UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                                    FORM 10-K


(Mark One)
[X]      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
         EXCHANGE ACT OF 1934

         For the fiscal year ended           December 31, 1999
                                   -------------------------------------

                                       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 0P6
      (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:


    Title of each class          Name of each exchange on which registered

   Limited Voting Shares,                 Boston Stock Exchange
   $1 (Canadian) per share                Pacific Exchange, Inc.
                                          Toronto Stock Exchange

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

   Limited Voting Shares,                   NASDAQ SmallCap Market
   $1 (Canadian) per share
                                (Title of Class)



<PAGE>





         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

         Indicate by check mark if disclosure of delinquent  filers  pursuant to
Item 405 of Regulation S-K(s.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.  $112,272,000 at March 17, 2000.

                   (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, 14,284,970
shares outstanding as of March 17, 2000.

                       DOCUMENTS INCORPORATED BY REFERENCE

         Proxy Statement of Canada Southern Petroleum Ltd. related to the Annual
Meeting  of  Shareholders  for the  year  ended  December  31,  1999,  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                                                          13

Item 3.  Legal Proceedings                                                   20

Item 4.  Submission of Matters to a Vote of Security Holders                 24

                                     PART II

Item 5.  Market for the Company's Limited Voting Shares and Related
         Stockholder Matters                                                 25

Item 6.  Selected Financial Data                                             27

Item 7.  Management's Discussion and Analysis of Financial Condition
         and Results of Operations                                           28

Item 7A. Quantitative and Qualitative Disclosures About Market Risk          35

Item 8.  Financial Statements and Supplementary Data                         36

Item 9.  Changes in and Disagreements with Accountants on
         Accounting and Financial Disclosure                                 58

                                    PART III

Item 10. Directors and Executive Officers of the Company                     58

Item 11. Executive Compensation                                              58

Item 12. Security Ownership of Certain Beneficial Owners and Management      58

Item 13. Certain Relationships and Related Transactions                      58

                                     PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K     59


----------------------------
Unless otherwise  indicated,  all dollar figures set forth are expressed in
Canadian currency.  The exchange rate at March 17, 2000 was $1.00 Canadian =
U.S. $.68.



<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  crude  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  natural gas field  located on  Exploration  Permit 1007 in the Yukon
Territory,  Canada.  The permit consists of 31,888 gross acres (9,566 net acres)
which is partially  developed  by two natural gas wells that had combined  gross
productive  capability  at December  31,  1999 of 65 million  cubic feet per day
(19.2  million   cubic  feet  per  day  net).   Gross  natural  gas  sales  were
approximately  45 million  cubic feet per day (net 13.5  million  cubic feet per
day) at December  31,1999 as a result of  shrinkage  and fuel gas  requirements.
Anderson  Exploration Ltd. (the "Operator")  operates the Kotaneelee  field. See
Item 3 - "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
                 1998                                  16.0
                 1999                                  22.3
                                                       ----
                 Total                                143.9
                                                      =====



<PAGE>


         A carried interest owner such as the Company is entitled to receive its
share of field  revenues  after  the  working  interest  parties  recover  their
operating and capital costs. The Operator  reported that as of November 30, 1999
development  costs  totaling  $96.7 million had been incurred and repaid.  As of
December 31, 1999,  the Operator also  reported that the Company's  share of net
revenues due to the Company totaled $412,374. The amount of recoverable costs is
one of the issues being  contested  in the  Kotaneelee  litigation.  The Company
claims,  and the defendants deny, that the defendants have made improper charges
to the carried interest account and one defendant (Amoco Canada)  maintains that
the  carried  interest  account  should be charged  additional  amounts  for gas
processing fees. Amoco Canada claims that the remaining costs to be recovered at
July 31, 1999 were either  $72,369,000 or $33,911,000  depending on inclusion of
interest.  At this time,  it is not possible to determine whether Amoco Canada
will be successful in its claim that gas processing fees should be charged to
the carried interest account.

         Although, according to the Operator's reports, the Kotaneelee gas field
reached pay out status on November  10,  1999,  the  Operator  has  notified the
Company  that it will not make any  payments  to the  carried  interest  owners,
including the Company,  until the issue of the amount of recoverable costs under
the carried  interest  account has been resolved by the Court of Queens Bench in
Calgary,  Canada.  The Operator  has stated that it will  deposit the  Company's
share of net production  proceeds in an interest  bearing account with an escrow
agent.  During March 2000, the Operator deposited $136,728 in the escrow account
which  represents the  Operator's  share of December 1999 gas sales less January
and February  2000  operating  and capital  expenditures.  A motion was filed in
December  1999 by the  plaintiffs  in Canada to direct all of the  defendants to
make timely  payments of all current and future  amounts due from the  Company's
share of field revenues. The Company expects that the Court will hear the motion
in April 2000.

British Columbia Properties

         The  Company's  major  source of income has been from the sale of crude
oil and natural gas from its properties  located in northeast  British  Columbia
where the Company has working and carried interests.

         In  addition  to its  producing  properties,  the  Company  has various
petroleum and natural gas leases in northeast British  Columbia.  As a result of
the geological and geophysical work performed on these leases,  various drilling
prospects were  identified.  Certain of these prospects were farmed-out to other
operators  and five  wells  were  drilled  in 1999 of  which  three  wells  were
successful.  There are also other  prospects  which have not been  drilled.  The
cumulative  dry  hole  costs  to  drill  these  prospects  is  estimated  to  be
approximately  $1.75 million.  The Company  continues to evaluate and attempt to
acquire  additional  petroleum  and  natural  gas  leases in  British  Columbia.
Presently,  the Company has interests in 49,013 gross developed acres (7,977 net
acres) and 28,820 gross undeveloped acres (15,091 net acres).

Arctic Islands

         As of December 31, 1999,  the Company held working  interests in 45,100
gross  acres  (1,817 net acres) and  carried  interests  in 133,260  gross acres
(37,257 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 Canadian
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. In 1996, the operator shut down  production  from
the  field  and  dismantled  the  production   facilities  because  of  economic
uncertainties.  The Company has a 5% carried  interest in the area which has not
yet reached pay out status. The timing of any pay out is uncertain.

Northwest Territories Properties

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

         Because  of the  recent  activity  in the  Northwest  Territories,  the
Company is reviewing its holdings in the area to take advantage of any potential
opportunities.

Alberta

           During  1999,  the  Company's   primary  Alberta  asset  and  revenue
producing  property was its heavy crude oil production and related facilities at
Kitscoty.  Due to the  requirement of  significant  additional  investment,  the
prospect of low prices for heavy oil and a shift in its business  strategy,  the
Company sold its 10 % working  interest to the  operator for $336,000  effective
October 1, 1999.  The  transaction  was completed  during  February 2000 and the
proceeds of sale will be credited to oil and gas properties in fiscal 2000.

         The Company  continues to invest in petroleum and natural gas leases in
Alberta  and has a current  land  inventory  of 21,637  gross  acres  (7,354 net
acres).  Its interests  range from 10% to 100% in these  leases.  The Company is
presently  performing  geological  and  geophysical  work  on  these  leases  to
determine the prospects for commercial petroleum and natural gas production.  As
prospects  are   identified,   the  Company  may  participate  in  drilling  or,
alternatively,   farm  out  the  prospects  to  other   operators  for  drilling
commitments.

Saskatchewan

         The  Company  has  a  3.75%  working   interest  in  five  sections  in
Saskatchewan.  During 1999,  there was no activity on these  properties  and the
lands remain undeveloped.

United States

         Texas

         In 1999, the Company participated in the drilling and completion of two
wells in Stephens County, Texas at a cost of $382,000.  This resulted in one dry
hole and one nominal crude oil/natural gas producer. The Company will attempt to
farm out its remaining  undrilled acreage and expects to make minimal additional
investment during the year 2000.

         California

         During  1999,  the Company sold its  investment  in its heavy crude oil
recovery project in California because of  dissatisfaction  with the progress of
the program to develop the field reserves.  The  consideration  received for its
30% interest was the purchaser's  common stock  (presently  unmarketable)  and a
promissory note which together approximated the carrying costs ($196,000) of the
property prior to the costs being written down in 1998 to a nominal value of $1.

         (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 - "Financial  Statements  and  Supplemental  Data" 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, Saskatchewan, the Northwest and
Yukon Territories and the Arctic Islands in Canada and in the United States. The
Company's principal asset 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, 1999, the Company's  share of unrecouped
expenditures was as follows:

         British Columbia:
           Ex-permit 149                           $4,019,000
           Ex-permit 102 (Siphon)                     980,000(At May 31, 1999)

         Yukon and Northwest Territories:
            Ex-permit 2713 (Celibeta)                 321,000


                   (i)      Principal Products

                            The  majority of the Company's oil and gas interests
are carried interests. The Company also participates in the production and sale
of crude oil and natural gas 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.

                   (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
crude oil and natural gas discovered on the areas covered.  See the 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

                            Most of the natural gas produced from Company
carried interest properties is being sold by the operators, Anderson Exploration
Ltd. and Petro-Canada Oil and Gas, to various gas marketers.  The production
from the Kotaneelee gas field is being sold by the working interest partners who
have not disclosed the purchasers.

                   (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 crude 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 crude oil or gas is dependent upon considerations such as
the ability to finance development costs, the availability of equipment, and the
ability to overcome 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 those 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) - "Risks Attendant to Foreign Operations".


                   (xi)     Research and Development

                            Not applicable.

                   (xii)    Environmental Regulation
                            See  Government ReguIation of the Canadian Oil and
Gas Industry - Environmental Regulation.

