,743)                -                 -
Unrealized tax loss                                                    400,389           593,162           459,633
                                                                     ---------         ---------         ---------
Actual provision for income taxes                                    $       -         $       -         $       -
                                                                     =========         =========         =========
</TABLE>

         At December 31, 1997,  the Company had net operating  losses for income
tax  purposes of  approximately  $3,821,000  which are  available  to be carried
forward to future periods.  These losses expire in the following  years:  1998 -
$563,000,  1999 - $194,000,  2000 - $294,000,  2001 - $545,000, 2002 - $569,000,
2003 - $1,077,000 and 2004 - $579,000.

         At December 31, 1997,  the  following  oil and gas tax  deductions  are
available to reduce future taxable income,  subject to a final  determination by
taxation authorities.


<PAGE>


6.        Income taxes (Cont'd)

Canada

Drilling, exploration and lease acquisition costs                   $12,932,000
Earned depletion                                                      1,975,000
Undepreciated capital costs                                           2,172,000
Cumulative eligible capital losses                                      407,000
Share issue costs                                                       274,000

United States

Exploration and lease acquisition costs                                $610,000

         The tax benefits  attributable  to the above  accumulated  expenditures
will not be  reflected  in the  consolidated  financial  statements  until  such
benefits are realized.

         Under U.S.  GAAP,  the  provisions for income taxes would have differed
for the reasons set out below:

         In February  1992,  the United States  Financial  Accounting  Standards
Board issued  Statement No. 109,  "Accounting  for Income Taxes",  effective for
fiscal years  beginning  after  December 15, 1993.  Under U.S. GAAP, the Company
would have been required to adopt Statement No. 109 commencing July 1, 1993.

         Under Statement No. 109, the liability method is used in accounting for
income  taxes.  Under this  method,  deferred  tax assets  and  liabilities  are
determined  based on differences  between  financial  reporting and tax bases of
assets and  liabilities  and are  measured  using the enacted tax rates and laws
that will be in effect when the  differences  are  expected  to  reverse.  Under
Canadian GAAP and previously  under U.S. GAAP,  income tax expense is determined
using the deferral method.  Deferred tax expense is based on items of income and
expense that are reported in different years in the financial statements and tax
returns and are  measured at the tax rate in effect in the year the  differences
originated.

         The following schedule  summarized the Company's income tax expense and
deferred tax liability  under U.S.  GAAP. If Statement No. 109 was adopted,  the
Company  would have had a deferred  tax asset  which  primarily  represents  the
excess of  available  resource  deductions  for  income  tax  purposes  over the
recorded  value of oil and gas  properties  together with  operating and capital
income tax loss  carryforwards.  These amounts are expected to be recovered from
the  production of current oil and gas reserves when the  Kotaneelee  litigation
expenditures  have ended.  As certain of the resource  deductions are restricted
and the  operating  loss  carryforwards  are  subject  to  expiration,  there is
considerable risk that certain of these deductions will not be utilized.

<PAGE>

6.       Income taxes (Cont'd)

Accordingly,  the  Company  would have  established  a  valuation  allowance  to
recognize this uncertainty.  Income taxes computed in accordance with U.S. GAAP,
would have resulted in a credit to the provision of taxes.


                                    1997              1996              1995
                                ------------      ------------      ------------
Deferred tax asset               $3,663,793        $3,233,506        $2,351,550
Valuation reserve                (2,733,655)       (2,473,526)       (1,816,792)
                                 ----------        ----------        ----------
Net deferred tax asset           $  930,138        $  759,980        $  534,758
                                 ==========        ==========        ==========

Deferred tax recovery            $  170,158        $  225,222        $  160,980
                                 ==========        ==========        ==========

         Net loss  under U.S.  GAAP,  in total,  and per share  based on average
number of shares outstanding during the periods shown is as follows:

