FORM 10-K

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

For the fiscal year ended    December 31, 1996

                                       OR

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

For the transition period from to


Commission file number  1-3793

                         CANADA SOUTHERN PETROLEUM LTD.

             (Exact name of registrant as specified in its charter)

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

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

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

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

                                                       Name of each exchange on
                         Title of each class                which registered

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

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

                                (Title of Class)

                                      NONE

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




<PAGE>



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

          The aggregate market value of the voting stock held by  non-affiliates
of the registrant was approximately U.S. $95,781,000 at March 18, 1997.


                   (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,  13,956,
540 shares outstanding as of March 18, 1997.

                       DOCUMENTS INCORPORATED BY REFERENCE

                  Proxy Statement of Canada Southern  Petroleum Ltd.  related to
the Annual Meeting of Shareholders  for the year ended December 31, 1996,  which
is incorporated into Part III of this Form 10-K.




<PAGE>





                                TABLE OF CONTENTS


                                                                            Page

                                     PART I

Item 1.           Business                                                    4

Item 2.           Properties                                                 15

Item 3.           Legal Proceedings                                          23

Item 4.           Submission of Matters to a Vote of Security Holders        26

                                     PART II

Item 5.           Market for the Company's Limited Voting Shares and
                  Related Stockholder Matters                                27

Item 6.           Selected Financial Data                                    29

Item 7.           Management's Discussion and Analysis of Financial
                  Condition and Results of Operations                        30

Item 8.           Financial Statements and Supplementary Data                36

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

                                    PART III

Item 10.          Directors and Executive Officers of the Company            56

Item 11.          Executive Compensation                                     56

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

Item 13.          Certain Relationships and Related Transactions             56

                                     PART IV

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


Unless  otherwise  indicated,  all dollar  figures  set forth are  expressed  in
Canadian currency. The exchange rate at March 18, 1997 was $1.00 Canadian = U.S.
$.7281.



<PAGE>



                                     PART I

Item 1.    Business.

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

         (a)  General Development of Business

Yukon Territory - The Kotaneelee Field

         The  Company's  principal  asset  is a  30%  carried  interest  in  the
Kotaneelee  gas field located on Ex-Permit 1007 (31,888 gross acres or 9,566 net
acres) in the extreme southeastern corner of the Yukon Territory. This partially
developed field is connected to a major pipeline  system.  Only three wells have
been completed to date and are capable of an estimated output of in excess of 60
million cubic feet per day, the capacity of the field dehydration plant. Present
production  is  approximately  40-45  million  cubic feet  ("mcf") per day.  The
operator  is Anderson  Exploration  Ltd.,  which  acquired  all of Columbia  Gas
Development of Canada's interests.  See "Legal Proceedings " for a discussion of
the Kotaneelee Litigation concerning this asset.

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

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

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



<PAGE>


         At  present,  the  Company  does not  receive  any cash  payments  from
production  but is credited with 30% of the gross  revenues until a like percent
of the working interest costs,  exclusive of any interest expense, are recovered
by the  operator.  The Company  will not receive  any  payment  from  production
revenues until its share of the working  interest costs are recovered.  When the
deferred  costs are recovered,  30% of gross  revenues (net of gross  overriding
royalties)  less  30% of  current  working  interest  costs  will be paid to the
Company.  Gross  overriding  royalties  amount  to 10% to the  Canadian  Federal
government  and 4.06% to certain  individuals.  The operator has reported to the
Company  development  costs  totaling  approximately  $88,000,000  and,  of that
amount, approximately $21,800,000 remained to be recovered at December 31, 1996.
The  Company  has  contested  the amount of costs that have been  charged to the
carried interest account.  It is expected that the Company will begin to receive
proceeds from the Kotaneelee gas field commencing in 1999, based upon a price of
$1.34 per mcf  (average  1996 price) and current  production  rates.  The period
before  payment to the  Company  begins may be shorter or longer,  depending  on
prevailing market conditions and the results of the Kotaneelee Litigation. Under
ordinary  circumstances,  increased natural gas prices would result in a shorter
period to payout.

British Columbia Properties

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

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


<PAGE>


         On the working  interest lands,  the most successful of these wells was
in the West Peejay field in British Columbia  (Company  interest  27.75%).  This
field has been  produced  for many  years,  without  any  attempt to explore the
field's  limits.  The 1993  sale of the  field  by the  majority  owner  and the
appointment of a new operator resulted in three new producing oil wells in 1994.
The  operator  has applied to unitize  and  waterflood  the West  Peejay  field.
Preliminary  approval  has  been  received  and work is  underway  with one well
drilled and a seismic program completed.  The first well encountered oil and gas
and it is expected that at least three more wells will be drilled in 1997.  Once
unitization is completed,  the Company will have a 14.0152%  working interest in
the oil and 14.1113%  working interest in the gas in the whole field rather than
a 27.75% working interest in a part of the field.

         CNRL  operates  the lands  which also  include  the  Company's  working
interest in the Peejay and Weasel  fields.  As of December 31, 1996, the Company
held  approximately  18,732  gross  acres  (4,434 net  acres) in this area.  The
Company owns interest in the following units:

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

         The Company  also holds  interests in 10 oil wells (2.64 net wells) and
10 gas wells.  (2.28 net wells) not  included  in the above  units.  The Company
estimates that the capital costs for its interests in the West Peejay field will
aggregate approximately $750,000 for 1997.

         The Company has a 33 1/3% working  interest in the Paradise  area.  Two
oil  discoveries in the area remain shut-in  because at current oil prices their
production rates are uneconomic.  The wells also encountered potential gas zones
which have not been  tested.  A portion  of the lands have been  farmed out on a
seismic  option basis and the farmee has committed to drill a well on the lands,
as soon as a surface lease and rig have been  acquired.  The Company will retain
an overriding  royalty  before  payout and a 6.67% working  interest in the well
after payout.

         There has been further  drilling and development  work on the Company's
carried interest  properties at Buick Creek and Siphon.  Initial production from
this work shows  promise  with a rate of 3.8  million  cubic feet per day from a
horizontal  well at Buick Creek.  Capital costs charged to the carried  interest
account in 1996 were $375,000. During 1996, the Siphon area properties were sold
by the operator and a new operator  appointed.  The Wargen area is also expected
to change  operators  in 1997.  The new owners of these  fields are  expected to
aggressively exploit the properties with increased capital expenditures.

         Carried  interest  lands are also  held by the  Company  in the  Ekwan,
Clarke Lake,  Siphon and Wargen  fields.  The Company  retains a 21.25 % carried
interest with a right to convert to a 21.25 % working  interest in most of these
fields.  Interests  in some of these  wells  are less than  21.25 %  because  of
pooling or side agreements.  As of December 31, 1996, there were 36 gas wells in
these  fields which are  producing  wells or wells  considered  to be capable of
production.

Arctic Islands

         As of December 31, 1996,  the Company held working  interests in 45,100
gross  acres  (1,817 net acres) and  carried  interests  in 133,260  gross acres
(37,255 net acres) in the Sverdrup  Basin,  located in the Arctic  Islands.  The
Hecla, Whitefish,  Drake Point, Roche Point,  Kristoffer,  Romulus and Bent Horn
fields have been designated  significant discovery lands ("SDL" ) by the Federal
Government.  The  Company's  interests in the SDL's have been  retained  pending
development.

Marketing of Bent Horn Production

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

Northwest Territories Properties

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

Alberta

         The Company  participated  in  9  wells on the  Alberta  lands in  1996
which resulted in 6 oil wells, 1 gas well and 2 dry holes.


