SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
---------------------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission file number 1-3793
CANADA SOUTHERN PETROLEUM LTD.
(Exact name of registrant as specified in its charter)
NOVA SCOTIA, CANADA 98-0085412
State or other jurisdiction of (I.R.S. Employer
incorporation or organization Identification No.)
Suite 1410, One Palliser Square
125 Ninth Avenue, S.E.
Calgary, Alberta CANADA T2G OP6
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (403) 269-7741
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
Limited Voting Shares, $1 (Canadian) per share NASDAQ SmallCap Market
Pacific Stock Exchange
Boston Stock Exchange
Toronto Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
(Title of Class)
NONE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. |X| Yes |_| No
<PAGE>
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K ss.229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [ X ]
The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately U.S. $107,468,000 at March 23, 1998.
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
Limited Voting Shares, par value $1.00 (Canadian) per share, 14,234,740
shares outstanding as of March 23, 1998.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement of Canada Southern Petroleum Ltd. related to
the Annual Meeting of Shareholders for the year ended December 31, 1997, which
is incorporated into Part III of this Form 10-K.
<PAGE>
TABLE OF CONTENTS
Page
PART I
Item 1. Business 4
Item 2. Properties 15
Item 3. Legal Proceedings 22
Item 4. Submission of Matters to a Vote of Security Holders 25
PART II
Item 5. Market for the Company's Limited Voting Shares and Related
Stockholder Matters 26
Item 6. Selected Financial Data 28
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 29
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 34
Item 8. Financial Statements and Supplementary Data 35
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 56
PART III
Item 10. Directors and Executive Officers of the Company 56
Item 11. Executive Compensation 56
Item 12. Security Ownership of Certain Beneficial Owners and Management 56
Item 13. Certain Relationships and Related Transactions 56
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 57
Unless otherwise indicated, all dollar figures set forth are expressed in
Canadian currency. The exchange rate at March 23, 1998 was $1.00 Canadian = U.S.
$.7046.
<PAGE>
PART I
Item 1. Business
The nature of Canada Southern Petroleum Ltd.'s (the "Company" or
"Canada Southern") business is described at Item 1(c) herein, and a description
of its principal oil and gas properties in Canada appears in Item 2 herein. For
additional information regarding the development of the Company's business, see
"Properties" and "Supplemental Information on Oil and Gas Activities".
(a) General Development of Business
Yukon Territory - The Kotaneelee Field
The Company's principal asset is a 30% carried interest in the
Kotaneelee gas field located on Ex-Permit 1007 (31,888 gross acres or 9,566 net
acres) in the extreme southeastern corner of the Yukon Territory. This partially
developed field is connected to a major pipeline system. Two wells have been
completed to date that are capable of an estimated output of in excess of 60
million cubic feet per day, the capacity of the field dehydration plant. Present
production is approximately 40 million cubic feet ("mcf") per day. The operator
is Anderson Exploration Ltd., which acquired all of Columbia Gas Development of
Canada's interests. See "Legal Proceedings " for a discussion of the Kotaneelee
Litigation concerning this asset.
Production at Kotaneelee commenced in February 1991. According to
government reports, total production in billion cubic feet ("bcf") from the
Kotaneelee gas field since 1991 has been as follows:
Calendar Year Production (bcf)
------------- ----------------
1991 8.1
1992 18.0
1993 17.5
1994 16.7
1995 15.7
1996 15.2
1997 14.4
In a 1989 application to the National Energy Board, a reserve study by
the operator estimated total gas in place at 1.6 trillion cubic feet with proved
and probable recoverable reserves of 781 BCF.
<PAGE>
At present, the Company does not receive any cash payments from
production but is credited with 30% of the gross revenues until a like percent
of the working interest costs, exclusive of any interest expense, are recovered
by the operator. The Company will not receive any payment from production
revenues until its share of the working interest costs are recovered. When the
deferred costs are recovered, 30% of gross revenues (net of gross overriding
royalties) less 30% of current working interest costs will be paid to the
Company. Gross overriding royalties amount to 10% to the Canadian Federal
government and 4.06% to certain individuals. The operator has reported to the
Company development costs totaling approximately $88,043,000 and, of that
amount, approximately $19,807,000 (Company share $5,942,000) remained to be
recovered at December 31, 1997. The Company has contested the amount of costs
that have been charged to the carried interest account. It is estimated that the
Company will not begin to receive proceeds from the Kotaneelee gas field before
the year 2000, based upon a price of $1.39 per mcf (average 1997 price) and
current production rates. The period before payment to the Company begins may be
shorter or longer, depending on prevailing market conditions and the results of
the Kotaneelee Litigation.
British Columbia Properties
The Company's major source of income is from oil and gas fields in
northeast British Columbia. These fields, developed in the 1950's and 1960's,
produce revenue through both working and carried interest agreements. The major
working interests in these fields are operated by Canadian Natural Resources
Ltd. ("CNRL"). Petro Canada had been the primary operator of the Company's
carried interest lands in British Columbia.
