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, 2000
                                   ---------------------------------------------

                                       OR

[   ]    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
         SECURITIES EXCHANGE ACT OF 1934

         For the transition period from                    to
                                        ------------------    ------------------

                         Commission file number 1-3793

                         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.)

#505, 706 - 7th  Avenue, S.W.,
 Calgary, Alberta  CANADA                                   T2P 0Z1
----------------------------------                 ----------------------------
(Address of principal executive offices)                  (Zip Code)

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

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

                                                      Name of each exchange on
       Title of each class                                which registered
---------------------------------                  -----------------------------

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

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

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



<PAGE>



28

         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 (ss.229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. |X|

         The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately U.S. $67,443,000 at March 16, 2001.

                   (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, 14,316,970
shares outstanding as of March 16, 2001.

                       DOCUMENTS INCORPORATED BY REFERENCE

         Proxy Statement of Canada Southern Petroleum Ltd. related to the Annual
Meeting of Shareholders for the year ended December 31, 2000, 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 Our 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                                57

                            PART III

Item 10.  Directors and Executive Officers of Canada Southern                57

Item 11.  Executive Compensation                                             57

Item 12.  Security Ownership of Certain Beneficial Owners and Management     57

Item 13.  Certain Relationships and Related Transactions                     57

                             PART IV

Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K    58

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

Unless otherwise indicated, all dollar figures set forth are expressed in
Canadian currency. The exchange rate at March 16, 2001 was $1.00 Canadian = U.S.
$.64.



<PAGE>



                                     PART I

Item 1.  Business

         The nature of Canada Southern Petroleum Ltd.'s 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 our business, see "Properties" and "Supplemental
Information on Oil and Gas Activities".

         (a)  General Development of Business

Yukon Territory - The Kotaneelee Field

         Our 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, 2000 of approximately 58 million cubic feet per day. Gross
natural gas sales were approximately 45 million cubic feet per day at December
31, 2000 as a result of shrinkage and fuel gas requirements. Anderson
Exploration Ltd. is the operator of 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 totaled 164.1 bcf as follows: 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, 2000 - 20.2. No revenues from the Kotaneelee gas field
have been included in income since production began.

         A carried interest owner such as Canada Southern is entitled to receive
its share of field revenues after the working interest parties recover their
operating and capital costs. Although, according to the operator's reports, the
Kotaneelee gas field reached pay out status during November 1999, the operator
notified us in December 1999 that it would not make any payments to the carried
interest owners, including us, until the issue of the amount of recoverable
costs under the carried interest account had been resolved by the Court of
Queens Bench in Calgary, Canada. The operator stated that it would deposit our
share of net production proceeds in an interest bearing account with an escrow
agent.

         Since March 2000, the operator of the Kotaneelee field has been
reporting the amount of our share of net revenues being deposited in escrow. The
March 2001 report provided information for production for the month of December
2000. Based on the reported data, we believe the total amount due us at December
31, 2000 (before interest) was approximately $17.6 million, of which $5.8
million has been deposited in escrow by the operator.

         Amoco Canada, one of the working interest partners, maintains that the
carried interest account should be charged additional amounts for gas processing
fees and that the carried interest account has not been paid out. According to
the last report from Amoco Canada the remaining amount to be paid out was
approximately $58.7 million (our share - $17.4 million) at December 31, 1999.
Based upon production and pricing information received from the operator, we
estimate that the carried interest account, even if the disputed processing fees
are included, should reach pay out status on or before March 31, 2001.

         The above information with respect to the pay out status constitutes
only an estimate and there are no assurances that the carried interest account
will in fact reach pay out status on or before March 31, 2001. While Amoco
Canada has indicated that we will receive a pay out status report in the near
future, Amoco Canada has not yet provided us with their alleged processing fee
charges or other information relating to sales of gas from the field for the
year 2000. In addition, the most recent pricing and production information that
we have received from the operator of the field relates to production for the
month of December 2000.

         Even if pay out status is reached  after  taking into  account all
disputed  processing  fee  charges,  there are no  assurances  that the  working
interest partners, all of whom are defendants in the Kotaneelee Litigation, will
pay us our share of the net production proceeds from the field. However,  recent
correspondence  from Amoco Canada and the  operator  suggest that it is probable
that we will receive our share of the net production  proceeds after taking into
account all disputed processing fee charges.

British Columbia Properties

         Our major source of income has been from the sale of crude oil and
natural gas from our properties located in northeast British Columbia where we
have working and carried interests. Effective January 1, 2001, Canada Southern
converted certain carried interests in Northeast British Columbia including
Buick Creek, Wargen and Clark Lake to working interests.

         In addition to our producing properties, we have various petroleum and
natural gas leases in northeast British Columbia which we continue to evaluate.
Presently, we have interests in 49,013 gross developed acres (7,977 net acres)
and 28,820 gross undeveloped acres (15,091 net acres).



<PAGE>


Arctic Islands

         As of December 31, 2000, we 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 as Significant Discovery Lands by the Canadian Federal
Government. These interests are being retained under Significant Discovery
Licenses 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. We have a 5% carried interest in the area which has not yet
reached pay out status. The timing of any pay out is uncertain.

         Major operators and industry investors have recently indicated interest
in exploring the Canadian Arctic Islands region to develop additional gas
reserves and productive capacity. Recent statements by major oil and gas
producers indicate that technological developments and the sustained world
prices for natural gas may lead to expanded exploration and production efforts
in the Canadian Arctic Islands, as well as advance the construction of a natural
gas pipeline to the region in the future.


Northwest Territories Properties

         We have a 45% carried interest in the Northwest Territories in the
Celibeta field, designated as a Significant Discovery Land 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, we are
reviewing our holdings in the area with a view to taking advantage of any
potential opportunities.


Alberta

         During 1999, our primary Alberta asset and revenue producing property
was our 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 our business strategy, we sold our 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 were credited to oil
and gas properties in fiscal 2000. In 2000, we participated in the drilling of
one gross (.33 net) well which was plugged and abandoned.

         We have a current land inventory of 21,477 gross acres (7,349 net
acres). As prospects are identified, we may participate in drilling or,
alternatively, farm out the prospects to other operators for drilling
commitments.


Saskatchewan

         We have a 3.75% working interest in three sections in Saskatchewan.
During 2000, there was no activity on these properties and the lands remain
undeveloped.


United States

         Texas

         In 1999, we participated in the drilling and completion of two wells in
Stephens County, Texas. This resulted in one dry hole and one nominal crude
oil/natural gas producer. Efforts to farm out the remaining undrilled acreage
were unsuccessful. During the second quarter of fiscal 2000, the carrying costs
($635,000) of the project on the books were written down to a nominal value of
$1.00.

         (b)      Financial Information about Industry Segments

         Since we are primarily engaged in only one industry, oil and gas
exploration and development, this item is not applicable to us. See Item 8 -
"Financial Statements and Supplemental Data" for general financial information
concerning Canada Southern.

         (c)      (1)      Narrative Description of the Business

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

         We are, either in our 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 we have interests are
undeveloped, all properties with proved reserves are partially or fully
developed. Our 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. Our principal asset is
our 30% carried interest in the Kotaneelee field, a partially developed gas
field (See Item 3 - "Legal Proceedings".) We also have 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 us until expenditures by the carrying
partners have been recouped from production, and that operating decisions are
made by the carrying partners. Generally, we 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 our share of the unrecouped expenditures for the
unit (i.e., expenditures not recouped from production revenues). At December 31,
2000, our share of unrecouped expenditures was as follows:

         British Columbia:
           Ex-permit 149 (Highway/Town
           Crown Lease #1081)                                       $4,014,000

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


                           (i)      Principal Products

                                    The  majority  of our oil and gas  interests
are carried interests.  We also participate  in the production and sale of crude
oil and natural gas derived from our working interests.

                           (ii)     Status of Product or Segment

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

                           (iii)    Raw Materials

                                    Not applicable.

                           (iv)     Patents, Licenses, Franchises and
                                    Concessions Held

                                    Permits and concessions are important to our
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

                                    Our  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.


<PAGE>



                           (vi)     Working Capital Items

                                    Not applicable.

                           (vii)    Customers

                                    Most of the  natural  gas  produced from our
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. We must compete with companies which have
substantially greater resources available to them. Because the majority of our
interests are in remote areas, operation of our 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 our
future operations.


