|UNITED STATES                     
|----------------------------------
|SECURITIES AND EXCHANGE COMMISSION
|WASHINGTON, D.C. 20549            
|FORM 10-K                         
|(Mark One)                        



|[X] | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|--- | ------------------------------------------------------------------------------------
|    | For the fiscal year ended December 31, 2003

OR                                     



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





|For the transition period from  to                                                                                     
|-----------------------------------------------------------------------------------------------------------------------
|Commission file number 001-03793

CANADA SOUTHERN PETROLEUM LTD.
(Exact name of registrant as specified in its charter)
|NOVA SCOTIA, CANADA                                                                                                    
|State or other jurisdiction of incorporation or organization                                                           
|#250, 706 - 7th Avenue, S.W.,
Calgary, Alberta, CANADA                                                                 
|(Address of principal executive offices)                                                                               
|                                                                                                                       
|Registrants telephone number, including area code                                                                     
|                                                                                                                       
|Securities registered pursuant to Section 12(b) of the Act:                                                            
|Title of each class                                                                                                    
|Limited Voting Shares, $1 (Canadian) per share                                                                         
|Securities registered pursuant to Section 12(g) of the Act:                                                            
|Limited Voting Shares, $1 (Canadian) per share                                                                         

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       o  No



Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§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



Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). o  Yes       x  No



The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately U.S. $66,321,742 at June 30, 2003.



(APPLICABLE ONLY TO CORPORATE REGISTRANTS)



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



Limited Voting Shares, par value $1.00 (Canadian) per share, 14,417,770 shares outstanding as of March 10, 2004.



DOCUMENTS INCORPORATED BY REFERENCE



Proxy Statement of Canada Southern Petroleum Ltd. related to the Annual Meeting of Shareholders for the year ended December 31, 2003, which is incorporated into Part III of this Form 10-K.

TABLE OF CONTENTS



Page



PART I



Item 1.

Business

4



Item 2.

Properties

20



Item 3.

Legal Proceedings

24



Item 4.

Submission of Matters to a Vote of Security Holders

27



PART II



Item 5.

Market for Canada Southern Petroleum Ltd. Limited Voting Shares and



Related Stockholder Matters

28



Item 6.

Selected Financial Data

30



Item 7.

Management's Discussion and Analysis of Financial Condition



and Results of Operations

31



Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

48



Item 8.

Financial Statements and Supplementary Data

49



Item 9.

Changes in and Disagreements with Accountants on

Accounting and Financial Disclosure

78



Item 9A.

Controls and Procedures

78



PART III



Item 10.

Directors and Executive Officers of Canada Southern

80



Item 11.

Executive Compensation

80



Item 12.

Security Ownership of Certain Beneficial Owners and Management

and Related Stockholder Matters

80



Item 13.

Certain Relationships and Related Transactions

81



Item 14.

Principal Accountant Fees and Services

81



PART IV



Item 15.

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

81



___________________________

Unless otherwise indicated, all dollar figures set forth are expressed in Canadian currency.  The exchange rate at March 10, 2004 was $1.00 Canadian = U.S. $0.7573.





PART I



Item 1.

Business



The nature of Canada Southern Petroleum Ltd.s business is described in Item 1(c) herein, and a description of its principal natural gas properties in Canada appears in Item 2 herein.  For additional information regarding the development of the business, see Item 1(a) and Item 2, Properties and Item 8, Supplemental Information on Oil and Gas Producing Activities.



(a)

General Development of Business



Yukon Territory - The Kotaneelee Field



The principal asset of Canada Southern Petroleum Ltd. (Canada Southern or the Company) is a 30.67% carried interest in the Kotaneelee Exploration Ex-Permit 1007 in the Yukon Territory, Canada.



On May 17, 1989, Permit 1007 was converted by the Yukon Government into 5 leases for a 21 year term, which expire on May 16, 2010.  Unproductive acreage may expire at the end of the lease term.  Canada Southern has held an interest in the 30,260 gross acres since 1957.



Canada Southern discovered the natural gas field in 1963 with the drilling of well I-27.



Six wells have been drilled on the property: two producing natural gas wells, one salt water disposal well and three abandoned wells.  Of the three abandoned wells, two were abandoned due to down-hole mechanical problems.  Government records indicate that the length of drilling time for these wells (from spud to rig release date) ranged from 198 to 526 days.



The two productive wells (B-38 and I-48) are producing from the Nahanni Formation. This formation is located approximately 12,000 feet below the surface and is characterized as being a low porosity, low permeability carbonate.  The prolific production is the result of a complex system of fractures within the reservoir.  The B-38 well was drilled in 1977 (drilling time of 198 days), penetrated 234 feet of net pay and had a maximum calculated natural gas flow of 265 million cubic feet (Mmcf) per day.  The I-48 well, drilled in 1980 (drilling time of 358 days), encountered 470 feet of net gas pay and tested a maximum calculated natural gas flow of 450 Mmcf per day.



Pursuant to 1966 and 1977 agreements, Canada Southern converted its interest into the carried interest position that it holds today.  As a carried interest owner, Canada Southern is entitled to receive its net share of field revenues after the working interest owners recover all of their capital and operating costs (i.e., upon the field reaching payout).



Under carried interest agreements, all of the operating decisions are effectively the responsibility of the working interest partners.  Canada Southern, at its option, may convert from a carried to a working interest position in the field.  Under the present payout status, Canada Southern would not be required to make any payments to the working interest owners to convert.  If however, field expenses were to exceed revenues for any reason, Canada Southern would be required to make payment to the payout account prior to converting.  Upon conversion, Canada Southern would have a 30.67% working interest in the field, and related facilities.  Although conversion would result in greater control over the Companys largest asset, other considerations include responsibility for marketing and transportation arrangements, and the requirement to fund future field development expenses as they occur.  Canada Southern continues to consider these factors in determining when, or if, it will convert to a working interest.



Although the Kotaneelee field sporadically produced a total of 1.6 BCF (billion cubic feet) of natural gas over 10 months between 1979 and 1981, continuous production commenced in February 1991.  According to government reports, gross yearly gas and water production (in Mbbls: thousands of barrels) from the Kotaneelee natural gas field since 1991 has been as follows:



|Calendar Year | Natural Gas Production (Bcf) | Water Production (Mbbls)
|------------- | ---------------------------- | ------------------------
|1991          | 8.1                          | 43                      
|1992          | 18.0                         | 90                      
|1993          | 17.5                         | 89                      
|1994          | 16.7                         | 90                      
|1995          | 15.7                         | 90                      
|1996          | 15.2                         | 85                      
|1997          | 14.4                         | 84                      
|1998          | 16.0                         | 98                      
|1999          | 22.3                         | 148                     
|2000          | 20.2                         | 143                     
|2001          | 16.9                         | 206                     
|2002          | 13.1                         | 370                     
|2003          | 9.1                          | 530                     
|Total         | 203.2                        | 2,066                   



The gross production from the field for the month of December 2003 was approximately 21.6 Mmcf per day (7.9 Mmcf per day from B-38 and 13.7 Mmcf per day from I-48).  Gross natural gas sales from both wells were approximately 16.8 Mmcf per day for the month of December 2003.



Natural gas sales from the Kotaneelee field are approximately 78% of total monthly production due to shrinkage and fuel gas requirements.



Water production has increased since 2001.  The operator improved the water handling capabilities of the surface equipment during the first quarter of 2002.  Water production continues to increase and water handling capacity continues to be a concern.  Natural gas production continues to decline as the reservoir pressure declines.  Water production will at some point become a constraining factor on gas production.  The Company is not able to predict with certainty the remaining economic life of the existing producing wells, their associated production profiles and the extent to which these wells will be able to access proven developed reserves.



Gross water production from each Kotaneelee well for the month of December 2003 was 1,427 bbs per day from the B-38 well and 161 bbls per day from the I-48 well (water production in December 2002  B-38 was 1,153 bbls per day and the I-48 was 120 bbls per day).



On January 19, 2001, Canada Southerns carried interest account in the Kotaneelee field reached undisputed payout status.  During the second quarter of 2001, Canada Southern began receiving its share of net proceeds from the field and accordingly commenced reporting its share of revenues.  Canada Southern has recorded net proceeds as follows:



|Calendar Year | Net Proceeds from Carried Interests | Production Period Recognized in Revenue
|------------- | ----------------------------------- | ---------------------------------------
|2001          | $12,548,697                         | January 20, 2001 to November 30, 2001  
|2002          | 7,193,686                           | December 1, 2001 to November 30, 2002  
|2003          | 8,742,080                           | December 1, 2002 to November 30, 2003  
|              |                                     |                                        



Because of uncertainties as to production rates, natural gas prices and future capital expenditures, Canada Southern is unable to accurately predict the amount of future net proceeds that it may receive from the field.



Canada Southern was a plaintiff in a lengthy litigation related to the Kotaneelee field, the settlement of which occurred in September 2003 (for details on the litigation see Item 3. Legal Proceedings of the Companys Annual Report on Form 10-K dated March 27, 2003, as amended by the Companys Form 10-K/A dated April 30, 2003).



Future Development of Kotaneelee



For many years, the Company believed that any future development of the field would not occur until the litigation concerning the field was concluded.  As a result of resolution of the litigation, it appears that the working interest owners may be willing to consider further development of the field.  An indicator of that motivation is the 23.6 kilometers (km) (14.7 miles) of 2-D seismic acquired by the operator in September 2003.



In December 2003, costs associated with the acquisition of this seismic data were charged to the carried interest account and these data were received by the Company in January 2004.  Upon receipt of this seismic data, the Company retained external geological, geophysical and engineering consultants for the task of reevaluating the fields exploration and development potential.  This reevaluation includes, among other things, reprocessing certain of the previously shot seismic data (currently all in its original form) in an attempt to enhance data quality through modern data processing technologies.  This reevaluation is expected to be completed by the end of May 2004.



Previous interpretations suggested that there were opportunities for additional drilling and proven reserves on the Kotaneelee block.  The Company believes that the geophysical data reprocessing now underway and subsequent reinterpretation may provide an indicator of such additional drilling and reserves potential.  Notwithstanding the results of the geophysical interpretation it is only through the drilling of additional wells that definitive information of this complex area can be obtained.



Risk Factors in Future Development of the Kotaneelee Field



Based on previous production data, there is no question that the Kotaneelee field has been a significant natural gas producer.  When, or if, future wells are drilled on the property, and whether new wells will tap additional economic reserves, is uncertain.  Although the Company is optimistic that additional wells will be drilled, investors are cautioned that further exploration and development of this block also comes at a significant capital cost and with significant risks.  Certain of these risks are as follows:



Geophysical risk:

With only six wells drilled over the entire 30,260 acres and extremely rugged surface topography, the quality of the older seismic data is very poor.  This in combination with the subsurface faulting and the very complex structures in this mountain terrain, provides for extremely challenging interpretations of the seismic data.  As such, any seismic interpretation is at risk of being inaccurate.



Geological risk:

The Nahanni Formation, the producing geologic zone at Kotaneelee, is very complex.  A new well could encounter the structure, but be drilled in an area where the fracture system believed to assist in natural gas production might not be present.



Production risk:

Assuming that a commercial reservoir of natural gas is encountered, and that a well is placed on production, the risk of water interfering with the operation of the well may prevent the production of a portion of the gas reserves in place. In all natural gas and oil fields, producers do not expect to recover all of the hydrocarbons in place.



Cost risk:

Factors such as subsurface faulting and fracturing could result in significantly longer drilling times than budgeted.  Additional drilling time typically equates to additional costs, which could be significant.



Future Yukon Land Sales



The Yukon Territory covers 483,450 square km (186,660 square miles) where a total of only 71 wells have been drilled to date.  Canada Southern currently has interests in the only two producing gas wells in the entire Yukon.  The Yukon Government assumed responsibility for its oil and gas resources in 1998 and has now established a regime which is intended to facilitate and promote new oil and gas exploration and development.  To achieve that goal, the Yukon Government is in the process of attempting to settle native land claims prior to granting mineral leases for the exploration of natural gas and oil.  Although the Yukon Government has achieved significant success in resolving these land claim disputes, settlement on lands surrounding Kotaneelee has yet to occur.  Once these land claims have been settled, Canada Southern understands that the Yukon Government intends to offer for sale the Petroleum and Natural Gas (P&NG) rights on acreage surrounding the Kotaneelee field.  Given the production from the Kotaneelee field, Canada Southern expects competition to be intense for control of this exploratory acreage.



British Columbia - Properties



Prior to the Kotaneelee field reaching undisputed payout status, Canada Southerns principal source of income has been from the sale of natural gas and associated liquids from properties located in northeast British Columbia.  Effective January 1, 2001, Canada Southern converted its carried interests in northeast British Columbia (including the areas of Buick Creek, Wargen, Clarke Lake, and Ekwan) to working interests.  Effective April 1, 2001, Canada Southern converted its carried interest in the Siphon area to a working interest.  The Company converted to working interest positions in an attempt to gain greater control of these assets.



Conversion issues



The conversion from carried to working interest at Buick Creek, Siphon and Wargen created an issue with respect to facility ownership.  When development of these properties occurred, the operators charged certain facility and pipeline infrastructure construction costs to the carried interest account.  As a result of payout and conversion, Canada Southern has paid for and therefore believed it should be recognized as an owner of these facilities.  Ownership interest in facilities has both strategic and economic benefits.



Commencing in 2001, Canada Southern approached the current operators to discuss its ownership rights in the Siphon, Buick Creek and Wargen facilities.



Subsequent to much discussion on the issue, Canada Southern became recognized as a 22.5% owner of the Siphon and Buick Creek facilities on April 7, 2003 and June 27, 2003, respectively.  Discussions with the operator at Wargen are ongoing and are expected to be completed in 2004.



Withheld revenue issue



In 2000, the operator of the carried interest properties at Buick Creek, Wargen and Clarke Lake in British Columbia withheld approximately $1,081,000 in payments from the carried interest account to recover an amount claimed to have been overpaid to Canada Southern in prior years.  Canada Southern disagrees with the operators position and is attempting to settle the dispute.  In accordance with the Companys accounting policies, no recovery of the disputed amount has been recorded.  The resolution of this issue has been delayed by the completion of the interrelated Wargen facility issue as discussed in a preceding paragraph.  Canada Southern expects to resolve this issue during 2004.



Siphon:



Canada Southern holds 7,600 gross (2,755 net) acres of certain mineral rights for an average 36% working interest in a natural gas field at Siphon.  The Company has owned its interest in certain of these lands since the early 1950s.  Canada Southern was formally recognized as a 22.5% working interest owner of the Siphon facilities on April 7, 2003.



In 2003, Canada Southerns share of sales averaged 358 mcf per day of natural gas and 4 bbls per day of natural gas liquids (2002  459 mcf per day of natural gas and 4 bbls per day of liquids respectively).



Siphon has been, and is currently an area of focus for the Company.  The area has multiple potentially productive zones and underutilized Company-owned processing facilities making it an attractive candidate for development.  During 2003, Canada Southern acquired the mineral rights to 1,600 acres of land at 100% working interest, acquired 63 kms (39 miles) of trade 2-D seismic and 3.4 square kms (2.15 square miles) of trade 3-D seismic in the area.



Canada Southern drilled and cased a 100% working interest well to a depth of 1,803 meters (5,915 feet) at 13-15-86-16W6M during December 2003.  Zones of interest include formations in the Permian, Triassic and Cretaceous intervals.  Due to extreme industry demand for services, the Company was unable to secure the equipment necessary for completion and testing of this well until mid-March.  The Belloy interval has been perforated, however efforts to fracture stimulate this zone have proved unsuccessful.  The Belloy interval will be abandoned prior to moving up hole to attempt completion of the Baldonnel formation.



The Company has acquired additional land in the area in 2004 and is currently evaluating two additional seismically identified prospects.  Depending upon results of those evaluations, Canada Southern may drill additional wells in the area in 2004.



Mike/Hazel:



Canada Southern currently holds 3,511 acres of 100% working interest undeveloped lands in the Mike/Hazel area of N.E. British Columbia.  A portion of these leases will start to expire in the near future.  In order to properly evaluate this land prior to expiry, Canada Southern, commencing in December 2003 (and completed in early February 2004), shot a 70 sq. km (27 sq. mile) 3-D seismic survey over area lands.  This seismic program, budgeted to cost $2,200,000, was acquired at a 100% proprietary interest.  Canada Southern owns the only copy of the survey and may, at its option, offer to sell licensed trade copies to industry partners.  The Company took possession of the processed seismic data in the first week of March.  Interpretation of this data is almost complete.  Should the interpretation indicate potential hydrocarbon reservoirs underlying Company lands, the Company intends to drill in the area during the winter drilling season of 2004/2005.  This land is not economically accessible during the summer months.



Buick Creek:



Canada Southern owns an average 22.5% working interest in a producing natural gas property at Buick Creek through its mineral lease of 22,498 gross (4,854 net) acres. The Company has owned an interest in this field from the date of its original development in the 1950s.  This field currently contains 14 natural gas wells mainly producing from the Dunlevy Formation.  In 2003, Canada Southerns share of gross sales from this field averaged 1,094 thousand cubic feet (mcf) per day of natural gas and 20 barrels (bbls) per day of natural gas liquids (2002  867 mcf per day of natural gas, and 16 bbls per day of liquids respectively).



The facility ownership issue at Buick Creek was resolved on June 27, 2003.  Canada Southern became responsible for its share of costs related to facility improvements that occurred in December 2001 by paying approximately $882,000, as well as $107,000 for repairs to the facility in 2002, and $365,000 for facility operating cost adjustments from January 1, 2001 to June 30, 2003.



In March 2004, the Company participated, as to its 11.25% working interest, in the drilling of a well in the Buick Creek area.  The well was cased and is currently awaiting completion.



Canada Southern has interests in 9,738 gross (2,151 net) undeveloped acres at Buick Creek.



Wargen:



At December 31, 2003, Canada Southern held 6,895 gross (1,237 net) working interest acres in the Wargen natural gas field for an average 18% working interest, of which 1,400 gross (315 net) acres were undeveloped.  Although the Company has held its interest in certain of these lands since 1952, the initial discovery was made in 1960 with further development between 1968 and 1988.  Sales from this area averaged 309 mcf of gas per day and 6 bbls per day of natural gas liquids during the year 2003 (2002  328 mcf per day and 7 bbls per day of liquids).



In December 2002, Canada Southern participated (22.5% working interest) in the acquisition of a wellhead screw compressor at D-56-C/94-H-6.  The compressor improved the wells gross production from approximately 300 mcf per day to 700 mcf per day (with the well currently producing approximately 500 mcf per day).



Further to a review of field production data, Canada Southern approached the fields operator and discussed the potential benefits of wellhead compression for additional wells in the area.  Late in the third quarter of 2003, wellhead compression was added to C-58-C/94-H-6, and increased the wells production from approximately 120 to 475 mcf per day.



In December 2002, Canada Southern acquired certain 3-D seismic coverage over a portion of its lands at Wargen.  Upon completion of technical analysis of the seismic and in combination with a competitors recent dry hole in the immediate vicinity, Canada Southern determined that the risk of drilling a deep (3,200 meter, 10,500 feet) and expensive exploratory Slave Point test well was too great.  The P&NG rights held on these lands have since expired.