In addition to the producing properties, since 1988 the Company has
acquired a number of leases in northeast British Columbia by participating in
British Columbia land sales. To date five wells have been drilled on the lands
resulting in three oil discoveries and two dry holes. Currently, the Company is
defining the prospects by geophysics. Work completed to date indicates that
seven of the prospects justify drilling. The Company estimates that the drilling
costs (excluding completion costs) of the seven prospects would be $1,625,000.
However, as most of these wells would be wildcat wells (exploratory wells), the
Company plans to reduce its risk by selling or farming out part of its interest.
The timing of the drilling is dependent on the availability of funds and the
Company anticipates that its average net cost per well (assuming a farmout or
sale) would be approximately $75,000, or a total of $525,000, for drilling and
completion costs.
The Company's main producing properties are located in the Peejay
fields in British Columbia. Although these fields have been producing for over
20 years, there is still the potential for additional exploration and
development. The 1993 sale of the field by the majority owner and the
appointment of a new operator resulted in new field activity. The most recent
developments have included new work programs in the West Peejay and Peejay Unit
#3 areas, as well as, the nearby Beaverdam area.
<PAGE>
At West Peejay a water flood was initiated in 1997 and three wells were
drilled resulting in three new oil wells and one existing well was converted to
a water injector. This will increase the allowable production in the field from
359 bpd to 503 bpd. The Company has an approximate 14% interest in the oil and
gas production.
The Peejay Unit #3 in which the Company has a 10.18% interest has been
declining for several years and the operator has proposed producing part of the
gas cap concurrent with the oil production. One development well was drilled in
1997 and is now producing oil.
In the Beaverdam area the operator has indicated plans to drill
additional wells to follow up the 3 wells drilled in the 1993/1994 winter
drilling season.
As of December 31, 1997, the Company held approximately 18,732 gross
acres (4,434 net acres) in this area. The Company owns interest in the
following units:
Unit Company
Acreage %
Peejay Unit #1 4,529 3.1643
Weasel Unit #2 1,569 15.4136
Peejay Unit #3 5,923 10.1775
The Company also holds interests in 10 oil wells (2.64 net wells) and
10 gas wells. (2.28 net wells) not included in the above units. The Company
estimates that the capital costs for its interests in the West Peejay field will
aggregate approximately $200,000 for 1998.
In the Paradise area, one well that was drilled and completed as an oil
well in 1997 proved to be non-commercial. Another oil well, which was drilled
under a farmout arrangement, is currently suspended. An additional farmout well
which was drilled in late 1997 has been plugged and abandoned.
The Company also has interests at Buick Creek, Wargen and Siphon. The
Siphon and Wargen fields have new operators. As these properties are held under
the carried interest agreements, the Company is not aware of any proposed
exploration and development plans for these properties, but anticipates the
change of operator will cause new work to be done. In late 1997, there was
activity in the Siphon field, but the Company has no information on the results.
<PAGE>
Arctic Islands
As of December 31, 1997, the Company held working interests in 45,100
gross acres (1,817 net acres) and carried interests in 133,260 gross acres
(37,255 net acres) in the Sverdrup Basin, located in the Arctic Islands. The
Hecla, Whitefish, Drake Point, Roche Point, Kristoffer, Romulus and Bent Horn
fields have been designated significant discovery lands ("SDL" ) by the Federal
Government. The Company's interests in the SDL's have been retained pending
development.
Panarctic Oils Ltd. ("Panarctic"), the operator, received Federal
government regulatory approvals for a pilot project to move shipments of crude
oil from the Bent Horn field by tanker through the Northwest Passage to southern
Canada in 1985. Through December 31, 1996, approximately 2.7 million barrels of
Bent Horn crude had been sold with deliveries being made at northern Canadian
and European markets as well as the eastern seaboard market. In 1996, the
operator decided to shut down production from the field and dismantle the
production facilities because of economic uncertainties. The Company has a 5%
carried interest in the area which has not yet reached payout status. The timing
of any payout is uncertain.
Northwest Territories Properties
The Company has a 45% carried interest in the Northwest Territories in
the Celibeta field designated as Significant Discovery Lands ("SDL") by the
Federal Government (1,594 gross acres and 717 net acres). The gas field is
presently shut-in.
Alberta
In 1997, the Company participated in 19 wells on the Alberta lands
which resulted in 11 oil wells, 4 gas wells, 2 water disposal wells, 1 suspended
well and 1 dry hole.
In 1994, the Company purchased a 5% working interest in the Kitscoty
heavy oil field and the related facilities. Oil recovery from this field is
being enhanced by steam injection. Two horizontal holes were drilled for
production with the steam being injected through vertical holes.
In 1996, the Company purchased an additional 5% working interest in the
Kitscoty field. Three more wells were drilled in 1996, two horizontal wells and
one vertical well. All the wells encountered oil and were completed as oil
wells. One well also discovered three potential gas zones which will be
evaluated for future use as fuel for the steam generation needed to enhance the
oil production. Scheduled remedial work programs have been postponed pending an
increase in the current low netbacks on heavy oil. Additional work at the new
Lloydminister heavy oil discovery at 16-2-51-2 W4M has also been postponed for
this reason.