                           (xi)     Research and Development

                                    Not applicable.



<PAGE>


                           (xii)    Environmental Regulation

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

                           (xiii)   Number of Persons Employed by Canada
                                    Southern

                                    We currently have two full time  employees,
both of whom are located in Canada.  We also rely to a great extent on
consultants (approximately 10) for technical, legal, accounting and
administrative services. We use 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 our operating assets and
revenues are attributable to our operations in Canada.
Operating losses are substantially attributable to the ongoing Kotaneelee
litigation.

                  (2)      Risks Attendant to Foreign Operations

                           The properties in which we have 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 fluctuations;
burdensome royalty terms; export sales restrictions; limitations on the transfer
of interests in exploration licenses; and other laws and regulations which may
adversely affect our interests in these 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 our shares represents an exposure to risks in addition to those inherent in
petroleum exploratory ventures.


Land Tenure

         Crude oil and natural gas located in the western provinces of Canada
are 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 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 provincial 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 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 Government 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 now been completed.

Production and Production Facilities

The Governments of Canada, Alberta, British Columbia, Saskatchewan and Yukon
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 Saskatchewan and Yukon
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. We are
committed to meeting our responsibilities to protect the environment wherever we
operate and believe that we are in material compliance with applicable
environmental laws and regulations. We have not been required to spend
significant sums to comply with clean up laws and regulations. Our compliance
with governmental provisions regulating the discharge of materials into the
environment or otherwise relating to the protection of the environment is not
expected to have a material effect on our capital expenditures, earnings or
competitive position.



<PAGE>


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

                  Not applicable.

Item 2.  Properties

         (a) Our principal asset is our 30% carried interest in the Kotaneelee
field, a partially developed gas field in the Yukon Territory. See Item 3 -
"Legal Proceedings." We also have 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. Geophysical,
geological and drilling work on our properties is conducted by the operators
under various agreements with us. The results of this work are reviewed by our
personnel and consultants retained by us.

         (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 Company Areas of Interest


<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 Kotaneelee field


<PAGE>











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




                   Map showing the Kotaneelee Permit Structure


<PAGE>











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




                        Map of the Canadian Arctic Island
                           showing our Lease Holdings


<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 2000, production was
primarily natural gas. In 1999, oil production was primarily heavy crude oil
with high lifting costs. In 1998, 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)
 ----   -------------  -------------          -------------   -------------
           ($)               ($)                    ($)             ($)
 2000       43.00              3.63                  24.10             .62
 1999       17.38              1.83                  12.82            1.45
 1998       14.84              2.17                   8.41            1.41

(4)      Productive Wells and Acreage

         Productive wells and acreage on working and carried interest properties
as of December 31, 2000 were 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                              4,816                         712
 Arctic Islands                       3,060                         153
 British Columbia                    46,027                       5,818
 Saskatchewan:`                         160                           6
 Yukon Territory                      3,350                       1,005
                                      -----                       -----
                                     57,413                       7,694
                                     ======                       =====



<PAGE>


(5)      Undeveloped Acreage

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

<TABLE>
<CAPTION>
                                    Gross and Net Petroleum Acreage as of December 31, 2000
                                      Developed Acres                    Undeveloped Acres
                                      Gross       Net                   Gross          Net
                                      Acres      Acres         %        Acres         Acres        %
                                      -----      -----         -        -----         -----        -
Canada:
<S>                                     <C>          <C>      <C>         <C>            <C>       <C>
  Alberta:                              4,816        712      14.8        19,028         7,066     37.1

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

   British Columbia:                   46,027      5,818      12.6        30,075        15,800     52.5

  Saskatchewan:                           160          6       3.8         1,760            66      3.8

  Yukon & Northwest Territories:
    Carried Interests                   3,350      1,005      30.0        28,376         8,752     30.8
                                        -----      -----                  ------         -----

  Total                                57,413      7,694                 254,539        70,605
                                       ======      =====                 =======        ======

     In addition , we have royalty interests in 2,061 developed acres and 1,370
undeveloped acres.

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

(6)      Drilling activity

         Productive and dry net wells drilled during the following periods:

                Gross                                Net
  Year        Productive           Dry            Productive           Dry
  ----        ----------           ---            ----------           ---
  2000              -               1                 -                .333
  1999              4               2               1.127              .798
  1998              9               2               1.440              .200

--------------------------------------------------------------------------------
(7)      Present Activities

         There were no wells drilling at December 31, 2000.

(8)      Delivery Commitments

         None.



<PAGE>


Item 3.  Legal Proceedings

         Canada  Southern  believes  that the  working  interest  owners  in the
Kotaneelee gas field have not adequately pursued the attainment of contracts for
the sale of Kotaneelee  gas. In October 1989 and in March 1990,  Canada Southern
filed  statements  of claim in the Court of Queen's  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,  Columbia Gas Development of Canada Ltd.,  Mobil Oil
Canada Ltd. and Esso Resource of Canada Ltd. In 1991, Anderson  Exploration Ltd.
acquired  all of the shares in Columbia  and changed its name to Anderson  Oil &
Gas  Inc.  Anderson  is now the  sole  operator  of the  field  and is a  direct
defendant in the Canadian lawsuit.  Columbia's previous parent, The Columbia Gas
System,  Inc.,  which was  reorganized in a bankruptcy  proceeding in the United
States, is contractually  liable to Anderson in the legal proceedings  currently
at trial.

         We claim that the defendants breached a contractual obligation and/or a
fiduciary duty owed to us to market gas from the Kotaneelee gas field when it
was possible to so do. We assert that marketing the Kotaneelee gas was possible
in 1984 and that the defendants deliberately failed to do so. We seek money
damages and the forfeiture of the Kotaneelee gas field. We presented evidence at
trial that the money damages sustained by us were approximately $100 million.

         In addition, we have claimed that the carried interest account should
be reduced because of improper charges to the carried interest account by the
defendants. We claim 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, we claim 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, we claim, 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.

         We claim that production from the field should have commenced in 1984.
At that time the field's carried interest account was approximately $63 million.
We claim that by 1993 at least $34 million of unnecessary expenses had been
wrongfully charged to the carried interest account. Our 30% share of these
expenses would be approximately $10.2 million. We further claim that if
production had commenced in 1984, the carried interest account would have been
paid out in approximately two years and we would have begun to receive revenues
from the field in 1986.

         The amount of recoverable costs is one of the issues being contested in
the Kotaneelee litigation. We claim, 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 December 31, 1999 were either $58,711,000 or
$19,325,000 depending on inclusion of interest. Amoco Canada has indicated that
it will provide us with their calculation of the status of the carried interest
account at December 31, 2000 in the near future. 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 notified us in
December 1999 that it would not make any payments to the carried interest
owners, including us, 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 stated that it would deposit our share of net
production proceeds in an interest bearing account with an escrow agent. The
operator is only depositing its share of our funds in the escrow account. The
other working interest partners have declined to escrow our share of the net
production proceeds. 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 our share of field revenues. On April 10, 2000, the
trial court dismissed our motion pending the Court's ultimate determination of
the issues surrounding the Kotaneelee field carried-interest account. We filed a
notice of appeal of the dismissal with the Alberta Court of Appeal. The Alberta
Court of Appeal has stayed our appeal of the trial court's refusal to direct the
working interest parties to make timely payments of all current and future
amounts which are due as our share of the field's net revenues. The stay was
granted on the basis that the appeal is premature until a judgment is rendered
on the entire trial. The appeal may be reactivated in the event that the trial
court ultimately decides the issue in favor of the defendants. The Court of
Appeal also indicated that it might consider the issue separately from, and in
advance of, any other appeal which might be brought from the trial court's
decision.

         Since March 2000, the operator of the Kotaneelee field has been
reporting the amount of our share of net revenues being deposited in escrow. The
March 2001 report provided information for production for the month of December
2000. Based on the reported data, we believe the total amount due us at December
31, 2000 (before interest) was approximately $17.6 million, of which $5.8
million has been deposited in escrow by the operator.