In October 2001, Canada Southern farmed out its 50% working interest in 1,397 gross acres of exploratory acreage in the Wargen area to an industry partner.  The farmee paid 100% of the capital costs to drill two wells on the lands and Canada Southern retained a 7.5% gross overriding royalty on the wells production, which is convertible at payout (at the Companys option) to a 20% working interest.  The operator placed one of the wells on production in March 2002.  Based on internal estimates, Canada Southern expects that this well will payout in 2005.  The second well was completed and tested during the winter of 2002/2003 and remains non-producing.



Clarke Lake:



Canada Southern owns a 15% average working interest in 3,370 gross (518 net) acres in the Clarke Lake area.  The Company has owned an interest in these mineral rights since the early 1950s.  Field activity over the last 2 years has increased Company production in the area. Sales from this area averaged 172 mcf of gas per day during the year 2003 (2002  96 mcf per day).



During the third quarter of 2002, Canada Southern participated (22.5% working interest) in the temporary repair of the A-61-F/94-J-10 well.  This well had been suspended since 1978, due to a suspected hole in the casing, but had produced over 47 BCF of natural gas from the Slave Point Formation.  In February 2003, Canada Southern participated in the completion of the down-hole repair and testing of this well.  The down-hole repair and production test was successfully completed in late February 2003 and resulted in gross restricted natural gas test rates of 1.1 Mmcf per day.  This well was equipped during mid 2003 and was placed on production in September 2003 at approximately 500 mcf per day.



In the fall of 2002, Canada Southern participated in the re-activation of a previously suspended 22.5% working interest natural gas well located at C-54-F/94-J-10.  During December 2002, the reactivation resulted in the increase of the fields gross production by 380 mcf per day (a production rate that has remained relatively consistent over the past year).



Other:



Canada Southern has other P&NG leases in northeast British Columbia that are being evaluated.  At December 31, 2003, Canada Southern held interests in 4,494 gross (752 net) developed acres and 9,312 gross (7,915 net) undeveloped acres in these leases.  Canada Southern has made attempts to farm out certain of these lands to industry partners, without success, and as a result, leases for certain of these lands will expire during 2004.



As of December 31, 2003, the only remaining convertible carried interest property located in British Columbia was in the Highway area.  Canada Southern holds a 50% net profits interest in the property which is convertible into a 50% working interest.  The Highway prospect is currently non-producing with approximately $4 million of capital costs that must be recovered before any payout to Canada Southern.  At present, the Highway prospect is not expected to be placed on production, nor is payout expected to occur in the foreseeable future.

Alberta - Properties

Canada Southern currently holds a working interest in 6,091 developed (2,567 net) acres and 7,781 gross (6,036 net) undeveloped acres in Alberta.



40 Mile Coulee:



In 2003, Canada Southern acquired the mineral rights to 6,880 contiguous acres of 100% working interest land in southern Alberta.  Southern Alberta is well known for shallow natural gas production.  Canada Southern acquired these lands as a low risk entry into southern Alberta.



In late October 2003, the Company drilled and cased the first 3 shallow natural gas wells in this project area.  The wells were fracture stimulated, tested and are currently awaiting construction of the pipeline and facilities infrastructure.  Of the three wells drilled, two were drilled to the Second White Specks (2WS) Formation (650 meters or 2,133 feet), while the third well was drilled to the deeper Sawtooth Formation (950 meters or 3,117 feet).  Although initial results from the deeper test were promising, extended testing determined that the arial extent of the pool was limited.  Subsequent to abandonment of the Sawtooth Formation, the Company moved uphole and completed and tested the 2WS.  Test results on the 2WS zone for the three wells were 81, 79, and 46 mcf per day respectively.



Based upon the relatively low productivity test results of the three wells, additional drilling success in the project area will be required prior to justifying the capital commitment to build pipelines and facilities.



In December 2003, the Company shot 31.2 km (19.5 miles) of 100% interest proprietary 2-D seismic over Company lands.  This seismic was shot to identify possible deeper and economically more attractive horizons than the 2WS.  Interpretation of this seismic is nearing completion.  Should interpretation suggest potentially prospective zones, the Company would likely drill a well or wells in the area during 2004.  If these wells are successful, the Company could accelerate the construction of facilities and pipeline infrastructure, and drill additional wells in the area.  If either the seismic provides no leads or a deeper test is unsuccessful, the Company may redirect funds to other projects and delay further development of this field.  In this circumstance, development could recommence once pipeline infrastructure moves closer to Company lands.



Canada Southern is considering becoming more active in the Province of Alberta.



Arctic Islands - Properties

As of December 31, 2003, Canada Southern held working interests in 45,100 gross acres and carried interests in 133,260 gross acres in the Sverdrup Basin, located in the Arctic Islands.  An estimated summary of the Companys ownership interests in Arctic Island lands is as follows:

|               | Acreage | Canada Southern Ownership Interest
|-------------- | ------- | ----------------------------------
|Property name  | Gross   | Net *                             
|Bent Horn      | 4,590   | 230                               
|Drake Point    | 9,112   | 568                               
|Drake Point    | 757     | 227                               
|Hecla          | 114,135 | 34,241                            
|Kristoffer Bay | 2,638   | 132                               
|Roche          | 1,495   | 45                                
|Romulus        | 6,095   | 914                               
|Whitefish      | 2,163   | 137                               
|Whitefish      | 32,330  | 1,066                             
|Whitefish      | 5,045   | 1,514                             
|Total          | 178,360 | 39,074                            



* For purposes of the preceding table, net carried interest acres were determined on an after conversion to working interest basis as until payout is reached the Company is not entitled to any cash flows from the property.



To promote drilling in Canadas north, during the 1980s, the Canadian Federal Government provided incentives to oil and gas companies to explore for hydrocarbons.  One such incentive enabled companies to hold acreage by deeming to have achieved Significant Discovery status.  If exploratory wells were drilled and resulted in the discovery of oil or gas, the interest in these lands would be continued for an extended period of time pending future development.  The Canadian Federal Government has designated the Bent Horn, Drake Point, Hecla, Kristoffer Bay, Roche Point, Romulus and Whitefish fields as Significant Discovery Lands.



Panarctic Oils Ltd., the operator, received Federal government regulatory approvals for a pilot project to move shipments of crude oil from the Bent Horn field by tanker through the Northwest Passage to southern Canada in 1985.  Through December 31, 1996, approximately 2.7 million barrels of Bent Horn crude had been sold. In 1996, the operator shut down production from the field and dismantled the production facilities because of economic uncertainties.  Canada Southern owns a 5% carried interest in Bent Horn, which has not yet reached payout status.  The timing of payout is uncertain.



Canada Southern expects that minimal exploration, development and production activity will occur in the Arctic region over the foreseeable future.



Canada Southern has over 4,800 kilometers (1,853 miles) of 2-D seismic data covering certain areas of the Arctic.



Northwest Territories - Properties



Canada Southern owns a 45% carried interest in 1,613 gross acres in the Celibeta field located in the Northwest Territories.  This field (ex-permit 2713) was designated as a Significant Discovery Land by the Federal Government.  There is no current activity on this land and it has not paid out.  Future development of this shut-in gas field is at the discretion of the operator.



Saskatchewan - Properties



Canada Southern currently holds a 79.4% working interest in a shut-in natural gas well and 1,280 gross acres in the Little Pine area of Saskatchewan.  Industry competitors have become more active in the area.  Depending on gas pricing and other economic considerations, it may become economic for Canada Southern to place its presently shut-in gas well on production.



United States - Properties



Canada Southern does not hold any direct interests in oil and gas properties in the United States, and has no plans to do so in the immediate future.



1(b)

Financial Information about Industry Segments



Since Canada Southern is primarily engaged in only one industry, oil and gas exploration and development, this item is not applicable.  See Item 8  Financial Statements and Supplemental Data for financial information concerning Canada Southern.



1(c)

Narrative Description of the Business



Canada Southern was incorporated in 1954 under the Canada Corporations Act.  In 1979, Canada Southern became subject to the Canadian Business Corporations Act, and in 1980, was continued under the Nova Scotia Companies Act.  Canada Southern currently has two wholly owned subsidiaries; Canpet Inc. and CS Petroleum Ltd. both of which are currently inactive.



The Companys corporate headquarters are located at suite 250, 706  7th Avenue SW, Calgary, Alberta, Canada, T2P 0Z1, where the telephone number is (403) 269-7741.  The Companys website address is "www.cansopet.com."



The Company's annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports are made available free of charge through either the Investor Relations, Financials, SEC Filings or SEDAR filings section of the Company's Internet website (www.cansopet.com) as soon as practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (website address - www.sec.gov) and Canadian Regulatory Authorities (website address - www.sedar.com).



Canada Southern is engaged in the exploration for and development of properties containing or believed to contain recoverable natural gas and oil reserves and the sale of natural gas and oil from these properties. Although many of the properties in which Canada Southern has interests are undeveloped, all properties with proved reserves are partially or fully developed.  Canada Southerns interests in exploratory ventures are on properties located in Alberta, British Columbia, Saskatchewan, the Northwest and Yukon Territories and the Arctic Islands in Canada.  Canada Southerns principal asset is its 30.67% carried interest in the Kotaneelee field, a producing natural gas field in the Yukon Territory.



Canada Southern also has interests in producing properties in British Columbia.



(i)

Principal Products

The principal source of Canada Southerns revenue is derived from carried interest proceeds from the Kotaneelee natural gas field.  Canada Southern also receives revenue from the sale of natural gas and associated liquids derived from its working interests in other areas.



(ii)

Status of Product or Segment

At present, certain of the properties in which Canada Southern has interests are undeveloped and/or non-producing.



(iii)

Raw Materials

Not applicable.



(iv)

Patents, Licenses, Franchises and Concessions Held

Permits, concessions and mineral leases are important to Canada Southerns operations, and form the necessary vehicle for the continuing effort of searching for and extraction of any natural gas and crude oil discovered on the areas covered.  See the schedule of properties under Item 2 - "Properties."



(v)

Seasonality of Business

Canada Southerns business is not seasonal, however the price received for natural gas sales generally increases during periods of increased consumer demand (i.e. the winter heating season).  Exploration and development activities are restricted in certain areas on a seasonal basis.  In certain areas, field access with heavy equipment is only possible during the winter months due to the presence of muskeg and the lack of developed road infrastructure.  In northern regions, extreme weather conditions affect transportation and the ability to pursue these activities.



(vi)

Working Capital Items



Not applicable.



(vii)

Customers



Currently, Canada Southern allows its partners to market its production.  Payments of the net carried interest revenues from the Kotaneelee field are received from BP Canada Energy Company, Devon Canada, Imperial Oil Resources and ExxonMobil Canada Properties.  Canada Southern receives its revenue from the following operators of its working interest properties: Samson Canada Resources, Anadarko Canada Corporation, Devon Canada and Petro-Canada Oil and Gas.



(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 natural gas and crude oil are highly competitive operations, both internally within the oil and gas industry and externally with producers of other types of energy.  The ability to exploit a discovery of crude oil or natural gas is dependent upon considerations such as the ability to finance development costs, the availability of equipment, and the ability to overcome engineering and construction delays and difficulties.  Canada Southern competes with companies which have substantially greater resources available to them.  Because the majority of Canada Southerns interests are in remote areas, operation of Canada Southerns properties is more difficult and costly than those in more accessible areas.  Furthermore, competitive conditions may be substantially affected by energy legislation in Canada.



(xi)

Research and Development



Not applicable.



(xii)

Environmental Regulation



See Environmental Regulation and Kyoto Accord in Item 1(d).



(xiii)

Number of Persons Employed by Canada Southern



Canada Southern currently has four full time employees, all of whom are located in Canada.  Canada Southern relies to a great extent on consultants (approximately 6) for engineering, land, geological, geophysical, and legal services because it is currently more cost effective than employing a larger full time staff.

1(d)

Financial Information about Foreign and Domestic Operations

and Export Sales



(1)

Revenues, Operating Income and Identifiable Assets



Canada Southerns operating assets and revenues are attributable to its operations in Canada.



(2)

Risks Attendant to Foreign Operations



The properties in which Canada Southern has interests are located in Canada and for U.S. investors would be subject to certain risks involved in the ownership and development of such foreign property interests.  These risks include but are not limited to those of: nationalization; expropriation; confiscatory taxation; native rights; changes in foreign exchange controls; currency fluctuations; burdensome royalty terms; export sales restrictions and other laws and regulations which may adversely affect Canada Southerns interests in these properties, such as those providing for conversion, proration, curtailment, cessation or other forms of limiting or controlling production of, or exploration for, hydrocarbons.



Land Tenure

The respective provincial and territorial governments own, for the most part, the crude oil and natural gas mineral rights located in the western portion of Canada. Governments grant mineral rights to explore for and produce crude oil and natural gas pursuant to leases, licenses and permits (termed Crown) for varying terms.  In certain cases, permit terms and conditions set forth in regulatory legislation may include the requirement of work commitments.  Crude oil and natural gas located in such provinces can also be privately owned (termed freehold) and rights to explore for and produce such hydrocarbons are granted by lease on such terms and conditions as may be negotiated individually with the mineral owner.  The term of both Crown and freehold leases will generally continue as long as crude oil or natural gas is produced from the property.



Crude oil and natural gas mineral rights on federal lands are generally regulated by the Government of Canada unless authority has been delegated to a territorial or provincial government.  In May 1993, the Canada Yukon Oil and Gas Accord was signed which allowed for the transfer to the Yukon Government of authority to administer and control hydrocarbon resources within that territory and for the establishment of an Oil and Gas Management Regime.  The transfer has now been completed.



Canada Southern is facing the expiry of certain of its leasehold mineral rights.  In the Petitot area of north east British Columbia, mineral leases totaling 5,208 acres (gross and net) expired in early 2004.



Production and Production Facilities

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



Pricing and Marketing - Natural Gas



In Canada, the price of natural gas is determined by negotiation between buyers and sellers, with the result that the market determines the price of natural gas.  Natural gas exported from Canada is subject to regulation by the National Energy Board (NEB).  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.  As is the case with crude oil, natural gas exports for a term of less than two years must be made pursuant to an NEB order or, in the case of exports for a longer duration, pursuant to an NEB license and Governor in Council approval.



Pricing and Marketing - Crude oil

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



Royalties and Incentives



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



From time to time the Governments of Canada, Alberta, British Columbia and Saskatchewan have established incentive programs, which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging natural gas and crude oil exploration, or enhanced recovery projects.  Incentives are intended to enhance the cash flow of the crude oil and natural gas industry and to improve the economics of finding and developing new and more costly crude oil and natural gas reserves. 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.



One such recent program was announced in December of 2003 by the Province of British Columbia, whereby a royalty holiday is available for new wells drilled between 2004 and 2009 to a depth deeper than 2,500 meters (8,202 feet).  Another such related British Columbia incentive program provides for a drilling rebate of up to a maximum $100,000 for wells drilled between April 1 and November 30, 2004.  Canada Southern believes it is well positioned to take advantage of both of these incentive programs.



Environmental Regulation



The Canadian oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation.  Environmental legislation provides for restrictions and prohibitions on spills, releases or emissions of various substances produced in association with certain crude oil and natural gas industry operations.  An environmental assessment and review may be required prior to initiating exploration or development projects or undertaking significant changes to existing projects.  In addition, legislation requires that well and facility sites are 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.  Canada Southern 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.  To date, Canada Southern has not been required to spend significant sums to comply with clean up laws and regulations.  However, as a part of the settlement of the Kotaneelee litigation, Canada Southern had agreed to assume a 30.67% in the environmental site restoration and site reclamation costs for the Kotaneelee field when the field has ceased production and has been abandoned.  Canada Southerns compliance with governmental provisions regulating the discharge of materials into the environment or otherwise relating to the protection of the environment is not expected to have a material effect on its capital expenditures, earnings or competitive position.



Kyoto Accord



The Kyoto Accord is an international agreement created by the United Nations.  Its goal is for developed countries to reduce greenhouse gas emissions by an average 5.2% below 1990 levels, by 2012.  Greenhouse gas emissions are carbon-based gases  mainly carbon dioxide, nitrous oxide and methane.  As of August 20, 2002, 89 countries have ratified the Kyoto Accord.  Although the Unites States does not support the Accord, Canada agreed to participate in December 2002.  Under the Kyoto Accord, Canada agreed to reduce its greenhouse gas emissions by 6% below 1990 levels by 2012.  The mechanics of how Canada intends to meet these emission reductions and the impact on the oil and gas sector is currently unclear.  Given that almost all of Canada Southerns production is natural gas (the cleanest burning fossil fuel), any adverse impact of the Kyoto Accord on the Company should be substantially less than that of other companies that produce both oil and gas.



(3)

Data Which are not Indicative of Current or Future Operations



Not applicable.



Item 2.

Properties



(1)

(a)

Canada Southerns principal asset is its 30.67% carried interest in the Kotaneelee field, a producing gas field in the Yukon Territory, Canada.  Canada Southern also has interests in producing properties in British Columbia.  Non-producing properties are located in British Columbia, Alberta, Saskatchewan, the Yukon and Northwest Territories and the Arctic Islands in Canada.  Canada Southern conducts geophysical, geological, engineering and drilling work on its properties.



(1)

(b)

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.



The following graphic presentation has been omitted, and will be included in the executive summary of the 2003 annual report.  The following is a description of the omitted material:



Map of Canada Southerns Areas of Leasehold Interests



The following graphic presentation has been omitted, and will be included in the executive summary of the 2003 annual report.  The following is a description of the omitted material:



Map of N.E. British Columbia and Yukon, Northwest Territories

showing Kotaneelee field



The following graphic presentation has been omitted, and will be included in the executive summary of the 2003 annual report.  The following is a description of the omitted material:



Map of the Canadian Arctic Islands

showing Canada Southerns Lease Holdings



(2)

Reserves Reported to Other Agencies



Not applicable.



(3)

Product Pricing and Production Costs



Average sales prices per unit and average production costs for oil and gas produced (for both carried and working interest properties) during the periods are shown below.  Production costs are allocated based on the weighted average of oil and gas sales. In 2003, 2002 and 2001 production was primarily natural gas and associated natural gas liquids.

|     |                     |                          |               |                  
|---- | ------------------- | ------------------------ | ------------- | -----------------
|     | Average Sales Price | Average Production Costs
|Year | Gas (per mcf)       | Liquids (per bbl)        | Gas (per mcf) | Liquids (per bbl)
|     | ($)                 | ($)                      | ($)           | ($)              
|2003 | 5.72                | 34.79                    | 0.80          | -                
|2002 | 3.58                | 29.01                    | 0.37          | -                
|2001 | 5.55                | 33.68                    | 0.74          | -                



(4)

Productive Wells



Productive wells on working and carried interest properties as of December 31, 2003, were as follows:



|                    | Gross Wells* | Net Wells*
|------------------- | ------------ | ----------
|                    | Gas          | Oil       
|Working interest    | 61           | 8         
|Carried interest ** | 6            | -         
|                    | 67           | 8         



* Gross wells means the total number of wells in which the Company has a working interest.  Net wells means the aggregate of the percentage working interest of each of the gross wells.

** Net carried interest wells are determined on an after conversion to working interest basis, as until payout is reached the Company is not entitled to any cash flows from the property.