                   (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)      Revenues, Operating Losses and Identifiable Assets

                           Substantially all of the Company's operating assets
and revenues are attributable to its operations in Canada.  Operating losses are
substantially attributable to the ongoing Kotaneelee litigation.

                  (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.

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  crude 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.  Crude oil and  natural  gas  located  in such
provinces can also be privately owned and rights to explore for and produce such
crude 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 crude oil or natural gas is produced from the property.

         Crude 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  allowed for the transfer to the Yukon
of  authority  to  administer  and control  crude oil and natural gas  resources
within that  territory and for the  establishment  of an Oil and Gas  Management
Regime.  The transfer has been completed and the lands are now  administered  by
the Yukon Government.

Production and Production Facilities

         The Governments of Canada,  Alberta,  British Columbia and Saskatchewan
have enacted  statutory  provisions  regulating  the production of crude 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 crude oil and
natural gas are also subject to regulation.

Pricing and Marketing - Crude oil

         In Canada,  producers of crude oil negotiate sales  contracts  directly
with crude oil purchasers,  with the result that the market determines the price
of crude oil. Certain purchasers periodically advertise for volumes of crude oil
they are prepared to purchase and the price being offered for such volumes.  The
price depends in part on crude oil quality,  prices of competing fuels, distance
to market and the value of refined products.

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
National  Energy Board ("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 crude 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
crude 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 crude oil exploration or enhanced recovery projects.  Incentives
are intended to enhance the existing  cash flow of the crude oil and natural gas
industry  and to improve the  economics of finding and  developing  new and more
costly  crude oil and  natural gas  reserves.  Crude 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.

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 crude 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.
The exploratory  ventures are properties  located in British Columbia,  Alberta,
Saskatchewan,  the Yukon and  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 are shown below.  Production costs are allocated
based on the weighted  average of oil and gas sales. In 1999, oil production was
primarily  heavy  crude  oil  with  high  lifting  costs.  In prior  years,  oil
production consisted of a mix of light and heavy crude oil.


                   Average Sales Price          Average Production Costs
         Year    Oil (per bbl) Gas (per mcf)     Oil (per bbl) Gas (per mcf)
                   ($)            ($)               ($)           ($)
         1999      17.38          1.83              12.82         1.45
         1998      14.84          2.17               8.41         1.41
         1997      22.50          2.31               8.70         1.30

(4)      Productive Wells and Acreage

         Productive wells and acreage on working and carried interest properties
as of December 31, 1999 are as follows:

            Gross Wells                        Net Wells
       Oil               Gas             Oil              Gas
        36                72             3.536           12.264

                                             Gross and Net Developed Acres
                                          Gross Acres            Net Acres

           Alberta                            5,420                   669
           British Columbia                  49,013                 7,977
           Yukon Territory                    3,350                 1,005
           Arctic Islands                     3,060                   153
           Texas, USA                            40                    16
                                          ---------               -------
                                             60,883                 9,820
                                             ======                 =====



<PAGE>


(5)      Undeveloped Acreage

         Total  developed  and  undeveloped  acreage  in which the  Company  has
interests is summarized by geographic area in the table below:
<TABLE>
                              Gross and Net Petroleum Acreage as of December 31, 1999
                                                    Developed Acres                    Undeveloped Acres
                                                 Gross          Net                   Gross          Net
                                                 Acres         Acres         %        Acres         Acres        %
Canada:
  British Columbia:
<S>                                              <C>            <C>        <C>          <C>            <C>      <C>
    Carried Interests                            30,130         6,410      21.3         5,708          1213     21.3
    Working Interests                             5,622           910      16.2        18,473        13,804     74.7
    Overriding royalty interest                  13,261           657       5.0         4,639            74      1.6
                                                 ------        ------                 -------     ---------
  Total British Columbia                         49,013         7,977                  28,820        15,091
                                                 ------         -----                  ------       -------

  Saskatchewan:
    Working Interests                                                                   3,200           120      3.8
                                                                                      -------      --------

  Alberta:
    Working Interests                             3,511           645      18.4        21,477         7,349     34.2
    Overriding Royalty Interest                   1,909            24       1.3           160             5      3.1
                                                -------       -------                --------    ----------
  Total Alberta                                   5,420           669                  21,637         7,354
                                                -------        ------                  ------       -------

  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       130,200        37,104     28.5
    Working Interests                                  -            -                  45,100         1,817      4.0
                                             -----------    ---------                --------       -------
  Total Arctic Islands                            3,060           153                 175,300        38,921
                                                -------        ------                 -------        ------

  Total Canada                                   60,843         9,804                 260,683        71,243

Texas, USA                                           40            16      40.0           460           245     53.3
                                                -------       -------               ---------      --------

               TOTAL                             60,883         9,820                 261,143        71,488
                                                 ======         =====                 =======        ======
</TABLE>

(6)      Drilling activity

         Productive and dry net wells drilled during the following periods:

                                  Gross                     Net
                    Year   Productive    Dry     Productive       Dry
                    1999       4          2        1.127          .798
                    1998       9          2        1.440          .200
                    1997      25          2        3.606          .250


<PAGE>


(7)      Present Activities

         There were no wells drilling at December 31, 1999.

(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"). 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 (the  "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 proceedings  currently
at trial.

         The Company claims that the Defendants  breached a contract  obligation
and/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  presented  evidence  at trial  that the money  damages
sustained by the Company were approximately $100 million.

         In  addition,  the  Company  has  claimed  that the  Company's  carried
interest  account should be reduced  because of 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 pay out 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 out in  approximately  two years and the
Company  would  have  begun to  receive  revenues  from the  field in 1986.  The
Operator has reported that as of November 30, 1999  development  costs  totaling
$96.7  million had been incurred and repaid.  As of December 31, 1999,  based on
the Operator's report, the Company's share of net revenues due to the Company by
all the defendants totaled $412,374.

         The amount of recoverable costs is one of the issues being contested in
the Kotaneelee litigation. The Company claims, and the defendants deny, that the
defendants have made improper  charges to the carried  interest  account and one
defendant  (Amoco Canada)  maintains that the carried interest account should be
charged additional amounts for gas processing fees. Amoco Canada claims that the
remaining  costs to be  recovered  at July 31, 1999 were either  $72,369,000  or
$33,911,000 depending on inclusion of interest. At this time, it is not possible
to  determine  whether  Amoco  Canada will be  successful  in its claim that gas
processing fees should be charged to the carried interest account.

         Although, according to the Operator's reports, the Kotaneelee gas field
reached pay out status on November  10,  1999,  the  Operator  has  notified the
Company  that it will not make any  payments  to the  carried  interest  owners,
including the Company,  until the issue of the amount of recoverable costs under
the carried  interest  account has been resolved by the Court of Queens Bench in
Calgary,  Canada.  The Operator  has stated that it will  deposit the  Company's
share of net production  proceeds in an interest  bearing account with an escrow
agent.  During March 2000, the Operator deposited $136,728 in the escrow account
which  represents the  Operator's  share of December 1999 gas sales less January
and February  2000  operating  and capital  expenditures.  A motion was filed in
December  1999 by the  plaintiffs  in Canada to direct all of the  defendants to
make timely  payments of all current and future  amounts due from the  Company's
share of field revenues. The Company expects that the Court will hear the motion
in April 2000.

         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 unrecovered sums Columbia has expended on the Kotaneelee
lands before the Company is entitled to its interest.

         The parties to the litigation  conducted  extensive discovery since the
filing of the claims.  The trial began on September  3, 1996 and the  Plaintiffs
completed  the  presentation  of  their  case  against  the  Defendants   during
September,  1998. The Defendants  completed their case during February 2000. The
Company  estimates  that its rebuttal  evidence  will be completed  during March
2000.  Both  parties  to the suit will then have  several  months to file  their
written closing arguments with the Court,  which probably will hear closing oral
arguments in the fall of 2000.

         Based upon newly  discovered  evidence,  the Company  filed a new claim
during  May 1998 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.


         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  non-prevailing  party.  Previously,  the
Company had reported  that while such costs were not  determinable,  the Company
estimated  that  taxable  costs,   assuming  a  twelve  month  trial,  could  be
approximately  $1.5  million  and noted  that the judge in complex  and  lengthy
trials has the discretion to increase an award.

         Effective September 1, 1998, the Alberta Rules of Court were amended to
provide  for a  material  increase  in the  costs  which may be  awarded  to the
prevailing party in matters before the Court. In addition,  the Company believes
that the trial  will  extend  well  beyond  its  original  time  estimates  and,
therefore, potentially assessable costs would increase accordingly.

         The trial has been lengthy,  complicated  and costly to all parties and
the Company believes that the prevailing party or parties in the litigation will
argue for a substantial  assessment of costs against the non-prevailing party or
parties.  The Court has very broad  discretion  as to whether to award costs and
disbursements  and  as  to  the  calculation  of  any  amounts  to  be  awarded.
Accordingly,  the Company is unable to determine  whether,  in the event that it
does not prevail on its claims in the litigation, costs will be assessed against
it or in what amounts.  However, since the costs incurred by the Defendants have
been  substantial,  and since the Court has broad  discretion in the awarding of
costs, an award to the Defendants  potentially  could be material.  A cost award
against the Company  could be of sufficient  magnitude to  necessitate a sale of
Company assets or a debt or equity financing to fund such an award. There are no
assurances that any such sale or financing would be consummated.

         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. Anthony Ashton      64       President     Since 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, Pacific and Boston Stock Exchanges [Symbol: CSW], and in
the NASDAQ SmallCap Market [Symbol: CSPLF].