<PAGE>


         In 1994,  the Company  purchased a 5% working  interest in the Kitscoty
heavy oil field and the  related  facilities.  Oil  recovery  from this field is
being  enhanced  by steam  injection.  Two  horizontal  holes were  drilled  for
production with the steam being injected through vertical holes.  Production has
increased from 60 bpd to 300 bpd.

         In 1996, the Company purchased an additional 5% working interest in the
Kitscoty field.  Three more wells were drilled in 1996, two horizontal wells and
one vertical well. All the wells encountered oil and are now on production.  One
well also  discovered  three  potential  gas zones which will be  evaluated  for
future  use as  fuel  for  the  steam  generation  needed  to  enhance  the  oil
production.

         The other  successful  wells in  Alberta  were at Atlee and  Leduc.  At
Atlee,  two horizontal wells were drilled and placed on production at a combined
rate of 500 bpd.  The operator  plans to complete a 3D seismic  program with the
possibility  of drilling six  additional  wells in 1997. The Company has a 12.5%
working interest in the two producing wells.

         At Leduc,  three wells were drilled of which two were  completed as oil
and gas wells and one well was a dry hole.  One well  encountered  two potential
producing zones and is currently  producing at the allowable rate of 68 bpd. The
second zone  containing oil and gas will be produced from a follow-up well to be
drilled in early 1997. The other successful well was completed as a gas well and
is  producing  1.5  million  cubic feet per day.  The  Company has a 15% working
interest in these  wells.  The operator  has  indicated  that is expects that at
least two  wells  will be  drilled  on the Leduc  properties  in 1997,  once the
results of the 1996 3D seismic program have been evaluated.

         The  Company  also  acquired a 10-20%  working  interest in over 12,000
acres in four other areas of Alberta. These lands were purchased on the basis of
seismic  work  which  showed  a number  of  promising  prospects.  Subsequently,
additional seismic work has confirmed the potential of those prospects. One well
will be drilled as soon as a rig is available and at least two additional  wells
are planned for 1997.

         The Company's gas well at  Drumheller  remains  shut-in and the Company
has agreed to sell its interest in the Sylvan Lake well.

         The Company has working interests ranging from 10% to 45% in a total of
40,702 gross (11,178 net) acres.

Saskatchewan

         Under the  Company's  land  acquisition  program,  it  acquired a 3.75%
working  interest  (2,560  gross  acres  -  96  net  acres)  in  4  sections  in
Saskatchewan in late 1994.


<PAGE>


Two wells were drilled on these  properties  in early 1995,  and,  although both
were  abandoned,  indications  are that the leases have good oil  potential  and
further  seismic work was  completed in 1996. A well was drilled on the basis of
the new seismic  program and the well tested over three  million  cubic feet per
day from a gas zone. The well is currently shut-in.

Australia

         The Company has a .08% working interest in 115,596 gross (90 net) acres
in the Amadeus  Basin in the  Northern  Territory in  Australia.  Because of the
limited  potential  of the only  remaining  property,  the Dingo gas field,  the
interest was written down to a nominal  value in 1992.  The Dingo gas field is a
shut-in gas field which is not connected to a gas pipeline.  Initial discussions
have been held with a potential gas purchaser for the sale of approximately  7.4
BCF of gas  over 10  years  with a  possible  contract  for 20  years.  Magellan
Petroleum  Australia  Limited  ("MPAL") is presently  operator of this property.
Benjamin  W. Heath and C. Dean  Reasoner,  directors  of the  Company,  are also
directors of MPAL. Mr.  Reasoner  resigned as a director of the Company on March
11, 1997.

United States

         The Company has agreed to  participate in the drilling of five wells in
Texas. The first two wells drilled in 1996 resulted in oil discoveries, however,
the wells are currently shut-in awaiting remedial work.
Two more wells will be drilled by mid 1997.

         (b)      Financial Information about Industry Segments.

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

         (c)      (1)      Narrative Description of the Business.

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

         The Company is,  either in its own right,  or through  other  entities,
engaged in the  exploration  for and  development  of  properties  containing or
believed to contain recoverable oil and gas reserves and the sale of oil and gas
from these properties.  Although many of the properties in which the Company has
interests are undeveloped,  all properties with proved reserves are partially or
fully  developed.  The  Company's  interests  in  exploratory  ventures  are  on
properties  located  in  Alberta,  British  Columbia,  the  Northwest  and Yukon
Territories  and the Arctic  Islands in Canada,  and the  Northern  Territory of
Australia.  A principal asset of the Company is its 30% carried  interest in the
Kotaneelee  field,  a  partially  developed  gas  field  (See  Item  3 -  "Legal
Proceedings".) The Company also has interests in producing properties in British
Columbia  and  Alberta.  Most of this  acreage is  covered  by carried  interest
agreements,  which  provide that  revenues are not payable to the Company  until
expenditures by the carrying  partners have been recouped from  production,  and
that  operating  decisions  are made by the carrying  partners.  Generally,  the
Company may, at any time,  as to each block or economic  unit,  elect to convert
from a carried interest  position to a working  interest  position by paying its
share of the  unrecouped  expenditures  for the  unit,  i.e.,  expenditures  not
recouped from production revenues.  At December 31, 1996, the Company's share of
unrecouped expenditures were as follows:

British Columbia:
 Ex-permit 149                                             $3,216,000

Yukon and Northwest Territories:
 Ex-permit 1007 (Kotaneelee)*                               6,534,000
 Ex-permit 2713 (Celibeta)                                    321,000

*See Item 3 - Legal Proceedings

                           (i)      Principal Products.

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

                           (ii)     Status of Product or Segment.

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

                           (iii)    Raw Materials.

                                    Not applicable.

                           (iv)     Patents, Licenses, Franchises and
                                    Concessions Held.

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



<PAGE>


                           (v)      Seasonality of Business.

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

                           (vi)     Working Capital Items.

                                    Not applicable.

                           (vii)    Customers.

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

                           (viii)   Backlog.

                                    Not applicable.

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

                                    Not applicable.

                           (x)      Competitive Conditions in the Business.

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


<PAGE>


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

                           (xi)     Research and Development.

                                    Not applicable.

                           (xii)    Environmental Regulation.

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

                           (xiii)   Number of Persons Employed by Company.

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

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

                  (1)      Identifiable Assets.

                           Substantially  all of the Company's  operating assets
are in Canada.

                           All of the Company's revenues are attributable to its
operations in Canada.

                  (2)      Risks Attendant to Foreign Operations.

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

Governmental Regulation of the Canadian Oil and Natural Gas Industry

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

Land Tenure

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

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



<PAGE>


Production and Production Facilities

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

Pricing and Marketing - Oil

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

Pricing and Marketing - Natural Gas

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

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

Royalties and Incentives

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

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

Environmental Regulation

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

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

                  Not applicable.

Item 2.  Properties.

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

         The  properties in Australia in which the Company has a minor  interest
are undeveloped and nonproducing,  and the Company has not incurred  significant
costs in connection with these properties.

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


<PAGE>











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




                  Map of Canada showing key Company properties


<PAGE>












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




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


<PAGE>












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




                        Map showing the Kotaneelee Field

<PAGE>












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




                         Map of the Arctic Island Fields
                       showing the Company interest lands


<PAGE>


(2)      Reserves Reported to Other Agencies.

         Not applicable.