<TABLE>
<CAPTION>
                                                                         1997              1996             1995
                                                                     ------------      ------------     ------------
<S>                                                                  <C>               <C>              <C>
Net loss under Canadian GAAP before income taxes                     $(1,757,664)      $(1,461,283)     $(1,161,763)
Income tax adjustment                                                    170,158           225,222          160,980
                                                                     ------------      ------------     ------------
Net loss under U.S. GAAP                                             $(1,587,506)      $(1,236,061)     $(1,000,783)
                                                                     ============      ============     ============
Per Share Basis:
Net loss under Canadian GAAP before income taxes                        $(.12)            $(.11)           $(.09)
Income tax adjustment                                                     .01               .02              .01
                                                                        ------            ------           ------
Net loss under U.S. GAAP                                                $(.11)            $(.09)           $(.08)
                                                                        ======            ======           ======
</TABLE>

          The  deficit  under  U.S.  GAAP  would  have  been   $20,212,326   and
$18,624,820 at December 31, 1997 and 1996, respectively.

7.        Line of credit

          The Company has a line of credit with a Canadian  chartered bank which
provides  for a loan of  $500,000.  The line of credit  provides  for a $125,000
operating  loan and  $375,000  for  letters of credit as part of the  directors'
indemnification  agreements. The interest rate on borrowing is at 3/4% above the
bank's prime lending rate. The line of credit is subject to annual review and is
secured by a general  assignment of accounts  receivable  and an  undertaking to
provide security in the form of assignment of future working interest  proceeds.
No drawings were made under this line during 1997 or 1996.



<PAGE>


8.       Litigation

         The  Company,  which has a 30%  interest in the  Kotaneelee  gas field,
believes  that the  working  interest  owners in the field  have not  adequately
pursued the  attainment of contracts for the sale of Kotaneelee  gas. In October
1989 and in March 1990,  the Company  filed  statements of claim in the Court of
Queens  Bench of Alberta,  Judicial  District of  Calgary,  Canada,  against the
working interest partners in the Kotaneelee gas field. The named defendants were
Amoco Canada  Petroleum  Corporation,  Ltd.,  Dome Petroleum  Limited (now Amoco
Canada Resources Ltd.), and Amoco Production  Company  (collectively  the "Amoco
Dome Group"),  Columbia Gas Development of Canada Ltd.  ("Columbia"),  Mobil Oil
Canada Ltd.  ("Mobil") and Esso Resource of Canada Ltd.  ("Esso")  (collectively
the "Defendants").

         The  Company  claims  that the  Defendants  breached  either a contract
obligation  or a  fiduciary  duty owed to the  Company  to  market  gas from the
Kotaneelee  gas field when it was  possible to so do. The Company  asserts  that
marketing  the  Kotaneelee  gas was  possible  in 1984 and  that the  Defendants
deliberately failed to do so. The Company seeks money damages and the forfeiture
of the  Kotaneelee  gas field.  The  Company  expects to argue at trial that the
money damages sustained by the Company are at least $86 million.

         In  addition,  the  Company  has  claimed  that the  Company's  carried
interest  account  should be reduced  because of the negligent  operation of the
field and improper  charges to the carried  interest  account by the Defendants.
The Company claims that when the Defendants in 1980  suspended  production  from
the field's gas wells, they failed to take  precautionary  measures necessary to
protect and maintain the wells in good operating condition. The wells thereafter
deteriorated,  which caused unnecessary  expenditures to be incurred,  including
expenditures  to  redrill  one  well.  In  addition,  the  Company  claims  that
expenditures made to repair and rebuild the field's dehydration plant should not
have been necessary had the facilities been properly  constructed and maintained
by the Defendants.  The expenditures,  the Company claims, were  inappropriately
charged to the field's  carried  interest  account.  The effect of an  increased
carried  interest  account is to extend the period  before  payout begins to the
carried interest account owners.

         The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million.  The Company  claims  that by 1993 at least $34 million of  unnecessary
expenses  had been  wrongfully  charged to the  carried  interest  account.  The
Company's 30% share of these expenses would be approximately $10.2 million.  The
Company  further  claims that if production  had commenced in 1984,  the carried
interest  account  would have been paid off in  approximately  two years and the
Company would have begun to receive revenues from the field in 1986. At present,
the Company does not expect to receive revenues before the year 2000, based on a
price of Cdn. $1.39 per mcf and current production rates.