Canada Southern also holds overriding royalty interests in 15 wells.



(5)

Total Acreage



According to Company records, total estimated developed and undeveloped mineral interests owned by Canada Southern as of December 31, 2003 is summarized by geographic area in the table below:



|                      | Working Interest | Carried Interest | Total  
|--------------------- | ---------------- | ---------------- | -------
|                      | Gross            | Net              | Gross  
|                      | Acres            | Acres            | Acres  
|Yukon                 | -                | -                | 27,078 
|British Columbia      | 25,953           | 15,087           | -      
|Artic Islands         | 43,820           | 1,777            | 130,700
|Alberta               | 7,781            | 6,036            | -      
|Saskatchewan          | 1,120            | 952              | -      
|Northwest Territories | -                | -                | 806    
|                      | 78,674           | 23,852           | 158,584



* For purposes of the preceding table, net carried interest acres are determined on an after conversion to working interest basis, as until payout is reached the Company is not entitled to any cash flows from the property.



(6)

Productive Acreage



According to Company records, estimated productive acreage on working and carried interest properties as of December 31, 2003, was as follows:



|                      | Working Interest | Carried Interest | Total      
|--------------------- | ---------------- | ---------------- | -----------
|                      | Gross
Acres      | Net
Acres        | Gross
Acres
|Yukon                 | -                | -                | 3,182      
|British Columbia      | 31,744           | 6,455            | 11,843     
|Arctic Islands        | 1,280            | 40               | 2,560      
|Alberta               | 6,091            | 2,567            | -          
|Saskatchewan          | 160              | 136              | -          
|Northwest Territories | -                | -                | 806        
|                      | 39,275           | 9,198            | 18,391     



* For purposes of the preceding table, net carried interest acres are determined on an after conversion to working interest basis, as until payout is reached the Company is not entitled to any cash flows from the property.



(7)

Undeveloped Acreage



According to Company records, total estimated undeveloped mineral interests held by Canada Southern as of December 31, 2003 is summarized by geographic area in the table below:

|                      | Working Interest | Carried Interest | Total      
|--------------------- | ---------------- | ---------------- | -----------
|                      | Gross
Acres      | Net
Acres        | Gross
Acres
|Yukon                 | -                | -                | 27,078     
|British Columbia      | 25,953           | 15,087           | -          
|Arctic Islands        | 43,820           | 1,777            | 130,700    
|Alberta               | 7,781            | 6,036            | -          
|Saskatchewan          | 1,120            | 952              | -          
|Northwest Territories | -                | -                | 806        
|                      | 78,674           | 23,852           | 158,584    





* For purposes of the preceding table, net carried interest acres are determined on an after conversion to working interest basis as until payout is reached the Company is not entitled to any cash flows from the property.



(8)

Royalty Interests



Apart from the ownership of wells and acreage described in 4, 5, 6, and 7 above, Canada Southern holds non-convertible royalty interests in 10 natural gas wells through its ownership of 3,564 gross acres.



(9)

Drilling Activity



Productive and dry wells drilled during the following periods:



|     | Gross      | Net
|---- | ---------- | ---
|Year | Productive | Dry
|2003 | 4          | -  
|2002 | -          | -  
|2001 | -          | -  





(10)

Average Sales Volumes



Comparative sales volumes in boes (barrel of oil equivalent) (where 6 mcf = 1 boe) from the Companys properties are as follows:



|              | Average Sales Volumes (boe/day)
|------------- | -------------------------------
|              | Year ended December 31,        
|Property name | 2003                           
|Kotaneelee    | 1,017                          
|Buick Creek   | 203                            
|Siphon        | 64                             
|Wargen        | 57                             
|Clarke Lake   | 29                             
|Ekwan         | 1                              
|Others        | 17                             
|Total         | 1,388                          



(11)

Present Activities



There were no wells drilling at December 31, 2003.



(12)

Delivery Commitments



None.



Item 3.

Legal Proceedings



Settlement of Kotaneelee Litigation



On September 9, 2003, the parties in the litigation concerning the Kotaneelee gas field entered into a comprehensive settlement agreement. (For details of the litigation see Item 3. Legal Proceedings, of the Companys Annual Report on Form 10-K dated March 27, 2003, as amended by the Companys Form 10-K/A dated April 30, 2003).



The settlement was finalized on October 3, 2003.  Pursuant to the settlement there has been a complete abandonment of the litigation, including the claim that the defendants failed to fully develop the field.



The Company realized a gross pre-income tax amount (net of certain related settlement costs: see Note 11 to the Consolidated Financial Statements) of $22,727,000 in the settlement, which amount represents a complete settlement of the litigation, including a recovery of the wrongfully withheld gas processing fees and related interest.  These proceeds constitute taxable income for Canadian income tax purposes upon receipt by the Company.



In connection with the settlement, Canada Southern acquired on October 31, 2003, from Perkins Holdings and Levcor International Inc., a 0.67% carried interest in Kotaneelee formerly held by Levcor, including the associated interest in the litigation.



Also in connection with the settlement, the Company agreed to be responsible for its share of abandonment and reclamation liabilities at the Kotaneelee field when they occur.  It is estimated that the Companys 30.67% share of the abandonment liabilities will amount to approximately $2,400,000.



The settlement agreement does not include any understandings with or commitments by the working interest owners to further develop the Kotaneelee field beyond those mechanisms for doing so contained in the 1959 agreement and subsequent amendments thereto.



Litigation Contingent Interests



In 1991, Canada Southern granted interests to the following officers, employees, directors, litigation counsel and consultants aggregating 7.8% (an additional .75% was granted in 1997 to litigation counsel) of any and all net recoveries from the defendants in the Kotaneelee gas field litigation due to the defendants failure to assure the earliest feasible development and marketing of gas and due to other failures:



|Holder                     | Relationship to Canada Southern at
Date of Grant | Net
Recovery Percentage
|-------------------------- | ------------------------------------------------ | -----------------------
|Robert J. Angerer          | Litigation Counsel                               | 2.00                   
|Reasoner, Davis & Fox      | Counsel                                          | 2.00                   
|Murtha Cullina LLP         | Securities Counsel                               | 1.00                   
|G&OD INC                  | Consultants                                      | 1.00                   
|J. Peter McMahon           | Litigation Counsel                               | 1.00                   
|V. D. MacDonald            | Litigation Counsel                               | .75                    
|Estate of Charles J. Horne | President                                        | .25                    
|Benjamin W. Heath          | Director                                         | .25                    
|Betsy F. Shaw              | Vice President                                   | .10                    
|Evelyn D. Scott            | Treasurer/Secretary                              | .10                    
|Angela N. Morar            | Accountant                                       | .10                    
|                           |                                                  | 8.55                   



Subsequent to the Kotaneelee litigation settlement, the Companys Board of Directors established a committee comprised solely of directors with no direct or indirect personal interest in the contingent interests.  This independent committee of directors, comprised of Messrs. Kanik, McGinity and Stewart, consulted with independent outside counsel with regard to what amounts, if any, were payable pursuant to the contingent interests.



In early October 2003, counsel to the independent committee advised each of the contingent interest grantees that the committee had concluded, based on advice of counsel, that there was no entitlement arising under such interests.



Mr. Arthur B. ODonnell (a director of Canada Southern since 1997), a beneficial holder of a 0.333% contingent interest (derived from G&OD Inc.), Mr. James R. Joyce, a beneficial holder of a 0.333% contingent interest (derived from G&OD Inc.), and Murtha Cullina LLP (Mr. Timothy L. Largay, a partner of the firm, has been a director of Canada Southern since 1997), a grantee of a 1.00% contingent interest, had each notified counsel to the committee of their agreement with the committees conclusion.



Prior to the conclusion of the independent committee that the contingent interest grantees had no entitlement arising under such interests, the Company had received communications from counsel representing the 2.0% contingent interest granted to C. Dean Reasoner asserting entitlements arising under such grants.



The following grantees, each of whom served as Kotaneelee litigation counsel to the Company, had advised the Company that they disagreed with the committees conclusion:



Robert J. Angerer, Sr., Esq.

2.00%

V. A. MacDonald, Esq.

0.75%

Peter McMahon, Esq.

1.00%



These grantees had asserted that the contingent interests applied to the withheld processing fees, production revenues from the field, and other alleged recoveries which could total more than $200,000,000.  The Company did not accept their position.



The Company was advised that certain contingent interest grantees had retained legal counsel to advise them on and pursue the matter with the Company.  The grantees who disputed the Companys position were as follows:



|Holder                     | Relationship to Canada Southern at
Date of Grant | Net
Recovery Percentage
|-------------------------- | ------------------------------------------------ | -----------------------
|Robert J. Angerer          | Litigation Counsel                               | 2.00                   
|Reasoner, Davis & Fox      | Counsel                                          | 2.00                   
|J. Peter McMahon           | Litigation Counsel                               | 1.00                   
|V. D. MacDonald            | Litigation Counsel                               | .75                    
|Estate of Charles J. Horne | President                                        | .25                    
|Benjamin W. Heath          | Director                                         | .25                    
|                           |                                                  | 6.25                   



In March 2004, in order to avoid a potentially prolonged, expensive and distracting litigation, the Company reached an agreement for an all-inclusive settlement with certain parties, including a former director and former litigation counsel to the Company, who were asserting claims of entitlement against the Companys net recoveries in the Kotaneelee litigation.  Under the terms of the settlement, which has been accrued in the Companys fourth quarter 2003 financial results, Canada Southern will pay these parties a total of $1,000,000 in return for a general release from the parties asserting the claims and an agreement by the Company not to seek an adjustment in the prior payments for professional services made to prior litigation counsel.



The independent committee of the Board, created to consider the matter of the contingent interests, remains of the view that there should be no entitlements under the contingent interest grants.  However, after lengthy consideration of the matter, involving continuous participation by outside counsel retained by the independent committee for this purpose, the independent committee reluctantly recommended that the Board of Directors approve the settlement summarized above.  It was the view of the independent committee and the Board of Directors that, on balance, the shareholders are better served by the Company focusing its human and financial resources on strategically repositioning Canada Southern rather than enduring the distraction of a potentially prolonged and expensive litigation the ultimate outcome of which could not be known with certainty.



Item 4.

Submission of Matters to a Vote of Security Holders



Not applicable.





Executive Officers of Canada Southern



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

Length of

Other Positions

Service

Held with

Name

Age

Office

in this Office

Canada Southern



Randy L. Denecky

40

Acting President

January 6, 2002

None

to present

Chief Financial and Accounting

November 7, 2001

None

Officer

to present





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



Canada Southern is not aware of any arrangement or understanding between Mr. Denecky and any other person by which Mr. Denecky was selected as an officer.



PART II



Item 5.

Market for Canada Southern Petroleum Ltd. Limited Voting Shares and Related Stockholder Matters



(a)

Principal Markets



Canada Southerns Limited Voting Shares, par value $1.00 per share, are traded on The Toronto, Pacific and Boston Stock Exchanges [Symbol: CSW], and in the NASDAQ SmallCap Market [Symbol: CSPLF].



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



|2003 | 1st quarter | 2nd quarter | 3rd quarter | 4th quarter
|---- | ----------- | ----------- | ----------- | -----------
|High | 5.20        | 6.53        | 8.33        | 7.55       
|Low  | 3.83        | 3.52        | 6.05        | 5.62       
|     |             |             |             |            
|2002 | 1st quarter | 2nd quarter | 3rd quarter | 4th quarter
|High | 8.59        | 8.00        | 5.75        | 4.79       
|Low  | 5.65        | 5.00        | 4.00        | 3.90       



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



|2003 | 1st quarter | 2nd quarter | 3rd quarter | 4th quarter
|---- | ----------- | ----------- | ----------- | -----------
|High | 3.55        | 4.87        | 6.08        | 5.84       
|Low  | 2.56        | 2.50        | 4.30        | 4.13       
|     |             |             |             |            
|2002 | 1st quarter | 2nd quarter | 3rd quarter | 4th quarter
|High | 5.40        | 3.15        | 3.70        | 3.15       
|Low  | 3.50        | 3.09        | 2.50        | 2.50       





(a)

Approximate Number of Holders of Limited Voting Shares at March 10, 2004



|Title of Class                                    | Approximate number of Record Holders
|------------------------------------------------- | ------------------------------------
|Limited Voting Shares, par value
$1.00 per share. | 3,728                               





(c)

Dividends



Canada Southern has never paid a dividend on its Limited Voting Shares.  Any future dividends will be dependent on earnings, financial condition, and business prospects.



Current Canadian law does not restrict the remittance of dividends to persons not residing in Canada.  Under current Canadian tax law and the United States-Canada Tax Convention (1980), any dividends paid to U.S. resident shareholders under the Convention are generally subject to a 15% Canadian withholding tax.



(d)

Recent Sales of Unregistered Securities



None.



Item 6.

Selected Financial Data



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

| | Years ended December 31,
| | ------------------------



|                                                 | 2003    | 2002     | 2001     | 2000     | 1999    
|------------------------------------------------ | ------- | -------- | -------- | -------- | --------
|                                                 |         | ($)      | ($)      | ($)      | ($)     
|                                                 |         |          |          |          |         
|Total revenues                                   | 13,183  | 9,937    | 16,036   | 1,379    | 1,030   
|                                                 |         |          |          |          |         
|Settlement of litigation                         | 22,727  | -        | -        | -        | -       
|                                                 |         |          |          |          |         
|Net income (loss)                                | 17,196  | 2,357    | 10,183   | (3,084)  | (3,001) 
|Net income (loss) - U.S. GAAP                    | 17,371  | 2,357    | 10,183   | (3,084)  | (3,001) 
|                                                 |         |          |          |          |         
|Net income (loss) per share:                     |         |          |          |          |         
|Basic                                            | 1.19    | .16      | .71      | (.22)    | (.21)   
|Diluted                                          | 1.19    | .16      | .70      | (.22)    | (.21)   
|Net income (loss) per share: -         U.S. GAAP |         |          |          |          |         
|Basic                                            | 1.20    | .16      | .71      | (.22)    | (.21)   
|Diluted                                          | 1.20    | .16      | .70      | (.22)    | (.21)   
|                                                 |         |          |          |          |         
|Working capital                                  | 38,212  | 20,963   | 14,858   | 1,261    | 3,629   
|                                                 |         |          |          |          |         
|Total assets                                     | 61,528  | 28,773   | 25,088   | 12,749   | 16,073  
|Total assets  U.S. GAAP                         | 62,125  | 28,832   | 25,515   | 12,749   | 16,073  
|                                                 |         |          |          |          |         
|Shareholders Equity:                            |         |          |          |          |         
|Capital stock                                    | 41,690  | 41,690   | 41,690   | 40,794   | 40,787  
|Retained earnings(deficit)                       | 1,109   | (16,087) | (18,444) | (28,626) | (22,542)
|Total                                            | 42,799  | 25,603   | 23,246   | 12,168   | 18,245  
|Total Shareholders Equity           U.S. GAAP  | 43,052  | 25,661   | 23,673   | 12,168   | 18,245  
|                                                 |         |          |          |          |         
|Average number of shares outstanding:            |         |          |          |          |         
|Basic                                            | 14,418  | 14,418   | 14,365   | 14,285   | 14,253  
|Diluted                                          | 14,424  | 14,418   | 14,476   | 14,285   | 14,253  
|                                                 |         |          |          |          |         
|Exchange rates:                                  |         |          |          |          |         
|(Canadian $ = U.S. $)                            |         |          |          |          |         
|Year-end                                         | .7724   | .6342    | .6278    | .6672    | .6924   
|Average for the period                           | .7138   | .6369    | .6458    | .6736    | .6733   
|Range                                            | .63-.77 | .62-.66  | .62-.67  | .65-.69  | .67-.69 



Item 7.

Management's Discussion and Analysis of Financial Condition

and Results of Operations



The following Managements Discussion and Analysis of Financial Condition and Results of Operations has been prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP), and conforms in all material respects to U.S. GAAP with the exception of the items discussed in Note 14 to the consolidated financial statements.



Forward Looking Statements



Statements included in Managements Discussion and Analysis of Financial Condition and Results of Operations which are not historical in nature are intended to be, and are hereby identified as, forward looking statements for purposes of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995.  Canada Southern cautions readers that forward looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those indicated in the forward looking statements.  Among these risks and uncertainties are uncertainties as to the pricing, production levels and costs from properties in which Canada Southern has interests, and the extent of the recoverable reserves at those properties.  The Company undertakes no obligation to update or revise forward looking statements, whether as a result of new information, future events, or otherwise.  The Company does caution, however, that results in 2004 will be significantly lower than in 2003, which was favorably affected by settlement of the Kotaneelee litigation.



Executive Summary



With the settlement of the lengthy and costly litigation, which effectively curtailed any exploration and development activities for the Company, the Board of Directors and management are now able to focus attention on other concerns facing the Company.  The Company believes that its largest producing asset (two wells at the Kotaneelee field) in terms of production volumes, cash flow, revenues, and earnings is nearing the end of its economic life.  While management is optimistic that further drilling of this field could occur, the timing and extent of future development is under the control of a third party operator.  While the working interest partners exercise operational control over this fields development, Company management has been in the process of identifying additional opportunities for growth and has commenced limited capital expenditures to achieve that goal.



Recently Issued Statements of Financial Accounting Standards



Effective January 1, 2004, the Company will adopt the new Accounting Guideline AcG-16 on full cost accounting for the oil and gas industry as published by the Canadian Institute of Chartered Accountants.  The primary effect of this change in accounting policy will be the use of future expected prices as opposed to year end prices for the purpose of determining potential impairments in the Companys oil and gas properties.  The Company does not expect the adoption of this Accounting Guideline to have a material impact on the consolidated financial statements.



In June 2001, the FASB issued Statement No. 143 Accounting for Asset Retirement Obligations.  This statement, effective in U.S. GAAP for fiscal years beginning on or after June 15, 2002, requires the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value of a liability can be made.  The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.  Similar standards have been introduced within Canadian GAAP effective for fiscal 2004.  The effect of this pronouncement on the financial position of Canada Southern and the resulting Canadian and U.S. GAAP differences are recorded in Note 14 (U.S. GAAP differences) to the Consolidated Financial Statements.



In August 2001, the FASB issued Statement No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets, which addresses financial accounting and reporting for the impairment of long-lived assets.  Statement No. 144 was effective for the 2002 fiscal year and did not have a material impact on Canada Southerns financial position.



Off-Balance Sheet Arrangements and Contractual Obligations



The Company does not use off-balance sheet arrangements such as securitization of receivables with any unconsolidated entities or other parties. The Company does not engage in trading or risk management activities and does not have material transactions involving related parties.



A summary of Canada Southerns contractual obligations as of December 31, 2003 is provided in the following table:



|                            | Payments due by Periods ($000s)
|--------------------------- | --------------------------------
|                            |                                 
|Contractual Obligations     | Total                           
|Operating leases            | $ 319                           
|Long term debt              | -                               
|Other long term liabilities | -                               
|Capital leases              | -                               
|Purchase obligations        | -                               
|Total                       | $ 319                           



Critical Accounting Policies and Estimates



Use of estimates



Inherent in the preparation of financial statements is the use of estimates and assumptions regarding certain assets, liabilities, revenues and expenses.  Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements.  Accordingly actual results may differ from the estimated amounts.  Areas that involve the use of significant estimates critical the accounts of Canada Southern are outlined below.