(3)      Production

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


                 Average Sales Price                Average Production Costs
Year     Oil (per bbl.)     Gas (per mcf.)      Oil (per bbl.)    Gas (per mcf.)
              ($)                ($)                  ($)               ($)
1996         25.47               1.64                 8.67              .79
1995         22.39               1.30                10.08              .77
1994         19.14               1.84                 7.49              .98

(4)      Productive Wells and Acreage

         Productive wells and acreage on working and carried interest properties
as of December 31, 1996:

           Gross Wells                                 Net Wells
       Oil             Gas                       Oil             Gas
        71              83                      11.69           14.91

                                             Gross and Net Developed Acres
                                        Gross Acres                   Net Acres

Alberta                                      5,697                         844
Saskatchewan                                   640                          24
British Columbia                            66,360                      16,113
Yukon Territory                              3,350                       1,005
Arctic Islands                               3,060                         153
Texas, USA                                      80                           7
                                           ---------                  ----------
                                            79,187                      18,146
                                            ======                      ======



<PAGE>


(5)      Undeveloped Acreage.

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

<TABLE>
<CAPTION>
                                  Gross and Net Petroleum Acreage as of December 31, 1996
                                                 Developed Acres                          Undeveloped Acres
                                         Gross          Net                       Gross            Net
                                         Acres         Acres          %           Acres           Acres           %

<S>                                      <C>           <C>           <C>          <C>             <C>           <C>
Canada:
  British Columbia:
    Carried Interests                     39,508         7,455       18.9          12,211             932        7.6
    Working Interests                     23,042         4,848       21.9          37,861          11,932       31.5
    Overriding royalty interest            3,810         3,810       3.0                -               -
                                         -------       -------                    -------         -------
  Total British Columbia                  66,360        16,113                     50,072          12,864
                                          ------        ------                     ------          ------

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

  Alberta:
     Working Interests                     5,697           844       14.8          36,285           9,929       27.4
                                           -----       -------                     ------          ------
  Yukon & Northwest Territories:
     Carried Interests                     3,350         1,005       30.0          31,726           9,757       30.8
                                         -------         -----                     ------          ------

  Arctic Islands:
     Carried Interests                     3,060           153       5.0          130,200          37,102       28.5
     Working Interests                         -             -                     45,100           1,817        4.0
                                      ----------    ----------                    -------          ------
  Total Arctic Islands                     3,060           153                    175,300          38,919
                                         -------       -------                    -------          ------

  Total Canada                            79,107        18,139                    295,943          71,565

Texas, USA                                    80             7       8.8                -               -
Australia                                      -             -                    115,596              90        .1
                                      ----------    ----------                    -------       ---------
               TOTAL                      79,187        18,146                    411,539          71,655
                                          ======        ======                    =======          ======
</TABLE>

(6)      Drilling activity.

         Productive and dry net wells drilled  during the following  periods (no
drilling in Australia):

                                   Gross                           Net
                          ---------------------          ----------------------
Year/Period Ended         Productive        Dry          Productive         Dry
-----------------         ----------        ---          ----------         ---
      1996                    10             2             1.044           .150
      1995                     1             3              .033           .258
      1994                     8             -              1.000            -


<PAGE>


(7)      Present Activities.

         There was no drilling activity at December 31, 1996.

(8)      Delivery Commitments.

         None.

Item 3.  Legal Proceedings.

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

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

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


<PAGE>


         The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million.  The Company  claims  that by 1993 at least $34 million of  unnecessary
expenses  had been  wrongfully  charged to the  carried  interest  account.  The
Company's 30% share of these expenses would be approximately $10.2 million.  The
Company  further  claims that if production  had commenced in 1984,  the carried
interest  account  would have been paid off in  approximately  two years and the
Company would have begun to receive revenues from the field in 1986. At present,
the Company does not expect to receive  revenues before 1999 based on a price of
$1.34 per mcf and current production rates.

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

         The parties to the litigation have conducted  extensive discovery since
the filing of the claims.  The trial began on September  3, 1996.  The trial was
suspended after approximately three weeks of testimony pending resolution of the
Company's motion to disqualify  Amoco's  litigation  counsel on the basis that a
partner  in the firm  representing  Amoco had served as the  Company's  Canadian
securities  counsel  for many  years.  The  Company's  motion was denied and the
denial was upheld on appeal.  The Company  has filed with the  Supreme  Court of
Canada an application for leave to appeal that decision. The parties have agreed
to expedite the application and a decision whether the Supreme Court will review
the decision is expected by the end of April.  If the Supreme  Court  refuses to
hear the case, trial is expected to resume on May 5, 1997.

Matters Ancillary to Kotaneelee Litigation

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

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

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

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


<PAGE>


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

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

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

         Under Canadian law certain costs of the litigation are assessed against
the nonprevailing  party. These costs consist primarily of attorney's and expert
witness  fees during  trial.  The trial is  presently  scheduled  to last twelve
months, therefore, these costs could be substantial. While the costs are not now
determinable,  the Company  estimates  that such costs,  assuming a twelve month
trial,  could be  approximately  $1.5 million.  However,  a judge in complex and
lengthy  trials  has the  discretion  to double an award of costs.  There are no
assurances  however,  that such costs will not  exceed  this  amount or that the
duration of the trial will not exceed twelve months.

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



<PAGE>


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

         Not applicable.

Executive Officers of the Company.

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

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

Charles J. Horne   71   President                   Since 1980      Director
M. A. Ashton       61   Executive Vice President    Since 1993      Director

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

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



<PAGE>


                                     PART II

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

         (a)      Principal Markets.

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

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

1995          1st quarter       2nd quarter       3rd quarter       4th quarter
----          -----------       -----------       -----------       -----------
High             7.875              7.75              9.00             10.25
Low              6.00               6.75              6.25              8.375


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

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

1995          1st quarter       2nd quarter       3rd quarter       4th quarter
----          -----------       -----------       -----------       -----------
High             5 5/8               6               6 3/4             7 1/2
Low              4 3/8            4 13/16            4 5/8             6 1/4


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



<PAGE>


         (b)      Approximate Number of Holders of Limited Voting
                  Shares at March 3, 1997.

                                                              Approximate
    Title of Class                                     Number of Record Holders

Limited Voting Shares, par value
$1.00 per share.                                                 6,500

         (c)      Dividends.

         The Company has never paid a dividend on its Limited Voting Shares. Any
future  dividends  will  be  dependent  on  the  Company's  earnings,  financial
condition, and business prospects. The Company is legally restricted from paying
any  dividend  or making  any other  payment to  shareholders  (except by way of
return of capital) on the Limited  Voting Shares until its  accumulated  deficit
($19,385,000 at December 31, 1996) is eliminated.

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



<PAGE>




Item 6.           Selected Financial Data.

         The following selected consolidated financial information (in thousands
except per share and exchange rate data) of the Company insofar as it relates to
each  of the  fiscal  periods  shown  has  been  extracted  from  the  Company's
consolidated  financial statements.  Effective July 1, 1993, the Company changed
its year end from June 30 to December 31.