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

1998       1st quarter        2nd quarter       3rd quarter         4th quarter
----       -----------        -----------       -----------         -----------
High         11.75               10.50              9.00                10.00
Low           9.00                8.00              5.50                 6.25


1999       1st quarter         2nd quarter       3rd quarter        4th quarter
----       -----------         -----------       -----------        -----------
High         11.00               11.00             16.00                12.35
Low           6.00                7.50             10.75                 8.00

         The quarterly high and low closing prices (in United States dollars) on
the  NASDAQ  SmallCap  Market  during the  calendar  periods  indicated  were as
follows:

1998       1st quarter         2nd quarter       3rd quarter        4th quarter
----       -----------         -----------       -----------        -----------
High         8.50                 7.88              6.63                 6.75
Low          6.25                 5.63              3.31                 3.94


1999       1st quarter         2nd quarter       3rd quarter        4th quarter
----       -----------         -----------       -----------        -----------
High         7.63                 7.50             11.50                 8.50
Low          4.50                 5.38              6.50                 5.09



<PAGE>


         (b)      Approximate Number of Holders of Limited Voting
                  Shares at March 17 , 2000

                                                            Approximate
         Title of Class                               Number of Record Holders

      Limited Voting Shares, par value                        4,500
      $1.00 per share.

         (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 deficit($25,542,920)
at December 31, 1999) 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.

         (d)      Recent Sales of Unregistered Securities

                  None.



<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.  Financial data for the years prior to 1999
have  been  restated  to  reflect  a change  from  the  deferral  method  of tax
allocation  accounting to the liability  method of accounting  for income taxes.
(See Note 1 of Notes to the Consolidated Financial Statements)

<TABLE>
                                                                           Year ended December 31,
------------------------------------------------------------------------------------------------------------------------------------
                                              1999               1998               1997                1996               1995
                                              ----               ----               ----                ----               ----
                                              ($)                 ($)                ($)                ($)                 ($)
                                                              (Restated)         (Restated)          (Restated)         (Restated)

<S>                                              <C>               <C>                <C>                <C>                 <C>
Operating revenues                               777               1,810              2,120              1,755               1,657
                                            ========             =======            =======            =======             =======

Total revenues                                 1,030               3,409              2,515              2,228               1,793
                                             =======             =======            =======            =======             =======

Net loss                                      (3,001)             (2,328)            (1,588)            (1,236)             (1,001)
                                             ========            ========           ========           ========            ========

Net loss per share                              (.21)              (.16)              (.11)              (.09)               (.08)
                                                =====          =========          =========          =========           =========

Working capital                                3,629               6,876              5,573              8,403               1,510
                                             =======             =======            =======            =======             =======

Total assets                                  17,216              19,740             22,772             22,021              13,801
                                              ======              ======             ======             ======             =======

Shareholders' Equity:
     Capital stock                            40,787              40,489             40,489             38,888              29,635
     Deficit                                 (25,542)            (22,540)           (18,625)           (17,037)            (15,801)
                                             --------            --------           --------           --------            --------
                                              15,245              17,949             21,864             21,851              13,834
                                             =======             =======            =======            =======             =======
Average number of
  shares outstanding                          14,253              14,235             14,084             13,362              12,622
                                             =======             =======            =======            =======             =======

Exchange rates:
     Year-end                                .6924               .6535              .6992              .7297               .7329
                                             =====               =====              =====              =====               =====

     Average for the period                  .6733               .6749              .7224              .7335               .7289
                                             =====               =====              =====              =====               =====

     Range                                  .67-.68             .63-.67            .69-.75            .72-.75             .70-.75
                                            =======             =======            =======            =======             =======
</TABLE>




<PAGE>


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

         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.

         Among these risks and uncertainties are:

         o  uncertainties as to the costs, length and outcome of the Kotaneelee
            litigation;

         o  uncertainty as to when or if the Company will receive its share of
            revenue from the Kotaneelee gas field.

(1)      Liquidity and Capital Resources

     At December 31, 1999,  the Company had  approximately  $3.6 million of cash
and  marketable  securities.  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  currently  has
adequate  working  capital for the year 2000.  However,  it might 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 1999 increased to $2,730,000
compared to $2,351,000 during the 1998 period.  The $379,000 difference between
the periods was caused primarily by the following:


                  Increase in loss from operations            $   (125,000)
                  Increase in accounts receivable and other       (965,000)
                  Net change in current liabilities                711,000
                                                                -------------
                  Increase in net cash used in operations     $   (379,000)
                                                              ==================

         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.  The  Kotaneelee  gas field and  certain
properties  in the Fort Nelson,  British  Columbia area in which the Company has
carried  interests  have  reached pay out 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 1999 will be approximately  $600,000.  In
addition,  substantial  continuing  expenses  are  expected  to be  incurred  in
connection  with the Kotaneelee  Litigation.  During 1999, the Company  expended
approximately  $2.1 million in connection with the Kotaneelee  Litigation  which
has been the principal cause of the Company's losses since 1991.

         The Company has  established  a provision  for its  potential  share of
future site  restoration  costs which totals  $175,000.  The estimated amount of
these costs,  which total  $228,000,  is being  provided on a unit of production
basis in accordance with existing legislation and industry practice.

 (2)     Results of Operations


Accounting policy changes

     In 1999, under new  recommendations  of the Canadian Institute of Chartered
Accountants,   the  Company   retroactively  adopted  the  liability  method  of
accounting for income taxes. Under this method, the Company records income taxes
to give effect to temporary  differences between the carrying amount and the tax
basis of the Company's assets and liabilities.  Temporary differences arise when
the  realization of an asset or the settlement of a liability would give rise to
either an increase or decrease in the  Company's  income  taxes  payable for the
year or later period. Future income taxes are recorded at the enacted income tax
rates that are expected to apply when the future tax liability is settled or the
future tax asset is  realized.  Income tax  expense is the tax  payable  for the
period and the change  during the period in future  income tax and  liabilities.
The  adoption of this  standard has  resulted in the  recognition  of future tax
assets and a reduction of the deficit at December 31, 1999 of $2,726,613 (1998 -
$2,194,197;  1997 -  $1,815,830)  and a  reduction  in the net  loss for 1999 of
$274,970  (1998 - $378,367;  1997 - $170,158).  This new standard is  consistent
with the accounting principles generally accepted in the United States.

1999 vs. 1998

         The net loss for the year 1999 was $3,001,424  ($.21 per share)
compared to a net loss of $2,328,170  ($.16 per share) for the 1998 period.  A
summary of revenue and expenses during the periods is as follows:

                          1999                 1998            Net Change
                          ----                 ----            ----------
Revenues            $   1,029,899          $ 3,409,361       $ (2,379,462)
Costs and expenses     (4,031,323)          (5,737,531)         1,706,208
                    --------------        -------------      -------------
Net loss            $ (3,001,424)          $(2,328,170)     $    (673,254)
                    =============          ============     ==============

         Oil  sales  decreased  by  83%  due  primarily  to a  86%  decrease  in
production which was partially offset by a 17% increase in the average prices of
crude oil sold. There was also a corresponding decrease in royalties paid by the
Company.  The Company sold the majority of its crude oil producing properties in
two  separate  transactions  effective  July 1,  1998  and  September  1,  1998.
Since the Company has disposed of most of its producing  properties,  future oil
sales are expected to be minimal  unless  additional  producing  properties  are
acquired through drilling or purchase. The 1999 royalties paid amount includes a
provincial  royalty tax credit in the amount of $4,782.  Crude oil unit sales in
barrels ("bbls") (before  deducting  royalties) and the average price per barrel
sold during the periods indicated were as follows:
                           1999                               1998
                       Average price                      Average price
                bbls       per bbl     Total          bbls    per bbl   Total

Crude oil      9,171       $17.38   $  159,000       64,954   $14.84   $964,000
sales
Royalties paid                          (8,000)                         (66,000)
                                  -------------                      -----------
Total                                 $ 151,000                         $898,000
                                      =========                         ========

         Gas sales  decreased  95% because of a 93%  decrease in number of units
sold and a 16%  decrease in the average  price for gas. In  addition,  gas sales
include  royalty  income  which  decreased  49% in 1999.  The  Company  sold the
majority of its working  interest gas properties  effective July 1, 1998,  which
accounts for the decrease in gas sales. Royalties paid includes a $59,000 amount
as part of a  settlement  for  royalties  due for the 1991 to 1998  period.  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:

                           1999                            1998
                       Average price                   Average price
                  mmcf   per mcf   Total         mmcf     per mcf     Total

Gas sales          21    $1.83    $ 37,000        304     $2.17      $660,000
Royalty income                      64,000                            127,000
Royalties paid                     (63,000)                           (82,000)
                                 ----------                        -----------
Total                              $ 38,000                           $705,000
                                   ========                           ========

         Proceeds from carried interests  increased 184% to $587,000 during 1999
compared  to  $207,000  in 1998  primarily  because  gas prices  increased  58%.
Operating  costs also  decreased  20% during 1999 . 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>



                             1999                          1998
                         Average price                 Average price
                   mmcf     per mcf     Total       mmcf   per mcf   Total

Gas sales          563      $2.79    $ 1,572,000    575     $1.77  $1016,000
Royalty paid                            (327,000)                   (238,000)
Operating costs                         (417,000)                   (522,000)
Capital costs                           (241,000)                    (49,000)
                                        --------                     --------
Total                                  $ 587,000                     $207,000
                                       =========                     ========

         Share of Kotaneelee net revenues for 1999.  Although,  according to the
Operator's  reports,  the Kotaneelee gas field carried  interest reached pay out
status during  November  1999, no revenue has been accrued for 1999. In order to
bring its billing practices in line with the industry standard,  the Operator of
the field changed the prior method of reporting the revenue and  expenditures of
the field.  This  resulted in two months of capital  expenditures  and operating
expenses  (December 1999 and January 2000) being charged  against a single month
of revenue  (November  1999).  This change in reporting is  consistent  with the
reporting of other  carried  interests  currently  held by the  Company.  In the
future,  the Company  expects that the  reporting of  Kotaneelee  gas sales will
continue  to lag  two  months  behind  actual  operating  expenses  and  capital
expenditures.  In addition,  the production  revenue from the two last months of
each quarter is accrued  during the  following  quarter because the data are not
usually available.