          The parties to the litigation have conducted extensive discovery since
the filing of the claims. The trial began on September 3, 1996. We completed the
presentation of our case against the defendants during September 1998. We
completed our rebuttal evidence on April 24, 2000. On June 26, 2000, we filed
our written closing argument with the court. The defendants filed their written
argument on August 28, 2000. On February 6, 2001, the presentation of the
evidence in the trial ended. We expect a written decision from the trial court
will be forthcoming before the end of 2001.

         Columbia has filed a counterclaim against us seeking, if we are
successful in our claim for the forfeiture of the field, repayment from us of
all unrecovered sums Columbia has expended on the Kotaneelee lands before we are
entitled to our interest.

         Based upon newly discovered evidence, we filed a new claim during May
1998 that the defendants failed to develop the field in a timely manner. We are
unable to estimate the time necessary to conclude this claim.


Matters Ancillary to Kotaneelee Litigation

         In our 1989 statement of claim, we 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 we will be assessed a processing fee on gas
                  throughput.

         With respect to the first issue, we maintain that no interest should
accrue on the account and the defendants have not contested this position. With
regard to the second issue, we maintain that the expenditures are chargeable to
the carried interest account. Mobil, Esso and Columbia have essentially agreed
to our position in the original pleadings to the court while the Amoco Dome
Group continues to contest this issue.

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



<PAGE>


Taxable Costs

         Under Canadian law, certain costs (known as "taxable costs") of the
litigation may be assessed against the non-prevailing party. 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.

         The trial has been lengthy, complicated and costly to all parties and
we believe 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, we are unable to determine whether, in the event that we do not
prevail on our claims in the litigation, costs will be assessed against us 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 of costs to the defendants potentially could be material. We have
expended in excess of $13 million on the litigation and believe the defendants
have expended substantially more than that amount. A cost award against us could
be of sufficient magnitude to necessitate a sale of our 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 whatsoever that we will be successful on the
merits of our claims, which have been vigorously defended by the defendants.
There is also no assurance that we will be awarded any damages, or that, if
damages are awarded, the Court will apply the measure of damages we claim should
be applied.





<PAGE>



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

         Not applicable.

Executive Officers of Canada Southern

         The following information with respect to our executive officers is
furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.
<TABLE>
<CAPTION>
                                                              Length of          Other Positions
                                                               Service              Held with
       Name         Age   Office                           in this Office        Canada Southern
       ----         ---   ------                           --------------        ---------------

<S>                 <C>   <C>                              <C>                      <C>
Ben A. Anderson(1)  43    President                         April 1, 2000           Director

David Blain         56    Secretary-Treasurer and          August 1, 2000            None
                          Chief Financial and Accounting
                          Officer
</TABLE>
-------
(1)      Mr. Anderson was elected President on April 1, 2000 after the
retirement of M. Anthony Ashton on March 31, 2000.

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

         We are not aware of any arrangement or understanding between the
individuals named above and any other person by which any individual was
selected as an officer.











<PAGE>


                                     PART II

Item 5.  Market for Our Limited Voting Shares and Related
                  Stockholder Matters

         (a)      Principal Markets

         Our 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:

2000      1st quarter      2nd quarter     3rd quarter       4th quarter
----      -----------      -----------     -----------       -----------
High        12.50            10.50           10.50               7.50
Low          8.25             6.30            7.00               4.90


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 U. S.  dollars) on the
NASDAQ SmallCap Market during the calendar periods indicated were as follows:

2000      1st quarter      2nd quarter     3rd quarter       4th quarter
----      -----------      -----------     -----------       -----------
High         8.44             7.50            7.06              5.50
Low          5.63             4.25            4.98              3.06


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 16, 2001

                                                             Approximate
         Title of Class                                Number of Record Holders
         --------------                                -------------------------

      Limited Voting Shares, par value                          4,400
      $1.00 per share.

         (c)      Dividends

         We have never paid a dividend on our Limited Voting Shares. Any future
dividends will be dependent on our earnings, financial condition, and business
prospects. We do not intend to pay any dividend or make any other payment to
shareholders on the Limited Voting Shares until our deficit ($28,626,000 at
December 31, 2000) 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 Convention (1980), any dividends paid to U.S. resident
shareholders under the Convention are generally 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 Canada Southern as it relates to
each of the fiscal periods shown has been extracted from our consolidated
financial statements.

                             Year ended December 31,
--------------------------------------------------------------------------------
                                 2000     1999      1998       1997     1996
                                 ----     ----      ----       ----     ----
                                 ($)       ($)       ($)       ($)       ($)

Operating revenues                1,232       777     1,810     2,120     1,755
                               ========  ========   =======   =======   =======

Total revenues                    1,379     1,030     3,409     2,515     2,228
                                =======   =======   =======   =======   =======

Net loss                         (3,084)   (3,001)   (2,328)   (1,588)   (1,236)
                                ========  ========  ========  ========  ========

Net loss per share                 (.22)    (.21)     (.16)     (.11)     (.09)
                                   =====    ===== ========= ========= =========

Working capital                   1,261     3,629     6,876     5,573     8,403
                                =======   =======   =======   =======   =======

Total assets                     12,749    16,073    18,854    22,772    22,021
                                 ======    ======    ======    ======    ======

Shareholders' Equity:
     Capital stock               40,794    40,787    40,489    40,489    38,888
     Deficit                    (28,626)  (25,542)  (22,540)  (18,625)  (17,037)
                                --------  --------  --------  --------  --------
Total                            12,168    15,245    17,949    21,864    21,851
                                =======   =======   =======   =======   =======

Average number of
  shares outstanding             14,285    14,253    14,235    14,084    13,362
                                =======   =======   =======   =======   =======

Exchange rates:
(Canadian $ = U.S. $)
     Year-end                   .6672     .6924     .6535     .6992     .7297
                                =====     =====     =====     =====     =====

     Average for the period     .6736     .6733     .6749     .7224     .7335
                                =====     =====     =====     =====     =====

     Range                     .65-.69   .67-.69   .63-.67   .69-.75   .72-.75
                               =======   =======   =======   =======   =======




<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. We caution 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; and
o        uncertainty as to when or if we will receive our share of revenue
               from the Kotaneelee gas field.

(1)      Liquidity and Capital Resources

         At December 31, 2000, we had approximately $1.2 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. We estimate that we currently have adequate working capital
for the year 2001. However, we might be required to raise additional funds in
order to complete the Kotaneelee Litigation.

         On January 15, 2001, we sold our interest in Doe Creek, British
Columbia for $800,000, effective January 1, 2001.

         On September 25, 2000, we filed a preliminary registration statement
with both the U.S. Securities and Exchange Commission and various Canadian
security commissions for a rights offering to our shareholders of our limited
voting shares. The number of shares to be sold, the purchase price and the terms
have not yet been determined.

         Cash flow used in operations during 2000 decreased to $2,401,000
compared to $2,668,000 during the 1999 period. The $267,000 difference between
the periods was caused primarily by the following:

                  Decrease in loss from operations            $   253,000
                  Net Change in accounts receivable and other     205,000
                  Net change in current liabilities              (191,000)
                                                              --------------
                  Decrease in net cash used in operations     $   267,000
                                                              ==============

         The $2.4 million of cash used in operations in 2000 was largely the
result of the $2 million legal costs associated with the Kotaneelee litigation.
Legal costs associated with the Kotaneelee Litigation have been the principal
cause of our losses since 1991. In addition, no revenue from Kotaneelee has been
recorded through December 2000.

         On February 6, 2001, the presentation of the evidence in the Kotaneelee
trial in the Queens Bench of Alberta, Canada ended. We expect a written decision
from the trial court will be forthcoming before the end of 2001. We also expect
that there will be a substantial decrease in legal costs pending the court's
decision.

         Amoco Canada, one of the working interest partners, maintains that the
carried interest account should be charged additional amounts for gas processing
fees and that the carried interest account has not been paid out. According to
the last report from Amoco Canada the remaining amount to be paid out was
approximately $58.7 million (our share - $17.4 million) at December 31, 1999.
Based upon production and pricing information received from the operator, we
estimate that the carried interest account, even if the disputed processing fees
are included, should reach pay out status on or before March 31, 2001.

         Even if pay out status is reached after taking into account all
disputed processing fee charges, there are no assurances that the working
interest partners, all of whom are defendants in the Kotaneelee Litigation, will
pay us our share of the net production proceeds from the field. However, recent
correspondence  from Amoco Canada and the  operator  suggest that it is probable
that we will receive our share of the net production  proceeds after taking into
account all disputed processing fee charges.