<PAGE>
During 1997, the Company joined in drilling 11 additional horizontal
wells to develop a glauconite heavy oil (14(degree) API) project in the
Atlee/Majestic area. A multitude of production problems occurred which caused
numerous delays. By year end, although only 8 of 13 wells were on-stream, the
field was producing 1,000 bpd. In addition, the Company participated in two
stratigraphic tests to calibrate and verify the 3D seismic. These wells were
later completed as water disposal wells. New production facilities are scheduled
for completion in April 1998 which should resolve the current production
problems.
At year end, the Company and its partner, Probe Exploration, Inc., were
negotiating to purchase additional prospective lands in the Atlee/Majestic area.
At Leduc in 1996, three wells were drilled of which two were completed
as oil and gas wells and one well was a dry hole. One well encountered two
potential producing zones and is currently producing at the allowable rate of 68
bpd. The Company has a 15% working interest in these wells. In 1997, a three
well program resulted in 2 gas wells and 1 dry hole. The two gas wells were
recently tied in at 1 Mmcf/d each.
The Company also acquired a 10-20% working interest in over 12,000
acres in four other areas of Alberta. These lands were purchased on the basis of
seismic work which showed a number of promising prospects. Subsequently,
additional seismic work has confirmed the potential of those prospects. One was
drilled in 1997 and completed as a potential gas well. A second well was drilled
in early 1998 and completed as an oil well.
In Alberta, the Company currently has working interests ranging from
10% to 100% in a total of 5,690 gross (729 net) developed acres and 31,514 gross
(7,989 net) undeveloped acres.
Saskatchewan
The Company has a 3.75% working interest in five sections in
Saskatchewan. During 1997, three wells were drilled on the lands resulting in 2
dry holes and 1 shut-in gas well.
Australia
Effective November 1, 1997, the Company sold its .08% working interest
in 115,596 gross (90 net) acres in the Amadeus Basin in the Northern Territory
in Australia for $3,000 to Magellan Petroleum Australia Limited ("MPAL").
Because of the limited potential of the only remaining property, the Dingo gas
field, the interest was written down to a nominal value in 1992. The Dingo gas
field is a shut-in gas field which is not connected to a gas pipeline.
<PAGE>
United States
Texas
In 1996 and 1997, the Company participated in the drilling of 4 wells
in Texas resulting in 4 potential oil wells. Two wells are shut-in pending
remedial work and two wells are currently producing. Based on the results of
these wells in which it has a relatively small interest, the Company has
commenced a leasing program and has acquired 4 leases on which it plans to do
seismic in 1998. The Company will have a 100% working interest initially in
these leases.
California
During March 1998, the Company agreed to participate with two other
companies in a heavy oil recovery project in California. The field is estimated
to have approximately 12 million barrels of oil in place with only 13% of the
oil recovered to date. The initial purchase price for a 90% (75% APO) interest
in the project is $200,000 (Company share 30% - $60,000). There is also a
commitment to spend $600,000 to perform remedial work on the field and to
complete a pilot stream flood program during the first year of the project
(Company share $180,000). If the total amount of expenditures is less than
$600,000, the participants' interests will be reduced proportionately to an
amount which is not less than 10% (Company share - 3%).
(b) Financial Information about Industry Segments
Since the Company is primarily engaged in only one industry, oil and
gas exploration and development, this item is not applicable to the Company. See
Item 8 for general financial information concerning the Company.
(c) (1) Narrative Description of the Business
The Company was incorporated in 1954 under the Canada
Corporations Act. In 1979, it became subject to the Canadian Business
Corporations Act and in 1980, was continued under the Nova Scotia Companies Act.
The Company is, either in its own right, or through other entities,
engaged in the exploration for and development of properties containing or
believed to contain recoverable oil and gas reserves and the sale of oil and gas
from these properties. Although many of the properties in which the Company has
interests are undeveloped, all properties with proved reserves are partially or
fully developed. The Company's interests in exploratory ventures are on
properties located in Alberta, British Columbia, the Northwest Saskatchewan and
Yukon Territories and the Arctic Islands in Canada and in the United States. A
principal asset of the Company is its 30% carried interest in the Kotaneelee
field, a partially developed gas field (See Item 3 - "Legal Proceedings".) The
Company also has interests in producing properties in British Columbia and
Alberta. Most of this acreage is covered by carried interest agreements, which
provide that revenues are not payable to the Company until expenditures by the
carrying partners have been recouped from production, and that operating
decisions are made by the carrying partners. Generally, the Company may, at any
time, as to each block or economic unit, elect to convert from a carried
interest position to a working interest position by paying its share of the
unrecouped expenditures for the unit, i.e., expenditures not recouped from
production revenues. At December 31, 1997, the Company's share of unrecouped
expenditures were as follows:
British Columbia:
Ex-permit 149 $3,186,000
Yukon and Northwest Territories:
Ex-permit 1007 (Kotaneelee)* $5,942,000
Ex-permit 2713 (Celibeta) $321,000
*See Item 3 - Legal Proceedings
(i) Principal Products
The majority of the Company's interests are
carried interests. The Company also participates in the production and sale of
crude oil, natural gas and natural gas liquids derived from its working
interests.