<PAGE>

8.       Litigation (Cont'd)

         Columbia has filed a counterclaim  against the Company seeking,  if the
Company is  successful in its claim for the  forfeiture of the field,  repayment
from the  Company of all sums  Columbia  has  expended on the  Kotaneelee  lands
before the Company is entitled to its interest.

         The parties to the litigation have conducted  extensive discovery since
the filing of the claims.  The trial began on  September 3, 1996 and is ongoing.
Based upon recently  discovered  evidence,  the Company has petitioned the court
for leave to amend its  complaint to add a claim that the  Defendants  failed to
develop the field in a timely manner. The Company is unable to estimate the time
necessary to conclude the litigation.

Matters Ancillary to Kotaneelee Litigation

         In its 1989  statement  of  claim,  the  Company  sought a  declaratory
judgment regarding two issues:

         (1)      whether interest accrued on the carried interest account; and

         (2)      whether  expenditures  for  gathering  lines  and  dehydration
                  equipment are expenditures  chargeable to the carried interest
                  account or whether the Company  will be assessed a  processing
                  fee on gas throughput.

         With respect to the first issue, the Company maintains that no interest
should  accrue  on the  account  and the  Defendants  have  not  contested  this
position.  With  regard to the second  issue,  the  Company  maintains  that the
expenditures are chargeable to the carried  interest  account.  Mobil,  Esso and
Columbia have essentially  agreed to the Company's position while the Amoco Dome
Group continues to contest this issue.

         On January 22, 1996, the Company settled two claims outstanding against
the Company in the Court of Queens Bench, Calgary,  Alberta,  which related to a
suit brought against  AlliedSignal  Inc.  ("AlliedSignal")  in Florida which was
dismissed on the basis that Canada was the appropriate forum for the litigation.
AlliedSignal  had sought  additional  relief  against  the  Company in Canada to
preclude  other  types of suits by the  Company  and to recover the costs of the
defense of the initial  action.  The settlement bars  AlliedSignal from making a
claim  against  the  Company  for any costs in  connection  with the  Kotaneelee
Litigation.  The Company agreed not to bring any action against  AlliedSignal in
connection  with the  Kotaneelee  gas field.  Neither  party  made any  monetary
payment to the other party.

<PAGE>

8.       Litigation (Cont'd)

         In 1991,  Anderson  Exploration  Ltd.  acquired  all of the  shares  in
Columbia and changed its name to Anderson Oil & Gas Inc. ("Anderson").  Anderson
is now the sole operator of the field and is a direct  defendant in the Canadian
lawsuit.  Columbia's  previous parent, The Columbia Gas System,  Inc., which was
reorganized in a bankruptcy  proceeding in the United States,  is  contractually
liable to Anderson in the legal proceeding described above.

         The working  interest  owners have reported that they have been selling
Kotaneelee gas since February 1991.

         Under  Canadian  law certain  costs  (known as "taxable  costs") of the
litigation  may be  assessed  against the  nonprevailing  party.  Taxable  costs
consist  primarily of attorney's and expert witness fees during trial. The trial
is presently scheduled to last twelve months, therefore,  taxable costs could be
substantial. While taxable costs are not now determinable, the Company estimates
that taxable costs,  assuming a twelve month trial,  could be approximately $1.5
million.  However,  a judge in complex and lengthy  trials has the discretion to
increase  an award of  taxable  costs.  There are no  assurances  however,  that
taxable costs will not exceed this amount or that the duration of the trial will
not  exceed  twelve  months.  The  actual  trial  time  through  March  1998  is
approximately  5 months.  During 1997,  the Company was  assessed  approximately
$110,000 in taxable  costs  payable to the  Defendants  in  connection  with the
Company's motion to disqualify Amoco's legal counsel which was denied.
The amount is included in 1997 legal expenses.