         As of December 31, 1999, based on the Operator's reports, the Company's
share of net revenues due the Company by all the  defendants  totaled  $412,374.
This amount was computed as follows:

Net Revenues (after royalties):
    November 1999 (after pay out)                          $  864,506
    December 1999                                           1,212,821
                                                           ----------
Total Revenues                                              2,077,327

Operating Expenses:
    November 1999 (after pay out)                             264,848
    December 1999                                             393,389
    January 2000                                               54,889
                                                          -----------
Total Operating Expenses                                      713,126

Capital Expenditures:
    December 1999                                             368,963
    January 2000                                              539,899
    February 2000                                              42,965
                                                         ------------
Total Capital Expenditures                                    951,827

Company share of net revenues                             $   412,374
                                                          ===========

         The Operator reported that it deposited during March 2000 the amount of
$136,728  in an escrow  account  for the benefit of the  Company.  This  deposit
represents the Operator's share of the $412,374 amount due.

         The  Kotaneelee  field  working  interest  partners  have  approved the
expenditure of an estimated $4.1 million for the  installation  of a compression
unit in the field to maintain  current  production  levels.  The schedule  above
reflects a charge of $951,827  against the  Company's  share of revenues for its
share of these costs which total  $1,372,000.  The remaining balance of $420,173
will be deducted from the Company's share of the year 2000 production  revenues.
Therefore,  the  share of  Kotaneelee  net  revenues  may  fluctuate  each  year
depending  on both  capital  expenditures  and any audit  adjustments  which are
attributable to prior years.

         Interest  and  other  income  increased  14% in 1999.  Interest  income
increased  from  $194,000  to  $230,000  in 1999  due to an  increase  in  funds
available  for  investment  during 1999  because of the  proceeds of sale of the
crude oil and gas  properties  in 1998.  In addition,  the 1999 period  includes
proceeds  from the sale of seismic  data in the amount of  $16,000  compared  to
$27,000 from such sales in 1998.  It is not possible for the Company to estimate
the amount of future  seismic data sales which are  dependent  on a  purchaser's
need for the seismic data that the Company owns.

         Gain on the sale of properties in 1999.  There were no properties  sold
in 1999. In 1998,  there was a gain of $1,378,000 from the sale of the Company's
heavy crude oil properties in Alberta and the sale of certain  working  interest
properties in British Columbia.

         General and  administrative  costs  decreased 7% in 1999 to  $1,209,000
from $1,301,000 in 1998.

         Legal  expenses  decreased  11% during 1999 to  $2,108,000  compared to
$2,358,000  during 1998. These expenses are related primarily to the cost of the
Kotaneelee  litigation.  During 1998, the Company  completed the presentation of
its case against the working  interest  partners.  The 1998 costs represent both
legal fees and the cost of various  Company  experts who  testified,  were being
prepared  for  testimony,  or  assisted  in  the  cross-examination  of  defense
witnesses.  During 1999, the Company continued its  cross-examination of defense
witnesses.

         Lease operating costs decreased 85% from $976,000 in 1998 to $147,000
in the 1999 period. The Company sold the majority of its oil and gas producing
properties during the second half of 1998.

         Depletion,  depreciation and amortization expense decreased 19% in 1999
to $707,000  from $870,000 in 1998.  Although,  the Company sold the majority of
its oil and gas producing  properties during 1998, the increased production from
the pay out of the  Kotaneelee  carried  interest  increased the 1999  depletion
expense by approximately $420,000.

         A foreign  exchange  loss of $77,000 was  recorded in 1999,  contrasted
with a gain of $179,000 on the Company's  U.S.  investments in 1998. In 1999 the
value of the Canadian dollar increased from U.S. $.65 to U.S. $.69. In 1998, the
gain was  attributable  to the continuing  strengthening  of the U.S.  dollar as
compared to the Canadian dollar on the Company's U.S. investments.

         Abandonments and write downs.  There were no abandonments and write
downs in 1999.  The 1998 amount of 685,000 resulted from a write down of certain
of the Company's properties in California and Texas.

         Income tax recovery  decreased  by 27% to $275,000 in 1999  compared to
$378,000 in 1998. The income tax recovery in 1999 decreased  because the loss in
1999 was less than the loss in 1998 after giving effect to the  $1,378,000  gain
on sale of assets in 1998 which was not recognized for income tax purposes.

1998 vs. 1997

         The net loss for the year 1998 was $2,328,170 ($.16 per share) compared
to a net loss of $1,587,506 ($.11 per share) for the 1997 period.  A summary of
revenue and expenses during the periods is as follows:

                           1998                   1997             Net Change
                           ----                   ----             ----------
Revenues               $ 3,409,361            $ 2,514,978        $    894,383
Costs and expenses      (5,737,531)            (4,102,484)         (1,635,047)
                      -------------           -------------      -------------
Net loss               $(2,328,170)           $(1,587,506)       $   (740,664)
                       ============            ============      =============

         Crude oil sales decreased by 20% due primarily to a 34% decrease in the
average prices of crude oil sold which was partially  offset by a 2% increase in
production.  There was also a decrease in  royalties  paid by the  Company.  The
Company  sold the  majority  of its oil  producing  properties  in two  separate
transactions  effective  July 1, 1998 and September 1, 1998.  The 1998 royalties
paid amount includes a provincial  royalty tax credit in the amount of $117,000.
Oil unit sales in barrels ("bbls") (before deducting  royalties) and the average
price per barrel sold during the periods indicated were as follows:

                              1998                           1997
                          Average price                  Average price
                   bbls      per bbl   Total       bbls      per bbl     Total

Crude oil sales   64,954     $14.84   $964,000    63,783     $22.50  $1,436,000
Royalties paid                         (66,000)                        (315,000)
                                    -----------                    -------------
Total                                 $898,000                       $1,121,000
                                      ========                       ==========

         Gas sales  increased  35% because of a 52%  increase in number of units
sold which was  partially  offset by a 6% decrease in the average price for gas.
In addition,  gas sales include  royalty income which decreased 13% in 1998. The
Company sold the majority of its working interest gas properties  effective July
1, 1998.  The primary  increase in gas  production  was the pay out of two wells
that had been in a penalty position. These wells were included in the properties
sold.  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:

                        1998                             1997
                    Average price                    Average price
                mmcf   per mcf    Total       mmcf      per mcf         Total

Gas sales       304    $2.17    $660,000       200      $2.31        $462,000
Royalty income                   127,000                              146,000
Royalties paid                   (82,000)                             (85,000)
                              -----------                          -----------
Total                           $705,000                             $523,000
                                ========                             ========

         Proceeds from carried  interests  decreased 57% to $207,000 during 1998
compared to $476,000 in 1997.  During 1998, there were significant  expenditures
made by the operators of the carried interest properties

         Interest  and  other  income  decreased  44% in 1998.  Interest  income
decreased  from  $336,000  to  $194,000  in 1998  due to the  decrease  in funds
available for investment and lower interest rates. In addition,  the 1998 period
includes  proceeds  from the  sale of  seismic  data in the  amount  of  $27,000
compared to $59,000 from such sales in 1997.

         Gain on the sale of properties in 1998 amounted to $1,378,000 primarily
represents  the sale of the Company's  heavy crude oil properties in Alberta and
the sale of certain working interest properties in British Columbia.

         General and  administrative  costs  increased 18% in 1998 to $1,301,000
from $1,105,000 in 1997 primarily as a result of increased  Company  activity in
connection with the Kotaneelee litigation and the Company's exploration program.
In addition,  the  expenses  increased  in the United  States  because of the 7%
increase in the value of the U.S.  dollar compared to the Canadian dollar during
1998.

         Legal  expenses  increased  24% during 1998 to  $2,358,000  compared to
$1,898,000  during 1997. These expenses are related primarily to the cost of the
Kotaneelee litigation.  During 1998, the Company continued the presentation of a
major part of its case against the working interest partners. The Company's case
was completed on September 16, 1998 and Defendants' case is now proceeding.  The
1998 costs represent both legal fees and the cost of various Company experts who
testified,   were  being   prepared   for   testimony,   or   assisted   in  the
cross-examination of defense witnesses.

         Lease  operating  costs increased 22% from $799,000 in 1997 to $976,000
in the 1998 period. The increase  represents the charges by the operators of the
Company's properties which is related to the increased production.  In addition,
the  Company's  share of production  costs in producing  Alberta heavy crude oil
increased.

         Depletion,  depreciation and amortization expense increased 39% in 1998
to $870,000  from  $624,000 in 1997.  The  increase in  depletion in 1998 is the
result  of  increased  production  and the  amount  of  additional  costs  being
depleted.

         A foreign  exchange  gain of $179,000 was recorded in 1998,  contrasted
with a gain of $231,000 on the Company's U.S.  investments in 1997. In 1998, the
gain was  attributable  to the continuing  strengthening  of the U.S.  dollar as
compared to the Canadian dollar on the Company's U.S. investments.

         Abandonments  and write downs were $685,000 which resulted from a write
down of certain of the Company's  properties in California and Texas. There were
no abandonments and write downs in 1997.