(ii) Status of Product or Segment
At present, some of the properties in which
the Company has interests are undeveloped and/or nonproducing.
<PAGE>
(iii) Raw Materials
Not applicable.
(iv) Patents, Licenses, Franchises and Concessions
Held
Permits and concessions are important to the
Company's operations, since they allow the search for and extraction of any oil,
gas and minerals discovered on the areas covered. See the detailed schedule of
properties under Item 2, "Properties."
(v) Seasonality of Business
The Company's business is not seasonal,
except that sales of natural gas peak during the winter heating season.
Exploration and development activities are restricted in certain areas on a
seasonal basis because extreme weather conditions affect transportation and the
ability to pursue these activities.
(vi) Working Capital Items
Not applicable.
(vii) Customers
Substantially all oil production from the
Company's properties for the current year was purchased by CNRL, the operator of
the majority of the producing properties. Most of the natural gas produced from
Company properties was sold by the operator, Petro Canada, to a company owned by
certain British Columbia gas producers, CanWest Gas Supply Inc. The production
from the Kotaneelee gas field is also being sold to CanWest Gas Supply, Inc.
(viii) Backlog
Not applicable.
(ix) Renegotiation of Profits or Termination of
Contracts or Subcontracts at the Election of
the Government
Not applicable.
(x) Competitive Conditions in the Business
The exploration for and production of oil and
gas are highly competitive operations, both internally within the oil and gas
industry and externally with producers of other types of energy. The ability to
exploit a discovery of oil or gas is dependent upon considerations such as the
ability to finance development costs, the availability of equipment, and
engineering and construction delays and difficulties. The Company must compete
with companies which have substantially greater resources available to them.
Because the majority of Company interests are in remote areas, operation of its
properties is more difficult and costly than in more accessible areas.
Furthermore, competitive conditions may be
substantially affected by various forms of energy legislation which may have
been or may be proposed in the United States and Canada; however, it is not
possible to predict the nature of any such legislation which may ultimately be
adopted or its effects upon the future operations of the Company. For a further
discussion of Canadian governmental regulation of the petroleum industry, see
Item 1(d)(2).
(xi) Research and Development
Not applicable.
<PAGE>
(xii) Environmental Regulation
In the exploration for and development of
natural resources, the Company is required to comply with significant
environmental laws and regulations which add to the expense of those activities.
The Company has not been required to spend significant sums to comply with clean
up laws and regulations. Compliance by the Company with governmental provisions
regulating the discharge of materials to the environment or otherwise relating
to the protection of the environment are not expected to have a material effect
on the capital expenditures, earnings or competitive position of the Company.
(xiii) Number of Persons Employed by Company
The Company currently has three full time
employees, all of whom are located in Canada. The Company also relies to a great
extent on consultants (approximately 10) for technical, legal, accounting and
administrative services. The Company uses consultants because it is more cost
effective than employing a larger full time staff.
(d) Financial Information about Foreign and Domestic Operations
and Export Sales
(1) Identifiable Assets
Substantially all of the Company's operating assets
and revenues are attributable to its operations in Canada.
(2) Risks Attendant to Foreign Operations
The properties in which the Company has interests are
located primarily in Canada and are subject to certain risks involved in the
ownership and development of such foreign property interests. These risks
include but are not limited to those of: nationalization; expropriation;
confiscatory taxation; native rights; changes in foreign exchange controls;
currency revaluation; burdensome royalty terms; export sales restrictions;
limitations on the transfer of interests in exploration licenses; and other laws
and regulations which may adversely affect the Company's properties, such as
those providing for conversion, proration, curtailment, cessation or other forms
of limiting or controlling production of, or exploration for, hydrocarbons.
Thus, an investment in the Company represents an exposure to risks in addition
to those inherent in petroleum exploratory ventures.
Governmental Regulation of the Canadian Oil and Natural Gas Industry
The oil and natural gas industry in Canada is subject to extensive
controls and regulations imposed by various levels of government relating to
land tenure, production, production facilities, pricing and marketing,
royalties, environmental protection and other matters. Outlined below are some
of the more significant aspects of the legislation, regulations and agreements
governing the oil and natural gas industry in Canada. All current legislation is
a matter of public record and the Company is unable to predict whether any
additional legislation or amendments may be enacted.