         There is no assurance  whatever  that the Company will be successful on
the merits of its claims, which have been vigorously defended by the Defendants.
There is also no  assurance  that the Company  will be awarded any  damages,  or
that,  if damages are  awarded,  the Court will apply the measure of damages the
Company claims should be applied.

9.       Related party transactions

         Fees paid  or accrued  for legal  services  rendered to  the Company by
Reasoner,  Davis & Fox, (of which firm Mr. C. Dean  Reasoner,  a director of the
Company until March 11, 1997, is a partner,) were U.S. $111,000 and $133,000 for
the years 1996 and 1995, respectively.

          In 1991,  the Company  granted  interests to certain of its  officers,
employees,  directors, counsel and consultants amounting to an aggregate of 7.8%
of any and all benefits to the Company  after  expenses  from the  litigation in
Canada  relating to the  Kotaneelee  gas field.  The Company has reserved a 2.2%
interest in such net  benefits  for  possible  future  grants to persons who may
include officers and directors of the Company.


<PAGE>


9.       Related party transactions (Cont'd)

         Messrs.  Heath  and  Reasoner have royalty  interests in certain of the
Company's  oil and gas  properties,  (present  and  past)  which  were  received
directly  or  indirectly  through  the  Company.  The  Company  and  third-party
operators and/or owners of properties made payments  pursuant to these royalties
for the benefit of Mr.  Reasoner  were U.S.  $5,342 and $6,159 in 1996 and 1995,
and for Mr.  Heath U.S.  $11,158,  $10,844 and  $12,777 in 1997,  1996 and 1995,
respectively.

10.      Other financial information

Accrued liabilities
                                                     1997             1996
                                                     ----             ----
Accrued liabilities due to working
  interest partners                                $      -         $ 12,050
Accrued accounting and legal expenses               137,650           52,793
Accrued royalties                                   139,645          116,415
Other                                                   420              846
                                                   --------         --------
                                                   $277,715         $182,104
                                                   ========         ========


                                                 Year ended December 31,
                                          1997            1996            1995

Royalty payments (1)                    $366,661        $147,572        $150,224
                                        ========        ========        ========

Interest payments (2)                   $  6,650        $  7,099        $ 10,000
                                        ========        ========        ========

Large corporation tax payments          $ 27,388        $  2,741        $  4,527
                                        ========        ========        ========
--------------------
(1)      Oil and gas sales are reported net of royalties paid.
(2)      Bank line of credit charges.

11.      Other commitments

         During March 1998,  the Company  agreed to  participate  with two other
companies in a heavy oil recovery project in California.  The field is estimated
to have  approximately  12 million  barrels of oil in place with only 13% of the
oil recovered to date.  The initial  purchase price for a 90% (75% APO) interest
in the  project  is  $200,000  (Company  share 30% -  $60,000).  There is also a
commitment  to spend  $600,000  to  perform  remedial  work on the  field and to
complete a pilot  stream  flood  program  during  the first year of the  project
(Company  share  $180,000).  If the total  amount of  expenditures  is less than
$600,000,  the  participants'  interests will be reduced  proportionately  to an
amount which is not less than 10% (Company share - 3%).



<PAGE>



                         CANADA SOUTHERN PETROLEUM LTD.
               SUPPLEMENTARY INFORMATION ON OIL AND GAS ACTIVITIES
                                   (unaudited)

          The  following  information  includes  estimates  which are subject to
rapid and unanticipated  change.  Therefore,  these estimates may not accurately
reflect future net income to the Company.

          All amounts below except for costs, acreage, wells drilled and present
activities  relate  to  Canada.  Oil and gas  reserve  data and the  information
relating to cash flows were  provided by Paddock  Lindstrom &  Associates  Ltd.,
independent consultants.