Full cost ceiling test calculations



Canada Southern follows the full cost method of accounting for its oil and gas properties.  The full cost method requires Canada Southern to calculate, on a quarterly basis, a ceiling test or limitation of the value of properties that can be capitalized on the balance sheet.



The ceiling test is a cost recovery test, that compares the expected future net revenues from the Companys oil and gas assets (adjusted for certain items) with the capitalized or net book value of such assets on the consolidated balance sheet.  If the capitalized costs on the consolidated balance sheet are in excess of the calculated ceiling, the excess must be expensed as additional depletion during the reporting period.



The discounted present value of Canada Southerns proved natural gas, liquids, and oil reserves is a major component of the ceiling test calculation. This component inherently contains many subjective judgments, such as projected future production rates, the timing of future expenditures, and the economic productive limit of the Companys assets.  Canada Southern utilizes the resources of a professional independent reserves evaluator, appointed by the Board of Directors, to evaluate all of its reserves on an annual basis.



The passage of time provides additional qualitative information regarding the Companys reserves that could result in reserve revisions or re-determinations.  Future significant reductions in a propertys production or a significant decrease in product pricing could result in a full cost ceiling test writedown.  In addition, significant changes in proven reserves will impact the calculation of depletion.



Future site restoration



The determination of the amount of future asset retirement obligations, asset retirement costs, reclamation, and other similar activities is subject to the use of significant estimates and assumptions.  Such estimates include major items such as the remaining economic reserve life of a property as discussed above, the timing of abandonment, the costs related to the abandonment, and others.  Significant changes in any of the assumptions could alter the amount of site restoration.



Revenue recognition



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



(1)

Liquidity and Capital Resources



At December 31, 2003, Canada Southern had approximately $49,082,000 of cash and cash equivalents.  These funds are expected to be used for general corporate purposes and for oil and gas exploration and development activities.



Net cash flow provided from operations during 2003 was $34,607,000 compared to $6,824,000 during 2002.  The $27,783,000 increase in net cash provided from operations during 2003 is comprised of:



Increase in income from operations

$ 15,649,000

Net changes in accounts receivable and other

(688,000)

Net changes in current liabilities

3,070,000

Net changes in current income taxes payable

9,752,000

Increase in net cash provided by operations

$27,783,000



On September 9, 2003 the Company announced that it had entered into a settlement agreement with the defendants in the Kotaneelee litigation.  The gross monies (net of certain costs related to the settlement; see Note 11 of the Consolidated Financial Statements) as a result of the settlement ($23,727,000) were received by the Company on October 3, 2003.  With the settlement of the Kotaneelee litigation, the risk of the Court of Appeal assessing Canada Southern with the litigation costs incurred by the defendants was eliminated.



The settlement of the litigation was a one time event that increased the Companys cash position, cash flow, revenues, and earnings per share.  Investors are cautioned that earnings per share in the future will likely be significantly lower than the $1.19 per share earned during the year ended December 31, 2003.



In connection with the receipt of taxable settlement proceeds the Company paid $9,743,000 of cash income tax to the Federal and Provincial taxation authorities on February 27, 2004.



Canada Southerns current cash flow from oil and gas operations is mainly derived from the Kotaneelee field.  Net field level receipts from Kotaneelee represented approximately 79% of the Companys total net field receipts for the year ended December 31, 2003 (2002 - 82%).



The Kotaneelee property continues to experience an increase in water production, and an associated decrease in gas production.  There is a possibility that Canada Southerns cash flow from Kotaneelee could either be significantly reduced or terminated at any time in the future.



Further development of the Kotaneelee field may assist with the recovery of the existing remaining reserves, and as well, identify additional reserves.  However, future development of Kotaneelee is highly risky due to the complexity and depth of the producing formation, the costs of drilling, and the possibility of water in the formation.



Should a well be drilled at Kotaneelee and Canada Southern has not yet converted to a working interest, then cash flows from the field would be suspended until payout is again achieved.



Should Canada Southern convert to a working interest position at Kotaneelee, a significant amount of cash resources could be required if the operator were to aggressively drill multiple wells in the field.  Drilling costs are estimated to be between $20 and $30 million gross ($6.1 to $9.2 million net to Canada Southerns interest) per well.  While the Company has sufficient funds to meet these potential requirements, it is mindful of this potential significant cash requirement in its strategic and capital planning.



The Company is evaluating the existing developed reserves at Kotaneelee and further development opportunities on the lease, with the assistance of consultants including independent reserve engineers, Gilbert Laustsen Jung Associates Ltd.



The oil and gas business is inherently risky and capital intensive and can require significant capital and cash resources to expand and develop the business.



The Companys northeast British Columbia properties are not as risky as Kotaneelee, but cannot be considered low risk due to depth of drilling, surface access, and related costs.



Now that settlement has been achieved, Company management will be able to focus on managing the Companys normal oil and gas operations.  Canada Southern commenced a capital program subsequent to settlement of the Kotaneelee litigation.  The objective of the capital program is to diversify the Companys cash flow, production, proven reserve base, and retain, replace or otherwise address expiring mineral leases.  This capital program was designed to explore and develop assets where the Company can maintain control over the timing of the activities.  A significant portion of the total capital expenditures was dedicated to the acquisition of seismic data.  Acquisition of seismic is one the early stages of the exploration cycle and upon evaluation, should result in the identification of suitable drilling locations in the future.



During the year ended December 31, 2003, Canada Southern expended $4,979,566 on capital additions (of which approximately $3.7 million occurred during the fourth quarter of 2003) for seismic, drilling, workovers, equipment, and other activities on lands outside of Kotaneelee.  A summary of capital expenditures for the year ended December 31, 2003, by area, is as follows:



|Property name  | Land      | Seismic    | Drilling      | Completions  | Facilities/
equipment | Total     
|-------------- | --------- | ---------- | ------------- | ------------ | --------------------- | ----------
|Mike/Hazel     | $  13,347 | $1,524,099 | $           - | $          - | $         -           | $1,537,446
|40 Mile Coulee | 303,537   | 136,729    | 520,298       | 338,789      | -                     | 1,299,353 
|Siphon         | 313,009   | 89,130     | 756,398       | 1,458        | -                     | 1,159,995 
|Clarke Lake    | 454       | -          | -             | 217,035      | 69,717                | 287,206   
|Buick Creek    | 7,072     | -          | -             | 16,771       | 236,389               | 260,232   
|Wargen         | 2,130     | 35,826     | -             | -            | 90,384                | 128,340   
|Others         | 229,950   | 3,249      | (3,056)       | 2,614        | 74,237                | 306,994   
|Total          | $ 869,499 | $1,789,033 | $1,273,640    | $576,667     | $470,727              | $4,979,566



To create a more balanced portfolio of risk opportunities, the Company acquired certain low risk properties in the second quarter of 2003.  Canada Southern acquired the mineral rights to approximately 10 contiguous sections (6,240 acres) of 100% interest land in the 40 Mile Coulee area of southern Alberta.  To prove the technical concept of this lower risk, shallow natural gas area, the Company drilled and cased 3 exploration wells during October and November 2003.



Canada Southern is currently performing technical evaluation of its mineral lease holdings in the Siphon and Mike/Hazel areas of northeast British Columbia.  The Company drilled and cased a 100% working interest gas well at Siphon in late 2003.  This well is currently awaiting completion, stimulation and testing.  Canada Southern has also completed a 25 sq. mile proprietary 3-D seismic program at Mike/Hazel with the acquired data now being processed and awaiting geophysical interpretation.  The Company may undertake drilling in 2004 at both areas pending completion of the geophysical and geological evaluations and economic analysis.



In the near term, Canada Southern expects to rely on internally generated cash flows and current cash on hand to provide sufficient resources to fund the Companys annual capital expenditure program.



Canada Southern has established a provision for its potential share of future site restoration costs.  The estimated amount of these costs, which totals approximately $3,941,000, is being provided for on a unit of production basis in accordance with existing accounting standards and industry practice.  At December 31, 2003, Canada Southern had accrued approximately $2,223,000 of these costs with $1,718,000 remaining to be accrued in the future.  During the year ended December 31, 2003, Canada Southern expended $101,000 to abandon a well, and $217,000 to repair another well to return it to production.  Both of these expenditures reduced the estimated remaining amount of future abandonment costs.



The Company anticipates that capital expenditures on oil and gas activities during 2004 will range from $5 million to $20 million with the greatest uncertainties being (i) whether or not the operator at Kotaneelee proposes a 2004 drilling program; (ii) the scope and estimated cost of any such proposed drilling program; and (iii) whether or not Canada Southern elects to convert from a carried interest to a working interest position at Kotaneelee.



(2)

Results of Operations

2003 vs. 2002 (Years ended December 31)



A comparison of revenues, costs and expenses, income taxes, net income and earnings per share for 2003 and 2002 is as follows:

|                         | Year ended December 31, |            
|------------------------ | ----------------------- | -----------
|                         | 2003                    | 2002       
|Revenues                 | $  13,183,117           | $ 9,936,730
|Costs and expenses       | (7,433,151)             | (6,067,135)
|Settlement of litigation | 22,727,078              | -          
|Income tax provision     | (11,281,000)            | (1,513,000)
|Net income               | $  17,196,044           | $ 2,356,595
|                         |                         |            
|Net income per share:    |                         |            
|Basic                    | $ 1.19                  | $ .16      
|Dilutive                 | $ 1.19                  | $ .16      



For the fourth quarter of 2003, the Companys quarterly net loss from operations was approximately $527,000 or $0.04 per share.  Net income was lower in the fourth quarter as compared with previous quarters mainly due to recognition of the settlement with the contingent interest grantees (described in Item 3 - Legal Proceedings) and higher depletion charges.  Depletion expenses were higher due to capital spending during the fourth quarter of 2003, and may remain at higher levels in the future.  As a result of the forgoing, and other expected increases in general and administrative costs, future earnings before unusual items may be lower than those experienced during 2003 (see quarterly results table on page 78).



Proceeds from carried interests increased 17% to $8,749,000 during 2003 from $7,470,000 in 2002.  Significantly higher gas prices offset the production declines experienced during 2003.  Fourth quarter proceeds from carried interest revenue were lower than otherwise due to inclusion in the carried interest account, by the operator, of seismic acquisition expenditures in the amount of $396,000 net to Canada Southern.



The following is a comparison of the proceeds from carried interests for the years indicated:



|                             | Year ended December 31,
|---------------------------- | -----------------------
|                             | 2003                   
|Kotaneelee natural gas field | $8,742,000             
|Other properties             | 7,000                  
|Total                        | $ 8,749,000            



Because of the uncertainties as to production rates, natural gas prices and future capital expenditures, Canada Southern is unable to accurately predict the amount of future net production proceeds that it may receive from the fields.



Production from the Kotaneelee field (natural gas  mmcf per day; water  bbls per day) during the year ended December 31, 2003, compared to 2002 is as follows:



|          | 2003   | 2002   | 2003   | 2002  
|--------- | ------ | ------ | ------ | ------
|Month     | Mmcf/d | Mmcf/d | Bbls/d | Bbls/d
|January   | 30.8   | 41.9   | 1,336  | 832   
|February  | 30.6   | 40.5   | 1,434  | 856   
|March     | 29.3   | 39.0   | 1,418  | 891   
|April     | 27.8   | 39.4   | 1,452  | 951   
|May       | 26.4   | 38.1   | 1,452  | 969   
|June      | 21.7   | 37.4   | 1,476  | 999   
|July      | 16.1   | 37.3   | 1,142  | 1,037 
|August    | 25.2   | 33.8   | 1,549  | 971   
|September | 23.8   | 24.8   | 1,697  | 784   
|October   | 23.6   | 34.2   | 1,771  | 1,316 
|November  | 22.6   | 33.6   | 1,726  | 1,294 
|December  | 21.6   | 32.1   | 1,589  | 1,273 



During the period from June 27 to July 10, 2003, the Kotaneelee field was shut-in (not producing) due to a scheduled facility turnaround at the Duke Energy Fort Nelson gas processing plant.



Individual Kotaneelee well production for the month of December 2003 was 7.9 Mmcf per day from the B-38 well and 13.7 Mmcf per day from the I-48 well (December 2002  B-38 was 16.3 Mmcf per day and the I-48 was 15.8 Mmcf per day).



Natural gas sales from the Kotaneelee field are approximately 78% of total monthly production due to shrinkage and fuel gas requirements.



Canada Southerns share of natural gas sales volumes decreased by 30% from 2002 to 2003 (from 3,167,000 mcf to 2,229,000 mcf respectively).  Average gas prices increased 63% and operating costs and capital costs increased by 52% and 160% respectively in 2003 as compared with 2002.



Water production has increased since 2001.  The operator improved the water handling capabilities of the surface equipment during the first quarter of 2002.  Water production continues to increase and water handling capacity continues to be a concern.  Natural gas production continues to decline as the reservoir pressure declines.  Water production will at some point become a constraining factor on gas production.  The Company is not able to predict with certainty the remaining economic life of the existing producing wells, their associated production profiles and the extent to which these wells will be able to access proven developed reserves.



Gross water production for the month of December 2003 was 1,427 bbs per day from the B-38 well and 161 bbls per day from the I-48 well (water production in December 2002  B-38 was 1,153 bbls per day and the I-48 was 149 bbls per day).



During the year 2002, proceeds from carried interest included $266,747 of carried interest revenues relating to production periods prior to January 1, 2002 from the Siphon property, which was converted to a working interest effective April 1, 2001.



During the year 2000, the operator of the carried interest properties at Buick Creek, Wargen and Clarke Lake withheld approximately $1,081,000 in payments from the carried interest account to recover an amount claimed to have been overpaid to Canada Southern in prior years.  Canada Southern disputes the operators position and is attempting to recover the disputed amount.  In accordance with the Companys accounting policies, no recovery of the disputed amount has been recorded.  The resolution of this issue has been delayed by the completion of the interrelated Wargen facility issue.  It is expected that this issue will be resolved during 2004.



Company carried interest natural gas volumes in thousand cubic feet (mcf) (before deducting royalties) and related liquids volumes in barrels (bbls) and the average sales price of gas per mcf and liquids per bbl sold during the periods indicated were as follows:



|                    | Carried Interests           
|------------------- | ----------------------------
|                    | Year ended December 31, 2003
|                    |                             
|                    | mcf/bbls                    
|Gas sales (mcf)     | 2,228,782                   
|Liquid sales (bbls) | 167                         
|Transportation      |                             
|Royalties           |                             
|Operating costs     |                             
|Capital costs       |                             
|Total               |                             





Gas revenue increased 81% from $1,832,000 in 2002 to $3,314,000 in 2003.  There was a 13% increase in the volumes of working interest gas sold and a 56% increase in the average sales price for gas.  Gas sales include royalty income, which increased 84% from $176,000 in 2002 to $326,000 in 2003.  Royalty volumes sold increased by 19% over 2002, and the sales price per mcf increased 55% over the same period.  As a result of capital expenditures, Canada Southern expects that gas revenue volumes will increase in the future.  The volumes in mcf (before deducting royalties) and the average price of gas per mcf sold during the periods indicated were as follows:



|               | Working and Royalty Interests
|-------------- | -----------------------------
|               | Year ended December 31, 2003 
|               |                              
|               | mcf                          
|Gas sales      | 688,808                      
|Royalty income | 53,788                       
|Royalties      | -                            
|Total          | 742,596                      



Oil and natural gas liquid sales increased by 44% in 2003 to $301,000 compared to $210,000 in 2002.  Since Canada Southern sold most of its producing oil properties in 2000, the majority of liquid sales are derived from natural gas liquids.  Future oil sales are expected to be minimal unless additional producing properties are drilled or purchased.  Crude oil and natural gas liquid unit sales in barrels (bbls) (before deducting royalties) and the average price per barrel sold during the periods indicated were as follows:



|               | Working and Royalty Interests
|-------------- | -----------------------------
|               | Year ended December 31, 2003 
|               |                              
|               | bbls                         
|Liquid sales   | 10,773                       
|Royalty income | 279                          
|Royalties      | -                            
|Total          | 11,052                       



Interest and other income increased 92% in 2003.  Interest income increased from $425,000 to $819,000 in 2003 because more funds were available for investment.  The 2003 year includes proceeds from the sale of seismic data in the amount of $24,000 compared to $51,000 from such sales in 2002.  Investment yields and cash on hand have declined since December 31, 2003, therefore interest income may decline in the future.



General and administrative costs increased 43% in 2003 to $2,327,000from $1,623,000 in 2002 primarily because of increases in directors fees and expenses, consultants expenses, audit services, and insurance expense.  Directors fees and expenses increased substantially due mainly to intense participation by all board members throughout the period in the complex settlement of the Kotaneelee litigation, the response to the contingent interest claims on the Kotaneelee settlement proceeds, and in planning for the resumption in normal exploration and development activities by the Company.  During the period there were 45 formal meetings of the board or committees thereof, and at least that number of informal meetings or teleconferences, directly related to the settlement.  The Chairman of the Board (Mr. McGinity) was continuously present in Calgary during most of August and early September, and the Board determined that an increase in the Chairmans compensation was therefore warranted, retroactive to July 1, 2003.  General and administrative costs have also increased as a result of the adoption of new disclosure and corporate governance regulations in both Canada and the United States which have contributed to increased directors fees and expenses, and increased the Companys legal, audit, and consultants fees.



No general and administrative expenses were capitalized during the period.



A comparative summary of general and administrative costs grouped by major category is as follows:



|                            | Year ended December 31,
|--------------------------- | -----------------------
|                            | 2003                   
|Directors fees and expenses | $   523,600            
|Consultants                 | 513,400                
|Insurance expense           | 317,800                
|Shareholder communications  | 253,800                
|Salaries and benefits       | 272,700                
|Audit and related services  | 232,700                
|Other                       | 212,700                
|Total                       | $2,326,700             



Legal expenses decreased 24% during 2003 to $727,000 compared to $952,000 in 2002.  These expenses were related primarily to the cost of the Kotaneelee litigation.  Legal work decreased significantly given the settlement of the litigation in early September 2003.  While legal costs related to the litigation have decreased due to the Kotaneelee settlement, new disclosure and corporate governance regulations have been adopted in both Canada and the United States, and are expected to contribute to increased legal expenses in the future.



Lease operating costs increased 62% from $779,000 in 2002 to $1,258,000 in 2003.  Operating costs were higher in 2003 mainly due to resolution of certain facility ownership issues at Buick Creek and Wargen.  In connection with being legally recognized as an owner of the Buick Creek facilities, Canada Southern became responsible for facility operating costs of $464,200 for the period from January 1, 2001 to December 30, 2003.  Discussions with the operator of the Wargen facilities resulted in the accounting recognition of $50,500 of estimated operating expenses for the period January 1, 2001 to December 31, 2003.  Other adjustments to operating costs, which could lead to a one time material adjustment to operating costs, would be recorded in a future period.  Any such amounts are currently undeterminable.



Depletion, depreciation and amortization expense decreased 4% in 2003 to $2,301,000from $2,398,000 in 2002.  Depletion, depreciation and amortization are a relatively high percentage (26%) of the net book value of oil and gas properties and equipment mainly due to the limited expected life of the proven reserves at the Kotaneelee field.