         Income tax  recovery  increased  122% to $378,000  in 1998  compared to
$170,000  in 1997.  The  increase  in the 1998  income tax  recovery  reflects a
similar  increase in the loss in 1998 after giving effect to the $1,378,000 gain
on sale of assets in 1998 which was not recognized for income tax purposes.






Item 7A. Quantitative and Qualitative Disclosure About Market Risk

         The Company  does not have any  significant  exposure to market risk as
the only market risk  sensitive  instruments  are its  investments in marketable
securities.  At December 31, 1999,  the carrying value of such  investments  was
approximately $ 3.2 million which was approximately equal to fair value and face
value of the  investments.  Since the Company expects to hold the investments to
maturity,  the maturity  value should be realized.  In addition,  the  Company's
investments in marketable  securities  included  investments  held in the United
States which are subject to foreign exchange fluctuations. At December 31, 1999,
the investments in the United States totaled $ 1.1 million.


<PAGE>


Item 8.  Financial Statements and Supplementary Data



                                AUDITORS' REPORT




To the Shareholders of
Canada Southern Petroleum Ltd.


We have audited the  consolidated  balance sheets of Canada  Southern  Petroleum
Ltd.  as at December  31,  1999 and 1998,  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, 1999.
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 auditing standards generally accepted
in Canada.  Those standards  require that we plan and perform an audit to obtain
reasonable  assurance  whether  the  financial  statements  are free of material
misstatement.  An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements.  An audit also includes
assessing the  accounting  principles  used and  significant  estimates  made by
management, as well as evaluating the overall financial statement presentation.

In our opinion,  the consolidated  financial  statements  present fairly, in all
material  respects,  the financial position of Canada Southern Petroleum Ltd. as
at December  31, 1999 and 1998 and the  results of its  operations  and its cash
flows for each of the years in the three year period ended December 31, 1999, in
accordance with accounting principles generally accepted in Canada.




Calgary, Canada                                          /s/ ERNST & YOUNG LLP
March 10, 2000                                           Chartered Accountants


<PAGE>


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

                           CONSOLIDATED BALANCE SHEETS
                         (Expressed in Canadian dollars)
<TABLE>
                                                                                         As at December 31,
                                                                                    1999                   1998
            Assets                                                                                       (Restated)
 Current assets
<S>                                                                             <C>                   <C>
 Cash and cash equivalents (Note 2)                                             $ 3,045,530           $  6,208,634
  Marketable securities (Note 3)                                                    568,374                751,511
  Accounts receivable (Notes 4 and 7)                                               360,752                266,116
  Accounts receivable - Kotaneelee (Note 8)                                               -                      -
   Other assets                                                                     307,519                319,697
                                                                               ------------         --------------
 Total current assets                                                             4,282,175              7,545,958
                                                                                -----------          -------------

 Oil and gas properties and equipment
   (full cost method) (Note 4)                                                   10,207,294             10,000,010
 Future tax asset (Note 6)                                                        1,583,475              1,308,505
                                                                              -------------          -------------
 Total assets                                                                   $16,072,944            $18,854,473
                                                                                ===========            ===========

           Liabilities and Shareholders' Equity

 Current liabilities
   Accounts payable                                                           $     634,600          $     375,554
   Accrued liabilities (Note 10)                                                     18,256                294,491
                                                                            ---------------         --------------
 Total current liabilities                                                          652,856                670,045
                                                                             --------------         --------------

 Future site restoration costs                                                      174,696                236,045
                                                                             --------------         --------------

 Contingencies (Note 8)                                                                   -                      -

 Shareholders' Equity
   Limited Voting Shares, par value
     $1 per share (Note 5)
   Authorized -100,000,000 shares
   Outstanding -14,284,970 (1999) 14,234,740 (1998) shares                       14,284,970             14,234,740
   Contributed surplus                                                           26,502,342             26,254,139
                                                                               ------------           ------------
 Total capital                                                                   40,787,312             40,488,879
 Deficit                                                                        (25,541,920)           (22,540,496)
                                                                               -------------          -------------
 Total shareholders' equity                                                      15,245,392             17,948,383
                                                                               ------------           ------------
 Total liabilities and shareholders' equity                                     $16,072,944            $18,854,473
                                                                                ===========            ===========
</TABLE>
                                                        See accompanying notes.


        Approved on behalf of the Board

                /s/ M. Anthony Ashton                   /s/ Arthur B. O'Donnell
                         Director                                Director


<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

                CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
                         (Expressed in Canadian dollars)

<TABLE>
                                                                               Year ended December 31,
                                                                   1999                 1998                 1997
                                                                                    (Restated)           (Restated)
Revenues:
<S>                                                         <C>                 <C>                    <C>
  Oil sales (Notes 9 and 10)                                $     151,137       $      897,878         $  1,120,789
  Gas sales (Notes 9 and 10)                                       38,324              705,277              523,433
  Proceeds from carried interests                                 587,073              206,503              475,697
  Share of Kotaneelee net revenues (Note 8)
                                                                        -                    -                    -
  Interest and other income                                       253,365              221,523              395,059
  Gain on sale of assets                                                             1,378,180
                                                                       -                                          -
                                                           --------------       --------------      ---------------
    Total revenues                                              1,029,899            3,409,361            2,514,978
                                                           --------------       --------------       --------------

Costs and expenses:
  General and administrative                                    1,209,325            1,300,595            1,104,535
  Legal (Note 8)                                                2,108,521            2,357,707            1,897,506
  Lease operating costs                                           147,332              975,899              799,372
  Depletion, depreciation and amortization                        707,200              869,600              623,600
  Foreign exchange (gains) losses                                  77,475             (178,850)            (231,457)
  Provision for future site restoration costs                         600               29,500               21,500
  Rent                                                             55,840               76,812               57,586
  Abandonments and write downs                                         -               684,635                   -
                                                           --------------       --------------       --------------
    Total costs and expenses                                    4,306,293            6,115,898            4,272,642
                                                           --------------       --------------       --------------

  Loss before income taxes                                     (3,276,394)          (2,706,537)          (1,757,664)
  Income tax recovery (Note 6)                                    274,970              378,367              170,158
                                                          ----------------     ---------------      ---------------
Net loss                                                       (3,001,424)          (2,328,170)          (1,587,506)
  Deficit - beginning of year                                 (22,540,496)         (20,212,326)         (18,624,820)
                                                            --------------       --------------       --------------
  Deficit - end of year                                      $(25,541,920)        $(22,540,496)        $(20,212,326)
                                                             =============        =============        =============

Net loss per share (Basic & Fully Diluted)                    $(.21)               $(.16)               $(.11)
                                                              ======               ======               ======

Average number of shares
  Outstanding (Basic & Fully Diluted)                          14,252,574           14,234,740           14,084,294
                                                               ==========           ==========           ==========
</TABLE>

                                                        See accompanying notes.



<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                         (Expressed in Canadian dollars)
<TABLE>
                                                                           Year ended December 31,
                                                               1999                   1998                   1997
                                                                                   (Restated)             (Restated)
Cash flows from operating activities:
<S>                                                        <C>                    <C>                    <C>
   Net loss                                               $(3,001,424)           $(2,328,170)           $(1,587,506)
    Adjustments to reconcile net loss
       to net cash provided by
      (used in) operating activities:
    Depreciation, depletion and amortization                   707,200                869,600                623,600
    Future site restoration costs (net)                        (61,349)                25,071                (39,300)
    Gain on sale of assets                                           -             (1,378,180)                     -
    Abandonments and write downs                                     -                684,635                      -
    Future tax recovery                                       (274,970)              (378,367)              (170,158)
  Change in assets and liabilities:
    Accounts receivable                                        (94,636)               959,970               (590,863)
    Other assets                                                12,178                (77,419)               (14,910)
    Accounts payable                                           259,045               (744,967)               680,684
    Accrued liabilities                                       (276,235)                16,776                 95,611
                                                          -------------         -------------          -------------
Net cash used in operations                                 (2,730,191)            (2,351,051)            (1,002,842)
                                                          -------------         ------------           ------------

Cash flows from investing activities:
  Additions   to  oil   and  gas   properties   and           (914,483)            (1,942,474)            (3,258,426)
  equipment
  Sale (purchase) of marketable securities                     183,137              2,621,823              2,079,452
  Proceeds from the sale of properties                                -             5,751,180                       -
                                                          -------------           -----------            ------------
Net cash provided by (used in) investing activities           (731,346)             6,430,529             (1,178,974)
                                                          -------------           -----------            ------------

Cash flows from financing activities:
  Exercise of stock options                                    298,433                       -             1,601,375
                                                         -------------            ------------           -----------
Net cash from financing activities                             298,433                       -             1,601,375
                                                         -------------            ------------           -----------

Increase (decrease) in cash
  and cash equivalents                                      (3,163,104)             4,079,478               (580,441)
Cash and cash equivalents at the
  beginning of period                                        6,208,634              2,129,156              2,709,597
                                                           -----------            -----------            -----------
Cash and cash equivalents at the
  end of period (Note 2)                                    $3,045,530             $6,208,634             $2,129,156
                                                            ==========             ==========             ==========
</TABLE>

                                                        See accompanying notes.

<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

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

<TABLE>
                                                                       Limited
                                                    Number          Voting Shares        Contributed
                                                   of shares         $1 par value          surplus             Total
                                                   ---------         ------------          -------             -----
<S>                                                <C>              <C>                 <C>                 <C>
Balance as 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 as at December 31, 1997 and 1998           14,234,740       14,234,740         26,254,139            40,488,879

Exercise of stock options and other sales
                                                       50,230            50,230             248,203             298,433
                                                -------------    --------------      --------------      --------------
Balance as at December 31, 1999                    14,284,970      $14,284,970         $26,502,342          $40,787,312
                                                   ==========      ===========         ===========          ===========
</TABLE>
                                                See accompanying notes.