         In the event that the working interest partners commence payment of our
share of the net production proceeds, based on July to December 2000 production
and pricing data, we estimate that we would receive net proceeds from the field
in excess of $1 million per month after taking into account the disputed
processing fee charges.

         At December 31, 2000, most of our properties were carried interest
properties including the Kotaneelee field. Capital expenditures made by the
working interest owners reduce our cash flow from operations as no revenues are
reported until all capital expenditures have been recovered. Proceeds from the
carried interest properties are our major source of cash flow and working
capital. Certain of the carried interest properties in British Columbia were
converted to working interests in early 2001.

         We do not expect to make any significant capital expenditures at the
present time. During the second half of 2001, we plan to spend approximately
$500,000 to exploit the existing reserves at Buick Creek in British Columbia.

         We have established a provision for our potential share of future site
restoration costs. The estimated amount of these costs, which totals $147,000,
is being provided on a unit of production basis in accordance with existing
legislation and industry practice. At December 31, 2000, we have accrued
$136,000 of these costs with $11,000 remaining costs to be accrued in the
future. (2) Results of Operations

2000 vs. 1999

         A comparison of revenues, costs and expenses, net loss and earnings per
share for 2000 and 1999 is as follows:
                                2000             1999          Net Change
                                ----             ----          ----------
Revenues                  $   1,379,311     $ 1,029,899        $ 349,412
Costs and expenses           (4,545,869)     (4,306,293)        (239,576)
Income tax recovery              82,225         274,970         (192,745)
                        ---------------   -------------     -------------
Net loss                   $ (3,084,333)    $(3,001,424)    $    (82,909)
                           =============    ============    =============

Net loss per share
(basic & diluted)              $ (.22)           $ (.21)         $ (.01)
                               =======           =======         =======

         Oil sales decreased by 88% in 2000 to $18,000 compared to $151,000 in
1999. We sold our remaining heavy oil production in February 2000. Future oil
sales are expected to be minimal unless additional producing properties are
acquired through drilling or purchase. Crude oil unit sales in barrels ("bbls")
(before deducting royalties) and the average price per barrel sold during the
periods indicated were as follows:
                             2000                          1999
                        Average price                  Average price
                  bbls     per bbl    Total       bbls    per bbl     Total
                  ----     -------    -----       ----    -------     -----
Crude oil sales    403     $43.42    $   18,000  9,171     $17.38      $159,000
Royalties                                                                (8,000)
                                     -----------                     -----------
                                              -
Total                                  $ 18,000                        $151,000
                                       ========                        ========


         Gas sales increased 1100% from $38,000 in 1999 to $418,000 in 2000.
There was a 138% in number of units sold and a 291% increase in the average
price for gas. In addition, gas sales include royalty income which increased
127% in 2000. 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:
                          2000                           1999
                     Average price                  Average price
               mmcf     per mcf    Total      mmcf     per mcf      Total
               ----     -------    -----      ----     -------      -----
Gas sales       50       $7.16      $358,000   21       $1.83         $37,000
Royalty income                       145,000                           64,000
Royalties                            (85,000)                         (63,000)
                                   ----------                      -----------
Total                               $418,000                        $  38,000
                                    ========                        =========

         Proceeds from carried interests increased 36% to $797,000 during 2000
compared to $587,000 in 1999 because gas prices increased 22% and operating and
capital costs decreased by $381,000 during 2000. During 2000, the operator of
certain properties withheld $1,081,000 in payments (which we did not record as
revenues) to recover a disputed amount with respect to prior year payments.
During February 2001, payments resumed on these properties. 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:

                            2000                             1999
                       Average price                    Average price
                 mmcf     per mcf     Total       mmcf     per mcf   Total
                 ----     -------     -----       ----     -------   -----
Gas sales         408      $3.39     $1,382,000    563      $2.79   $1,572,000
Oil sales                                11,000                              -
Royalty                                (319,000)                      (327,000)
Operating costs                        (260,000)                      (417,000)
Capital costs                           (17,000)                      (241,000)
                                        --------                      ---------
Total                                 $ 797,000                       $587,000
                                      =========                       ========


         Share of Kotaneelee net revenues for 2000. No revenues have been
included from the Kotaneelee gas field during 2000. We own a 30% carried
interest in the Kotaneelee gas field. The field produces approximately 55 mmcf/d
of which approximately 45 mmcf/d is sold. Although, according to the operator's
reports, the Kotaneelee gas field reached pay out status during November 1999,
the operator notified us in December 1999 that it would not make any payments to
the carried interest owners, including us, until the issue of the amount of
recoverable costs under the carried interest account has been resolved by the
Kotaneelee Litigation. The operator stated that it would deposit our share of
net production proceeds in an interest bearing account with an escrow agent.

         Since March 2000, the operator of the Kotaneelee field has been
reporting the amount of our share of net revenues being deposited in escrow. The
March 2001 report provided information for production for the month of December
2000. Based on the reported data, we believe the total amount due us at December
31, 2000 (before interest) was approximately $17.6 million, of which $5.8
million has been deposited in escrow by the operator.

         Amoco Canada, one of the working interest partners, maintains that the
carried interest account should be charged additional amounts for gas processing
fees and that the carried interest account has not been paid out. According to
the last report from Amoco Canada the remaining amount to be paid out was
approximately $58.7 million (our share - $17.4 million) at December 31, 1999.
Based upon production and pricing information received from the operator, we
estimate that the carried interest account, even if the disputed processing fees
are included, should reach pay out status on or before March 31, 2001.

         The above information with respect to the pay out status constitutes
only an estimate and there are no assurances that the carried interest account
will in fact reach pay out status on or before March 31, 2001. While Amoco
Canada has indicated that we will receive a pay out status report in the near
future, Amoco Canada has not yet provided us with their alleged processing fee
charges or other information relating to sales of gas from the field for the
year 2000. In addition, the most recent pricing and production information that
we have received from the operator of the field relates to production for the
month of December 2000.

         Even if pay out status is reached after taking into account all
disputed processing fee charges, there are no assurances that the working
interest partners, all of whom are defendants in the Kotaneelee Litigation, will
pay us our share of the net production proceeds from the field. However, recent
correspondence  from Amoco Canada and the  operator  suggest that it is probable
that we will receive our share of the net production  proceeds after taking into
account all disputed processing fee charges.

         In the event that the working interest partners commence payment of our
share of the net production proceeds, based on July to December 2000 production
and pricing data, we estimate that we would receive net proceeds from the field
in excess of $1 million per month after taking into account the disputed
processing fee charges.

         Interest and other income decreased 42% in 2000. Interest income
decreased from $231,000 to $131,000 in 2000 because less funds were available
for investment. The 2000 period includes proceeds from the sale of seismic data
in the amount of $22,000 compared to $16,000 from such sales in 1999.

         General and administrative costs increased 34% in 2000 to $1,694,000
from $1,265,000 in 1999 primarily because of the $227,000 in costs associated
with our proposed rights offering to shareholders. In addition, salaries
increased approximately $113,000 during 2000.

         Legal expenses decreased 6% during 2000 to $1,990,000 compared to
$2,108,000 during 1999. These expenses are related primarily to the cost of the
Kotaneelee litigation. During 2000, we prepared and filed our written closing
arguments. On February 6, 2001, presentation of evidence to the trial court was
concluded. We expect that there will be a substantial decrease in legal costs
pending the court's decision.

         Lease operating costs decreased 57% from $147,000 in 1999 to $63,000 in
the 2000 period. We sold our remaining heavy oil production properties during
February 2000.

         Depletion, depreciation and amortization expense decreased 69% in 2000
to $216,000 from $707,000 in 1999. We sold our remaining heavy oil properties
during February 2000.

         A foreign  exchange  gain of $51,000 was  recorded in 2000,  contrasted
with an exchange loss of $77,000 in 1999 on our U.S.  investments.  The value of
the Canadian dollar was U.S. $.6672 at December 31, 2000 compared to U.S. $.6924
at December 31, 1999.

         Abandonments and write downs increased to $635,000 during 2000. Our
investment in the Texas project was written down to a nominal value during the
second quarter because the project was deemed to be uneconomic.