<TABLE>
<CAPTION>
                                                                   Year ended                                     Year ended
                                                                    December 31,                                    June 30,
                                       
                                         1996              1995              1994              1993                 1993
                                         ----              ----              ----              ----                 ----
                                         ($)               ($)               ($)               ($)                   ($)

<S>                                   <C>               <C>                <C>              <C>                   <C>  
Operating revenues                      1,755             1,657             1,691             1,915                  2,061
                                      =======           =======            ======           =======                 ======

Total revenues                          2,228             1,793             1,942             2,103                  2,389
                                      =======           =======            ======           =======                =======

Net loss                               (1,461)           (1,162)           (1,210)             (977)                  (613)
                                      ========          ========           ========         ========              =========

Net loss per share                      (.11)             (.09)            (.10)              (.08)                  (.05)
                                    =========         =========         =========          ========             ==========

Working capital                         8,403             1,510             2,417             3,890                  3,750
                                      =======           =======            ======           =======                 ======

Total assets                           20,375            12,380            13,390            14,484                 14,104
                                       ======           =======            ======            ======                 ======

Shareholders' Equity:
     Capital stock                     38,888            29,635            29,513            29,513                 28,739
     Deficit                          (19,385)          (17,923)          (16,762)          (15,552)               (14,999)
                                      --------          --------          --------          --------               --------
                                       19,503            11,712            12,751            13,961                 13,740
                                      =======           =======            ======            ======                 ======
Average number of
  shares outstanding                   13,362            12,622            12,613            12,453                 12,363
                                      =======           =======            ======            ======                 ======

Exchange rates:
     Year-end                           .7297             .7329             .7129             .7554                .7801
                                        =====             =====             =====             =====                =====

     Average for the period             .7335             .7289             .7324             .7757                .8013
                                        =====             =====             =====             =====                =====

     Range                           .7234-.7520       .7026-.7480        .7098-7634       .7436-.8045           .7768-.8458
</TABLE>

U.S. GAAP Information

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

<TABLE>
<CAPTION>
<S>                                    <C>               <C>               <C>                 <C>                  <C>  
Net loss                               (1,236)           (1,001)           (1,140)             (673)                (613)
                                       =======           =======           ========            =====                =====
Net loss per share                      (.09)             (.08)             (.09)               .05                 (.05)
                                        =====             =====             =====               ===                 =====
</TABLE>



<PAGE>


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

(1)      Liquidity and Capital Resources.

         At December 31,  1996,  the Company had  approximately  $8.4 million of
cash and securities  available.  These funds are expected to be used for general
corporate  purposes,  including  exploration and development and to continue the
Kotaneelee field litigation.

         Cash flow used in operations during 1996 decreased to $775,000 compared
to $783,000 during the 1995 period.  The $8,000 difference  between  the periods
was caused primarily by the following:

Increase in loss from operations                                       $217,000
Increase in accounts receivable                                         220,000
Increase in accounts payable and accrued liabilities                   (247,000)
Decrease in prepaid insurance and deferred costs                       (198,000)
                                                                       ---------
Difference in net cash used in operations                            $   (8,000)
                                                                     ===========

         A  significant  proportion  of the  Company's  property  interests  are
covered by carried interest agreements,  which provide that expenditures made by
the operator are recouped solely out of revenues from production.  Major capital
expenditures  made by the operators  have an impact on the  Company's  cash flow
from  operations as no revenues are reported or received until the capital costs
have been  recovered by the  operator.  Properties  in the Fort Nelson,  British
Columbia  area in which the Company has carried  interests  have reached  payout
status.  Proceeds  from  these  carried  interests  plus oil and gas sales  from
working interest  properties are the Company's major sources of working capital.
During 1996, however, capital expenditures in the Fort Nelson area resulted in a
temporary suspension of carried interest revenue.

         The Company is currently evaluating and expects to continue to evaluate
oil and gas properties and may make  investments  in such  properties  utilizing
cash on hand. The Company  anticipates  that its capital  expenditures  for land
acquisitions  and drilling for the year 1997 will be  approximately  $2,300,000.
The $1,110,000 increase in net cash used in investing activities during the 1996
period compared to the 1995 period  reflects the Company's  effort to expand its
oil and gas exploration  program. In addition,  substantial  continuing expenses
are expected to be incurred in connection  with the Kotaneelee  Litigation.  The
expense  of the  Kotaneelee  Litigation  has  been  the  principal  cause of the
Company's losses since 1991.

         The Company has established a reserve for its potential share of future
site  restoration  costs.  The  estimated  amount of these  costs,  which  total
$728,000,  is being  provided on a unit of production  basis in accordance  with
existing legislation and industry practice.

(2)      Results of Operations.

1996 vs. 1995

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

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


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


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

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

</TABLE>


<PAGE>


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


<TABLE>
<CAPTION>
                                           1996                                            1995
                                           -----                                           ----
                                       Average price                                   Average price
                            mmcf          per mcf          Total            mmcf          per mcf         Total

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

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

         Interest  and other  income was 247%  higher in 1996.  Interest  income
increased  from  $90,000  to  $258,000  in 1996  due to the  increase  in  funds
available for investment from the June 1996 rights offering to shareholders.  In
addition, the 1996 period includes proceeds from the sale of seismic data in the
amount of $215,000 compared to $46,000 in 1995.

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

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

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

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


<PAGE>


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

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

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

Fiscal Year Ended December 31, 1995 vs. 1994

         The net loss for  the  year  1995  was  $1,161,763,  ($.09  per  share)
compared to a net loss of  $1,210,109  ($.10 per share) for the  1994 period.  A
summary of revenue and expenses during the periods is as follows:


                              1995                1994               Net Change
                              ----                ----               ----------
Revenues                   $1,793,112           $1,942,289           $(149,177)
Costs and expenses          2,954,875            3,152,398             197,523
                            ---------            ---------           ---------
Net loss                  $(1,161,763)         $(1,210,109)         $   48,346
                          ============         ============         ==========


         Oil  sales  increased  by 2% due  primarily  to a 17%  increase  in the
average price of oil sold which offset a 16% decrease in  production.  There was
also a 16%  decrease  in  royalties  paid.  Oil unit sales in  barrels  ("bbls")
(before  deducting  royalties)  and the average price per barrel sold during the
periods indicated were as follows:


<TABLE>
<CAPTION>
                                         1995                                                 1994
                                         -----                                                ----
                                     Average price                                        Average price
                        bbls            per bbl            Total             bbls            per bbl            Total

<S>                    <C>               <C>               <C>              <C>               <C>               <C>     
                       29,198            $22.39            $654,000         34,711            $19.14            $664,000
Royalties paid                                              (98,000)                                            (116,000)
                                                          ----------                                            ---------
Total                                                      $556,000                                             $548,000
                                                           ========                                             ========

</TABLE>

<PAGE>


         Gas sales  decreased 25%. There was a 29% decrease in the average price
for gas which was partially  offset by a 8% increase in units sold. In addition,
gas sales includes  royalty  income which  decreased 31% in 1995. 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:


<TABLE>
<CAPTION>
                                             1995                                              1994
                                             -----                                             ----
                                         Average price                                     Average price
                            mmcf            per mcf           Total            mmcf           per mcf           Total

<S>                          <C>             <C>              <C>               <C>            <C>              <C>     
Gas sales                    252             $1.30            $327,000          234            $1.84            $431,000
Royalty income                                                  92,000                                           134,000
Royalties paid                                                 (52,000)                                          (78,000)
                                                              ---------                                         ---------
Total                                                         $367,000                                          $487,000
                                                              ========                                          ========
</TABLE>

         Proceeds under carried  interest  agreements  increased 12% to $734,066
during 1995 compared to $656,303 in 1994. The operator of the Company's  carried
interest properties  significantly  increased its development  activities during
the late 1994 and early 1995, thereby incurring  additional  expenses.  Proceeds
under carried  interest  agreements are derived from gross  production  revenues
after payout of these  expenses.  The latter part of 1995  benefited  from these
development activities by increased production.

         Interest  and other income was 46% lower in 1995.  Interest  income was
lower in 1995 due to the  decrease  in funds  available  to invest  during  1995
compared to the prior year. In addition, 1995 includes proceeds from the sale of
seismic data in the amount of $46,124 compared to $125,368 in 1994.

         General and administrative costs decreased 18% in 1995. The 1994 period
included the additional  expenses of the Special Meeting of Shareholders held in
July 1994 and  associated  costs.  The 1994 period also  included  higher salary
expenses related to retired personnel.