Future site restoration costs decreased 9% to $285,000 in 2003from $314,000 in 2002.  The decrease in the amount relates to cash expenditures incurred in the first quarter of 2003 that reduced the aggregate amount of future site restoration liabilities.  A well at Jackfish was abandoned, and a well at ClarkeLake was repaired for reinstatement of production, resulting in a $416,000 reduction in the aggregate estimated corporate cost of site restoration.  In connection with settlement of the Kotaneelee litigation in September 2003, the Company agreed to be responsible for its share of the future site restoration costs at Kotaneelee.  As at December 31, 2003, the aggregate estimate of future site restoration obligation was $3,941,000, of which $2,223,000 has been recorded in the financial statements (leaving the remaining $1,718,000 to be recorded in future periods).  As a result, Canada Southern expects future site restoration costs to increase in the future.



Effective January 1, 2004, Canada Southern adopted new accounting rules for future site restoration costs.  The impact of the changes is disclosed in Note 14 (U.S. GAAP differences) of the Consolidated Financial Statements.



A foreign exchange loss of $536,000 was recorded in 2003, as opposed tothe exchange loss of $300 in 2002 on Canada Southerns U.S. investments.Canada Southern held investments in marketable securities in U.S. currency, which is subject to foreign exchange fluctuations.  At December 31, 2003, the U.S. dollar investments totalled $2,067,193(U.S. $1,596,781) (December 31, 2002 - $2,602,497; U.S. $1,650,388).  The strengthening of the Canadian dollar compared to the U.S. dollar resulted in the loss.  With the relative volatility between the U.S. and Canadian dollar, the Company expects to record further foreign exchange losses or gains in the future.  The value of the Canadian dollar was U.S. $.7724 at December 31, 2003 compared to U.S. $.6342 at December 31, 2002.



The income tax provision increased to $11,281,000 in 2003ascompared to the income tax provision of $1,513,000 in 2002.  The increase in income tax provision is attributable to the taxable proceeds from settlement of the Kotaneelee litigation.  During the year ended December 31, 2003, the Companys effective tax rate was 39.6% as compared to 39% for the year ended December 31, 2002.



2002 vs. 2001 (Years ended December 31)



A comparison of revenues, costs and expenses, income taxes, net income (loss) and earnings per share for 2002 and 2001 is as follows:



|                      | Year ended December 31 |            
|--------------------- | ---------------------- | -----------
|                      | 2002                   | 2001       
|Revenues              | $9,936,730             | $16,036,476
|Costs and expenses    | (6,067,135)            | (4,658,275)
|Income tax provision  | (1,513,000)            | (1,195,700)
|Net income            | 2,356,595              | $10,182,501
|                      |                        |            
|Net income per share: |                        |            
|Basic                 | $.16                   | $.71       
|Dilutive              | $.16                   | $.70       



Proceeds from carried interests decreased 42% to $7,470,000 during 2002 from $12,880,000 in 2001, mainly due to the decreased production volumes and lower gas prices.  Effective for the production period beginning September 2001, the working interest owners no longer deducted a processing fee on the monthly payments of carried interest revenues.  The following is a comparison of the proceeds from carried interests for the years indicated:



|                     | Year ended December 31
|-------------------- | ----------------------
|                     | 2002                  
|Kotaneelee gas field | $7,194,000            
|Other properties     | 276,000               
|Total                | $7,470,000            



Natural gas sales from the Kotaneelee field are approximately 80% of total monthly production.



Because of the uncertainties as to production rates, natural gas prices and future capital expenditures, Canada Southern is unable to accurately predict the amount of future net production proceeds that it may receive from the field.



In addition, water production has increased since 2001 and the producing field may require the drilling of another water disposal well.  To alleviate the concern of water disposal capacity the operator improved the water handling capabilities of the surface equipment during the first quarter of 2002.  If water production were to continue to increase, future gas production from the B-38 well could be adversely impacted.



Production from the Kotaneelee field during the year 2002 was as follows:



|Month    | Mmcf/d | Month     | Mmcf/d
|-------- | ------ | --------- | ------
|January  | 41.9   | July      | 37.3  
|February | 40.5   | August    | 33.8  
|March    | 39.0   | September | 24.8  
|April    | 39.4   | October   | 34.2  
|May      | 38.1   | November  | 33.6  
|June     | 37.4   | December  | 32.1  



Individual Kotaneelee well production for the month of December 2002 was 16.3 Mmcf per day from the B-38 well and 15.8 Mmcf per day from the I-48 well (December 2001  B-38 was 24.8 Mmcf per day and the I-48 was 17.5 Mmcf per day).



Sales volumes decreased by 10% from 2001 to 2002 (from 3,504,000 mcf to 3,167,000 mcf respectively).  Average gas prices decreased 35% and operating and capital costs decreased by 39% in 2002 as compared with 2001.



During the year 2002, proceeds from carried interest included $266,747 of carried interest revenues relating to production periods prior to January 1, 2002 from the Siphon property, which was converted to a working interest effective April 1, 2001.



During the year 2001, proceeds from carried interests included $315,000 of carried interest revenues relating to production periods prior to January 1, 2001 from the Buick Creek, Wargen and Clarke Lake properties, which were converted to working interests effective January 1, 2001.



Company carried interest natural gas volumes in thousand cubic feet (mcf) (before deducting royalties) and related liquids volumes in barrels (bbls) and the average price of gas per mcf and liquids per bbl sold during the periods indicated were as follows:



|                 | Carried Interests           
|---------------- | ----------------------------
|                 | Year ended December 31, 2002
|                 |                             
|                 | mcf/bbls                    
|Gas sales (mcf)  | 3,166,982                   
|Oil sales (bbls) | 560                         
|Royalties        |                             
|Operating costs  |                             
|Processing fees  |                             
|Transportation   |                             
|Capital costs    |                             
|Total            |                             



Gas revenue decreased 32% from $2,714,000 in 2001 to $1,832,000 in 2002.  There was a 26% increase in the number of working interest gas units sold and a 45% decrease in the average price for related gas.  Gas sales include royalty income, which decreased 18% from $215,000 in 2001 to $176,000 in 2002.  The number of royalty units sold increased by 50% over 2001, however the sales price per mcf decreased 46% over the same period.  The volumes in mcf (before deducting royalties) and the average price of gas per mcf sold during the periods indicated were as follows:



|               | Working and Royalty Interests
|-------------- | -----------------------------
|               | Year ended December 31, 2002 
|               |                              
|               | mcf                          
|Gas sales      | 610,366                      
|Royalty income | 45,132                       
|Royalties      | -                            
|Total          | 655,498                      



Oil and natural gas liquid sales increased by 27% in 2002 to $210,000 compared to $165,000 in 2001.  Since Canada Southern sold most of its producing oil properties in 2000, the majority of liquid sales are derived from natural gas liquids.  Future oil sales are expected to be minimal unless additional producing properties are drilled or purchased. Crude oil and natural gas liquid unit sales in barrels (bbls) (before deducting royalties) and the average price per barrel sold during the periods indicated were as follows:



|               | Working and Royalty Interests
|-------------- | -----------------------------
|               | Year ended December 31, 2002 
|               |                              
|               | bbls                         
|Liquid sales   | 9,607                        
|Royalty income | 179                          
|Royalties      | -                            
|Total          | 9,786                        



Interest and other income increased 53% in 2002.  Interest income increased from $278,000 to $425,000 in 2002 because more funds were available for investment, and because of steps taken to improve the yield on those funds.  The 2002 period includes proceeds from the sale of seismic data in the amount of $51,000 compared to $25,000 from such sales in 2001.



General and administrative costs increased 14% in 2002 to $1,623,000 from $1,429,000 in 2001, primarily because of increases in auditing costs, insurance costs, shareholder communications costs, and directors expenses.  Canada Southern performed joint venture audits on three of the four Kotaneelee working interest partners in the fourth quarter of 2002.  After September 11, 2001, insurance premiums rose significantly.  With the election of two new directors in 2002, directors fees and expenses increased over the prior year.  A comparative summary of general and administrative costs grouped by major category is as follows:



|                            | Year ended December 31
|--------------------------- | ----------------------
|                            | 2002                  
|Consultants                 | $   365,900           
|Salaries and benefits       | 234,300               
|Shareholder communications  | 289,000               
|Insurance expense           | 218,700               
|Directors fees and expenses | 199,700               
|Audit and related services  | 165,800               
|Other                       | 149,600               
|Total                       | $1,623,000            



Legal expenses decreased 6% during 2002 to $952,000 compared to $1,012,000 in 2001. These expenses are related primarily to the cost of the Kotaneelee litigation.  Legal work associated with the appeal of the trial courts decision resulted in legal expenses in 2002 somewhat below those of 2001.



Lease operating costs increased 66% from $468,000 in 2001 to $779,000 in 2002.  Operating costs were higher in 2002 mainly due to the emergency repair of one of the Companys gas wells, the inclusion of accounting adjustments to the facility operating expenses at Siphon, and a gas compressor turnaround at Siphon.  In 2002, Canada Southern also experienced the impact of a full year of operating expenses following the conversion from carried into working interest in early 2001.  Once Canada Southern resolves certain facility ownership issues at Buick Creek and Wargen, it may be invoiced for certain previous period facility operating costs which could lead to a one time material adjustment to operating costs recorded in a future period.  Any such amounts are currently undeterminable.



Depletion, depreciation and amortization expense increased 44% in 2002 to $2,398,000 from $1,663,000 in 2001.  The increase in depletion, depreciation and amortization is mainly due to the impact of the decrease in Canada Southerns estimated reserves from the Kotaneelee field.



The provision for site restoration increased 129% to $314,000 in 2002from $137,000 in 2001, mainly due to the revision of future site restoration cost estimates and the impact of the decrease in Canada Southerns estimated reserves from the Kotaneelee field.



A foreign exchange loss of $300 was recorded in 2002, as opposed tothe exchange gain of $51,000 in 2001 on Canada Southerns U.S. investments.  The value of the Canadian dollar was U.S. $.6342 at December 31, 2002 compared to U.S. $.6278 at December 31, 2001.



There were no writedowns during 2002 and 2001.



The income tax provision increased 27% to $1,513,000 in 2002ascompared to the income tax provision of $1,196,000 in 2001.  During the 2001 period, $1,196,000 of income taxes were provided which resulted in an effective tax of rate 11% instead of the expected rate of 43.37% because of the utilization of tax loss carry forwards and earned depletion not previously recorded.



Item 7A.

Quantitative and Qualitative Disclosures About Market Risk



Canada Southern does not have any significant exposure to financial market risk as the only market risk sensitive instruments are investments in commercial paper and marketable securities.  At December 31, 2003, the carrying value of such investments (including those classified as cash and cash equivalents) was $48,918,350 which was approximately equal to fair value and face value of the investments.



Canada Southern utilizes the guidance provided from the Dominion Bond Rating Service Limited (DBRS) Commercial Paper and Short Term Rating Scale in evaluating its investments.  DBRS is the benchmark rating service for money market securities in Canada (as are S&P and Moodys in the United States).  This rating scale is meant to give an indication of the risk that the borrower will not fulfill its repayment obligations in a timely manner.  DBRS utilizes three main classifications of investment quality; R-1 (prime credit quality), R-2 (adequate credit quality), and R-3 (speculative).  Within each main classification, DBRS uses subset grades to designate the relative standing of credit within the particular category (high, mid or low).  Generally only Government of Canada guaranteed investments earn an R-1 high rating.



To ensure capital preservation, Canada Southerns investment policy allows only for investments within the highest quality ratings of R-1 (high, mid, or low).  Given that credit ratings can change rapidly in todays economy, Canada Southerns current practice is to invest in a particular investment for periods no longer than 90 days.  As a result of the strategy to select high quality investments in combination with short terms to maturity, Canada Southern expects to hold the investments to maturity, and realize maturity value.



In addition, the investments in marketable securities included investments held in United States currency, which are subject to foreign exchange fluctuations.  At December 31, 2003, the U.S. dollar investments totaled $2,067,193 (U.S. $1,596,781) (2002 - $2,602,497; U.S. $1,650,388).



Item 8.

Financial Statements and Supplementary Data







AUDITORS REPORT









To the Shareholders of

Canada Southern Petroleum Ltd.





We have audited the consolidated balance sheets of Canada Southern Petroleum Ltd. as at December 31, 2003 and 2002, and the consolidated statements of operations and retained earnings (deficit) and cash flows for each of the years in the three year period ended December 31, 2003.  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 Canadian and United States 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 present fairly, in all material respects, the financial position of Canada Southern Petroleum Ltd. as at December 31, 2003 and 2002 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2003, in accordance with Canadian generally accepted accounting principles.





Calgary, Canada



March 5, 2004 (except for notes 9, 11 and 12

/s/Ernst and Young LLP

which are as of March 24, 2004)

Chartered Accountants







CANADA SOUTHERN PETROLEUM LTD.

(Incorporated under the laws of Nova Scotia)



CONSOLIDATED BALANCE SHEETS

(Expressed in Canadian dollars)



| | As at December 31,
| | ------------------
| | 2003              



|Assets                                                           |                 |             
|---------------------------------------------------------------- | --------------- | ------------
|Current assets                                                   |                 |             
|Cash and cash equivalents (Note 2)                               | $ 49,082,386    | $ 19,454,453
|Accounts receivable (Notes 3 and 12)                             | 3,138,465       | 2,683,367   
|Other assets                                                     | 400,643         | 408,074     
|Total current assets                                             | 52,621,494      | 22,545,894  
|                                                                 |                 |             
|Oil and gas properties and equipment (full cost method) (Note 4) | 8,906,029       | 6,227,463   
|                                                                 |                 |             
|Total assets                                                     | $61,527,523     | $28,773,357 
|                                                                 |                 |             
|Liabilities and Shareholders Equity                             |                 |             
|                                                                 |                 |             
|Current liabilities                                              |                 |             
|Accounts payable (Note 12)                                       | $     2,947,763 | $    515,429
|Accrued liabilities (Note 5)                                     | 1,709,889       | 1,067,504   
|Accrued income taxes payable (Note 6)                            | 9,752,303       | -           
|Total current liabilities                                        | 14,409,955      | 1,582,933   
|                                                                 |                 |             
|Future income tax liability (Note 7)                             | 2,096,000       | 1,016,000   
|Future site restoration provision (Note 8)                       | 2,223,078       | 571,978     
|                                                                 | 18,729,033      | 3,170,911   
|                                                                 |                 |             
|Commitments and contingencies (Notes 9, 11 and 12)               |                 |             
|                                                                 |                 |             
|Shareholders Equity                                             |                 |             
|Limited Voting Shares, par value                                 |                 |             
|$1 per share (Note 10)                                           |                 |             
|Authorized 100,000,000 shares                                   |                 |             
|Outstanding 14,417,770 shares                                   | 14,417,770      | 14,417,770  
|Contributed surplus                                              | 27,271,833      | 27,271,833  
|Total capital                                                    | 41,689,603      | 41,689,603  
|Retained earnings (deficit)                                      | 1,108,887       | (16,087,157)
|Total shareholders equity                                       | 42,798,490      | 25,602,446  
|Total liabilities and shareholders equity                       | $61,527,523     | $28,773,357 



See accompanying notes.



Signed on behalf of the Board



/s/ Richard C. McGinity

/s/ D. Michael G. Stewart

Chairman of the Board

Chairman of the Audit Committee

CANADA SOUTHERN PETROLEUM LTD.



CONSOLIDATED STATEMENTS OF OPERATIONS

AND RETAINED EARNINGS (DEFICIT)

(Expressed in Canadian dollars)



| |                         
| | ------------------------
| | Years ended December 31,



|                                                     | 2003           | 2002          | 2001         
|---------------------------------------------------- | -------------- | ------------- | -------------
|                                                     |                |               |              
|Revenues:                                            |                |               |              
|Proceeds from carried interests
(Notes 9, 12 and 13) | $ 8,749,422    | $ 7,469,587   | $  12,879,512
|Natural gas sales (Notes 12 and 13)                  | 3,313,747      | 1,832,031     | 2,713,636    
|Oil and liquid sales (Notes 12 and 13)               | 301,235        | 209,757       | 164,996      
|Interest and other income                            | 818,713        | 425,355       | 278,332      
|Total revenues                                       | 13,183,117     | 9,936,730     | 16,036,476   
|                                                     |                |               |              
|Costs and expenses:                                  |                |               |              
|General and administrative                           | 2,326,706      | 1,623,389     | 1,428,915    
|Legal (Notes 9, 11 and 12)                           | 727,097        | 952,426       | 1,011,521    
|Lease operating costs                                | 1,257,827      | 778,586       | 468,089      
|Depletion, depreciation and amortization             | 2,301,000      | 2,398,358     | 1,663,402    
|Future site restoration provision                    | 285,000        | 314,000       | 137,000      
|Foreign exchange (gains) losses                      | 535,521        | 376           | (50,652)     
|Total costs and expenses                             | 7,433,151      | 6,067,135     | 4,658,275    
|Revenues, less costs and expenses                    | 5,749,966      | 3,869,595     | 11,378,201   
|Settlement of litigation (Notes 9, 11 and 12)        | 22,727,078     | -             | -            
|Income before income taxes                           | 28,477,044     | 3,869,595     | 11,378,201   
|Income tax expense (Note 7)                          | (11,281,000)   | (1,513,000)   | (1,195,700)  
|Net income                                           | 17,196,044     | 2,356,595     | 10,182,501   
|                                                     |                |               |              
|Deficit  beginning of year                          | (16,087,157)   | (18,443,752)  | (28,626,253) 
|Retained earnings (deficit)  end of year            | $    1,108,887 | $(16,087,157) | $(18,443,752)
|                                                     |                |               |              
|Net income per share (Note 10):                      |                |               |              
|Basic                                                | $1.19          | $.16          | $.71         
|Diluted                                              | $1.19          | $.16          | $.70         
|                                                     |                |               |              
|Average number of shares outstanding:
Basic          | 14,417,770     | 14,417,770    | 14,365,278   
|Diluted                                              | 14,423,667     | 14,417,770    | 14,475,788   







See accompanying notes.







CANADA SOUTHERN PETROLEUM LTD.