         Income tax recovery decreased to $82,000 in 2000 compared to $275,000
in 1999 due to higher unrecognized benefit of tax losses in 2000.

<PAGE>

1999 vs. 1998

         A comparison of revenues, costs and expenses, net loss and earnings per
share for 1999 and 1998 is as follows:
                               1999            1998          Net Change
                               ----            ----          ----------
Revenues                 $   1,029,899     $ 3,409,361      $ (2,379,462)
Costs and expenses          (4,306,293)     (6,115,898)        1,809,605
Income tax recovery            274,970         378,367          (103,397)
                        --------------   -------------    ---------------
Net loss                  $ (3,001,424)    $(2,328,170)    $    (673,254)
                          =============    ============    ==============

Net loss per share
(basic & diluted)             $ (.21)           $ (.16)          $ (.05)
                              =======           =======          =======

         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 us.
We sold the majority of our crude oil producing properties in two separate
transactions effective July 1, 1998 and September 1, 1998. Since we have
disposed of most of our 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 sales  9,171       $17.38   $  159,000  64,954    $14.84    $964,000
Royalties                                 (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. We sold the majority of our
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:


<PAGE>



                          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                              (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:

                         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    $1,016,000
Royalty                                (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 was accrued for 1999. The operator
reported that it deposited during March 2000 the amount of $136,728 in an escrow
account for our benefit. This deposit represents the operator's share of the
$412,374 amount due from all of the Kotaneelee field defendants.

         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.

         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 our 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, we completed the presentation of our case
against the working interest partners. The 1998 costs represent both legal fees
and the cost of various Canada Southern experts who testified, were being
prepared for testimony, or assisted in the cross-examination of defense
witnesses. During 1999, we continued our cross-examination of defense witnesses.

         Lease operating costs decreased 85% from $976,000 in 1998 to $147,000
in the 1999 period. We sold the majority of our 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, we sold the majority of our 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 an exchange gain of $179,000 on our 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 our 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 our 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.

<PAGE>

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

         We do not have any significant exposure to market risk as the only
market risk sensitive instruments are our investments in marketable securities.
At December 31, 2000, the carrying value of such investments (including those
classified as cash and cash equivalents) was approximately $995,000 which was
approximately equal to fair value and face value of the investments. Since we
expect to hold the investments to maturity, the maturity value should be
realized. In addition, our investments in marketable securities included
investments held in the United States which are subject to foreign exchange
fluctuations. At December 31, 2000, our U.S. dollar investments totaled
approximately $298,000.


<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, 2000 and 1999, 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, 2000.
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  and the  United  States.  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, 2000 and 1999 and the results of its operations and its cash
flows for each of the years in the three year period ended December 31, 2000, in
accordance with accounting principles generally accepted in Canada.


                                                /S/ ERNST & YOUNG LLP
                                                Chartered Accountants

Calgary, Canada
March 2, 2001


<PAGE>


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

                           CONSOLIDATED BALANCE SHEETS
                         (Expressed in Canadian dollars)

                                                        As at December 31,
                                                       2000           1999
                                                  ----------------------------
           Assets
 Current assets
   Cash and cash equivalents (Note 2)              $ 1,160,031     $ 3,045,530
   Marketable securities (Note 3)                            -         568,374
   Accounts receivable (Note 4)                        244,745         360,752
   Other assets                                        300,871         307,519
                                                    ----------      ----------
 Total current assets                                1,705,647       4,282,175
                                                     ---------       ---------

 Oil and gas properties and equipment
   (full cost method) (Note 4)                       9,378,008      10,207,294
 Future tax asset (Note 6)                           1,665,700       1,583,475
                                                 -------------   -------------
 Total assets                                      $12,749,355     $16,072,944
                                                   ===========     ===========

           Liabilities and Shareholders' Equity

 Current liabilities
   Accounts payable                              $     307,550   $     634,600
   Accrued liabilities (Note 10)                       137,527          18,256
                                                       -------        --------
 Total current liabilities                             445,077         652,856
                                                       -------         -------

 Future site restoration costs                         136,123         174,696

 Contingencies (Note 8)                                      -               -

 Shareholders' Equity
   Limited Voting Shares, par value
     $1 per share (Note 5)
   Authorized -100,000,000 shares
   Outstanding -14,285,970 (2000)
                14,284,970 (1999) shares            14,285,970      14,284,970
   Contributed surplus                              26,508,438      26,502,342
                                                    ----------      ----------
 Total capital                                      40,794,408      40,787,312
 Deficit                                           (28,626,253)    (25,541,920)
                                                   ------------    ------------
 Total shareholders' equity                         12,168,155      15,245,392
                                                  ------------    ------------
 Total liabilities and shareholders' equity        $12,749,355     $16,072,944
                                                   ===========     ===========

                             See accompanying notes.


    Approved on behalf of the Board

                /s/ Ben A. Anderson                     /s/ M. Anthony Ashton
                --------------------                    -----------------------
                       Director                                Director


<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

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

<TABLE>
<CAPTION>
                                                             Year ended December 31,
                                                             -----------------------
                                                    2000                 1999                 1998
                                                    ----------------------------------------------

Revenues:
<S>                                               <C>                 <C>                 <C>
  Oil sales (Notes 9 and 10)                      $     17,522        $     151,137       $      897,878
  Gas sales (Notes 9 and 10)                           418,053               38,324              705,277
  Proceeds from carried interests                      796,560              587,073              206,503
  Share of Kotaneelee net revenues (Note 8)                  -                    -                    -
  Interest and other income                            147,176              253,365              221,523
  Gain on sale of assets                                    -                    -             1,378,180
                                                     ---------            ---------            ---------
    Total revenues                                   1,379,311            1,029,899            3,409,361
                                                     ---------            ---------            ---------

Costs and expenses:
  General and administrative                         1,693,710            1,265,165            1,377,407
  Legal (Note 8)                                     1,989,540            2,108,521            2,357,707
  Lease operating costs                                 62,778              147,332              975,899
  Depletion, depreciation and amortization             216,000              707,800              899,100
  Foreign exchange (gains) losses                      (50,741)              77,475             (178,850)
  Abandonments and write downs (Note 4)                634,582                   -               684,635
                                                     ---------            ---------            ---------
    Total costs and expenses                         4,545,869            4,306,293            6,115,898
                                                     ---------            ---------            ---------

  Loss before income taxes                          (3,166,558)          (3,276,394)          (2,706,537)
  Income tax recovery (Note 6)                          82,225              274,970              378,367
                                                  -------------        -------------        ------------
Net loss                                            (3,084,333)          (3,001,424)          (2,328,170)
  Deficit - beginning of year                      (25,541,920)         (22,540,496)         (20,212,326)
                                                  -------------        -------------        -------------
  Deficit - end of year                           $(28,626,253)        $(25,541,920)        $(22,540,496)
                                                  =============        =============        =============

Net loss per share (basic & fully diluted)         $(.22)               $(.21)               $(.16)
                                                   ======               ======               ======

Average number of shares
  Outstanding (basic & fully diluted)               14,285,047           14,252,574           14,234,740
                                                    ==========           ==========           ==========
</TABLE>



                             See accompanying notes.