         Legal expenses were 5% lower in 1995 compared to the prior year.  These
expenses are related  primarily to the Kotaneelee  litigation in which discovery
is now substantially  complete.  These expenses are expected to increase in 1996
as a result of trial  preparation  and the  conduct  of the trial  scheduled  to
commence on September 3, 1996.

         Depletion, depreciation and amortization expense was 13% higher in 1995
due to an increase  in  estimated  future  capital  costs  to  develop  existing
reserves.


<PAGE>


         A foreign  exchange loss of  $13,915 was recorded  in 1995,  contrasted
with a gain of  $57,791 on  U.S. cash  investments  in 1994.  During  1995,  the
Company  had a  minimal amount invested  in the  United  States.  In  1994,  the
significant  gain was attributable to a strengthening  of  the  U.S.  dollar  as
compared to the Canadian dollar on the Company's U.S. investments.

         Provision for  restoration  costs decreased to $16,800 in 1995 compared
to $76,656 in 1994.  The Company has  re-evaluated  its potential  liability and
accordingly reduced its provision for restoration costs.

         Rent expense was 7% lower in the 1995 period as a result of lower pass-
through operating costs under the lease.

         Income taxes. No provision for income taxes was required for 1995.



<PAGE>


Item 8.  Financial Statements and Supplementary Data



                         REPORT OF INDEPENDENT AUDITORS








To the Shareholders of
Canada Southern Petroleum Ltd.


We have audited the accompanying  consolidated balance sheets of Canada Southern
Petroleum Ltd. as at December 31, 1996 and 1995, 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, 1996.
These financial  statements are the responsibility of the Company's  management.
Our responsibility is to express an opinion on these financial  statements based
on our audits.

We  conducted  our  audits  in  accordance  with  generally   accepted  auditing
standards.  Those standards  require that we plan and perform an audit to obtain
reasonable  assurance  whether  the  financial  statements  are free of material
misstatement.  An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements.  An audit also includes
assessing the  accounting  principles  used and  significant  estimates  made by
management, as well as evaluating the overall financial statement presentation.

In our opinion, the consolidated  financial statements referred to above present
fairly,  in all material  respects,  the financial  position of Canada  Southern
Petroleum  Ltd.  as at  December  31,  1996  and  1995  and the  results  of its
operations  and the changes in its  financial  position for each of the years in
the three year period ended  December 31, 1996,  in accordance  with  accounting
principles generally accepted in Canada.




Calgary, Canada                                           ERNST & YOUNG
March 6, 1997                                             Chartered Accountants


<PAGE>


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

                           CONSOLIDATED BALANCE SHEETS
                         (Expressed in Canadian dollars)


<TABLE>
<CAPTION>
                                                                                 December 31,          December 31,
                                                                                    1996                   1995
                                                                                    -----                  ----

             Assets

<S>                                                                              <C>                  <C>          
   Cash and cash equivalents (Note 2)                                              $2,709,597          $   1,181,581
   U.S. Government securities (Note 3)                                              3,404,213                      -
   Accounts and interest receivable                                                   635,223                350,598
   Prepaid insurance and other                                                        227,368                226,539
   Other                                                                                    -                112,903
                                                                                  -----------          -------------
   Total current assets                                                             6,976,401              1,871,621
                                                                                   ----------           ------------

   U.S. Government securities (Note 3)                                              2,048,573                      -
                                                                                    ---------          -------------

   Oil and gas properties and equipment
     (full cost method) (Note 4)                                                   11,349,945             10,508,619
                                                                                   ----------             ----------
                                                                                  $20,374,919            $12,380,240
                                                                                  ===========            ===========

             Liabilities and Shareholders' Equity

   Current liabilities
     Accounts payable                                                            $    439,837          $     125,509
     Accrued liabilities (Note 10)                                                    182,104                236,332
                                                                                 ------------          -------------
   Total current liabilities                                                          621,941                361,841
                                                                                 ------------          -------------

   Future site restoration costs                                                      250,274                306,728
                                                                                 ------------          -------------

   Contingencies (Notes 8 and 11)                                                           -                      -

   Shareholders' Equity
     Limited Voting Shares, par value
       $1 per share (Note 5)
     Authorized - 100,000,000 shares
     Outstanding -13,956,540  (1995 - 12,645,791) shares                           13,956,540             12,645,791
     Contributed surplus                                                           24,930,964             16,989,397
                                                                                   ----------            -----------
                                                                                   38,887,504             29,635,188
                                                                                   ----------             ----------
   Deficit                                                                        (19,384,800)           (17,923,517)
                                                                                  ------------           ------------
   Total shareholders' equity                                                      19,502,704             11,711,671
                                                                                  -----------            -----------
                                                                                  $20,374,919            $12,380,240
                                                                                  ===========            ===========

</TABLE>

                             See accompanying notes.



<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

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


<TABLE>
<CAPTION>
                                                                                Year ended December 31,

                                                                       1996                1995                  1994
                                                                       -----               -----                 ----

<S>                                                            <C>                  <C>                  <C>         
         Revenues:
           Oil sales                                           $    768,576         $    555,894         $    547,509
           Gas sales                                                395,068              366,700              486,764
           Proceeds under carried
               interest agreements                                  590,935              734,066              656,303
           Interest and other income                                473,814              136,452              251,713
                                                                -----------          -----------         ------------
                                                                  2,228,393            1,793,112            1,942,289
                                                                 ----------           ----------           ----------
         Costs and expenses:
           General and administrative                               894,766              988,395            1,204,565
           Legal (Note 9)                                         1,610,477              879,821              928,560
           Lease operating costs                                    476,562              503,648              502,452
           Depletion, depreciation,
           and amortization                                         654,982              499,630              441,033
           Foreign exchange
             (gains)                                                (24,693)              13,915              (57,791)
           Provision for future site
              restoration costs                                      24,600               16,800               76,656
           Rent                                                      52,982               52,666               56,923
                                                                -----------         ------------         ------------
                                                                  3,689,676            2,954,875            3,152,398
           Loss before income taxes                              (1,461,283)          (1,161,763)          (1,210,109)
           Income taxes (Note 6)                                          -                    -                    -
                                                            ----------------     ----------------     ----------------  
         Net loss                                                (1,461,283)          (1,161,763)          (1,210,109)
           Deficit - beginning of period                        (17,923,517)         (16,761,754)         (15,551,645)
                                                               -------------        -------------        -------------
           Deficit - end of period                             $(19,384,800)        $(17,923,517)        $(16,761,754)
                                                               =============        =============        =============

         Average number of shares
           outstanding                                           13,362,410           12,621,560           12,612,791
                                                                 ==========           ==========          ===========

         Net loss per share                                        $(.11)               $(.09)               $(.10)
                                                                   ======               ======               ======
</TABLE>




                             See accompanying notes.