Estimated net quantities of proved oil and gas reserves:


                                                   Oil            Gas
                                                  (bbls)         (bcf)
Proved reserves:
December 31, 1994                                473,600         32.957
  Revisions of previous estimates               (157,908)         1.559
  Production*                                    (30,892)        (1.311)
                                                 --------        -------
December 31,1995                                 284,800         33.205
  Revisions of previous estimates                178,448         (2.655)
  Production*                                    (37,448)        (1.519)
                                                 --------        -------
December 31, 1996                                425,800         29.031
  Revisions of previous estimates                179,333         (3.802)
  Production*                                    (71,333)         (.838)
                                                 --------        -------
December 31, 1997                                533,800         24.391
                                                 =======         ======

Proved developed reserves:
December 31, 1994                                473,600         32.957
                                                 =======         ======
December 31, 1995                                284,800         33.205
                                                 =======         ======
December 31, 1996                                358,400         28.265
                                                 =======         ======
December 31, 1997                                508,200         24.391
                                                 =======         ======

-----------------
*     Production  data  includes  oil and gas  sales and the  proceeds  from the
      carried interest properties.


<PAGE>


Results of oil and gas operations:


<TABLE>
<CAPTION>
                                                            1997                 1996                 1995
                                                         ----------           ----------           ----------
Income:
<S>                                                      <C>                  <C>                  <C>
  Oil and gas sales                                      $1,644,222           $1,163,644           $  922,594
  Proceeds under carried
    interest agreements                                     475,697              590,935              734,066
                                                         ----------           ----------           ----------
                                                          2,119,919            1,754,579            1,656,660
                                                         ----------           ----------           ----------
Costs and expenses:
  Production costs                                          799,372              476,562              503,648
  Depletion depreciation, and
    amortization                                            623,600              654,982              499,630
  Provision for future site
    restoration costs                                        21,500               24,600               16,800
  Income tax expense                                              -                    -                    -
                                                         ----------           ----------           ----------
                                                          1,444,472            1,156,144            1,020,078
                                                         ----------           ----------           ----------
Net income from operations                               $  675,447           $  598,453           $  636,582
                                                         ==========           ==========           ==========

Costs of oil and gas activities:


                                                             1997                 1996                 1995
                                                         ----------           ----------           ----------
Acquisition costs                                        $  399,000           $  484,000           $   49,000
Exploration                                                 546,000              146,000               92,000
Development                                               2,313,000              866,000              243,000
</TABLE>

Standardized  measure of discounted future net cash flows relating to proved oil
and gas  reserve  quantities  during  the  following  period  (in  thousands  of
dollars):


<TABLE>
<CAPTION>
                                                            1997                 1996                 1995
                                                         ----------           ----------           ----------
<S>                                                      <C>                  <C>                  <C>
Future cash inflows                                      $   46,435           $   49,410           $   48,298
Future development and
  production costs                                          (22,517)             (20,813)             (18,473)
                                                         ----------           ----------           ----------
                                                             23,918               28,597               29,825
Future income tax expense*                                   (1,573)              (2,931)              (4,218)
                                                         ----------           ----------           ----------
Future net cash flows                                        22,345               25,666               25,607
10% annual discount                                          (7,836)              (9,691)             (10,679)
                                                         ----------           ----------           ----------
Standardized measure of discounted
  future net cash flows                                  $   14,509           $   15,975           $   14,928
                                                         ==========           ==========           ==========
</TABLE>

* Reflects tax benefit for the years 1997, 1996 and 1995,  from  carryforward of
exploration,  development and lease  acquisition  costs,  undepreciated  capital
costs and book earned depletion of $18,065,000, $17,032,000 and $13,679,000.

         Current prices used in the foregoing  estimates were based upon selling
prices at the wellhead in the last month of each fiscal  period.  Current  costs
were based upon estimates made by consulting engineers at the end of each year.