<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                         (Expressed in Canadian dollars)

<TABLE>
<CAPTION>
                                                                                 Year ended
                                                                                December 31,
                                                                                ------------
                                                             2000                   1999                   1998
                                                             ----                   ----                   ----

Cash flows from operating activities:
<S>                                                        <C>                    <C>                    <C>
   Net loss                                                $(3,084,333)           $(3,001,424)           $(2,328,170)
    Adjustments to reconcile net loss
       to net cash provided by
      (used in) operating activities:
    Depreciation, depletion and amortization                   216,000                707,800                899,100
    Gain on sale of assets                                           -                      -             (1,378,180)
    Abandonments and write downs                               634,582                      -                684,635
    Future tax recovery                                        (82,225)              (274,970)              (378,367)
                                                          -------------           ------------          -------------
    Funds used in operations                                (2,315,976)            (2,568,594)            (2,500,982)
  Change in assets and liabilities:
    Accounts receivable                                        116,007                (94,636)               959,970
    Other assets                                                 6,648                 12,178                (77,419)
    Accounts payable                                          (327,050)               259,045               (744,967)
    Accrued liabilities                                        119,271               (276,235)                16,776
                                                           -----------            ------------          ------------
Net cash used in operations                                 (2,401,100)            (2,668,242)            (2,346,622)
                                                            -----------            -----------            -----------

Cash flows from investing activities:
  Additions to oil and gas properties and
  equipment                                                   (357,296)              (914,483)            (1,942,474)
  Site restoration expenditures                                (38,573)               (61,949)                (4,429)
  Sale of marketable securities                                568,374                183,137              2,621,823
  Proceeds from the sale of properties                         336,000                      -              5,751,180
                                                               -------         --------------             ----------
Net cash provided by (used in) investing activities            508,505               (793,295)             6,426,100
                                                               -------               ---------            ----------

Cash flows from financing activities:
  Exercise of stock options                                      7,096                298,433                      -
                                                                 -----                -------           ------------
Net cash from financing activities                               7,096                298,433                      -
                                                                 -----                -------           ------------

Increase (decrease) in cash
  and cash equivalents                                      (1,885,499)            (3,163,104)             4,079,478
Cash and cash equivalents at the
  beginning of period                                        3,045,530              6,208,634              2,129,156
                                                            ----------             ----------             ----------
Cash and cash equivalents at the
  end of period (Note 2)                                    $1,160,031             $3,045,530             $6,208,634
                                                            ==========             ==========             ==========


                             See accompanying notes.
</TABLE>

<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

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


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


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

Exercise of stock options                               1,000            1,000               6,096                7,096
                                                   ----------      -----------         -----------          -----------

Balance as at December 31, 2000                    14,285,970      $14,285,970         $26,508,438          $40,794,408
                                                   ==========      ===========         ===========          ===========


                                                See accompanying notes.
</TABLE>


<PAGE>



                         CANADA SOUTHERN PETROLEUM LTD.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         (Expressed in Canadian dollars)
                        December 31, 2000, 1999 and 1998

1.       Summary of significant accounting policies

Accounting principles

         Canada Southern prepares its accounts in accordance with accounting
principles generally accepted in Canada which conform in all material respects
with accounting principles generally accepted in the United States ("U.S. GAAP")
except as disclosed in Note 5.

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
and the differences could be material.

Oil and gas properties and equipment

         Canada Southern, 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. Canada Southern's cost centers
are Canada and the United States.

         Canada Southern 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, 2000, 1999 and 1998

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

         The net carrying cost of Canada Southern'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%.

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

Revenue recognition

         Canada Southern recognizes revenue on its working and royalty interest
properties from the production of oil and gas in the period the oil and gas are
sold.

         Revenue under carried interest agreements is recorded in the period
when the net proceeds become receivable and collection is reasonably
assured. Under the carried interest agreements Canada Southern receives oil and
gas revenues net of operating and capital costs incurred by the working interest
participants. The time the net revenues become receivable and collection is
reasonably assured depends on the terms and conditions of the relevant
agreements and the practices followed by the operator. As a result, net revenues
may lag the production month by one or more months.


<PAGE>



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

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 only
reconciling  item in the  calculation  of diluted EPS is the dilutive  effect of
stock  options  which was  computed  using the  treasury  stock  method.  Canada
Southern's  basic  and  diluted  calculations  of EPS are the same  because  the
exercise of options is not  assumed in  calculating  diluted  EPS, as the result
would be  anti-dilutive  (Canada Southern has continuing  losses).  In addditon,
Canada  Southern's  basic and diluted  calculations of EPS are the same for both
U.S. and Canadian GAAP.

Future site restoration costs

         Future site restoration costs for working interest properties 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. The estimated costs of abandoning carried interest
wells 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.

Future income taxes

         Canada Southern follows the liability method of accounting for income
taxes. Under this method, Canada Southern records income taxes to give effect to
temporary differences between the carrying amount and the tax basis of Canada
Southern'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 Canada Southern'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 assets and
liabilities.





<PAGE>


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

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.


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.

Stock based compensation

         Canada Southern has a stock based compensation plan for its employees,
officers and directors to acquire common shares. Options are issued at the fair
market value of the shares on the date of the grant; consequently no
compensation expense is recorded. Consideration received on the exercise of the
options is credited to share capital. Note 5 contains the details of the current
options outstanding.

         For U.S. GAAP, Canada Southern follows Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees" and related
interpretations in accounting for its stock options. This method is consistent
with Canada Southern's accounting under Canadian GAAP.


 Comprehensive income

         Canada Southern has no items of other comprehensive income for U.S.
GAAP. Classifications within other comprehensive income include foreign currency
items, minimum pension liability adjustments and unrealized gains and losses on
certain investments in debt and equity securities. Comprehensive loss for all
periods presented is equal to the net loss.



<PAGE>


2.       Cash and cash equivalents

         Canada Southern 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>
<CAPTION>
                                                                  2000                 1999
                                                                  ----                 ----
<S>                                                          <C>                  <C>
Cash                                                         $   165,355          $   398,884
Canadian and U.S. marketable securities (Yield: 2000-5.7%,       994,676            2,646,646
1999-5.0%)                                                       -------            ---------
                                                              $1,160,031           $3,045,530
                                                              ==========           ==========
</TABLE>

3.       Marketable securities

         At December 31, 2000 there were no marketable securities. At December
31, 1999, Canada Southern held the following marketable securities:

<TABLE>
<CAPTION>
                                                                    Amortized
                   Security         Par value    Maturity Date       Cost         Fair value
                   --------          ---------   -------------       -----       ----------
1999
----
U.S. Federal Home Loan
Bank Disc. Note (Yield: 5.2%)
<S>                               <C>           <C>                       <C>             <C>
                                     $577,700      Jan. 18, 2000      $568,374        $576,300
                                     ========                         ========        ========
</TABLE>

4.       Oil and gas properties and equipment

<TABLE>
<CAPTION>
                                                                              Less Accumulated
                                                                                Depreciation
                                                                               Depletion and,        Net Book
                                                                Cost             Writedowns            Value
Balance December 31, 2000
<S>                                                            <C>                 <C>               <C>
Oil and gas properties - developed                             $18,972,989         $9,628,766        $  9,344,223
Oil and gas properties (U.S.) - undeveloped                      1,319,218          1,319,218                   -
Seismic data                                                       112,000            112,00                    -
                                                               -----------        -----------        ------------
                                                                20,404,207         11,059,984           9,344,223
Equipment                                                           75,379             41,594              33,785
                                                               -----------        -----------        ------------
                                                               $20,479,586        $11,101,578         $ 9,378,008
                                                               ===========        ===========        ============

Balance December 31, 1999
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
                                                               ===========        ===========         ===========
</TABLE>

         As at December 31, 2000, there were no capital assets included (year
ended December 31, 1999 - $581,700) relating to undeveloped properties, which
have been excluded from the depletion calculation. During 2000, a total of
$70,000 ($73,000 in 1999 and $95,000 in 1998) of general and administrative
expenses were capitalized.
<PAGE>

4.       Oil and gas properties and equipment (Cont'd)

 Total future site restoration costs at December 31, 2000 are estimated to be
$147,000. The estimated future site restoration costs to be accrued over the
remaining life of the proven reserves at December 31, 2000 are approximately
$11,000.

         Substantially all gas sales in 2000 were made to Producers Marketing
Ltd. Included in the amount of accounts receivable is $82,000 due from various
industry partners which include Berkley Petroleum Ltd., Petro-Canada, and
Farries Engineering.

         During 1999, Canada Southern's primary Alberta asset and revenue
producing property was its heavy crude oil production and related facilities at
Kitscoty. Canada Southern 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 were credited to oil and gas properties
in 2000. The amount of abandonments and write downs are same under both Canadian
and U.S. GAAP.

         During the second quarter of fiscal 2000, the carrying costs ($635,000)
of the Texas project on the books were written down to a nominal value of $1.00.
The 1998 abandonment amount of $685,000 resulted from a write down of certain of
our properties in California and Texas.


5.       Limited voting shares and stock options

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

         On September 25, 2000, Canada Southern filed a preliminary registration
statement with both the U.S. Securities and Exchange Commission and various
Canadian security commissions for a rights offering to its shareholders or its
limited voting shares. The number of shares to be sold, the purchase price and
the terms have not yet been determined.