<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.
                      Consolidated Statements of Cash Flows
                         (Expressed in Canadian dollars)

<TABLE>
<CAPTION>
                                                                                 Year ended
                                                                                 December 31,

                                                             1996                   1995                  1994
                                                             ----                   ----                  ----

<S>                                                       <C>                    <C>                    <C>         
Cash flows from operating activities:
    Net loss                                              $(1,461,283)           $(1,161,763)           $(1,210,109)
    Adjustments to reconcile net loss
       to net cash provided by
      (used in) operating activity:
    Depreciation, depletion and
      amortization                                            654,982                499,630                441,033
    Future site restoration costs (net)                       (56,454)                16,800                 76,656
  Change in assets and liabilities:
    Accounts and interest receivable                         (284,625)               (64,491)               143,390
    Prepaid insurance and other                               112,074                (85,775)               (40,034)
    Accounts payable                                          314,328                (38,583)               (27,797)
    Accrued liabilities                                       (54,228)                51,620                 67,723
                                                           -----------             ----------            -----------
Net cash used in operations                                  (775,206)              (782,562)              (549,138)
                                                            ----------             ----------            -----------

Cash flows from investing activities:
  Additions to oil and gas properties (net)                (1,496,308)              (383,519)            (1,090,969)
  U.S. Government securities purchased                     (5,452,786)                     -                      -
  Repayments of loans due Company                                   -                      -                310,000
                                                          ------------           ------------           ------------
Net cash used in investing activities                      (6,949,094               (383,519)              (780,969)
                                                           ----------              ----------           ------------

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

Increase (decrease) in cash
  and cash equivalents                                      1,528,016             (1,044,301)            (1,330,107)
Cash and cash equivalents at the
  beginning of period                                       1,181,581              2,225,882              3,555,989
                                                            ---------              ---------              ---------
Cash and cash equivalents at the
  end of period (Note 2)                                   $2,709,597             $1,181,581             $2,225,882
                                                           ==========             ==========             ==========
</TABLE>

                             See accompanying notes.

<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.

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


<TABLE>
<CAPTION>

                                                                    Limited
                                                 Number          Voting Shares        Contributed
                                                of shares         $1 par value          surplus             Total
                                                ---------         ------------          -------             -----

<S>                                             <C>                <C>                 <C>                <C>       
Balance at December 31, 1993 and
  1994                                          12,612,791         12,612,791          16,900,617         29,513,408

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

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

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

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

</TABLE>


                             See accompanying notes.



<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         (Expressed in Canadian dollars)
                                December 31, 1996


1.       Summary of significant accounting policies

Accounting principles

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

Consolidation

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

Use of Estimates

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

Cash and cash equivalents

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

Oil and gas properties and equipment

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

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


<PAGE>


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

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

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

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

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

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

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

Revenue recognition

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

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


<PAGE>


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

Earnings per share

         Earnings per limited voting share is based upon the weighted average of
shares  outstanding  during the period.  Primary and fully diluted  earnings per
share are the same.

Future site restoration costs

         Estimated  future  site  restoration  costs which are  estimated  to be
$728,000 are being  provided on a unit of  production  basis.  The  provision is
based on current  costs of  complying  with  existing  legislation  and industry
practice  for  site   restoration  and   abandonment.   At  December  31,  1996,
approximately $478,000 in such costs have not been accrued.

Deferred income taxes

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

Foreign currency translation

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

2.       Cash and cash equivalents

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

                                                 1996                  1995
                                             ------------           -----------

Cash                                          $   319,616           $   326,031
Canadian bankers acceptances (2.65%)            1,441,170               855,550
U.S. Treasury Bills (4.75%)                       948,811                     -
                                              -----------           -----------
                                               $2,709,597            $1,181,581
                                               ==========            ==========


<PAGE>


3.       U.S. Government Securities

         At December 31,1996,  the Company has the following amounts invested in
U.S. government securities which are expected to be held until maturity:

<TABLE>
<CAPTION>
                                                                                  Amortized
       Security                    Par value             Maturity Date              Cost                Fair value
       --------                    ---------             -------------              ----                ----------
<S>                              <C>                     <C>                       <C>                 <C>        
U.S. Treasury Bill               $   822,256             Mar. 27, 1997             $   801,637         $   812,570
U.S. Treasury Bill                   685,213             Apr. 3, 1997                  657,599             676,271
U.S. Treasury Bill                 2,055,639             Jun. 26, 1997               1,944,977           2,004,289
                                   ---------                                         ---------           ---------
Total short term                   3,563,108                                         3,404,213           3,493,130
                                   ---------                                         ---------           ---------

U.S. Treasury Bill                 2,055,639             Jun. 26, 1998               2,048,573           2,056,914
                                   ---------                                         ---------           ---------

Total                             $5,618,747                                        $5,452,786          $5,550,044
                                  ==========                                        ==========          ==========
</TABLE>

4.       Oil and gas properties and equipment

<TABLE>
<CAPTION>
                                                                               Accumulated
                                                                              Provisions and        Net Book
                                                               Cost             Writedowns            Value


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

Balance December 31, 1995
Oil and gas properties - developed                           $17,069,321          $6,590,176         $10,479,145
Oil and gas properties - undeveloped                                   1                   -                   1
Seismic data                                                     112,000             104,508               7,492
                                                             -----------        ------------      --------------
                                                              17,181,322           6,694,684          10,486,638
Equipment                                                         57,865              35,884              21,981
                                                            ------------        ------------       -------------
                                                             $17,239,187          $6,730,568         $10,508,619
                                                             ===========          ==========         ===========
</TABLE>


         Substantially  all gas sales were made to CanWest Gas Supply  Inc.  and
oil sales were made to Canadian Natural Resources Ltd.

5.       Limited voting shares and stock options

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

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

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

         On June 24, 1996, the Company  concluded its offering of  approximately
1.3 million  shares to its  shareholders  at $7.50 per share.  The  offering was
oversubscribed  and the proceeds to the Company were $9,019,609  after deducting
the $494,509 cost of the offering.

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

Options outstanding                    Number of shares           Option Prices
                                                                       ($)
December 31, 1993                           159,700                3.45 - 4.06
  Granted                                   335,000                   7.00
                                            -------
December 31, 1994                           494,700                3.45 - 7.00
  Exercised                                 (33,000)               3.45 - 4.06
                                          ----------
December 31, 1995                           461,700
                                            =======
  Canceled                                 (137,000)               3.45 - 7.00
  Exercised                                 (42,200)               3.45 - 8.75
  Granted                                   150,700                3.15 - 6.37
  Granted                                    12,500                   8.75
                                          ---------
December 31, 1996                           445,700
                                            =======

Options reserved for future grants          212,134


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

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


<PAGE>


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

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

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

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

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

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

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>
                                                                                    Year ended December 31,


                                                              1996                 1995                 1994
                                                              ----                 ----                 ----
                                                             44.84%               44.84%               44.84%
                                                             ======               ======               ======
<S>                                                         <C>                  <C>                  <C>       
Provision for income taxes based on combined basic
Canadian federal and provincial income tax                  $(577,532)           $(520,935)           $(542,614)
Nondeductible crown charges                                    61,599               60,354               72,577
Other                                                             478                  948                1,707
Unrealized tax loss                                           515,455              459,633              468,330
                                                             --------             --------              -------
Actual provision for income taxes                           $       -            $       -            $       -
                                                            =========            =========            =========
</TABLE>


         At December 31, 1996,  the Company had net operating  losses for income
tax  purposes of  approximately  $3,217,000  which are  available  to be carried
forward to future periods.  These losses expire in the following  years:  1998 -
$563,000, 1999 - $194,000, 2000 - $294,000, 2001 - $545,000, 2002 - $569,000 and
2003 - $1,052,000.


<PAGE>


6.        Income taxes (Cont'd)

         At December 31, 1996,  the  following  oil and gas tax  deductions  are
available to reduce future taxable income,  subject to a final  determination by
taxation authorities.