<PAGE>


Changes in the standardized  measure during the following  periods (in thousands
of dollars):

                                                   Year ended December 31,
                                              1997          1996          1995
                                            --------      --------      --------
Changes due to:
Prices and production costs                 $  (579)      $ 3,248       $   (88)
Future development costs                     (2,350)       (1,049)           83
Sales net of production costs                (1,562)       (1,330)       (1,428)
Development costs incurred
  during the year                             2,313           866           243
Net change due to extensions,
  discoveries and improved recovery           1,692         1,458             -
Revisions of quantity estimates              (3,642)       (4,229)       (3,404)
Accretion of discount                         1,723         1,660         1,927
Net change in income taxes                      939           423         1,078
                                            -------       -------       -------
Net change                                  $(1,466)      $ 1,047       $(1,589)
                                            ========      =======       ========



<PAGE>


Item 9.  Changes in and Disagreements with Accountants on
         Accounting and Financial Disclosure

         None.

                                    PART III

         For information  concerning Item 10 - Directors and Executive  Officers
of the Company, Item 11 - Executive  Compensation,  Item 12 - Security Ownership
of Certain Beneficial Owners and Management and Item 13 - Certain  Relationships
and Related  Transactions,  see the Proxy Statement of Canada Southern Petroleum
Ltd.  relative to the Annual Meeting of  Shareholders  for the fiscal year ended
December  31,  1997,  which  will be filed  with  the  Securities  and  Exchange
Commission,   which  information  is  incorporated  herein  by  reference.   For
information concerning Item 10 - Executive Officers of the Company, see Part I.



<PAGE>


                                     PART IV

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

         (a)      (1)      Financial Statements

                  The financial  statements listed below and included under Item
8, above are filed as part of this report.

                                                                  Page Reference

Report of Independent Auditors                                           35
Consolidated balance sheets at December 31, 1997 and 1996                36
For the years ended December 31, 1997, 1996 and 1995
    Consolidated statements of operations and deficit                    37
    Consolidated statements of cash flows                                38
Consolidated statements of Limited Voting Shares and Contributed
  Surplus for the three years ended December 31, 1997                    39
Notes to consolidated financial statements                             40-52
Supplementary information on oil and gas activities (unaudited)          53

                  (2)      Consolidated Financial Statement Schedules

                           All schedules  have been  omitted since  the required
information  is not  present or not  present in  amounts  sufficient  to require
submission of the schedule,  or because the information  required is included in
the consolidated financial statements or the notes thereto.

                  (3)      Exhibits

                           The  following  exhibits  are  filed  as part of this
report:

             Item Number

                  2.       Plan of acquisition, arrangement, liquidation or
                           succession

                           None

<PAGE>


                  3.       Articles of Incorporation and By-Laws

                           Memorandum  of  Association  as  amended  on June 30,
                           1982, May 14, 1985 and April 7, 1988 and By-laws,  as
                           amended, filed as Exhibit 3 to Registration Statement
                           No. 33-99052 as filed on November 7, 1995.

                  4.       Instruments defining the rights of security holders,
                           including indentures

                           None.

                  9.       Voting trust agreement

                           None.

                  10.      Material contracts

                           (a)  Agreements relating to Kotaneelee.
                             (1.) Copy of Agreement  dated May 28, 1959  between
                           the Company  et al.  and  Home  Oil  Company  Limited
                           et al.  and  Signal Oil  and  Gas  Company  filed  as
                           Exhibit  10 (a) (1)  to  Registration  Statement  No.
                           33-99052 as filed on November 7, 1995 is incorporated
                           herein by reference.

                             (2.) Copies of  Supplementary  Documents to May 28,
                           1959 Agreement (see (1) above),  dated June 24, 1959,
                           consisting  of Guarantee by Home Oil Company  Limited
                           and Pipeline  Promotion  Agreement,  filed as Exhibit
                           10(a)(2) to  Registration  Statement No.  33-99052 as
                           filed on November 7, 1995 is  incorporated  herein by
                           reference.

                             (3.) Copy of  Modification  to Agreement  dated May
                           28,  1959 (see (1)  above),  made as of  January  31,
                           1961,  filed  as  Exhibit  10(a)(3)  to  Registration
                           Statement  No.  33-99052 as filed on November 7, 1995
                           is incorporated herein by reference.