CONSOLIDATED STATEMENTS OF CASH FLOWS

(Expressed in Canadian dollars)



| | Years ended December 31,
| | ------------------------



|                                                                                            | 2003        | 2002        | 2001       
|------------------------------------------------------------------------------------------- | ----------- | ----------- | -----------
|                                                                                            |             |             |            
|Cash flows from operating activities:                                                       |             |             |            
|Net income                                                                                  | $17,196,044 | $2,356,595  | $10,182,501
|Adjustments to reconcile net income to net cash provided by (used in) operating activities: |             |             |            
|Depletion, depreciation and amortization                                                    | 2,301,000   | 2,398,358   | 1,663,402  
|Future site restoration provision                                                           | 1,823,000   | 314,000     | 137,000    
|Site restoration expenditures                                                               | (171,900)   | (5,362)     | (9,783)    
|Future income tax expense                                                                   | 1,080,000   | 1,516,000   | 1,165,700  
|Funds provided by operations                                                                | 22,228,144  | 6,579,591   | 13,138,820 
|Change in current assets and liabilities:                                                   |             |             |            
|Accounts receivable                                                                         | (455,098)   | 325,265     | (2,763,887)
|Other assets                                                                                | 7,431       | (85,327)    | (21,876)   
|Accounts payable                                                                            | 2,432,334   | (181,147)   | 389,026    
|Accrued liabilities                                                                         | 642,385     | 185,556     | 744,421    
|Accrued income taxes payable                                                                | 9,752,303   | -           | -          
|Net cash provided by operating activities                                                   | 34,607,499  | 6,823,938   | 11,486,504 
|                                                                                            |             |             |            
|Cash flows from investing activities:                                                       |             |             |            
|Additions to oil and gas properties and equipment                                           | (4,979,566) | (474,151)   | (1,238,291)
|Proceeds from the sale of properties                                                        | -           | -           | 801,227    
|Net cash used in investing activities                                                       | (4,979,566) | (474,151)   | (437,064)  
|                                                                                            |             |             |            
|Cash flows from financing activities:                                                       |             |             |            
|Exercise of stock options                                                                   | -           | -           | 895,195    
|Net cash provided from financing activities                                                 | -           | -           | 895,195    
|                                                                                            |             |             |            
|Increase in cash and cash equivalents                                                       | 29,627,933  | 6,349,787   | 11,944,635 
|Cash and cash equivalents at the beginning of year                                          | 19,454,453  | 13,104,666  | 1,160,031  
|Cash and cash equivalents at the end of year 
(Note 2)                                      | $49,082,386 | $19,454,453 | $13,104,666





See accompanying notes.



Note 1.

Summary of significant accounting policies



Accounting principles



Canada Southern Petroleum Ltd. (Canada Southern) prepares its accounts in accordance with Canadian generally accepted accounting principles (Canadian GAAP) which conform in all material respects with U.S. generally accepted accounting principles (U.S. GAAP) except as disclosed in Note 14.



Consolidation



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



Use of estimates



The preparation of financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Specifically estimates were utilized in calculating depletion, depreciation and amortization, ceiling test values, site restoration costs, and the fair value of stock options.  Actual results could differ from those estimates and the differences could be material.



Oil and gas properties and equipment



Canada Southern, which is engaged in one industry, the exploration for and the development of oil and gas properties in Canada, follows the full cost method of accounting for oil and gas properties, whereby all costs associated with the exploration for and the development of oil and gas reserves are capitalized.  Such costs include land acquisition, drilling, geological, geophysical and overhead expenses.  Canada Southerns cost center is Canada.



Canada Southern periodically reviews the costs associated with unproved 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.



The net carrying cost of Canada Southerns oil and gas properties in producing cost centers is limited to an estimated recoverable amount.  This amount is the aggregate of future net revenues from proved reserves and the costs of unproved properties, net of impairment allowances, less future general and administrative costs, financing costs and income taxes.  Future net revenues are calculated using year-end prices that are not escalated or discounted.  For Canadian GAAP future net revenues are undiscounted, whereas, for U.S. GAAP future net revenues are discounted at 10%.



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



Depletion is provided on costs accumulated in producing cost centers including production equipment using the unit of production method.  For purposes of the depletion calculation, the Companys gross proved oil and gas reserves as determined by the independent reserves evaluator appointed by the Board of Directors are converted to a common unit of measure on the basis of their approximate relative energy content.  Depreciation has been computed for equipment, other than production equipment, on the straight-line method based on estimated useful lives of four to ten years.



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



Revenue recognition



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



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



Net income per share



In 2001, Canada Southern, in accordance with the standards issued by the Canadian Institute of Chartered Accountants, retroactively adopted the treasury method of calculating diluted earnings per share (EPS).  The new methodology establishes dilution assuming proceeds from the exercise of dilutive options are used to purchase shares at the average market price for the year.  The previous methodology assumed proceeds were used to repay debt.



Future site restoration provision



Canada Southern has established a policy to accrue for its potential share of future site restoration costs for all working interest properties held.  The estimated amount of these costs, which totals approximately $3,941,000, is being provided for on a unit of production basis in accordance with existing legislation and industry practice.  At December 31, 2003, Canada Southern had accrued for $2,223,000 of these costs with $1,718,000 remaining to be accrued in the future.  The estimated costs of abandoning carried interest wells, other than Kotaneelee, are not included in future site restoration costs.  The Company expects that these costs would be paid by the working interest partners and charged to the carried interest account.



Future income taxes



Canada Southern follows the liability method of accounting for income taxes. Under this method, Canada Southern records income taxes to give effect to temporary differences between the carrying amounts and the tax bases of Canada Southerns assets and liabilities.  Future income taxes are recorded at the substantively enacted income tax rates that are expected to apply when the future tax liability is settled or the future tax asset is realized.  Income tax expense is the tax payable for the period and the change during the period in future income tax assets and liabilities.



Foreign currency translation



Transactions settled in U.S. dollars have been translated at the rate of exchange in effect at the time of settlement.  Monetary assets and liabilities in U.S. dollars have been translated at the year end exchange rates.  Exchange gains or losses resulting from these adjustments are included in costs and expenses.

Financial instruments



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



Stock-based compensation



Canada Southern has a stock-based compensation plan for its employees, officers, directors, and non-employees to acquire common shares.  Stock options are issued at the fair market value of the shares on the date of the grant.  As Canada Southern follows the intrinsic value method in accounting for its stock options issued to employees, officers and directors, no compensation expense is recorded when options are granted.  Options issued to non-employees are valued at fair value and compensation expense is recorded over the vesting period.  Consideration received on the exercise of the options is credited to share capital.  Note 10 contain the details of the options outstanding at December 31, 2003.



Note 2.

Cash and cash equivalents



Canada Southern considers all highly liquid short-term investments with maturities of three months or less at date of acquisition to be cash equivalents.  Cash equivalents are carried at cost, which approximates market value due to their short term nature.



|                                                                  | As at December 31,
|----------------------------------------------------------------- | ------------------
|                                                                  | 2003              
|Cash                                                              | $     164,036     
|Canadian marketable securities (Yield: 2003  2.8%, 
2002  2.8%) | 46,851,157        
|U.S. marketable securities (Yield: 2003  1.2%, 
2002 -1.9%)      | 2,067,193         
|Total                                                             | $49,082,386       



Note 3.

Accounts receivable



Accounts receivable is comprised of normal trade accounts mainly from various industry partners in the Companys oil and gas properties as follows:



|                            | As at December 31,
|--------------------------- | ------------------
|                            | 2003              
|Kotaneelee partners         | $2,083,278        
|Samson Canada Resources     | 401,517           
|Anadarko Canada Corporation | 37,993            
|Others                      | 615,677           
|Total                       | $3,138,465        



The Kotaneelee partners are comprised of BP Canada Energy Company, Devon Canada, Imperial Oil Resources and ExxonMobil Canada Properties.



Note 4.

Oil and gas properties and equipment



The following tables provide the detail of oil and gas properties and equipment at December 31, 2003 and 2002:

|                                          |             | Depreciation   |           
|----------------------------------------- | ----------- | -------------- | ----------
|                                          |             | Depletion and, | Net Book  
|                                          | Cost        | Write downs    | Value     
|Balance, December 31, 2003                |             |                |           
|Oil and gas properties  developed        | $24,890,843 | $16,051,766    | $8,839,077
|Oil and gas properties (U.S.)  developed | 1,319,218   | 1,319,218      | -         
|                                          | 26,210,061  | 17,370,984     | 8,839,077 
|Equipment                                 | 160,304     | 93,352         | 66,952    
|                                          | $26,370,365 | $17,464,336    | $8,906,029
|                                          |             |                |           
|Balance, December 31, 2002                |             |                |           
|Oil and gas properties  developed        | $19,985,513 | $13,769,766    | $6,215,747
|Oil and gas properties (U.S.)  developed | 1,319,218   | 1,319,218      | -         
|                                          | 21,304,731  | 15,088,984     | 6,215,747 
|Equipment                                 | 86,069      | 74,353         | 11,716    
|                                          | $21,390,800 | $15,163,337    | $6,227,463



As at December 31, 2003, there were $383,391 (2002  $0) of capital assets relating to unproved properties, which have been excluded from the depletion calculation.



During 2003 and 2002, no general and administrative expenses were capitalized.



Note 5.

Accrued liabilities



|                                        | As at December 31,
|--------------------------------------- | ------------------
|Accrued liabilities                     | 2003              
|Contingent interests settlement         | 1,000,000         
|Royalties                               | 355,800           
|Capital and field operating costs       | 169,063           
|Legal and accounting expenses           | 76,473            
|Audit fees                              | 40,000            
|Engineering fees                        | 36,200            
|Chairman of the Board of Directors fees | 32,353            
|Joint venture audit fees                | -                 
|                                        | $ 1,709,889       



Upon recognition of Canada Southern as an owner of facilities in the Buick Creek area of British Columbia, on June 27, 2003, Canada Southern became responsible for the payment of monies for previous years capital additions of $884,000.  In the period ended December 31, 2002, Canada Southern had accrued for its estimated $675,000 of these costs, and based on information provided by the operator, revised that amount to $884,000 in the third quarter of 2003.



Note 6.

Accrued income taxes payable



|                                                     | As at December 31,
|---------------------------------------------------- | ------------------
|Accrued income taxes payable                         | 2003              
|Current income tax expense                           | 10,201,000        
|Current income tax installments paid during the year | (425,000)         
|Adjustments from previous years                      | (31,700)          
|Other                                                | 8,003             
|                                                     | $ 9,752,303       



On February 27, 2004, Canada Southern made cash payments to the Federal and Provincial taxation authorities totaling $9,743,000.



Note 7.

Income taxes



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

|                                                                                              | Years ended December 31,
|--------------------------------------------------------------------------------------------- | ------------------------
|                                                                                              | 2003                    
|                                                                                              | 41.82%                  
|Provision for income taxes based on combined basic
Canadian federal and provincial income tax | $11,909,100             
|Non-resource income related rate reduction                                                    | (1,075,415)             
|Nondeductible Crown charges                                                                   | 384,039                 
|Nondeductible foreign exchange loss                                                           | 224,212                 
|Resource allowance                                                                            | (162,093)               
|Other                                                                                         | 1,157                   
|Non-capital loss previously unrecognized                                                      | -                       
|Depletion previously unrecognized                                                             | -                       
|Rate adjustments                                                                              | -                       
|Actual income tax expense                                                                     | $11,281,000             
|                                                                                              |                         
|Future income tax expense                                                                     | $1,080,000              
|Current income tax expense (recovery)                                                         | 10,201,000              
|Total                                                                                         | $11,281,000             



At December 31, 2003, Canada Southern had no net operating losses for Canadian income tax purposes, which were available to be carried forward to future periods.

At December 31, 2003, Canada Southern had the following oil and gas income tax deductions available to reduce future taxable income, subject to a final determination by taxation authorities:



|Canada                                            |              
|------------------------------------------------- | -------------
|Drilling, exploration and lease acquisition costs | $1,059,000   
|Undepreciated capital costs                       | 1,180,000    
|Cumulative eligible capital                       | 197,000      
|                                                  |              
|United States                                     |              
|Net operating losses                              | U.S. $962,000

Canada Southern has a future income tax liability which primarily represents the excess of recorded value of oil and gas properties over the available resource deductions for income tax purposes.  As certain of the resource deductions are restricted, there is considerable risk that these deductions will not be utilized.  Accordingly, Canada Southern has established a valuation allowance to recognize this uncertainty.



|                                                | As at December 31,
|----------------------------------------------- | ------------------
|                                                | 2003              
|Tax value of assets less than of carrying value | $2,359,410        
|Contingent interest settlement                  | (436,800)         
|Future site restoration costs                   | (790,384)         
|Other                                           | 31,593            
|Future income tax liabilities                   | 1,163,819         
|Valuation allowance                             | 932,181           
|Net future income tax liability                 | $2,096,000        



Note 8.

Future site restoration provision

|                                                                      | As at December 31,
|--------------------------------------------------------------------- | ------------------
|                                                                      | 2003              
|Balance  beginning of year                                           | $571,978          
|Future site restoration provision                                     | 285,000           
|Future site restoration provision resulting from settlement (Note 11) | 1,538,000         
|Current year expenditures                                             | (171,900)         
|Balance  end of year                                                 | $ 2,223,078       



Total future site restoration costs at December 31, 2003 were estimated to be $3,941,000.  The estimated future site restoration costs to be accrued over the remaining life of the proven reserves at December 31, 2003 were approximately $1,718,000.



In connection with the settlement of the Kotaneelee litigation, the Company agreed to be responsible for its share of abandonment liabilities in a carried interest position for the field.  The Companys share of additional abandonment and site restoration liabilities assumed is estimated to be $2,350,000 (the fair value of which was included in the provision for the period).  Upon closing the acquisition of an additional 0.67% carried interest in the Kotaneelee field which occurred on October 31, 2003, the Company assumed an estimated additional $50,000 of site restoration liabilities.



Note 9.

Commitments and Contingencies



Settlement of Kotaneelee Litigation



On September 9, 2003, the parties in the litigation concerning the Kotaneelee gas field entered into a comprehensive settlement agreement.  (For details of the litigation see Item 3. Legal Proceedings of the Companys Annual Report on Form 10-K dated March 27, 2003, as amended by the Companys Form 10-K/A dated April 30, 2003).



The settlement was finalized on October 3, 2003.  Pursuant to the settlement there has been a complete abandonment of the litigation, including the claim that the defendants failed to fully develop the field.



The Company realized a pre-income tax amount (net of certain related settlement costs: see Note 11) of $22,727,000 in the settlement, which amount represents a complete settlement of the litigation, including a recovery of the wrongfully withheld gas processing fees and related interest.  These proceeds constitute taxable income for Canadian income tax purposes upon receipt by the Company.



In connection with the settlement, Canada Southern acquired on October 31, 2003, from Perkins Holdings and Levcor International Inc., their 0.67% carried interest formerly held by Levcor, including the associated interest in the litigation.



Also in connection with the settlement, the Company agreed to be responsible for its share of abandonment and reclamation liabilities at the Kotaneelee field when they occur.  It is estimated that the Companys 30.67% share of the abandonment liabilities will amount to approximately $2,400,000.



The settlement agreement does not include any understandings with or commitments by the working interest owners to further develop the Kotaneelee field beyond those mechanisms for doing so contained in the 1959 agreement and subsequent amendments thereto.



Litigation Contingent Interests



In 1991, Canada Southern granted interests to the following officers, employees, directors, litigation counsel and consultants aggregating 7.8% (an additional .75% was granted in 1997 to litigation counsel) of any and all net recoveries from the defendants in the Kotaneelee gas field litigation due to the defendants failure to assure the earliest feasible development and marketing of gas and due to other failures:



|Holder                     | Relationship to 
Canada Southern at Date of Grant | Net
Recovery Percentage
|-------------------------- | ------------------------------------------------- | -----------------------
|Robert J. Angerer          | Litigation Counsel                                | 2.00                   
|Reasoner, Davis & Fox      | Counsel                                           | 2.00                   
|Murtha Cullina LLP         | Securities Counsel                                | 1.00                   
|G&OD INC                  | Consultants                                       | 1.00                   
|J. Peter McMahon           | Litigation Counsel                                | 1.00                   
|V. D. MacDonald            | Litigation Counsel                                | .75                    
|Estate of Charles J. Horne | President                                         | .25                    
|Benjamin W. Heath          | Director                                          | .25                    
|Betsy F. Shaw              | Vice President                                    | .10                    
|Evelyn D. Scott            | Treasurer/Secretary                               | .10                    
|Angela N. Morar            | Accountant                                        | .10                    
|                           |                                                   | 8.55                   



Subsequent to the Kotaneelee litigation settlement, the Companys Board of Directors established a committee comprised solely of directors with no direct or indirect personal interest in the contingent interests.  This independent committee of directors, comprised of Messrs. Kanik, McGinity and Stewart, consulted with independent outside counsel with regard to what amounts, if any, were payable pursuant to the contingent interests.



In early October 2003, counsel to the independent committee advised each of the contingent interest grantees that the committee had concluded, based on advice of counsel, that there was no entitlement arising under such interests.



Mr. Arthur B. ODonnell (a director of Canada Southern since 1997), a beneficial holder of a 0.333% contingent interest (derived from G&OD Inc.), Mr. James R. Joyce, a beneficial holder of a 0.333% contingent interest (derived from G&OD Inc.), and Murtha Cullina LLP (Mr. Timothy L. Largay, a partner of the firm, has been a director of Canada Southern since 1997), a grantee of a 1.00% contingent interest, had each notified counsel to the committee of their agreement with the committees conclusion.



Prior to the conclusion of the independent committee that the contingent interest grantees had no entitlement arising under such interests, the Company had received communications from counsel representing the 2.0% contingent interest granted to C. Dean Reasoner asserting entitlements arising under such grants.



The following grantees, each of whom previously served as litigation counsel to the Company, had advised the Company that they disagree with the committees conclusion:



Robert J. Angerer, Sr., Esq.

2.00%

V. A. MacDonald, Esq.

0.75%

Peter McMahon, Esq.

1.00%



These grantees had asserted that the contingent interests applied to the withheld processing fees, production revenues from the field, and other alleged recoveries which could total more than $200,000,000.  The Company did not accept their position.



The Company was advised that certain contingent interest grantees had retained legal counsel to advise them on and pursue the matter with the Company.  The grantees who disputed the Companys position were as follows:



|Holder                     | Relationship to 
Canada Southern at Date of Grant | Net
Recovery Percentage
|-------------------------- | ------------------------------------------------- | -----------------------
|Robert J. Angerer          | Litigation Counsel                                | 2.00                   
|Reasoner, Davis & Fox      | Counsel                                           | 2.00                   
|J. Peter McMahon           | Litigation Counsel                                | 1.00                   
|V. D. MacDonald            | Litigation Counsel                                | .75                    
|Estate of Charles J. Horne | President                                         | .25                    
|Benjamin W. Heath          | Director                                          | .25                    
|                           |                                                   | 6.25                   



In March 2004, in order to avoid a potentially prolonged, expensive and distracting litigation, the Company reached an agreement for an all-inclusive settlement with certain parties, including a former director and former litigation counsel to the Company, who were asserting claims of entitlement against the Companys net recoveries in the Kotaneelee litigation.  Under the terms of the settlement, which has been accrued in the Companys fourth quarter 2003 financial results, Canada Southern will pay these parties a total of $1,000,000 in return for a general release from the parties asserting the claims and an agreement by the Company not to seek an adjustment in the prior payments for professional services made to prior litigation counsel.



The independent committee of the Board, created to consider the matter of the contingent interests, remains of the view that there should be no entitlements under the contingent interest grants.  However, after lengthy consideration of the matter, involving continuous participation by outside counsel retained by the independent committee for this purpose, the independent committee reluctantly recommended that the Board of Directors approve the settlement summarized above.  It was the view of the independent committee and the Board of Directors that, on balance, the shareholders are better served by the Company focusing its human and financial resources on strategically repositioning Canada Southern rather than enduring the distraction of a potentially prolonged and expensive litigation the ultimate outcome of which could not be known with certainty.