         Under the terms of Canada Southern's 1985, 1992 and 1998 stock option
plans, Canada Southern 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, Canada Southern 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.



<PAGE>


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

         A summary of stock option transactions for the three years ended
December 31, 2000 is as follows:

Options Outstanding   Expiration Dates  Number of Shares    Option Prices ($)
-------------------   ----------------  ----------------    -----------------
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)
  Granted                                      75,000             8.36
  Exercised                                    (1,000)            7.00
  Expired                                      (4,000)            7.00
                                            ----------
December 31, 2000    May 2001-Jan. 2005       593,500   ($7.11 weighted average)
                                              =======


Summary of Options Outstanding at December 31, 2000
---------------------------------------------------
Granted 1994   May 2001                       80,000                      7.00
Granted 1996   May 2001                       62,500                      6.37
Granted 1999   Jan. 2004                     376,000                      7.00
Granted 2000   Jan. 2005                      75,000                      8.36
                                           --------
Total - December 31,  2000                  593,500
                                            =======

Options Reserved for Future Grants          436,134
----------------------------------          =======

         Pro forma information regarding net income and earnings per share is
required by FASB Statement No. 123, and has been determined as if Canada
Southern 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 dividend. 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. The assumptions used in the 2000 valuation model
were: risk free interest rate - 6.7%, expected life - 5 years and expected
volatility - .578.

          Because Canada Southern'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.





<PAGE>


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



          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. Canada Southern's pro forma information is as follows:

                                                    Amount        Per Share
Net loss as reported  - December 31, 1998        $(2,328,170)      $(.16)
Stock option expense                                  29,600       .    -
                                                 -----------       ------
Pro forma net loss  - December 31, 1998          $(2,357,770)      $(.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)
                                                 ============      ======

Net loss as reported  - December 31, 2000        $(3,084,335)      $(.22)
Stock option expense                                 112,000       .    -
                                                  -----------      ------
Pro forma net loss  - December 31, 2000          $(3,196,335)      $(.22)
                                                 ============      ======

6.        Income taxes

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

                                                     2000             1999              1998
                                                     ----             ----              ----
                                                    44.84%           44.84%            44.84%
                                                    ======           ======            ======
Recovery for income taxes based on combined
<S>                                               <C>              <C>               <C>
basic Canadian federal and provincial income tax  $(1,469,135)     $(1,213,611)      $(1,419,885)
Nondeductible crown charges                            40,361           11,249           104,663
Resource allowance                                    284,725          383,663           403,270
Other                                                 (16,902)         (47,601)           24,919
Nontaxable portion of capital gain                          -                -           (20,049)
Unrecognized benefit of the tax loss                1,029,476          846,854           322,441
                                                    ----------      ----------        ----------
Actual  income tax recovery                         $ (82,225)      $ (274,970)       $ (378,367)
                                                    ==========      ===========       ===========
</TABLE>

         At December 31, 2000, Canada Southern had net operating losses for
income tax purposes of approximately $6,391,000 which are available to be
carried forward to future periods. These losses expire in the following years:
2001 - $545,000, 2002 - $569,000, 2003 - $1,077,000, 2004 - $544,000, 2005 -
$1,407,000, 2006 - $590,000 and 2007 - $1,659,000.



<PAGE>



6.       Income taxes (Cont'd)

         At December 31, 2000, Canada Southern 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         $ 10,906,000
Earned depletion                                             1,975,000
Undepreciated capital costs                                  2,309,000
Cumulative eligible capital losses                             407,000
United States
-------------
Net operating losses                                           964,000

         As a result of these deductions, Canada Southern 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 these
deductions will not be utilized. Accordingly, Canada Southern has established a
valuation allowance to recognize this uncertainty.

                          2000             1999               1998
Future tax asset       $6,379,479       $6,749,358         $5,728,699
Valuation reserve      (4,713,779)      (5,165,883)        (4,420,194)
                       -----------      -----------        -----------
Net future tax asset   $1,665,700       $1,583,475         $1,308,505
                       ==========       ==========         ==========

Future tax recovery   $    82,225      $   274,970        $   378,367
                      ===========      ===========        ===========


7.        Line of credit

          Canada Southern's $500,000 operating line of credit with a commercial
bank was terminated in February 2001. Only minor drawings were made under this
line during 2000 and none in 1999.

8.       Litigation

         Canada Southern'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


<PAGE>


 8.      Litigation (Cont'd)

two natural gas wells that had combined gross productive capability at December
31, 2000 of approximately 55 million cubic feet per day. Gross natural gas sales
were approximately 45 million cubic feet per day at December 31, No revenues
have been included from the Kotaneelee gas field since production from the field
began in 1991.

         Since 1989, Canada Southern and the other carried interest parties have
been involved in litigation in the Court of Queens Bench in Calgary, Canada with
the field working interest parties (defendants). Canada Southern claims that the
defendants breached a contract obligation and/or a fiduciary duty owed to Canada
Southern to market gas in 1984 from the field when it was possible to so. In
addition, Canada Southern has claimed that Canada Southern's carried interest
account should be reduced because of improper charges to the carried interest
account by the defendants. Canada Southern seeks money damages and the
forfeiture of the Kotaneelee gas field. Canada Southern presented evidence at
trial that the money damages sustained by Canada Southern were approximately
$100 million.

         A carried interest owner such as Canada Southern is entitled to receive
its share of field revenues after the working interest parties recover their
operating and capital costs. Although, according to the operator's reports, the
Kotaneelee gas field reached pay out status during November 1999, the operator
notified Canada Southern in December 1999 that it would not make any payments to
the carried interest owners, including Canada Southern, 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 stated that it
would deposit Canada Southern's share of net production proceeds in an interest
bearing account with an escrow agent.

         Since March 2000, the operator of the Kotaneelee field has been
reporting the amount of our share of net revenues being deposited in escrow. The
March 2001 report provided information for production for the month of December
2000. Based on the reported data, Canada Southern believes the total amount due
Canada Southern at December 31, 2000 (before interest) was approximately $17.6
million, of which $5.8 million has been deposited in escrow by the operator.

         Amoco Canada, one of the working interest partners, maintains that the
carried interest account should be charged additional amounts for gas processing
fees and that the carried interest account has not been paid out. According to
the last report from Amoco Canada the remaining amount to be paid out was
approximately $58.7 million (our share - $17.4 million) at December 31, 1999.
Based upon production and pricing information received from the operator, Canada
Southern estimates that the carried interest account, even if the disputed
processing fees are included, should reach pay out status on or before March 31,
2001.

        The parties to the litigation have conducted extensive discovery since
the filing of the claims. The trial began in September 1996. Canada Southern
completed the presentation of its case against the defendants during September
1998. During 2000, Canada Southern completed its rebuttal evidence and filed its
written closing argument with the court. On February 6, 2001, the presentation
of the evidence in the trial ended. Canada Southern expect a written decision
from the trial court will be forthcoming before the end of 2001.

         Based upon newly discovered evidence, Canada Southern filed a new claim
during May 1998 that the defendants failed to develop the field in a timely
manner. Canada Southern is unable to estimate the time necessary to conclude
this claim.

         Under Canadian law, certain costs (known as "taxable costs") of the
litigation may be assessed against the non-prevailing party. The trial has been
lengthy, complicated and costly to all parties and Canada Southern 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, Canada Southern 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 of costs
to the defendants potentially could be material. Canada Southern has expended in
excess of $13 million on the litigation and believe the defendants have expended
substantially more than that amount. A cost award against Canada Southern could
be of sufficient magnitude to necessitate a sale of Canada Southern's assets or
a debt or equity financing to fund such an award. There are no assurances that
any such sale or financing would be successful.

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

9.       Related party transactions

          In 1991, Canada Southern 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 Canada Southern after expenses from the litigation in
Canada relating to the Kotaneelee gas field. Canada Southern has reserved a 2.2%
interest in such net benefits for possible future grants to persons who may
include Canada Southern officers and directors.


         Mr. Heath, a director of Canada Southern, has royalty interests in
certain of Canada Southern's oil and gas properties, (present and past) which
were received directly or indirectly through Canada Southern. Canada Southern
and third-party operators and/or owners of properties made payments pursuant to
these royalties for the benefit of Mr. Heath totaling U.S. $25,247, $15,435 and
$8,324 in 2000, 1999 and 1998, respectively. These amounts have been recorded at
exchange values.