<PAGE>



                         CANADA SOUTHERN PETROLEUM LTD.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         (Expressed in Canadian dollars)
                        December 31, 1999, 1998 and 1997

1.       Summary of significant accounting policies

Accounting principles

     The Company prepares its accounts in accordance with accounting  principles
generally  accepted in Canada which 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.   Specifically   estimates  were  utilized  in  calculating
depletion,   depreciation  and   amortization,   site  restoration   costs,  and
abandonments and write downs. 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. Such costs include land acquisition, drilling,
geological,  geophysical and overhead  expenses.  The Company's cost centers are
Canada and the United States.

         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, 1999, 1998 and 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. For Canadian GAAP future net revenues are undiscounted, whereas, for
U.S. GAAP future net revenues are discounted at 10%.

         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 pay out are also included in the proved oil and gas reserves
base for the purpose of computing  depletion.  During  November  1999, the field
achieved pay out status.

         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 production 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  production
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.



<PAGE>


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

         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.  Each carried
interest  account is subject to an independent  audit. In the past, these audits
have resulted in both positive and negative  adjustments  which are attributable
to prior year periods.  For these reasons,  the proceeds under carried  interest
agreements may fluctuate each year  depending on both capital  expenditures  and
any audit adjustments.

         The Company  follows the industry  practice of  reporting  its revenues
from carried interest agreements,  whereby a single month of revenues is charged
for the operating  and capital  expenditures  for the  following two months.  In
addition,  the  production  revenue  from the last two months of each quarter is
reported during the following quarter because the data are not usually
available.

Earnings per share

         Earnings  per common share  ("EPS") is based upon the weighted  average
number of common and common equivalent shares outstanding during the period. The
Company's  basic and diluted  calculations of EPS are the same for both U.S. and
Canadian GAAP.

Future site restoration costs

         Total future site  restoration  costs are  estimated to be $228,000 and
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, 1999, approximately $53,000 in
such costs have yet to be accrued.  The estimated  costs of  abandoning  the two
producing  wells  in the  Kotaneelee  field  are not  included  in  future  site
restoration  costs.  These costs would be paid by the working interest  partners
and charged to the carried interest account.


<PAGE>


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

Future income taxes

     In 1999, under new  recommendations  of the Canadian Institute of Chartered
Accountants,   the  Company   retroactively  adopted  the  liability  method  of
accounting for income taxes. Under this method, the Company records income taxes
to give effect to temporary  differences between the carrying amount and the tax
basis of the Company's assets and liabilities.  Temporary differences arise when
the  realization of an asset or the settlement of a liability would give rise to
either an increase or decrease in the  Company's  income  taxes  payable for the
year or later period. Future income taxes are recorded at the enacted income tax
rates that are expected to apply when the future tax liability is settled or the
future tax asset is  realized.  Income tax  expense is the tax  payable  for the
period and the change during the period in future income tax and liabilities.

         Adoption  of the  liability  method  of  accounting  for  income  taxes
resulted in changes to previously  reported net income, net income per share and
the balance sheet accounts, as follows:
<TABLE>
                                                                                    1998                1997

<S>                                                                             <C>                 <C>
Net loss previously reported                                                      $(2,706,537)        $(1,757,664)
Adjustment for the effect of the change in accounting method                          378,367             170,158
                                                                                 -------------       -------------
           Net loss as restated                                                   $(2,328,170)        $(1,587,506)
                                                                                 =============        ============

Net loss per share previously reported                                                  $(.19)              $(.12)
Adjustment for the effect of the change in accounting method                              .03                 .01
                                                                                          ---                 ---
           Net loss per share as restated                                               $(.16)              $(.11)
                                                                                        ======              ======

Future tax asset previous reported                                               $     -             $      -
Adjustment for the effect of the change in accounting method                        1,308,505             930,138
                                                                                 ------------         -----------
           Future tax asset as restated                                            $1,308,505           $ 930,138
                                                                                 =============        ============

Deficit previously reported                                                      $(23,849,001)       $(21,142,464)
Adjustment for the effect of the change in accounting method                        1,308,505              930,138
                                                                                 -------------       -------------
           Deficit as restated                                                   $(22,540,496)       $(20,212,326)
                                                                                 =============       =============
</TABLE>

         If the tax  allocation  method of accounting  for income taxes had been
retained,  the Company would have reported a net loss of  $(3,276,394) or $(.23)
per share for 1999.

Foreign currency translation

         Transactions  for  settlement in U.S.  dollars have been  translated at
average monthly exchange rates.  Monetary 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.


<PAGE>


1.       Summary of significant accounting policies (Cont'd

Financial instruments

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

Comprehensive income

         The Company has no items of other  comprehensive  income for U.S. GAAP.
Comprehensive loss for all periods presented is equal to the net 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.
<TABLE>
                                                                                     1999                 1998
<S>                                                                             <C>                  <C>
Cash                                                                            $   398,884          $   269,918
Canadian and U.S. bankers acceptances (Yield: 1999-5.0%,                          2,076,663            4,880,833
1998-4.9%)
U.S. Government securities (Yield: 1999-5.4%, 1998-4.8%)                            569,983            1,057,883
                                                                                -----------          -----------
                                                                                 $3,045,530           $6,208,634
                                                                                 ==========           ==========
</TABLE>
3.       Marketable Securities

         At December 31, 1999 and 1998,  the Company held the following
marketable securities which were expected to be held until maturity:


           Security         Par value  Maturity Date  Amortized Cost Fair value

1999
U.S. Federal Home Loan
Bank Disc. Note              $577,700  Jan. 18, 2000  $568,374        $576,300
                             ========                 ========        ========

1998
U.S. Federal National
Mortgage Assoc.              $765,100  Apr. 7, 1999   $751,500        $751,700
                             ========                 ========        ========



<PAGE>


4.       Oil and gas properties and equipment
<TABLE>
                                                                                    Less
                                                                                Accumulated
                                                                                Depreciation,
                                                                                 Depletion
                                                                                 and                  Net Book
                                                                Cost             Writedowns            Value
Balance December 31, 1999
<S>                                                            <C>                 <C>               <C>
Oil and gas properties - developed                             $19,009,974         $9,422,066        $  9,587,908
Oil and gas properties (U.S.) - undeveloped                      1,266,334            684,635             581,699
Seismic data                                                       112,000            112,000
                                                            --------------       ------------
                                                                                                                -
                                                                20,388,308         10,218,701          10,169,607
Equipment                                                           89,567             51,880              37,687
                                                           ---------------      -------------    ----------------
                                                               $20,477,875        $10,270,581         $10,207,294
                                                               ===========        ===========         ===========

Balance December 31, 1998
Oil and gas properties-developed                               $18,524,670         $8,720,066        $  9,804,605
Oil and gas properties (U.S.) - undeveloped                        851,651            684,635             167,016
Seismic data                                                       112,000            112,000
                                                            --------------       ------------
                                                                                                                -
                                                                19,488,321          9,516,701           9,971,621
Equipment                                                           75,073             46,684              28,389
                                                           ---------------      -------------    ----------------
                                                               $19,563,394         $9,563,385         $10,000,010
                                                               ===========         ==========         ===========
</TABLE>
     Substantially  all gas sales were made to CanWest Gas Supply  Inc.  and oil
sales were made to Probe Exploration, Inc. ("Probe"). The gain on sale of assets
and the amount of abandonments  and write downs are same under both Canadian and
U.S. GAAP. During 1999, a total of $73,000 ($95,000 in 1998 and $91,000 in 1997)
of general and administrative expenses were capitalized.

     Included in the amount of accounts  receivable is $269,000 due from various
industry  partners which include Berkley  Petroleum Ltd.,  PetroCanada,  Alberta
Treasury, Oil For America - Exploration and Farries Engineering.

     During 1999,  the Company's  primary  Alberta  asset and revenue  producing
property was its heavy crude oil production and related  facilities at Kitscoty.
The  Company  sold  its 10 %  working  interest  to the  operator  for  $336,000
effective  October 1, 1999. The transaction  was completed  during February 2000
and the  proceeds of sale will be credited to oil and gas  properties  in fiscal
2000.

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, 1992 and 1998 stock option
plans, the Company is authorized to grant certain employees, directors 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 normally exercisable immediately and issued for a period of five years from
the date of grant.

         During 1998,  the Company  adopted a stock option plan that permits the
granting of both stock options and stock appreciation rights. A total of 700,000
Limited Voting Shares are reserved for issuance under the plan.

         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   Expiration Dates   Number of Shares  Option Prices ($)
-------------------   ----------------   ----------------  -----------------
December 31, 1996   Oct. 1999 - Jun. 2001     445,700
  Exercised                                  (278,200)        3.70 - 8.75
  Granted                                      35,000            13.50
December 31, 1997   Aug. 1999 - Oct. 2002     202,500         6.37 - 13.50
  Granted                                       7,500            10.25
                                            ---------
December 31, 1998   Aug. 1999 - Apr. 2003     210,000   ($7.94 weighted average)
  Granted                                     362,500             7.02
  Exercised                                   (49,000)        6.37-7.00
                                            ---------
December 31, 1999   Nov. 2000 - Jan. 2004     523,500   ($6.92 weighted average)
                                              =======
Summary of Options Outstanding at December 31, 1999

Granted 1994        Nov. 2000                  80,000              7.00
Granted 1996        Nov. 2000                  62,500              6.37
Granted 1999        Jan. 2004                 381,000              7.00
                                              -------
Total - December 31,  1999                    523,500
                                              =======

Options reserved for future grants            507,134
                                              =======
         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.  This method,
which is consistent with the Company's  accounting under Canadian GAAP, has been
chosen  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 FASB  Statement  No. 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. All of the valuations
assumed no expected 5.