                             (4.) Copy of  Agreement  dated  April 1, 1966 among
                           the Company et al. and Dome Petroleum  Limited et al.
                           filed as Exhibit  10(a)(4) to Registration  Statement
                           No.   33-99052  as  filed  on  November  7,  1995  is
                           incorporated herein by reference.


<PAGE>


                             (5.) Copy of Letter  Agreement  dated  February  1,
                           1977 between the Company and Columbia Gas Development
                           of Canada,  Ltd. for operation of the  Kotaneelee gas
                           field   filed  as  Exhibit   10(a)  to   Registration
                           Statement  No.  33-99052 as filed on November 7, 1995
                           is incorporated herein by reference.

                           (b) Copy of Agreement  dated January 28, 1972 between
                           the Company and Panarctic  Oils Ltd. for  development
                           of the  offshore  Arctic  Islands gas fields filed as
                           Exhibit 10(b) to Registration  Statement No. 33-99052
                           as filed on November 7, 1995 is  incorporated  herein
                           by reference.

                           (c) Stock Option Plan adopted  December 9, 1992 filed
                           as  Exhibit  10(g)  to  Report  on Form  10-K for the
                           fiscal  year  ended  June  30,  1993 is  incorporated
                           herein by reference.

                  11.      Statement re computation of per share earnings

                           Not applicable.

                  12.      Statement re computation of ratios

                           None.

                  13.      Annual report to security holders

                           Not applicable.

                  16.      Letter re change in certifying accountant

                           Not applicable.

                  18.      Letter re change in accounting principles

                           None.

                  20.      Previously unfiled documents

                           None.

                  21.      Subsidiaries of the Company

                           Canpet  Inc.  incorporated  in  Delaware on August 3,
                           1973.  C. S. Petroleum Limited  incorporated  in Nova
                           Scotia on December 15, 1981.
<PAGE>

                  22.      Published report regarding  matters submitted to vote
                           of security holders

                           None.

                  23.      Consents of experts and counsel

                           (a)  Paddock  Lindstrom  &  Associates,  Ltd.   filed
                           herein.

                           (b)  Ernst & Young filed herein.

                  24.      Power of attorney

                           Not applicable.

                  27.      Financial Data Schedule

                           Filed herein.

                  28.      Information from reports furnished to state insurance
                           regulatory authorities

                           Not applicable.

                  99.      Additional exhibits

                  (a)      Complaint of Allied-Signal Inc. in its action against
                           Dome Petroleum Limited, Amoco Production Company, and
                           Amoco  Canada Petroleum Company Ltd. filed  September
                           2, 1988 in the  Court of  Queens  Bench  of  Alberta,
                           Judicial  District  of  Calgary,  Canada,   filed  as
                           Exhibit 99(a) to Registration Statement No.  33-99052
                           as filed on  November 7,  1995 is incorporated herein
                           by reference.

                  (b)      Answer and  Counterclaim  of Dome Petroleum  Limited,
                           Amoco Production Company,  and Amoco Canada Petroleum
                           Company Ltd. filed September 21, 1988 in the Court of
                           Queen's  Bench  of  Alberta,   Judicial  District  of
                           Calgary,  Canada,  which  answers  the  Allied-Signal
                           complaint  in (b) above and which  names the  Company
                           and  others  as  counterclaim  defendants,  filed  as
                           Exhibit 99(b) to Registration  Statement No. 33-99052
                           as filed on November 7, 1995 is  incorporated  herein
                           by reference.


<PAGE>


                  (c)      Statement  of Claim filed on October 27, 1989 against
                           Columbia  Gas  Development  of  Canada  Ltd.,   Amoco
                           Production  Company,  Dome Petroleum  Limited,  Amoco
                           Canada Petroleum  Company Ltd., Mobil Oil Canada Ltd.
                           and Esso  Resources  of Canada  Ltd.  in the Court of
                           Queen's  Bench  of  Alberta   Judicial   District  of
                           Calgary,  Alberta,  Canada filed as Exhibit  99(c) to
                           Registration  Statement  No.  33-99052  as  filed  on
                           November 7, 1995 is incorporated herein by reference.