Drilling, exploration and lease acquisition costs                   $11,103,000
Earned depletion                                                      1,975,000
Undepreciated capital costs                                           1,463,000
Cumulative eligible capital losses                                      407,000
Share issue costs                                                       495,000

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

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

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

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

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


<PAGE>


6.       Income taxes (Cont'd)

                                                   December 31,
                                   1996               1995               1994
                                   ----               ----               ----
Deferred tax asset              $3,233,506        $2,351,550         $2,169,085
Valuation reserve               (2,473,526)       (1,816,792)        (1,795,307)
                                -----------       -----------        -----------
Net deferred tax asset          $  759,980        $  534,758         $  373,778
                                   -------           =======            =======

Deferred tax recovery           $  225,222        $  160,980         $   69,995
                                   =======           =======             ======

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

<TABLE>
<CAPTION>
                                                                       Year ended December 31,
                                                            1996                 1995                  1994
                                                            ----                 ----                  ----

<S>                                                     <C>                  <C>                  <C>         
Net loss under Canadian GAAP before income taxes        $(1,461,283)         $(1,161,763)         $(1,210,109)
Income tax adjustment                                       225,222              160,980               69,995
                                                       ------------         ------------        -------------
Net loss under U.S. GAAP                                $(1,236,061)          (1,000,783)         $(1,140,114)
                                                        ============          ===========         ============
Per Share Basis:
Net loss under Canadian GAAP before income taxes           $(.11)               $(.09)               $(.10)
Income tax adjustment                                         .02                  .01                  .01
                                                    ---       ---        ---       ---        ---       ---
Net loss under U.S. GAAP                                   $(.09)               $(.08)               $(.09)
                                                           ======               ======               ======
</TABLE>


<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         (Expressed in Canadian dollars)
                                December 31, 1996




          The  deficit  under  U.S.  GAAP  would  have  been   $18,624,820   and
$17,388,759 at December 31, 1996 and 1995, respectively.

7.        Line of credit

          The Company has a line of credit with a Canadian  chartered bank which
provides  for a loan of  $500,000.  The line of credit  provides  for a $125,000
operating  loan and  $375,000  for  letters of credit as part of the  directors'
indemnification  agreements. The interest rate on borrowing is at 3/4% above the
bank's prime lending rate. The line of credit is subject to annual review and is
secured by a general  assignment of accounts  receivable  and an  undertaking to
provide security in the form of assignment of future working interest  proceeds.
No drawings were made under this line during 1996 or 1995.

8.        Litigation

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

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

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

         The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million.  The Company  claims  that by 1993 at least $34 million of  unnecessary
expenses  had been  wrongfully  charged to the  carried  interest  account.  The
Company's 30% share of these expenses would be approximately $10.2 million.  The
Company  further  claims that if production  had commenced in 1984,  the carried
interest  account  would have been paid off in  approximately  two years and the
Company would have begun to receive revenues from the field in 1986. At present,
the Company does not expect to receive  revenues before 1999 based on a price of
$1.34 per mcf (average 1996 price) and current production rates.

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



<PAGE>


8.        Litigation (Cont'd)

         The parties to the litigation have conducted  extensive discovery since
the filing of the claims.  The trial began on September  3, 1996.  The trial was
suspended after approximately three weeks of testimony pending resolution of the
Company's motion to disqualify  Amoco's  litigation  counsel on the basis that a
partner  in the firm  representing  Amoco had served as the  Company's  Canadian
securities  counsel  for many  years.  The  Company's  motion was denied and the
denial was upheld on appeal.  The Company  has filed with the  Supreme  Court of
Canada an application for leave to appeal that decision. The parties have agreed
to expedite the application and a decision whether the Supreme Court will review
the decision is expected by the end of April.  If the Supreme  Court  refuses to
hear the case, trial is expected to resume on May 5, 1997.

Matters Ancillary to Kotaneelee Litigation

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

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

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

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

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

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


<PAGE>


8.        Litigation (Cont'd)

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

         Under Canadian law certain costs of the litigation are assessed against
the nonprevailing  party. These costs consist primarily of attorney's and expert
witness  fees during  trial.  The trial is  presently  scheduled  to last twelve
months, therefore, these costs could be substantial. While the costs are not now
determinable,  the Company  estimates  that such costs,  assuming a twelve month
trial,  could be  approximately  $1.5 million.  However,  a judge in complex and
lengthy  trials  has the  discretion  to double an award of costs.  There are no
assurances  however,  that such costs will not  exceed  this  amount or that the
duration of the trial will not exceed twelve months.

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

9.        Related party transactions

          Fees paid or accrued for legal  services  rendered to  the  Company by
Reasoner,  Davis & Fox, (of which firm  Mr. C. Dean Reasoner,  a director of the
Company, is a partner,) were U.S. $111,000, $133,000  and $111,000 for the years
1996,  1995  and  1994,  respectively.  Mr. Reasoner  resigned  as a director on
March 11, 1997.

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

         Directors  Heath and Reasoner have royalty  interests in certain of the
Company's  oil and gas  properties,  (present  and  past)  which  were  received
directly or indirectly through the Company. During the years 1996,1995 and 1994,
the Company and third-party  operators and/or owners of properties made payments
pursuant to these royalties for the benefit of Mr. Reasoner and Mr. Heath in the
amounts of U.S.  $5,342,  $6,159  and  $13,263  and U.S.  $10,844,  $12,777  and
$28,604, respectively.


<PAGE>


10.      Other financial information

Accrued liabilities
                                                     1996              1995
                                                     ----              ----
Accrued liabilities due to working
  interest partners                              $   12,050        $   23,830
Accrued accounting and legal expenses                52,793           107,228
Accrued royalties                                   116,415            99,405
Other                                                   846             5,869
                                                 ----------        ----------
                                                   $182,104         $ 236,332
                                                   ========         =========



<TABLE>
<CAPTION>
                                                      Year ended December 31,
                                         1996                   1995                   1994
                                         ----                   ----                   ----

<S>                                   <C>                    <C>                    <C>     
Royalty payments (1)                    $146,673               $150,224               $191,785
                                        ========               ========               ========

Interest payments (2)                 $    7,099              $  10,000              $  10,746
                                      ==========              =========              =========

Large corporation tax payments        $    2,741             $    4,527             $    7,740
                                      ==========             ==========             ==========
</TABLE>
--------------------
(1)      Oil and gas sales are reported net of royalties paid.
(2)      Bank line of credit charges.


<PAGE>


                         CANADA SOUTHERN PETROLEUM LTD.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                         (Expressed in Canadian dollars)
                                December 31, 1994
              (Information for the year ended December 31, 1993 and
            for the six months ended December 31, 1992 is unaudited)


                                                               

11.      Contingency

         The operator of one of the Company's carried interest properties, which
includes  approximately 36 wells, is claiming that certain payments made in 1995
and 1996 were outside the area of mutual interest.  The Company is disputing the
claim of  $319,000 at December  31,  1996 and a  resolution  of the claim is not
expected  until  an  independent  audit  of  the  carried  interest  account  is
completed.  If it is subsequently determined that the operator's claim is valid,
then any  overpayment  will be  recovered  from  the  future  revenues  of these
properties.