<PAGE>
Land Tenure
Crude oil and natural gas located in the western provinces is owned
predominantly by the respective provincial governments. Provincial governments
grant rights to explore for and produce oil and natural gas pursuant to leases,
licenses and permits for varying terms from two years and on terms and
conditions set forth in provincial legislation including requirements to perform
specific work or make payments. Oil and natural gas located in such provinces
can also be privately owned and rights to explore for and produce such oil and
natural gas are granted by lease on such terms and conditions as may be
negotiated. The term of both Crown and freehold leases will generally continue
as long as oil or natural gas is produced from the property.
Oil and natural gas rights on federal lands outside of the provinces is
generally regulated by the Government of Canada unless authority has been
delegated by agreement to the territorial government or the government of the
province adjacent to the federal offshore area. In May 1993, the Canada Yukon
Oil and Gas Accord was signed which allows for the transfer to the Yukon of
authority to administer and control oil and natural gas resources within that
territory and for the establishment of an Oil and Gas Management Regime. The
National Energy Board ("NEB") is working with Yukon officials to facilitate the
transfer of oil and natural gas regulatory responsibilities in accordance with
the Yukon Accord Implementation Agreement.
Production and Production Facilities
The Governments of Canada, Alberta, British Columbia and Saskatchewan
have enacted statutory provisions regulating the production of oil and natural
gas. These regulations may restrict the maximum allowable production from a well
based on reservoir engineering and/or conservation practices. The construction
and operation of facilities to recover and process oil and natural gas are also
subject to regulation.
Pricing and Marketing - Oil
In Canada, producers of oil negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of oil. Certain
purchasers periodically advertise for volumes of oil they are prepared to
purchase and the price being offered for such volumes. The price depends in part
on oil quality, prices of competing fuels, distance to market and the value of
refined products. Oil exports may be made pursuant to export contracts with
terms not exceeding one year in the case of light crude, and not exceeding two
years in the case of heavy crude, provided that an order approving any such
export has been obtained from the NEB. Any oil export to be made pursuant to a
contract of longer duration requires an exporter to obtain an export license
from the NEB and the issue of such a license requires the approval of the
Governor in Council.
<PAGE>
Pricing and Marketing - Natural Gas
In Canada, the price of natural gas is determined by negotiation
between buyers and sellers, with the result that the market determines the price
of natural gas. Natural gas exported from Canada is subject to regulation by the
NEB and the Government of Canada. Exporters are free to negotiate prices and
other terms with purchasers, provided that the export contracts must continue to
meet certain criteria prescribed by the NEB and the Government of Canada. As is
the case with oil, natural gas exports for a term of less than two years must be
made pursuant to an NEB order, or, in the case of exports for a longer duration,
pursuant to an NEB license and Governor in Council approval.
The Governments of Alberta, British Columbia and Saskatchewan also
regulate the volume of natural gas which may be removed from those provinces for
consumption elsewhere based on such factors as reserve availability,
transportation arrangements and market considerations.
Royalties and Incentives
The royalty regime is a significant factor in the profitability of oil
and natural gas production. Royalties payable on production from lands other
than Crown lands are determined by negotiations between the mineral owner and
the lessee, although production from such lands may also be subject to
provincial taxes and regulations. Crown royalties are determined by government
regulation and are generally calculated as a percentage of the value of the
gross production, and the rate of royalties payable generally depends in part on
prescribed reference prices, well productivity, geographical location, field
discovery date and the type or quality of the product produced. The value of the
gross production for royalty purposes may be based on a deemed value for the
product rather than the actual value received by the interest holder.
From time to time the Governments of Canada, Alberta, British Columbia
and Saskatchewan have established incentive programs which have included royalty
rate reductions, royalty holidays and tax credits for the purpose of encouraging
natural gas and oil exploration or enhanced recovery projects. Incentives are
intended to enhance the existing cash flow of the oil and natural gas industry
and to improve the economics of finding and developing new and more costly oil
and natural gas reserves. Oil royalty holidays for specific wells and royalty
reductions reduce the amount of Crown royalties paid by the interest holder to
the respective government. Tax credit programs provide a rebate on Crown
royalties paid.
<PAGE>
Environmental Regulation
The oil and natural gas industry is subject to environmental regulation
pursuant to local, provincial and federal legislation. Environmental legislation
provides for restrictions and prohibitions on spills, releases or emissions of
various substances produced in association with certain oil and natural gas
industry operations. An environmental assessment and review may be required
prior to initiating exploration or development projects or undertaking
significant changes to existing projects. In addition, legislation requires that
well and facility sites be abandoned and reclaimed to the satisfaction of the
appropriate authorities. A breach of such legislation may result in the
imposition of fines or penalties. Federal environmental regulations also apply
to the use and transport of certain restricted and prohibited substances. The
Company is committed to meeting its responsibilities to protect the environment
wherever it operates and believes that it is in material compliance with
applicable environmental laws and regulations. The Company has not been required
to spend significant sums to comply with clean up laws and regulations.
Compliance by the Company with governmental provisions regulating the discharge
of materials to the environment or otherwise relating to the protection of the
environment are not expected to have a material effect on the capital
expenditures, earnings or competitive position of the Company.
(3) Data which Are Not Indicative of Current or Future Operations
Not applicable.