                  (d)      Amended Statement of Claim,  amending the October 27,
                           1989 Statement of Claim,  filed on March 12, 1990 and
                           filed as Exhibit 99(d) to Registration  Statement No.
                           33-99052 as filed on November 7, 1995 is incorporated
                           herein by reference.

                  (e)      Amended Statement of Claim in the same action,  filed
                           on November 17, 1993, filed as Exhibit 28(ii) to Form
                           8-K dated November 17, 1993 is incorporated herein by
                           reference.

                  (f)      Amended  Statement  of Third  Party  Notice  by Amoco
                           Canada  Production  Company Ltd. and Amoco Production
                           Company,  filed November 17, 1993 in the same action,
                           and filed as Exhibit 99(e).

                  (g)      Amended Statement of Defense to Third Party Notice by
                           Anderson  Oil  &  Gas  Inc.  (formerly  Columbia  Gas
                           Development of Canada Ltd.) filed January 27, 1994 in
                           the same action,  and filed as Exhibit  99(g) to Form
                           10-K dated for the period ended December 31, 1993, is
                           incorporated herein by reference.

                  (h)      Documents regarding settlement with AlliedSignal Inc.
                           as  Exhibits to Form 8-K as filed on January 30, 1996
                           are incorporated herein by reference.

                           (1)  Covenant Not to Sue.

                           (2)  Discontinuance of Action.  Action No. 8801-13549
                                Court  of  Queen's  Bench  of  Alberta  Judicial
                                District of Calgary.

                           (3)  Order.  Action  No. 8801-123549  Court of Queens
                                Bench of Alberta Judicial District of Calgary.

                           (4)  Partial Discontinuance of  Counterclaim.  Action
                                No. 8801-13549 Court of Queen  Bench of  Alberta
                                Judicial District of Calgary.
<PAGE>

                           (5)  Notice  of   Discontinuance   of   Third   Party
                                Proceedings as Against Allied-Signal Inc. Action
                                No. 9001-03466  Court of Queens Bench of Alberta
                                Judicial District of Calgary.

         (b)      Reports on Form 8-K

                  On October 1, 1997, the Company filed a Current Report on Form
8-K to report  that Mr.  Charles J. Horne  resigned as a director of the Company
for  primarily  health  reasons,  and that Mr.  Timothy L.  Largay was elected a
director.



<PAGE>



                                   SIGNATURES


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

                                        CANADA SOUTHERN PETROLEUM LTD.
                                                   (Registrant)


Dated:        March 27, 1998            By /s/ M. Anthony Ashton
       ---------------------------         -----------------------
                                           M. Anthony Ashton
                                           President and Chief Executive Officer

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


By /s/ M. Anthony Ashton                    By /s/ Beverley A. Scobie
   M. Anthony Ashton                           Beverley A. Scobie
   President and Director                      Treasurer and Chief Financial and
                                                  Accounting Officer

Dated:         March 27, 1998               Dated:         March 27, 1998
       -------------------------------             -----------------------------


By /s/ Benjamin W. Heath                    By /s/ Timothy L. Largay
   Benjamin W. Heath                           Timothy L. Largay
   Director                                    Director


Dated:         March 27, 1998               Dated:         March 27, 1998
       -------------------------------             -----------------------------


By /s/ Arthur B. O'Donnell                  By /s/ Eugene C. Pendery
   Arthur B. O'Donnell                         Eugene C. Pendery
   Director                                    Director


Dated:         March 27, 1998               Dated:         March 27, 1998
       -------------------------------             -----------------------------




<PAGE>



                                Index to Exhibits



                Exhibit 23(a)         Consent of Independent Petroleum Engineers


                Exhibit 23(b)         Consent of Independent Auditors


                Exhibit 27            Financial Data Schedule