<PAGE>





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

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

          The  Company  has no proved oil and gas  reserves  in  Australia  that
require  disclosure  under  SEC  regulations  and no  revenues  from oil and gas
production in that country. 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, 1993                              441,000         33.831
  Revisions of previous estimates               66,488          0.207
  Production*                                  (33,888)        (1.081)
                                             ----------       --------
December 31, 1994                              473,600         32.957
  Revisions of previous estimates             (157,908)         1.559
  Production*                                  (30,892)        (1.311)
                                             ----------       --------
December 31,1995                               284,800         33.205
  Revisions of previous estimates              178,448         (2.655)
  Production                                   (37,448)        (1.519)
                                               --------        -------
  December 1996                                425,800         29.031
                                               =======         ======

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

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


<PAGE>


Results of oil and gas operations:
<TABLE>
<CAPTION>
                                                                         Year ended December 31,
                                                             1996                 1995                 1994
                                                             ----                 ----                 ----
<S>                                                       <C>                 <C>                  <C>       
Income:
  Oil and gas sales                                       1,163,644           $  922,594           $1,034,273
  Proceeds under carried
    interest agreements                                     590,935              734,066              656,303
                                                          ---------          -----------          -----------
                                                          1,754,579            1,656,660            1,690,576
                                                          ---------           ----------           ----------
Costs and expenses:
  Production costs                                          476,562              503,648              502,452
  Depletion depreciation, and
    amortization                                            654,982              499,630              441,033
  Provision for future site
    restoration costs                                        24,600               16,800               76,656
  Income tax expense                                              -                    -                    -
                                                        -----------        -------------         ------------
                                                          1,156,144            1,020,078            1,020,141
                                                          ---------          -----------           ----------
Net income from operations                               $  598,453        $     636,582          $   670,435
                                                         ==========        =============          ===========
</TABLE>

Costs of oil and gas activities:

<TABLE>
<CAPTION>
                                                                                Year ended
                                                                         Year ended December 31,

                                                               1996                 1995                 1994
                                                               ----                 ----                 ----
<S>                                                         <C>                 <C>                   <C>     
Acquisition costs                                           $484,000            $  49,000             $395,000
Exploration                                                  146,000               92,000              253,000
Development                                                  866,000              243,000              443,000
</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>
                                                                         Year ended December 31,

                                                             1996                 1995                 1994
                                                             ----                 ----                 ----

<S>                                                        <C>                  <C>                   <C>    
Future cash inflows                                        $ 49,410             $ 48,298              $56,981
Future development and
  production costs                                          (20,813)             (18,473)             (20,796)
                                                           ---------            ---------            ---------
                                                             28,597               29,825               36,185
Future income tax expense*                                   (2,931)              (4,218)              (6,778)
                                                          ----------            --------            ----------
Future net cash flows                                        25,666               25,607               29,407
10% annual discount                                          (9,691)             (10,679)             (12,890)
                                                          ----------            ---------             --------
Standardized measure of
  discounted  future net
  cash flows                                               $ 15,975             $ 14,928              $16,517
                                                           ========             ========              =======
</TABLE>

* Reflects  tax benefit  for the year ended  December  31,  1996 and 1995,  from
carryforward  of  exploration,   development   and  lease   acquisition   costs,
undepreciated   capital  costs  and  book  earned   depletion  of   $17,032,000,
$13,679,000 and $13,520,000.

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


<PAGE>


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

<TABLE>
<CAPTION>
                                                                      Year ended December 31,

                                                         1996                   1995                   1994
                                                         ----                   ----                   ----
<S>                                                     <C>                    <C>                  <C>       
Changes due to:
Prices and production costs                              $3,248                   $(88)              $    (21)
Future development costs                                 (1,049)                    83                      4
Sales net of production costs                            (1,330)                (1,428)                (1,188)
Development costs incurred
  during the year                                           866                    243                    443
Net change due to extensions,
  discoveries and improved
  recovery                                                1,458                      -                    358
Revisions of quantity estimates                          (4,229)                (3,404)                  (214)
Accretion of discount                                     1,660                  1,927                  1,832
Net change in income taxes                                  423                  1,078                    740
Other                                                         -                      -                    141
                                                       --------              ----------              --------
Net change                                               $1,047                $(1,589)                $2,095
                                                         ======                ========                ======
</TABLE>



<PAGE>


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

         None.

                                    PART III

         For information  concerning Item 10 - Directors and Executive  Officers
of the Company, Item 11 - Executive  Compensation,  Item 12 - Security Ownership
of Certain Beneficial Owners and Management and Item 13 - Certain  Relationships
and Related  Transactions,  see the Proxy Statement of Canada Southern Petroleum
Ltd.  relative to the Annual Meeting of  Shareholders  for the fiscal year ended
December  31,  1996,  which  will be filed  with  the  Securities  and  Exchange
Commission,   which  information  is  incorporated  herein  by  reference.   For
information concerning Item 10 - Executive Officers of the Company, see Part I.

         Mr. C. Dean Reasoner  resigned as a Director of the Company for health-
related  reasons on March 11, 1997. On March 13, 1997,  Mr. Arthur B. O'Donnell,
a former vice  president of the  Company, was elected to complete Mr. Reasoner's
term as a director.  Mr. O'Donnell, a CPA, has over  40  years experience in the
oil and gas business.


<PAGE>


                                     PART IV

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

         (a)      (1)      Financial Statements.

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

                                                                  Page Reference

Report of Independent Auditors                                           36
Consolidated balance sheets at December 31, 1996
  and 1995                                                               37
For the years ended December 31, 1996, 1995 and 1994
    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, 1996                                              40
Notes to consolidated financial statements                              41-52
Supplementary information on oil and gas activities
  (unaudited)                                                            53

                  (2)      Consolidated Financial Statement Schedules.

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

                  (3)      Exhibits.

                           The  following  exhibits  are  filed  as part of this
report:

         Item Number.

                  2.       Plan  of  acquisition,  arrangement,  liquidation  or
succession

                           None

<PAGE>



                  3.       Articles of Incorporation and By-Laws.

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

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

                           None.

                  9.       Voting trust agreement.

                           None.

                  10.      Material contracts.

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

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

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

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


<PAGE>


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

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

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

                  11.      Statement re computation of per share earnings.

                           Not applicable.

                  12.      Statement re computation of ratios.

                           None.

                  13.      Annual report to security holders.

                           Not applicable.

                  16.      Letter re change in certifying accountant.

                           Not applicable.

                  18.      Letter re change in accounting principles.

                           None.

                  20.      Previously unfiled documents.

                           None.

                  21.      Subsidiaries of the Company.

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

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

                           None.

                  23.      Consents of experts and counsel.

                           (a)  Paddock Lindstrom & Associates, Ltd.
                           (b)  Ernst & Young

                  24.      Power of attorney.

                           Not applicable.

                  27.      Financial Data Schedule.

                           Filed herein.

                  28.      Information from reports furnished to state insurance
                           regulatory authorities.

                           Not applicable.

                  99.      Additional exhibits.

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

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


<PAGE>


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

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

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

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

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

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

                           (1)      Covenant Not to Sue.

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

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

                           (4)      Partial  Discontinuance  of  Counterclaim.
                                    Action No.  8801-13549 Court of Queens Bench
                                    of Alberta Judicial District of Calgary.

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

         (b)      Reports on Form 8-K.

                  On October 21,  1996,  the Company  filed a Current  Report on
Form 8-K to report that the trial of its lawsuit  against  Amoco  Canada and the
other Kotaneelee working interest partners was adjourned pending resolution of a
conflict of interest dispute involving Amoco Canada's law firm.

                  On December 23, 1996,  the Company  filed a Current  Report on
Form 8-K to report that the Court of Queen's  Bench in Calgary ruled in favor of
allowing  Amoco  Canada's  law  firm  to  continue  to  represent  Amoco  in the
Kotaneelee lawsuit.  The Company expects to appeal this decision.



<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 21, 1997                   By /s/ Charles J. Horne
-----------------------------------        --------------------
                                           Charles J. Horne
                                           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.


/s/ Charles J. Horne                       /s/ Beverley A. Scobie
Charles J. Horne, President                Beverley A. Scobie, Treasurer,
and Director                               Chief Financial and Accounting
                                           Officer


Dated: March 21, 1997                      Dated: March 21, 1997
-------------------------------------      ---------------------


/s/ Benjamin W. Heath                      /s/ M. Anthony Ashton
Benjamin W. Heath, Director                M. Anthony Ashton, Director


Dated: March 21, 1997                      Dated: March 21, 1997
-------------------------------------      ---------------------


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


Dated:                                     Dated: March 21, 1997


<PAGE>