Item 2. Properties
(a) The principal asset of the Company is its 30% carried interest in
the Kotaneelee field, a partially developed gas field in the Yukon Territory.
See Item 3. "Legal Proceedings." The Company also has interests in producing
properties in British Columbia and Alberta and in several exploration prospects.
These interests are in exploratory ventures in properties located in Alberta,
Saskatchewan, the Northwest Territories and the Arctic Islands in Canada and in
the United States. Geophysical, geological and drilling work on the Company's
properties is conducted by the operators under various agreements with the
Company. The results of this work are reviewed by Company personnel and
consultants retained by the Company.
(b) (1) The information regarding reserves, costs of oil and gas
activities, capitalized costs, discounted future net cash flows and results of
operations is contained in Item 8. "Financial Statements and Supplementary
Data."
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of Canada showing key Company properties
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of N.E. British Columbia and Yukon, Northwest Territories
showing Company interest lands
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map showing the Kotaneelee Field
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of the Arctic Island Fields
showing the Company interest lands
<PAGE>
(2) Reserves Reported to Other Agencies
Not applicable.
(3) Production
Average sales price per unit and average production cost for oil and
gas produced during the periods shown below are as follows:
Average Sales Price Average Production Costs
Year Oil (per bbl.) Gas (per mcf.) Oil (per bbl.) Gas (per mcf.)
($) ($) ($) ($)
1997 22.50 2.31 8.70 1.30
1996 25.47 1.64 8.67 .79
1995 22.39 1.30 10.08 .77
(4) Productive Wells and Acreage
Productive wells and acreage on working and carried interest properties
as of December 31, 1997:
Gross Wells Net Wells
Oil Gas Oil Gas
90 89 14.43 15.71
Gross and Net Developed Acres
Gross Acres Net Acres
Alberta 5,690 729
Saskatchewan 640 24
British Columbia 67,058 11,729
Yukon Territory 3,350 1,005
Arctic Islands 3,060 153
Texas, USA 160 33
------ ------
79,958 13,673
====== ======
<PAGE>
(5) Undeveloped Acreage
Total developed and undeveloped acreage in which the Company has
interests is summarized by geographic area in the table below:
Gross and Net Petroleum Acreage as of December 31, 1997
Developed Acres Undeveloped Acres
--------------------- ----------------------
Gross Net Gross Net
Acres Acres % Acres Acres %
----- ----- ----- -----
Canada:
British Columbia:
Carried Interests 28,592 6,043 21.1 6,415 1,363 21.2
Working Interests 20,266 4,897 24.2 39,347 13,239 33.6
Overriding royalty interest 18,200 789 4.3 2,189 30 1.4
------ ------ ------- ------
Total British Columbia 67,058 11,729 47,951 14,632
------ ------ ------- ------
Saskatchewan:
Working Interests 640 24 3.8 2,560 96 3.8
------ ------ ------- ------
Alberta:
Working Interests 4,410 715 16.2 30,874 7,906 25.6
Overriding Royalty Interest 1,280 14 1.1 640 83 13.0
------ ------ ------- ------
Total Alberta 5,690 729 31,514 7,989
------ ------ ------- ------
Yukon & Northwest Territories:
Carried Interests 3,350 1,005 30.0 31,726 9,757 30.8
Arctic Islands:
Carried Interests 3,060 153 5.0 128,670 37,027 28.8
Working Interests - - 45,100 1,817 4.0
------ ------ ------- ------
Total Arctic Islands 3,060 153 173,770 38,844
------ ------ ------- ------
Total Canada 79,798 13,640 287,521 71,318
Texas, USA 160 33 20.6 - -
------ ------ ------- ------
TOTAL 79,958 13,673 287,521 71,318
====== ====== ======= ======
(6) Drilling activity
Productive and dry net wells drilled during the following periods:
Gross Net
--------------------- -----------------------
Year Productive Dry Productive Dry
1997 25 2 3.606 .250
1996 10 2 1.044 .150
1995 1 3 .033 .258
<PAGE>
(7) Present Activities
There was one well drilling at December 31, 1997.
(8) Delivery Commitments
None.
Item 3. Legal Proceedings
The Company, which has a 30% interest in the Kotaneelee gas field,
believes that the working interest owners in the field have not adequately
pursued the attainment of contracts for the sale of Kotaneelee gas. In October
1989 and in March 1990, the Company filed statements of claim in the Court of
Queens Bench of Alberta, Judicial District of Calgary, Canada, against the
working interest partners in the Kotaneelee gas field. The named defendants were
Amoco Canada Petroleum Corporation, Ltd., Dome Petroleum Limited (now Amoco
Canada Resources Ltd.), and Amoco Production Company (collectively the "Amoco
Dome Group"), Columbia Gas Development of Canada Ltd. ("Columbia"), Mobil Oil
Canada Ltd. ("Mobil") and Esso Resource of Canada Ltd. ("Esso") (collectively
the "Defendants").