<PAGE>


Limited Voting Shares and stock options (Cont'd)

dividend.  The assumptions used in the 1997 valuation model were: risk free
interest rate - 5.7%, expected life - 5 years and expected volatility - .459.
The assumptions used in the 1998 valuation model were: risk free interest rate -
4.45%,  expected life - 5 years and expected  volatility - .328. The assumptions
used in the 1999 valuation model were: risk free interest rate - 4.65%, expected
life - 5 years and expected volatility - .503.

          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 is as follows:

                                                 Amount               Per Share
Net loss as reported  - December 31, 1997    $(1,587,506)              $(.11)
Stock option expense                              225,400               (.02)
                                              ------------            -------
Pro forma net loss  - December 31, 1997       $(1,362,106)             $(.13)
                                              ============             ======

Net loss as reported  - December 31, 1998     $(2,328,170)             $(.16)
Stock option expense                               29,600                 -
                                              ------------            -------
Pro forma net loss  - December 31, 1998       $(2,298,570)             $(.16)
                                              ============             ======

Net loss as reported  - December 31, 1999     $(3,001,424)            $(.21)
Stock option expense                            1,247,000              (.09)
                                             -------------            ------
Pro forma net loss  - December 31, 1999       $(4,248,424)             $(.30)
                                              ============             ======

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>
                                                                         1999             1998              1997
                                                                        44.84%           44.84%            44.84%
                                                                        ======           ======            ======
Recovery for income taxes based on combined basic
Canadian federal and provincial income tax
<S>                                                                 <C>              <C>                <C>
                                                                    $(1,469,135)     $(1,213,611)       $ (788,137)
Nondeductible crown charges                                              11,249          104,663           154,463
Resource allowance                                                      383,663          403,270           232,922
Other                                                                   (47,601)          24,919            21,106
Nontaxable portion of capital gain                                            -          (20,049)          (20,743)
Unrealized tax loss                                                     846,854          322,441           170,158
                                                                  -------------     ------------       -----------
Actual income tax recovery                                           $ (274,970)      $ (378,367)       $ (230,231)
                                                                     ===========      ===========       ===========
</TABLE>


6.       Income taxes (Cont'd)

At  December  31,  1999,  the Company  had net  operating  losses for income tax
purposes of  approximately  $6,597,000 which are available to be carried forward
to future periods.  These losses expire in the following years: 2000 - $294,000,
2001 - $545,000,  2002 - $569,000,  2003 - $1,077,000,  2004 - $544,000,  2005 -
$1,711,000 and 2006 - $1,857,000.

         At December 31,  1999,  the Company has the  following  oil and gas tax
deductions  available  to  reduce  future  taxable  income,  subject  to a final
determination by taxation authorities.

Canada
Drilling, exploration and lease acquisition costs               $ 10,570,000
Earned depletion                                                   1,975,000
Undepreciated capital costs                                        2,336,000
Cumulative eligible capital losses                                   407,000
Share issue costs                                                     99,000

United States
Exploration and lease acquisition costs                         $  1,234,000

         As a result of these  deductions,  the  Company  has a future 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. 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.  Accordingly,  the  Company  has
established a valuation allowance to recognize this uncertainty.

                         1999                    1998                   1997
Future tax asset      $6,749,358             $5,728,699             $ 4,642,765
Valuation reserve     (5,165,883)            (4,420,194)             (3,712,627)
                      -----------            -----------             -----------
Net future tax asset  $1,583,475             $1,308,505            $    930,138
                      ===========            ===========             ===========

Future tax recovery   $  274,970             $   378,367           $    170,158
                      ===========            ===========            ============





<PAGE>




7.        Line of credit

          The Company has an operating line of credit with a Canadian  chartered
bank which provides for a loan of $500,000. 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 1999 or 1998.

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"). 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 (the  "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 proceedings  currently
at trial.


         The Company claims that the Defendants  breached a contract  obligation
and/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  presented  evidence  at trial  that the money  damages
sustained by the Company were approximately $100 million.

     In addition,  the Company has claimed that the Company's  carried  interest
account should be reduced  because of 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 pay out 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 out in  approximately  two years and the
Company  would  have  begun to  receive  revenues  from the  field in 1986.  The
Operator  reported that as of November 30, 1999 development costs totaling $96.7
million had been  incurred and repaid.  As of December  31,  1999,  based on the
Operator's report, the Company's share of net revenues due to the Company by all
of the defendants totaled $412,374.

         The amount of recoverable costs is one of the issues being contested in
the Kotaneelee litigation. The Company claims, and the defendants deny, that the
defendants have made improper  charges to the carried  interest  account and one
defendant  (Amoco Canada)  maintains that the carried interest account should be
charged additional amounts for gas processing fees. Amoco Canada claims that the
remaining  costs to be  recovered  at July 31, 1999 were either  $72,369,000  or
$33,911,000 depending on inclusion of interest. At this time, it is not possible
to  determine  whether  Amoco  Canada will be  successful  in its claim that gas
processing fees should be charged to the carried interest account.

         Although, according to the Operator's reports, the Kotaneelee gas field
reached pay out status on November  10,  1999,  the  Operator  has  notified the
Company  that it will not make any  payments  to the  carried  interest  owners,
including the Company,  until the issue of the amount of recoverable costs under
the carried  interest  account has been resolved by the Court of Queens Bench in
Calgary,  Canada.  The Operator  has stated that it will  deposit the  Company's
share of net production  proceeds in an interest  bearing account with an escrow
agent.  During March 2000, the Operator deposited $136,728 in the escrow account
which  represents the  Operator's  share of December 1999 gas sales less January
and February  2000  operating  and capital  expenditures.  A motion was filed in
December  1999 by the  plaintiffs  in Canada to direct all of the  defendants to
make timely  payments of all current and future  amounts due from the  Company's
share of field revenues. The Company expects that the Court will hear the motion
in April 2000.

         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 unrecovered sums Columbia has expended on the Kotaneelee
lands before the Company is entitled to its interest.

         The parties to the litigation  conducted  extensive discovery since the
filing of the claims.  The trial began on September  3, 1996 and the  Plaintiffs
completed  the  presentation  of  their  case  against  the  Defendants   during
September,  1998. The Defendants  completed their case during February 2000. The
Company  estimates  that its rebuttal  evidence  will be completed  during March
2000.  Both  parties  to the suit will then have  several  months to file  their
written closing arguments with the Court,  which probably will hear closing oral
arguments in the fall of 2000.

         Based upon newly  discovered  evidence,  the Company  filed a new claim
during  May 1998 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.


         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  non-prevailing  party.  Previously,  the
Company had reported  that while such costs were not  determinable,  the Company
estimated  that  taxable  costs,   assuming  a  twelve  month  trial,  could  be
approximately  $1.5  million  and noted  that the judge in complex  and  lengthy
trials has the discretion to increase an award.

         Effective September 1, 1998, the Alberta Rules of Court were amended to
provide  for a  material  increase  in the  costs  which may be  awarded  to the
prevailing party in matters before the Court. In addition,  the Company believes
that the trial  will  extend  well  beyond  its  original  time  estimates  and,
therefore, potentially assessable costs would increase accordingly.

         The trial has been lengthy,  complicated  and costly to all parties and
the Company believes that the prevailing party or parties in the litigation will
argue for a substantial  assessment of costs against the non-prevailing party or
parties.  The Court has very broad  discretion  as to whether to award costs and
disbursements  and  as  to  the  calculation  of  any  amounts  to  be  awarded.
Accordingly,  the Company is unable to determine  whether,  in the event that it
does not prevail on its claims in the litigation, costs will be assessed against
it or in what amounts.  However, since the costs incurred by the Defendants have
been  substantial,  and since the Court has broad  discretion in the awarding of
costs, an award to the Defendants  potentially  could be material.  A cost award
against the Company  could be of sufficient  magnitude to  necessitate a sale of
Company assets or a debt or equity financing to fund such an award. There are no
assurances that any such sale or financing would be consummated.

         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>


9.       Related party transactions

          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.

         Mr. Heath, a director of the Company,  has 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. Heath totaling U.S. $15,435,  $8,324 and $11,158 in 1999,
1998 and 1997, respectively.

10.      Other financial information

Accrued liabilities
                                                   1999                  1998
                                                   ----                  ----
Accrued accounting and legal expenses          $  18,256             $  69,890
Accrued royalties                                      -               141,575
Other                                                  -                83,026
                                               ----------             ----------
                                                $  18,256              $294,491
                                                =========              ========


                                           Year ended December 31,
                                  1999              1998               1997

Royalty payments (1)           $    71,838        $146,161           $366,661
                               ===========        ========           ========

Interest payments (2)          $    2,600       $    1,625         $    1,775
                               ==========       ==========         ==========

Large corporation tax payments $  15,108         $  22,837           $  27,388
                               =========         =========           =========
--------------------
(1)      Oil and gas sales are reported net of royalties paid.
(2)      Bank line of credit charges.