Facilities and operations



Prior to January 2001, Canada Southern held a significant portion of its oil and gas properties in British Columbia in the form of carried interests.  In January 2001, the operators recovered all of their costs from the carried interest account through related net production revenue and payout occurred.  Effective January 1, and April 1, 2001, Canada Southern converted certain of these properties to a working interest position.



When development of the Siphon, Buick Creek and Wargen properties occurred, the operators charged certain facility and pipeline infrastructure construction costs to the carried interest account.  As a result of payout and conversion, Canada Southern has paid for and therefore believes that it should be recognized as an owner of these facilities.



On April 7 and June 27, 2003, Canada Southern became formally recognized as an owner of the Siphon and Buick Creek facilities respectively.  During 2002, all accounting adjustments related the Siphon facilities were recorded, and prior to the third quarter of 2003 accounting adjustments related to the Buick Creek facility were recorded.  Upon recognition as an owner of the Buick Creek facilities, Canada Southern became responsible for facility improvements and repairs that were completed in prior years.Canada Southern alsobecame responsible for facility operating costs since January 1, 2001.  During the third quarter of 2003, Canada Southern was invoiced for and made net payments to the operator of approximately $1,324,000 related to these issues.



Although recognition of the ownership of the Wargen facilities has yet to be formally documented, the operator provided Canada Southern with an estimate of its share of facility operating costs.  This estimate ($50,462) was recorded for accounting purposes in the fourth quarter of 2003.  Discussions with the operator of the Wargen area on the facility issue are ongoing.  Canada Southern may also be invoiced for additional operating and or capital costs in excess of this estimate at Wargen.  Possible amounts of such additional costs are currently undeterminable.



Operating lease commitment



At December 31, 2003, the future minimum rental payments and estimated operating costs applicable to Canada Southerns non-cancelable four year operating (office) lease which was effective September 1, 2003, total $318,796 as follows: $83,332 in 2004, $86,388 in 2005, $89,447 in 2006 and $59,629 in 2007.



Note 10.

Limited voting shares and stock options



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



Under the terms of Canada Southerns 1992 and 1998 stock option plans, Canada Southern is authorized to grant certain employees, directors and non-employees options to purchase Limited Voting Shares at prices based on the market price of the shares as determined on the date of the grant.  The options are normally issued for a period of five years from the date of grant.  No stock options have been issued to non-employees in the past three years.



A summary of stock option transactions for the three years ended December 31, 2003 is as follows:



|Options Outstanding | Expiration Dates       | Number of Shares | Option Prices ($)       
|------------------- | ---------------------- | ---------------- | ------------------------
|January 1, 2001     | May 2001  Jan. 2004   | 593,500          | ($7.11 weighted average)
|Granted             |                        | 45,000           | 6.81                    
|Exercised           |                        | (131,800)        | 6.79                    
|Expired             |                        | (64,000)         | 6.81                    
|December 31, 2001   | Jan. 2004  Nov. 2006  | 442,700          | ($7.21 weighted average)
|Granted             | January 2007           | 100,000          | 7.53                    
|Granted             | April 2007             | 50,000           | 6.81                    
|Expired             | June 2002              | (75,000)         | 8.36                    
|December 31, 2002   | Jan. 2004  April 2007 | 517,700          | ($7.07 weighted average)
|Granted             | June 2008              | 50,000           | 6.58                    
|Granted             | December 2008          | 30,000           | 6.97                    
|December 31, 2003   | Jan. 2004  Dec. 2008  | 597,700          | ($7.02 weighted average)



|Summary of Options Outstanding at December 31, 2003 | Total                | Exercisable | Option Prices ($)
|--------------------------------------------------- | -------------------- | ----------- | -----------------
|Granted 1999                                        | Jan. 2004            | 322,700     | 322,700          
|Granted 2001                                        | Nov. 2006            | 45,000      | 30,000           
|Granted 2002                                        | Jan.  April 2007    | 150,000     | 150,000          
|Granted 2003                                        | June  December 2008 | 80,000      | 50,000           
|Total  December 31, 2003                           |                      | 597,700     | 552,700          
|                                                    |                      |             |                  
|Options Reserved for Future Grants                  | 300,134              |             |                  



The dates that unvested options become exercisable are 15,000 on May 1, 2004, 15,000 on December 17, 2004, and the final 15,000 on December 17, 2005.



Previously granted stock options (322,700 options at $7.00 per share) expired on January 28, 2004 without exercise.



The following table outlines the calculation of basic and diluted net income per share using the treasury stock method:



|                                                                    | Years ended December 31,
|------------------------------------------------------------------- | ------------------------
|                                                                    | 2003                    
|                                                                    | Basic                   
|                                                                    |                         
|Net income                                                          | $17,196,044             
|                                                                    |                         
|Weighted average common shares outstanding                          | 14,417,770              
|Add dilutive effects:                                               |                         
|Stock options                                                       | -                       
|Weighted average common shares for net income per share calculation | 14,417,770              
|Net income per share                                                | $1.19                   



Pro forma information regarding net income and net income per share is required by Canadian and U.S. accounting standards, and has been determined as if Canada Southern had accounted for its stock options using the fair value method.  The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model.  Option valuation models require the input of highly subjective assumptions including the expected stock price volatility.  All of the valuations assumed no expected dividend.  The assumptions used in the 2001 valuation model were:  risk free interest rate  3.5%, expected life  5 years and expected volatility - .625.  The assumptions used in the 2002 valuation model were:  risk free interest rate  3.96%, expected life  5 years and expected volatility - .647.  The assumptions used in the 2003 valuation model were: risk free interest rate  3.91%, expected life  5 years and expected volatility - .615.



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

For the purpose of pro forma disclosures, the estimated fair value of the stock options is expensed evenly over the vesting period.  Canada Southerns pro forma information is as follows:

Amount

Per Share

Net income as reported  December 31, 2001

$10,182,501

$.71

Stock option expense

(122,000)

(.01)

Pro forma net income  December 31, 2001

$10,060,501

$.70



Net income as reported  December 31, 2002

$2,356,595

$.16

Stock option expense

(652,820)

(.05)

Pro forma net income  December 31, 2002

$1,703,775

$.11



Net income as reported  December 31, 2003

$17,196,044

$1.19

Stock option expense

(252,798)

(.02)

Pro forma net income  December 31, 2003

$  16,943,246

$1.17



Note 11.

Settlement of litigation



Details of the components of the Kotaneelee settlement are as follows:



|                               | Year ended December 31, 2003
|------------------------------ | ----------------------------
|Processing fees                | $22,031,459                 
|Capital pool claim             | 1,589,263                   
|Interest                       | 1,567,705                   
|                               | 25,188,427                  
|Other *                        | (1,461,349)                 
|Contingent interest settlement | (1,000,000)                 
|                               | $22,727,078                 



*Other includes legal fees recovered, recognition of fair value of abandonment liabilities assumed on settlement and amount paid for Levcor International Inc. and Perkins Holdings, Ltd. carried interest in Kotaneelee.



Note 12.

Related party transactions



In 1991 and 1997, the Company granted contingent interests in certain net recoveries from the Kotaneelee litigation.  After the settlement with the defendants was agreed upon, the Companys Board of Directors established a committee comprised solely of directors with no direct or indirect personal interest in the matter of the contingent interests.  This independent committee of directors, comprised of Messrs. Kanik, McGinity and Stewart, consulted with independent outside counsel with regard to what amounts, if any, were payable pursuant to the contingent interests.



Murtha Cullina LLP, securities counsel to Canada Southern (Mr. Timothy L. Largay, a partner of the firm, has been a director of Canada Southern since 1977) was granted a 1% interest and Directors Benjamin W. Heath and Arthur B. ODonnell were granted 0.25% and 0.333% interest, respectively.  Mr. ODonnells interest was derived from a 1% interest granted to G&OD INC in 1991.  Mr. Heath ceased to be a director of the Company on June 24, 2003.



In early October 2003, counsel to the independent committee advised each of the contingent interest grantees that the committee had concluded, based on advice of counsel, that there is no entitlement arising under such interests.  See Note 9 (Commitments and Contingencies) for further discussion.



Mr. Arthur B. ODonnell (a director of Canada Southern since 1997), a beneficial holder of a 0.333% contingent interest (derived from G&OD Inc.), Mr. James R. Joyce, a beneficial holder of a 0.333% contingent interest (derived from G&OD Inc.), and Murtha Cullina LLP, a grantee of a 1.00% contingent interest, have each notified counsel to the committee that is in agreement with the committees conclusion.



Mr. Heath (a director of Canada Southern until June 24, 2003) is not in agreement with the independent committee and has joined a group of contingent interest holders that has retained legal counsel to collect monies to which they believe they are entitled.  Mr. Heath has royalty interests in certain of Canada Southerns oil and gas properties (present and past), which were received directly or indirectly through Canada Southern.  Canada Southern and third-party operators of properties made payments pursuant to these royalties for the benefit of Mr. Heath totaling U.S. $21,007 and U.S. $40,538 in 2002, and 2001, respectively.  These amounts have been recorded at exchange values.  Mr. Heath has not provided Canada Southern with amounts received in 2003.



The law firm Murtha Cullina LLP was paid fees of $134,135 for legal services for the year 2003 ($153,978 for 2002 and $230,992 for 2001).  At December 31, 2003, $59,280 was included in accounts payable to Murtha Cullina (2002 - $1,698).



Kanik and Associates Ltd. (controlled by Mr. Kanik, a director of the Company) was paid fees of $83,334 for consulting services during the year (2002 - $66,667, 2001 - $0).  The consulting contract with Kanik and Associates Ltd. was terminated subsequent to settlement of the Kotaneelee litigation.  At December 31, 2003, amounts included in accounts receivable was $8,333 (2002 - $0) from Kanik and Associates Ltd.



All payments to related parties have been recorded at the exchange amount.  Amounts payable at the year end are due on demand and do not bear interest.



Note 13.

Other financial information





|                                           | December 31
|------------------------------------------ | -----------
|                                           | 2003       
|                                           |            
|Royalty payments (1)                       | $2,816,751 
|                                           |            
|Rent payments                              | $57,889    
|                                           |            
|Interest and line of credit fees           | $ 749      
|                                           |            
|Large corporation & capital tax payments   | $ 425,000  
|                                           |            
|Accounting and administrative services (2) | $ 16,850   



(1)

Oil and gas sales are reported net of royalties incurred. The amount for the year ended December 31, 2003 includes $1,662,234 (2002 - $1,481,319, 2001 - $2,384,723) of royalties paid out of carried interest revenues.



(2)

G&OD INC, a Connecticut, United States based company provided certain accounting and financial services to Canada Southern for many years until December 31, 2002.



Note 14.

U. S. GAAP differences



The reconciliation of net income between Canadian and U.S. GAAP is summarized in the table below:



|                                                                           | Years ended December 31,
|-------------------------------------------------------------------------- | ------------------------
|                                                                           | 2003                    
|Net income  Canadian GAAP                                                 | $17,196,044             
|Depletion expense (a)                                                      | 507,975                 
|Future site restoration provision (a)                                      | (285,000)               
|Accretion of asset retirement obligation (a)                               | (101,915)               
|Income taxes (a)                                                           | (50,627)                
|Income before change in accounting principle 
- U.S. GAAP                  | 17,266,477              
|Cumulative effect of change in accounting
principle (a)                    | 104,669                 
|Net income  U.S. GAAP                                                     | 17,371,146              
|Change in value of available for sale securities (b)                       | 19,131                  
|Other comprehensive income                                                 | $17,390,277             
|                                                                           |                         
|U.S. GAAP  cumulative effect of change in accounting principle per share: |                         
|Basic                                                                      | $.007                   
|Diluted                                                                    | $.007                   
|                                                                           |                         
|U.S. GAAP  net income per share                                           |                         
|Basic                                                                      | $1.20                   
|Diluted                                                                    | $1.20                   
|                                                                           |                         
|Average number of shares outstanding:                                      |                         
|Basic                                                                      | 14,417,770              
|Diluted                                                                    | 14,423,667              
|                                                                           |                         



The balance sheet information for the Canadian and U.S. GAAP differences is summarized in the table below:



|Balance sheet information                |                  
|---------------------------------------- | -----------------
|                                         | December 31, 2003
|                                         | Canadian
GAAP    
|                                         |                  
|Current assets (b)                       | $ 52,621,494     
|Oil and gas properties and equipment (a) | 8,906,029        
|                                         | $ 61,527,523     
|                                         |                  
|Current liabilities                      | $ 14,409,955     
|Future income tax liability (a)(b)       | 2,096,000        
|Future site restoration provision (a)    | 2,223,078        
|Share capital                            | 41,689,603       
|Retained Earnings (Deficit) (a)          | 1,108,887        
|Accumulated other comprehensive          |                  
|income (b)                               | -                
|                                         | $ 61,527,523     



(a)  FASB Statement No. 143 Accounting for Asset Retirement Obligations



In June 2001, the FASB issued Statement No. 143 Accounting for Asset Retirement Obligations. (FAS 143)  This statement requires the fair value of a liability for an asset retirement obligation (ARO)be recognized in the period in which it is incurred if a reasonable estimate of the fair value of a liability can be made.  The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.  The requirements are effective for fiscal years beginning on or after June 15, 2002.  The effect of this pronouncement on the financial position of Canada Southern and the resulting Canadian and U.S. GAAP differences are contained in the table above.



Upon adoption of FASB 143 as at January 1, 2003, oil and gas properties and equipment would be increased by $355,919 which is the calculated present value of the retirement obligation when the properties were acquired of $593,450, less the related adjustment to past accumulated depletion of $237,531.  The asset retirement obligation (ARO) for the oil and gas assets is $747,991, which would result in an increase in the future site restoration provision of $176,013 from the $571,978 provided for in the December 31, 2002 audited financial statements.  The cumulative effect of the change in prior years resulted in a charge to income of $104,669 (net of deferred income taxes of $81,025) which is included in income for the year ended December 31, 2003. The accounting change also increased net income for 2003, before the cumulative effect of the accounting change, by $70,433.



During the period ended December 31, 2003, and in connection with the settlement of the Kotaneelee litigation the Company assumed an additional $2,350,000 of abandonment liabilities at Kotaneelee.  The net present value of this liability has been included in the ARO liability at December 31, 2003.  Upon closing of the acquisition of an additional 0.67% carried interest share in the Kotaneelee field on October 31, 2003, an additional $50,000 of abandonment liabilities was assumed.



SFAS No. 143 calls for the ARO liability to include as a component of expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainty inherent in the obligations.  This is referred to as the market-risk premium.  No amount of market-risk premium has been included in the estimate of the Companys ARO liability as management does not believe there to be sufficient evidence in the oil and gas industry to estimate any such market premium.



The following table describes all changes to the Companys asset retirement obligation liability:



|                                                 | Year ended December 31,
|------------------------------------------------ | -----------------------
|                                                 | 2003                   
|Asset retirement obligation, beginning of period | $747,991               
|Liabilities incurred                             | 1,758,980              
|Accretion expense                                | 101,915                
|Cash expenditures for site restoration           | (171,900)              
|Asset retirement obligation, end of period       | $ 2,436,986            



The pro forma effects of the application of FASB 143 as if it had been adopted on January 1, 2001 (rather than January 1, 2003) are presented below:



|                                                                                      | Years ended December 31,
|------------------------------------------------------------------------------------- | ------------------------
|                                                                                      | 2003                    
|Pro forma amounts assuming the accounting change is applied retroactively net-of-tax: |                         
|                                                                                      |                         
|Pro forma net income                                                                  | $17,266,477             
|                                                                                      |                         
|Pro forma net income per
share:                                                       |                         
|Basic                                                                                 | $1.20                   
|Diluted                                                                               | $1.20                   





The pro forma asset retirement obligation liability balances as if FASB 143 had been adopted on January 1, 2001 (rather than January 1, 2003) are as follows:









|                                                                                      | Years ended December 31,
|------------------------------------------------------------------------------------- | ------------------------
|                                                                                      | 2003                    
|Pro forma amounts of liability for asset retirement obligation at beginning of period | $747,991                
|                                                                                      |                         
|Pro forma amounts of liability for asset retirement obligation at end of period       | $2,761,986              



(b)  Other Comprehensive Income



Classifications within other comprehensive income relate to unrealized gains (losses) on certain investments in equity securities.  During 1998, the Company wrote down the value of its interest in the Tapia Canyon, California heavy oil project to a nominal value.  During August 1999, the project was sold and the Company received shares of stock in the purchaser. The purchaser has become a public company (Sefton Resources, Inc), which is listed on the London Stock Exchange (trading symbol SER).  At December 31, 2003, the Company owned approximately 1% (2002  3%) of Sefton Resources, Inc. (Sefton) with a fair market value of $82,969 (December 31, 2002 - $58,443) and a carrying value of $1.00.



Under U.S. GAAP, the Sefton shares would be classified as available-for-sale securities and recorded at fair value at December 31, 2003.  This would result in other comprehensive income for the year ended December 31, 2003 (other comprehensive loss for the year ended December 31, 2002.  In addition, the balance sheet would reflect Marketable Securities in the amount of $82,969 (December 31, 2002 - $58,443) with a corresponding credit to Shareholders Equity  Accumulated other comprehensive income in the same amount.





CANADA SOUTHERN PETROLEUM LTD.

SUPPLEMENTARY INFORMATION ON OIL AND

GAS PRODUCING ACTIVITIES

(unaudited)



|                                                                                     | Years ended December 31,             
|------------------------------------------------------------------------------------ | -------------------------------------
|Total Sales Volumes (before royalties)                                               | 2003                                 
|Carried interests (mcf)                                                              | 2,228,782                            
|Carried interests (bbls)                                                             | 167                                  
|                                                                                     |                                      
|Natural gas (mcf)                                                                    | 742,596                              
|Oil and liquids (bbls)                                                               | 11,052                               
|                                                                                     |                                      
|boes (6 mcf = 1 boe)                                                                | 506,449                              
|boes per day                                                                        | 1,388                                
|                                                                                     |                                      
|mcfes (1 bbl = 6 mcfe)                                                              | 3,038,692                            
|mcfes per day                                                                       | 8,325                                
|                                                                                    
|                                                                                    
|The corporate sales mix between oil and gas is as follows:                          
|                                                                                    
|Sales Mix Percent                                                                   
|Natural gas (mcf)                                                                    | 98                                   
|Oil and liquids (mcfe)                                                               | 2                                    
|                                                                                     |                                      
|                                                                                     |                                      
|The corporate netback analysis for carried interest sales is as follows:            
|Netback Analysis                                                                     |                                      
|Carried interests (per mcfe)                                                         |                                      
|Sales                                                                                | $5.76                                
|Royalties                                                                            | (.75)                                
|Transportation                                                                       | (.58)                                
|Net Sales                                                                            | 4.43                                 
|Lease operating expenses                                                             | (.33)                                
|Carried interest capital                                                             | (.18)                                
|Field netback                                                                        | $3.92                                
|                                                                                     |                                      
|The corporate netback analysis for working and royalty interest sales is as follows:
|                                                                                     |                                      
|Working and royalty interests (per mcfe)                                             |                                      
|Sales                                                                                | $5.90                                
|Royalties                                                                            | (1.43)                               
|Net Sales                                                                            | 4.47                                 
|Lease operating expenses                                                             | (1.55)                               
|Field netback                                                                        | $2.92                                
|                                                                                     |                                      
|Definition of Terms                                                                 
|boe = barrel of oil equivalent                                                       | mcfe = thousand cubic feet equivalent
|mcf = thousand cubic feet of natural gas                                             | bbl = barrel of oil                  
|                                                                                    



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



All amounts below except for costs, acreage, wells drilled and present activities relate to Canada.  Gilbert Laustsen Jung Associates Ltd., the independent reserves evaluator appointed by the Board of Directors, provided oil and natural gas reserve data and the information relating to cash flows for the year 2003 (Paddock Lindstrom & Associates Ltd. for the years 2001  2002).  No reserve estimates were filed with any other Federal authority or agency.