The Company claims that the Defendants breached either a contract
obligation or a fiduciary duty owed to the Company to market gas from the
Kotaneelee gas field when it was possible to so do. The Company asserts that
marketing the Kotaneelee gas was possible in 1984 and that the Defendants
deliberately failed to do so. The Company seeks money damages and the forfeiture
of the Kotaneelee gas field. The Company expects to argue at trial that the
money damages sustained by the Company are at least $86 million.
In addition, the Company has claimed that the Company's carried
interest account should be reduced because of the negligent operation of the
field and improper charges to the carried interest account by the Defendants.
The Company claims that when the Defendants in 1980 suspended production from
the field's gas wells, they failed to take precautionary measures necessary to
protect and maintain the wells in good operating condition. The wells thereafter
deteriorated, which caused unnecessary expenditures to be incurred, including
expenditures to redrill one well. In addition, the Company claims that
expenditures made to repair and rebuild the field's dehydration plant should not
have been necessary had the facilities been properly constructed and maintained
by the Defendants. The expenditures, the Company claims, were inappropriately
charged to the field's carried interest account. The effect of an increased
carried interest account is to extend the period before payout begins to the
carried interest account owners.
<PAGE>
The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million. The Company claims that by 1993 at least $34 million of unnecessary
expenses had been wrongfully charged to the carried interest account. The
Company's 30% share of these expenses would be approximately $10.2 million. The
Company further claims that if production had commenced in 1984, the carried
interest account would have been paid off in approximately two years and the
Company would have begun to receive revenues from the field in 1986. At present,
the Company does not expect to receive revenues before the year 2000, based on a
price of Cdn. $1.39 per mcf and current production rates.
Columbia has filed a counterclaim against the Company seeking, if the
Company is successful in its claim for the forfeiture of the field, repayment
from the Company of all sums Columbia has expended on the Kotaneelee lands
before the Company is entitled to its interest.
The parties to the litigation have conducted extensive discovery since
the filing of the claims. The trial began on September 3, 1996 and is ongoing.
Based upon recently discovered evidence, the Company has petitioned the court
for leave to amend its complaint to add a claim that the Defendants failed to
develop the field in a timely manner. The Company is unable to estimate the time
necessary to conclude the litigation.
Matters Ancillary to Kotaneelee Litigation
In its 1989 statement of claim, the Company sought a declaratory
judgment regarding two issues:
(1) whether interest accrued on the carried interest account; and
(2) whether expenditures for gathering lines and dehydration
equipment are expenditures chargeable to the carried interest
account or whether the Company will be assessed a processing
fee on gas throughput.
With respect to the first issue, the Company maintains that no interest
should accrue on the account and the Defendants have not contested this
position. With regard to the second issue, the Company maintains that the
expenditures are chargeable to the carried interest account. Mobil, Esso and
Columbia have essentially agreed to the Company's position while the Amoco Dome
Group continues to contest this issue.
<PAGE>
On January 22, 1996, the Company settled two claims outstanding against
the Company in the Court of Queens Bench, Calgary, Alberta, which related to a
suit brought against AlliedSignal Inc. ("AlliedSignal") in Florida which was
dismissed on the basis that Canada was the appropriate forum for the litigation.
AlliedSignal had sought additional relief against the Company in Canada to
preclude other types of suits by the Company and to recover the costs of the
defense of the initial action. The settlement bars AlliedSignal from making a
claim against the Company for any costs in connection with the Kotaneelee
Litigation. The Company agreed not to bring any action against AlliedSignal in
connection with the Kotaneelee gas field. Neither party made any monetary
payment to the other party.
In 1991, Anderson Exploration Ltd. acquired all of the shares in
Columbia and changed its name to Anderson Oil & Gas Inc. ("Anderson"). Anderson
is now the sole operator of the field and is a direct defendant in the Canadian
lawsuit. Columbia's previous parent, The Columbia Gas System, Inc., which was
reorganized in a bankruptcy proceeding in the United States, is contractually
liable to Anderson in the legal proceeding described above.
The working interest owners have reported that they have been selling
Kotaneelee gas since February 1991.
Under Canadian law certain costs (known as "taxable costs") of the
litigation may be assessed against the nonprevailing party. Taxable costs
consist primarily of attorney's and expert witness fees during trial. The trial
is presently scheduled to last twelve months, therefore, taxable costs could be
substantial. While taxable costs are not now determinable, the Company estimates
that taxable costs, assuming a twelve month trial, could be approximately $1.5
million. However, a judge in complex and lengthy trials has the discretion to
increase an award of taxable costs. There are no assurances however, that
taxable costs will not exceed this amount or that the duration of the trial will
not exceed twelve months. The actual trial time through March 1998 is
approximately 5 months. During 1997, the Company was assessed approximately
$110,000 in taxable costs payable to the Defendants in connection with the
Company's motion to disqualify Amoco's legal counsel which was denied.
The amount is included in 1997 legal expenses.
There is no assurance whatever that the Company will be successful on
the merits of its claims, which have been vigorously defended by the Defendants.