<PAGE>



                         CANADA SOUTHERN PETROLEUM LTD.
                      SUPPLEMENTARY INFORMATION ON OIL AND
                            GAS PRODUCING 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:

<TABLE>
                                                                                              Oil         Gas
                                                                                           (bbls)       (bcf)
Proved reserves:
<S>      <C> <C>                                                                          <C>              <C>
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
  Sale of properties                                                                     (350,800)         (2.632)
  Revisions of previous estimates                                                         (73,419)         (2.088)
  Production*                                                                             (73,381)         (1.263)
                                                                                        ----------        --------
December 31, 1998                                                                          36,200          18.408
  Revisions of previous estimates                                                          5,050            6.786
  Production*                                                                             (11,650)         (1.710)
                                                                                        ----------        --------
December 31,1999                                                                           29,600          23.484
                                                                                         ========          ======

Proved developed reserves:
December 31, 1996                                                                         358,400          28.265
                                                                                          =======          ======
December 31, 1997                                                                         508,200          24.391
                                                                                          =======          ======
December 31, 1998                                                                          36,200          18.408
                                                                                         ========          ======
December 31, 1999                                                                          29,600          23.484
                                                                                         ========          ======

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

<PAGE>


<TABLE>
Results of oil and gas operations:

                                                              1999                  1998                 1997
                                                                               (Restated)            (Restated)
Income:
<S>                                                       <C>                  <C>                   <C>
  Oil and gas sales                                       $  189,461           $1,603,155            $1,644,222
  Proceeds  from carried interests                           587,073              206,503               475,697
  Gain on sale of assets                                               -        1,378,180                         -
                                                       -----------------       ----------         -----------------
                                                             776,534            3,187,838             2,119,919
                                                         -----------           ----------            ----------
Costs and expenses:
  Production costs                                           147,332              975,899               799,372
  Depletion depreciation, and amortization                   707,200              869,600               623,600
  Provision for future site restoration costs                    600               29,500                21,500
  Abandonments and write downs                                     -              684,635                     -
  Income tax expense (recovery)                              (35,243)             281,687               302,870
                                                       --------------         -----------          ------------
                                                             819,889            2,841,321             1,747,342
                                                        ------------           ----------            ----------
Net income (loss) from operations                      $     (43,355)          $  346,517            $  372,577
                                                       ==============          ==========            ==========
</TABLE>
<TABLE>
Capitalized costs of oil and gas activities:

                                                              1999                  1998                 1997
<S>                                                        <C>                 <C>                   <C>
Acquisition costs                                          $  241,000          $    11,000           $   399,000
Exploration                                                   514,000              174,000               546,000
Development                                                   145,000            1,758,000             2,313,000
</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>
                                                              1999                  1998                 1997

<S>                                                          <C>                  <C>                   <C>
Future cash inflows                                          $70,491              $28,052               $46,435
Future development and production costs                      (24,364)             (14,030)              (22,517)
                                                             --------            ---------             ---------
                                                              46,127               14,022                23,918
Future income tax expense*                                    (6,331)                   -                (1,573)
                                                            ---------       -------------             ----------
Future net cash flows                                         39,796               14,022                22,345
10% annual discount                                           (8,758)              (4,781)               (7,836)
                                                            ---------           ----------            ----------
Standardized measure of discounted
  future net cash flows                                      $31,038             $  9,241              $ 14,509
                                                             =======             ========              ========
</TABLE>
------
* Reflects tax benefit for the years 1999,  1998 and 1997, from carry forward of
exploration,  development and lease  acquisition  costs,  undepreciated  capital
costs and book earned depletion of $18,940,000, $16,381,000 and $18,065,000.

         Current  prices  used in the above  estimates  were based upon  selling
prices at the  wellhead at December of each year.  The actual  price  ($2.83) of
Kotaneelee gas at December 31, 1999, was used in these estimates.  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):
<TABLE>

                                                                        Year ended December 31,

                                                           1999                   1998                  1997
Changes due to:
<S>                                                  <C>                         <C>               <C>
Sale of properties                                   $          -                $(4,374)          $         -
Prices and production costs                                17,776                   (402)                 (579)
Future development costs                                     (116)                (1,204)               (2,350)
Sales net of production costs                                (619)                  (906)               (1,562)
Development costs incurred
  during the year                                             145                  1,758                 2,313
Net change due to extensions,
  discoveries and improved recovery                             -                      -                 1,692
Revisions of quantity estimates                             7,256                   (872)               (3,642)
Accretion of discount                                         924                  1,045                 1,723
Net change in income taxes                                 (3,569)                  (313)                  939
                                                        ----------             ----------            ---------
Net change                                                $21,797                $(5,268)              $(1,466)
                                                          =======                ========              ========
</TABLE>


<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, 1999, 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 and schedules  listed below
and included under Item 8, above are filed as part of
this report.

                                                                         Page
                                                                       Reference

Auditors' Report                                                           36
Consolidated Balance Sheets as at December 31, 1999 and 1998               37
For the years ended December 31, 1999, 1998 and 1997
    Consolidated Statements of Operations and Deficit                      38
    Consolidated Statements of Cash Flows                                  39
Consolidated Statements of Limited Voting Shares and Contributed
  Surplus for the three years ended December 31, 1999                      40
Notes to Consolidated Financial Statements                                41-54
Supplementary Information On Oil and Gas Producing Activities (unaudited) 55-57

                  (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

                           List of each management contract or compensatory or
arrangement required to be filed as an exhibit pursuant to Item 14(c).

                           None.

         (b)      Reports on Form 8-K

                  (1) On November 2, 1999, the Company filed a Current Report on
Form 8-K to report the death of a director.

                  (2) On December 28, 1999,  the Company filed a Current  Report
on Form 8-K to report current  developments  in the Kotaneelee  Litigation  (See
Item 3. Legal Proceedings).

         (c)      Exhibits

                  The following exhibits are filed as part of this report:

         Item Number

                  2.       Plan of acquisition, reorganization, arrangement,
                           liquidation or succession

                           Not applicable.

                  3.       Articles of Incorporation and By-Laws

                           (a)  Memorandum of Association as amended on June 30,
                           1982, May 14, 1985 and April 7, 1988 filed as Exhibit
                           4B to Form  S-8 as  filed  on  November  25,  1998 is
                           incorporated by reference.

                           (b)  By-laws,  as amended, filed as Exhibit 4C to
                           Form S-8 as filed on November 25, 1998 are
                           incorporated by reference.

                  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) to Report on Form 10-K for the year ended
                           December 31, 1998 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) to  Report  on Form  10-K  for the  year  ended
                           December   31,   1998  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) to Report of Form 10-K
                           for the year ended December 31, 1998 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) to Report on Form 10-K for the
                           year ended December 31, 1998 is  incorporated  herein
                           by reference.

                             (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 Report on Form 10-K
                           for the year ended December 31, 1998 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  Report  on Form  10-K for the year
                           ended  December  31, 1998 is  incorporated  herein by
                           reference.

                           (c) Stock Option Plan adopted December 9, 1992, filed
                           as Exhibit  10(c) to Report on Form 10-K for the year
                           ended  December  31, 1998 is  incorporated  herein by
                           reference.

                           (d) Stock Option Plan effective July 1, 1998 filed as
                           Exhibit  A  to  Schedule   14A   Information   (Proxy
                           Statement) as filed on May 1, 1998 is incorporated by
                           reference.

                  11.      Statement re computation of per share earnings

                           None.

                  12.      Statement re computation of ratios

                           None.

                  13.      Annual report to security holders, Form 10-Q or
                           quarterly report to security holders

                           Not applicable.

                  16.      Letter re change in certifying accountant

                           Not applicable.

                  18.      Letter re change in accounting principles

                           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.

                  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 LLP filed herein.

                  24.      Power of attorney

                           Not applicable.

                  27.      Financial Data Schedule

                           Filed herein (EDGAR filing only).

                  99.      Additional exhibits

                  (a)      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(a) to
                           Report on Form 10-K for the year ended  December  31,
                           1998 is incorporated herein by reference.

                  (b)      Amended Statement of Claim,  amending the October 27,
                           1989  Statement  of Claim,  filed on March 12,  1990,
                           filed as Exhibit 99(b) to Report on Form 10-K for the
                           year ended December 31, 1998 is  incorporated  herein
                           by reference.

                  (c)      Amended Statement of Claim in the same action,  filed
                           on  November  17,  1993,  filed as  Exhibit  99(c) to
                           Report on Form 10-K for the year ended  December  31,
                           1998 is incorporated herein by reference.

                  (d)      Amended  Statement  of Third  Party  Notice  by Amoco
                           Canada  Production  Company Ltd. and Amoco Production
                           Company,  filed November 17, 1993 in the same action,
                           filed as Exhibit 99(d) to Report on Form 10-K for the
                           year ended December 31, 1998 is  incorporated  herein
                           by reference.

                  (e)      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,  filed as Exhibit 99(e) to Report on
                           Form 10-K for the year  ended  December  31,  1998 is
                           incorporated herein by reference.

         (d)      Financial Statement Schedules

                  None.


<PAGE>



                                   SIGNATURES

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

                                                  CANADA SOUTHERN PETROLEUM LTD.
                                                       (Registrant)


Dated:     March 28, 2000               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/ Kelly B. Johnson
    M. Anthony Ashton                         Kelly B. Johnson
    President and Director                    Treasurer and Chief Financial and
                                              Accounting Officer

Dated:     March  28, 2000               Dated:     March 28, 2000
       ------------------------           --------------------------------------


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


Dated:     March 28, 2000               Dated:     March 28, 2000
       ------------------------           --------------------------------------


By /s/ Arthur B. O'Donnell
    Arthur B. O'Donnell
    Director


Dated:     March 28, 2000
       ------------------------

<PAGE>



                                INDEX TO EXHIBITS


     23.      (a)     Consent of Independent Petroleum Engineers

              (b)     Consent of Independent Auditors

     27.      Financial Data Schedule (EDGAR filing only)