Estimated net (after royalty) quantities of proved liquids and gas reserves:



|                                 | Liquids | Natural Gas
|-------------------------------- | ------- | -----------
|Proved reserves:                 | (bbls)  | (Bcf)      
|December 31, 2001                | 20,600  | 12.083     
|Revisions of previous estimates  | 47,138  | 1.631      
|Production*                      | (7,038) | (3.244)    
|December 31, 2002                | 60,700  | 10.470     
|Revisions of previous estimates  | 3,257   | (.953)     
|Reserve additions and extensions | -       | .445       
|Acquisitions                     | -       | .078       
|Production *                     | (8,606) | (2.508)    
|December 31, 2003                | 55,351  | 7.532      
|                                 |         |            
|Proved developed reserves:       |         |            
|December 31, 2001                | 20,600  | 12.083     
|December 31, 2002                | 60,700  | 10.470     
|December 31, 2003                | 55,351  | 7.532      



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



Results of oil and gas operations:





|                                            | Years ended December 31,
|------------------------------------------- | ------------------------
|                                            | 2003                    
|Income:                                     |                         
|Proceeds from carried interests             | $8,749,422              
|Natural gas and liquid sales                | 3,614,982               
|Settlement of litigation                    | 22,727,078              
|                                            | 35,091,482              
|Costs and expenses:                         |                         
|Lease operating costs                       | 1,257,827               
|Depletion depreciation, and amortization    | 2,282,000               
|Provision for future site restoration costs | 285,000                 
|Adjustment  U.S. GAAP                      | (223,000)               
|Accretion expense                           | 101,000                 
|Current income tax expense (recovery)       | 10,201,000              
|Future income tax expense                   | 1,080,000               
|                                            | 14,983,827              
|Net income from operations                  | $20,107,655             



Capitalized costs of oil and gas activities:





|                                                               | Years ended December 31,
|-------------------------------------------------------------- | ------------------------
|                                                               | 2003                    
|Acquisition costs                                              | $   849,000             
|Exploration                                                    | 3,382,000               
|Development                                                    | 675,000                 
|Revisions for site restoration                                 | 484,000                 
|Site restoration obligations on adoption of           FASB 143 | 356,000                 
|Site restoration obligations incurred during         the year  | 1,759,000               
|Total                                                          | $7,505,000              



Standardized measure of discounted future net cash flows relating to proved oil

and gas reserve quantities during the following period (in thousands of dollars):





|                                                                    | Years ended December 31,
|------------------------------------------------------------------- | ------------------------
|                                                                    | 2003                    
|                                                                    |                         
|Future cash inflows                                                 | $40,973                 
|Future development and production costs                             | (9,087)                 
|                                                                    | 31,886                  
|Future income tax expense*                                          | (10,850)                
|Future net cash flows                                               | 21,036                  
|10% annual discount                                                 | (5,916)                 
|Standardized measure of discounted                                  |                         
|future net cash flows                                               | $15,120                 
|Fair value of abandonment  FASB 143                                | (2,762)                 
|Standardized measure of discounted
future net cash flows  FASB 143 | $12,358                 

*

Reflects total tax pools for the years 2003, 2002 and 2001 that may be used to offset oil and gas income. The tax pools are comprised of carry forward of exploration, development and lease acquisition costs, undepreciated capital costs and earned depletion of $2,436,000, $3,786,000, and $9,416,000 for the years 2003, 2002, and 2001, respectively.



Current prices used in the above estimates were based upon selling prices at the wellhead at December 31, of each year as follows: 2003 - $5.18 per mcf, 2002 - $4.95 per mcf and 2001 - $2.66 per mcf.  Current costs were based upon estimates made by consulting engineers at the end of each year.



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



| | Years ended December 31,
| | ------------------------



|                                | 2003        | 2002        | 2001        
|------------------------------- | ----------- | ----------- | ------------
|Changes due to:                 |             |             |             
|Sale of properties              | $         - | $         - | $    (3,197)
|Acquisition of properties       | 260         | -           | -           
|Extensions and discoveries      | 1,299       | 1,120       | -           
|Prices and production costs     | (2,531)     | 11,289      | (24,171)    
|Future development costs        | (191)       | (384)       | (1,461)     
|Sales net of production costs   | (11,107)    | (6,580)     | (28,380)    
|Development costs incurred      |             |             |             
|during the year                 | 675         | 299         | 832         
|Revisions of quantity estimates | (2,761)     | 7,779       | (52,195)    
|Accretion of discount           | 3,527       | 1,977       | 9,088       
|Net change in income taxes      | 6,205       | (10,505)    | 30,311      
|Other changes                   | (1,258)     | -           | -           
|Net change                      | $ (5,882)   | $ 4,995     | $ (69,173)  



Selected quarterly financial data (unaudited)



The following is a summary (in thousands) except for per share amounts of the quarterly results of operations for the years 2003 and 2002:  See Managements Discussion and Analysis of Financial Condition and Results of Operations.



|2003                                            | QTR 1   | QTR 2   | QTR 3   | QTR 4  
|----------------------------------------------- | ------- | ------- | ------- | -------
|                                                | ($)     | ($)     | ($)     | ($)    
|Total revenues                                  | 4,142   | 4,105   | 2,364   | 2,572  
|Costs and expenses                              | (1,796) | (1,597) | (1,689) | (2,351)
|Settlement of litigation - actual and
potential | -       | -       | 23,727  | (1,000)
|Income tax provision                            | (1,035) | (954)   | (9,544) | 252    
|Net income (loss)                               | 1,311   | 1,554   | 14,858  | (527)  
|Per share (basic)                               | .09     | .11     | 1.03    | (0.04) 
|Per share (diluted)                             | .09     | .11     | 1.03    | (0.04) 
|Average number of shares outstanding            | 14,418  | 14,418  | 14,418  | 14,418 
|                                                |         |         |         |        
|2002                                            | QTR 1   | QTR 2   | QTR 3   | QTR 4  
|                                                | ($)     | ($)     | ($)     | ($)    
|Total revenues                                  | 2,393   | 2,521   | 2,206   | 2,817  
|Costs and expenses                              | (1,492) | (1,744) | (1,300) | (1,531)
|Income tax provision                            | (494)   | (228)   | (398)   | (393)  
|Net income                                      | 407     | 549     | 508     | 893    
|Per share (basic)                               | .03     | .04     | .04     | .05    
|Per share (diluted)                             | .03     | .04     | .04     | .05    
|Average number of shares outstanding            | 14,418  | 14,418  | 14,418  | 14,418 



Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure



None.



Item 9A.

Controls and Procedures



(a)  Disclosure Controls and Procedures.  The Company's management, with the participation of the Company's Chief Financial Officer and Acting President, has evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the period covered by this report.  Based on such evaluation, the Companys Chief Financial Officer and Acting President has concluded that, as of the end of such period, the Company's disclosure controls and procedures were effective, in all material respects, to ensure that information required to be disclosed in the reports the Company files and submits under the Exchange Act is recorded, processed, summarized and reported as and when required.



It should be noted, however, that even the most well designed and executed control systems are subject to inherent limitations and assumptions about the likelihood of future events and as a result, an internal control system can provide reasonable, but not absolute, assurance that its objectives will be met under all potential future conditions.  Because of these and other inherent limitations of control systems, there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.  The Company's Chief Financial Officer and Acting President has concluded that the Companys disclosure controls and procedures are effective at a reasonable assurance level as of the end of the period covered by this report.



(b)  Internal Control Over Financial Reporting.  There have not been any changes in the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15 (f) under the Exchange Act) during the fiscal quarter to which this report relates (the registrants fourth fiscal quarter in the case of an annual report) that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.



PART III



For information concerning Item 10  Directors and Executive Officers of Canada Southern, Item 11  Executive Compensation, Item 12  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters (except for the Equity Compensation Plan information), Item 13  Certain Relationships and Related Transactions, and Item 14  Principal Accountant Fees and Services see the Proxy Statement of Canada Southern Petroleum Ltd. relative to the Annual Meeting of Shareholders to be held during June 2004, to be filed with the Securities and Exchange Commission, which information is incorporated herein by reference.



Item 10.

Directors and Executive Officers of Canada Southern



Item 11.

Executive Compensation



Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters



EQUITY COMPENSATION PLAN INFORMATION



The following table provides information about the Companys common stock that may be issued upon the exercise of options and rights under all of the Companys existing equity compensation plans as of December 31, 2003, including the 1992 and 1998 Stock Option Plans.



|Plan Category                                              | Number of Securities to be issued upon exercise of outstanding options, warrants and rights
(a) (#) | Weighted average exercise price of outstanding options, warrants and rights
(b) ($) | Number of securities remaining available for issuance under equity compensation plans (excluding securities reflected in column (a))
(c) (#)
|---------------------------------------------------------- | --------------------------------------------------------------------------------------------------- | ----------------------------------------------------------------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------
|Equity compensation plans approved by security holders     | 597,700 (1)                                                                                         | $7.02                                                                               | 300,134(2)                                                                                                                                  
|Equity compensation plans not approved by security holders | -                                                                                                   | -                                                                                   | -                                                                                                                                           
|Total:                                                     | 597,700                                                                                             | $7.02                                                                               | 300,134                                                                                                                                     



(1)

1998 Stock Option Plan - 399,866 options issued.

(1)

1992 Stock Option Plan - 197,834 options issued.

(2)

Balance remaining under stock option plan.



The Company's 1992 Stock Option Plan was approved by the shareholders of the Company on December 9, 1992.  600,000 shares of the Company's Limited Voting Shares were authorized for issuance under the terms of the plan.  Options under the plan may be granted only to directors, officers, key employees of, and consultants and consulting firms to, (i) the Company, (ii) subsidiary corporations of the Company from time to time and any business entity in which the Company from time to time has a substantial interest.  The exercise price of each option to be granted under the plan shall not be less than the fair market value of the stock subject to the option on the date of grant of the option.  Of the 600,000 authorized shares under the terms of the 1992 plan, no shares remain available for future issuance under the 1992 Stock Option Plan.



The Company's 1998 Stock Option Plan was approved by the shareholders of the Company on June 11, 1998.  700,000 shares of the Company's common stock were authorized for issuance under the terms of the plan.  Options under the plan may be granted only to directors, officers, key employees of, and consultants and consulting firms to, (i) the Company, (ii) subsidiary corporations of the Company from time to time and any business entity in which the Company from time to time has a substantial interest.  The exercise price of each option to be granted under the plan shall not be less than the fair market value of the stock subject to the option on the date of grant of the option.  As at December 31, 2003, a total of 399,866 options were granted under the plan and 300,134 options were available for future grants.



Item 13.

Certain Relationships and Related Transactions



Item 14.

Principal Accountant Fees and Services



PART IV



Item 15.

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



(a)

(1)

Financial Statements



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

|                                                                          | PageReference
|------------------------------------------------------------------------- | -------------
|                                                                          |              
|Auditors Report                                                          | 49           
|Consolidated Balance Sheets as at December 31, 2003 and 2002              | 50           
|For the years ended December 31, 2003, 2002 and 2001                      |              
|Consolidated Statements of Operations and Deficit                         | 51           
|Consolidated Statements of Cash Flows                                     | 52           
|Notes to Consolidated Financial Statements                                | 53-73        
|Supplementary Information On Oil and Gas Producing Activities (unaudited) | 74-77        
|Selected quarterly financial data (unaudited)                             | 78           





(2)

Consolidated Financial Statement Schedules



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



(b)

Reports on Form 8-K



None.



(c)

Exhibits



The following exhibits are filed as part of this report:



Item Number



2.

Plan of acquisition, reorganization, arrangement,

liquidation or succession



Not applicable.



3.

Articles of Incorporation and By-Laws



(a)  Memorandum of Association as amended on June 30, 1982, May 14, 1985 and April 7, 1988 filed as Exhibit 4B to Form S-8 as filed on November 25, 1998 (File number 001-03793) is incorporated by reference.



(b)  By-laws, as amended, filed as Exhibit 4C to Form S-8 as filed on November 25, 1998 (File number 001-03793) are incorporated by reference.



4.

Instruments defining the rights of security holders, including indentures



None.



9.

Voting trust agreement



None.



10.

Material contracts



(a)

Agreements relating to Kotaneelee Gas Field:



(1.)  Copy of Agreement dated May 28, 1959 between Canada Southern et al. and Home Oil Company Limited et al. and Signal Oil and Gas Company filed as Exhibit 10(a) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.

(2.)  Copies of Supplementary Documents to May 28, 1959 Agreement (see (1) above), dated June 24, 1959, consisting of Guarantee by Home Oil Company Limited and Pipeline Promotion Agreement, filed as Exhibit 10(a) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.

(3.)  Copy of Modification to Agreement dated May 28, 1959 (see (1) above); made as of January 31, 1961, filed as Exhibit 10(a) to Report of Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.

(4.)  Copy of Agreement dated April 1, 1966 among Canada Southern et al. and Dome Petroleum Limited et al., filed as Exhibit 10(a) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.

(5.)  Copy of Letter Agreement dated February 1, 1977 between Canada Southern and Columbia Gas Development of Canada, Ltd. for operation of the Kotaneelee gas field, filed as Exhibit 10(a) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.



(b)  Copy of Agreement dated January 28, 1972 between Canada Southern and Panarctic Oils Ltd. for development of the offshore Arctic Islands gas fields, filed as Exhibit 10(b) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.



(c)  Stock Option Plan adopted December 9, 1992, filed as Exhibit 10(c) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.



(d)  Stock Option Plan effective July 1, 1998 filed as Exhibit A to Schedule 14A Information (Proxy Statement) as filed on May 1, 1998 (File number 001-03793) is incorporated by reference.



(e)  Minutes of Settlement between Canada Southern Petroleum Ltd. and the defendants of the Kotaneelee litigation filed as Exhibit 10.1 to Form 10-Q/A as filed on November 18, 2003 for the period ended September 30, 2003,. is incorporated herein by reference.



11.

Statement re computation of per share earnings



None.



12.

Statement re computation of ratios



None.



13.

Annual report to security holders, Form 10-Q or

quarterly report to security holders



Not applicable.



16.

Letter re change in certifying accountant



Not applicable.



18.

Letter re change in accounting principles



None.



21.

Subsidiaries of Canada Southern



Canpet Inc. incorporated in Delaware on August 3, 1973.

C. S. Petroleum Limited incorporated in Nova Scotia on December 15, 1981.



22.

Published report regarding matters submitted to vote of

security holders



None.



23.

Consents of experts and counsel



(a)  Gilbert Laustsen Jung Associates Ltd., filed herein.

(b)  Ernst & Young, LLP, filed herein.



24.

Power of attorney



Power of attorney, filed herein.



99.

Additional exhibits



(a)

Statement of Claim filed on October 27, 1989 against Columbia Gas Development of Canada Ltd., Amoco Production Company, Dome Petroleum Limited, Amoco Canada Petroleum Company Ltd., Mobil Oil Canada Ltd. and Esso Resources of Canada Ltd. in the Court of Queen's Bench of Alberta Judicial District of Calgary, Alberta, Canada, filed as Exhibit 99(a) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.

(b)

Amended Statement of Claim, amending the October 27, 1989 Statement of Claim, filed on March 12, 1990, filed as Exhibit 99(b) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.

(c)

Amended Statement of Claim in the same action, filed on November 17, 1993, filed as Exhibit 99(c) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.

(d)

Amended Statement of Third Party Notice by Amoco Canada Production Company Ltd. and Amoco Production Company, filed November 17, 1993 in the same action, filed as Exhibit 99(d) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.

(e)

Amended Statement of Defense to Third Party Notice by Anderson Oil & Gas Inc. (formerly Columbia Gas Development of Canada Ltd.) filed January 27, 1994 in the same action, filed as Exhibit 99(e) to Report on Form 10-K for the year ended December 31, 1998 (File number 001-03793) is incorporated herein by reference.



(f)

The decision of the trial court in Calgary regarding the Kotaneelee gas filed litigation is incorporated by reference to Current Report on Form 8-K/A filed on October 1, 2001 ((File number 001-03793).



(g)

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 executed by Randy L. Denecky.



(d)

Financial Statement Schedules



None.

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)                    
|                                                                                                                                                                                                              |                                 
|                                                                                                                                                                                                              | By /s/ Randy L. Denecky         
|                                                                                                                                                                                                              | Randy L. Denecky                
|Dated: March 24, 2004                                                                                                                                                                                         | Acting President and Chief      
|                                                                                                                                                                                                              | Financial Officer               
|Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
|                                                                                                                                                                                                              |                                 
|                                                                                                                                                                                                              |                                 
|By /s/ Myron F. Kanik*                                                                                                                                                                                        | By /s/ Randy L. Denecky         
|Myron F. Kanik                                                                                                                                                                                                | Randy L. Denecky                
|Director                                                                                                                                                                                                      | Acting President and Chief      
|                                                                                                                                                                                                              | Financial and Accounting Officer
|                                                                                                                                                                                                              |                                 
|Dated: March 24, 2004                                                                                                                                                                                         | Dated: March 24, 2004           
|                                                                                                                                                                                                              |                                 
|                                                                                                                                                                                                              |                                 
|                                                                                                                                                                                                              |                                 
|By /s/ Timothy L. Largay*                                                                                                                                                                                     | By /s/ D. Michael G. Stewart*   
|Timothy L. Largay                                                                                                                                                                                             | D. Michael G. Stewart           
|Director                                                                                                                                                                                                      | Director                        
|                                                                                                                                                                                                              |                                 
|Dated: March 24, 2004                                                                                                                                                                                         | Dated: March 24, 2004           
|                                                                                                                                                                                                              |                                 
|                                                                                                                                                                                                              |                                 
|                                                                                                                                                                                                              |                                 
|By /s/ Arthur B. ODonnell*                                                                                                                                                                                   | By /s/ Richard C. McGinity*     
|Arthur B. ODonnell                                                                                                                                                                                           | Richard C. McGinity             
|Director                                                                                                                                                                                                      | Director                        
|                                                                                                                                                                                                              |                                 
|Dated: March 24, 2004                                                                                                                                                                                         | Dated: March 24, 2004           
|                                                                                                                                                                                                              |                                 



* Signed by Randy L. Denecky, as attorney-in-fact.

INDEX TO EXHIBITS





23.

(a)

Consent of Independent Petroleum Engineers



(b)

Consent of Independent Auditors



24.

Power of Attorney



31.

Rule 13a-14 certification of Randy L. Denecky, President and Chief Financial Officer.



32.

Certification pursuant to Section 906 of the Sarbanes Oxley Act by Randy L. Denecky, President and Chief Financial Officer