10.      Other financial information

Accrued liabilities
-------------------
                                      2000                  1999
                                      ----                  ----
Accounting and legal expenses        $  61,527             $  18,256
Royalties                               28,000                     -
Audit fees                              25,000                     -
Capital and operating costs             23,000                     -
                                    ----------      ----------------
                                    $  137,527             $  18,256
                                    ==========             =========

                                               Year ended December 31,
                                               -----------------------
                                          2000          1999        1998
                                          ----          ----        ----
Royalty payments (1)                    $    84,769   $    71,838    $146,161
                                        ===========   ===========    ========

Rent payments                           $    49,057   $    55,840    $ 76,812
                                        ===========   ===========    ========

Interest and line of credit fees         $    4,641    $    2,600  $    1,625
                                         ==========    ==========  ==========

Large corporation tax payments            $   7,824     $  15,108   $  22,837
                                          =========     =========   =========

--------------------
(1)      Oil and gas sales are reported net of royalties incurred.


11.      Leases

         At December 31, 2000, the future minimum rental payments and estimated
operating costs applicable to Canada Southern's noncancelable five year
operating (office) lease which was effective June 1, 2000 total $ 181,853 and
are as follows: $39,534 in 2001, $40,943 in 2002, $41,949 in 2003, $41,949 in
2004 and $17,478 in 2005.



12.      Subsequent events

         Effective January 1, 2001, Canada Southern converted certain carried
interests in Northeast British Columbia including Buick Creek, Wargen and Clark
Lake to working interests.

         On January 15, 2001,  Canada Southern sold its interest in Doe Creek in
British Columbia for $800,000, effective January 1, 2001.




<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. Canada Southern cautions that the discounted
future net cash flows from proved oil and gas reserves are not an indication of
the fair market value of Canada Southern's oil and gas properties or the future
net cash flows expected to be generated from the properties. The discounted
future net cash flows do not include the fair market value of exploratory
properties and probable or possible oil and gas reserves. Also, the estimates do
not consider the effect of future changes in oil and gas prices, development,
site restoration and production costs, and possible changes in tax and royalty
regulations. The prescribed discount rate of 10% may not appropriately reflect
future interest rates.

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


Estimated net quantities of proved oil and gas reserves:
                                                  Oil         Gas
                                               (bbls)       (bcf)
                                               ------       -----
Proved reserves:
December 31, 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
  Revisions of previous estimates              4,787           (4.531)
  Production*                                  (3,787)          (.375)
                                             ---------         -------
December 31,2000                               28,600          18,578
                                             ========          ======

Proved developed reserves:
December 31, 1997                             508,200          24.391
                                              =======          ======
December 31, 1998                              36,200          18.408
                                             ========          ======
December 31, 1999                              29,600          23.484
                                             ========          ======
December 31, 2000                              25,800          18.312
                                             ========          ======

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


<PAGE>

<TABLE>
<CAPTION>

Results of oil and gas operations:
----------------------------------

                                                              2000                  1999                 1998
                                                              ----                  ----                 ----
Income:
<S>                                                       <C>                  <C>                   <C>
  Oil and gas sales                                       $  435,575           $  189,461            $1,603,155
  Proceeds  from carried interests                           796,560              587,073               206,503
  Gain on sale of assets                                           -                    -             1,378,180
                                                           ---------           ----------            ----------
                                                           1,232,135              776,534             3,187,838
                                                           ---------           ----------            ----------
Costs and expenses:
  Production costs                                            62,778              147,332               975,899
  Depletion depreciation, and amortization                   216,000              707,200               869,600
  Provision for future site restoration costs                      -                  600                29,500
  Abandonments and write downs                               634,582                    -               684,635
  Income tax expense (recovery)                              142,939              (35,243)              281,687
                                                       -------------        --------------           ----------
                                                           1,056,299              819,889             2,841,321
                                                       -------------        --------------           -----------
Net income (loss) from operations                      $     175,836        $     (43,355)           $  346,517
                                                       =============        ==============           ==========
</TABLE>


Capitalized costs of oil and gas activities:
--------------------------------------------

<TABLE>
<CAPTION>
                                                              2000                  1999                 1998
                                                              ----                  ----                 ----
<S>                                                         <C>                 <C>                  <C>
Acquisition costs                                           $  92,000           $  241,000           $    11,000
Exploration                                                    65,000              514,000               174,000
Development                                                   195,000              145,000             1,758,000
</TABLE>


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

<TABLE>
<CAPTION>

                                                              2000                  1999                 1998
                                                              ----                  ----                 ----

<S>                                                         <C>                   <C>                   <C>
Future cash inflows                                         $171,283              $70,491               $28,052
Future development and production costs                       (7,345)             (24,364)              (14,030)
                                                            ---------             --------             ---------
                                                             163,938               46,127                14,022
Future income tax expense*                                   (50,591)              (6,331)                    -
                                                            ---------             --------             --------
Future net cash flows                                        113,347               39,796                14,022
10% annual discount                                          (28,167)              (8,758)               (4,781)
                                                            ---------             --------             ---------
Standardized measure of discounted
  future net cash flows                                      $85,180              $31,038              $  9,241
                                                             =======              =======              ========
</TABLE>

------
* Reflects tax benefit for the years 2000, 1999 and 1998, from carry forward of
exploration, development and lease acquisition costs, undepreciated capital
costs and earned depletion of $21,988,000, $18,940,000 and $16,381,000.

         Current prices used in the above estimates were based upon selling
prices at the wellhead at December of each year as follows: 2000 - $9.19, 1999 -
$2.98 and 1998 - $1.41 per mcf. 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>
<CAPTION>

                                                                        Year ended December 31,
                                                                        -----------------------
                                                           2000                   1999                  1998
                                                           ----                   ----                  ----
Changes due to:
<S>                                                  <C>                    <C>                        <C>
Sale of properties                                   $          -           $          -               $(4,374)
Prices and production costs                                88,555                 17,776                  (402)
Future development costs                                     (273)                  (116)               (1,204)
Sales net of production costs                              (8,984)                  (619)                 (906)
Development costs incurred
  during the year                                             195                    145                 1,758
Net change due to extensions,
  discoveries and improved recovery                             -                      -                     -
Revisions of quantity estimates                             1,697                  7,256                  (872)
Accretion of discount                                       3,461                    924                 1,045
Net change in income taxes                                (30,509)                (3,569)                 (313)
                                                       -----------             ----------            ----------
Net change                                                $54,142                $21,797               $(5,268)
                                                          =======                =======               ========
</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 Canada Southern," 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
year ended December 31, 2000, 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 Canada Southern," 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, 2000 and 1999               37
For the years ended December 31, 2000, 1999 and 1998
    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, 2000                    40
Notes to Consolidated Financial Statements                               41-53
Supplementary Information On Oil and Gas Producing Activities (unaudited)54-56

                  (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.

         (b)      Reports on Form 8-K
                  -------------------

                  None

         (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 Gas Field:

                           (1.)Copy of Agreement  dated May 28, 1959 between
                           Canada  Southern 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
                           Canada Southern 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 Canada Southern 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
                           Canada Southern 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 Canada Southern
                           -------------------------------

                           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.

                  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, 2001              By /s/ Ben A. Anderson
       -------------------------        ----------------------------------------
                                          Ben A. Anderson
                                          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/ Ben A. Anderson                    By /s/ David Blain
   -------------------------              ------------------------------------
    Ben A. Anderson                           David Blain
    President and Director                    Treasurer and Chief Financial and
                                              Accounting Officer

Dated:    March 28, 2001                Dated:     March 28, 2001
       ---------------------                    -----------------------------


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


Dated:    March 28, 2001                 Dated:    March 28, 2001
       ---------------------              --------------------------------


By /s/  Arthur B. O'Donnell               By /s/ M. A. Ashton
        -------------------               -------------------------
        Arthur B. O'Donnell                   M. A. Ashton
        Director                              Director

Dated:    March 28, 2001                 Dated:    March 28, 2001
       ---------------------              --------------------------------







                                INDEX TO EXHIBITS


     23.      (a)     Consent of Independent Petroleum Engineers

              (b)     Consent of Independent Auditors