There is also no assurance that the Company will be awarded any damages, or
that, if damages are awarded, the Court will apply the measure of damages the
Company claims should be applied.
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
Executive Officers of the Company
The following information with respect to the executive officers of the
Company is furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.
Length of Other Positions
Service Held with
Name Age Office in this Office Company
M. A. Ashton 62 President Since June 4, 1997 Director
All officers of the Company are elected annually by the Board of
Directors and serve at the pleasure of the Board of Directors.
The Company is aware of no arrangement or understanding between the
individual named above and any other person pursuant to which any individual was
selected as an officer.
<PAGE>
PART II
Item 5. Market for the Company's Limited Voting Shares and Related
Stockholder Matters
(a) Principal Markets
The Company's Limited Voting Shares, par value $1.00 per share, are
traded on The Toronto Stock Exchange and the Pacific and Boston Stock Exchanges,
and in the NASDAQ SmallCap market.
The quarterly high and low closing prices (in Canadian dollars) on The
Toronto Stock Exchange during the calendar periods indicated were as follows:
1996 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 11.25 11.50 11.55 10.25
Low 7.75 8.00 8.50 8.50
1997 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 11.00 12.50 16.60 15.00
Low 8.50 7.50 12.25 10.75
The quarterly high and low closing prices (in United States dollars) on
the Pacific Stock Exchange during the calendar periods indicated were as
follows:
1996 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 8 1/8 8 1/4 8 1/2 7 5/8
Low 6 6 1/8 6 3/8 6 1/2
1997 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 8 9 11 15/16 11
Low 6 1/2 5 3/4 8 13/16 7 1/4
<PAGE>
(b) Approximate Number of Holders of Limited Voting
Shares at March 23, 1998
Approximate
Title of Class Number of Record Holders
Limited Voting Shares, par value
$1.00 per share. 6,100
(c) Dividends
The Company has never paid a dividend on its Limited Voting Shares. Any
future dividends will be dependent on the Company's earnings, financial
condition, and business prospects. The Company is legally restricted from paying
any dividend or making any other payment to shareholders (except by way of
return of capital) on the Limited Voting Shares until its accumulated deficit
($21,142,464 at December 31, 1997) is eliminated.
Current Canadian law does not restrict the remittance of dividends to
persons not resident of Canada. Under current Canadian tax law and the United
States-Canada tax treaty, any dividends paid to U.S. shareholders are currently
subject to a 15% Canadian withholding tax.
<PAGE>
Item 6. Selected Financial Data
The following selected consolidated financial information (in thousands
except per share and exchange rate data) of the Company insofar as it relates to
each of the fiscal periods shown has been extracted from the Company's
consolidated financial statements.
<TABLE>
<CAPTION>
Year ended December 31,
-------------------------------------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
($) ($) ($) ($) ($)
<S> <C> <C> <C> <C> <C>
Operating revenues 2,120 1,755 1,657 1,691 1,915
====== ====== ====== ====== ======
Total revenues 2,515 2,228 1,793 1,942 2,103
====== ====== ====== ====== ======
Net loss (1,758) (1,461) (1,162) (1,210) (977)
====== ====== ====== ====== ======
Net loss per share (.12) (.11) (.09) (.10) (.08)
====== ====== ====== ====== ======
Working capital 5,573 8,403 1,510 2,417 3,890
====== ====== ====== ====== ======
Total assets 20,956 20,375 12,380 13,390 14,484
====== ====== ====== ====== ======
Shareholders' Equity:
Capital stock 40,489 38,888 29,635 29,513 29,513
Deficit (21,143) (19,385) (17,923) (16,762) (15,552)
------ ------ ------ ------ ------
19,346 19,503 11,712 12,751 13,961
====== ====== ====== ====== ======
Average number of
shares outstanding 14,084 13,362 12,622 12,613 12,453
====== ====== ====== ====== ======
Exchange rates:
Year-end .6992 .7297 .7329 .7129 .7554
===== ===== ===== ===== =====
Average for the period .7224 .7335 .7289 .7324 .7757
===== ===== ===== ===== =====
Range .6947-.7482 .7234-.7520 .7026-.7480 .7098-7634 .7436-.8045
</TABLE>
U.S. GAAP Information
Under U.S. generally accepted accounting principles ("GAAP"), the above selected
information would be as follows (See Note 6 in Notes to Consolidated Financial
Statements):
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
Net loss (1,588) (1,236) (1,001) (1,140) (673)
======= ======= ======= ======= =====
Net loss per share (.11) (.09) (.08) (.09) (.05)
===== ===== ===== ===== =====
</TABLE>
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
(1) Liquidity and Capital Resources
Statements included in Management's Discussion and Analysis of
Financial Condition and Results of Operations which are not historical in nature
are intended to be, and are hereby identified as, "forward looking statements"
for purposes of the "Safe Harbor" Statement under the Private Securities
Litigation Reform Act of 1995. The Company cautions readers that forward looking
statements are subject to certain risks and uncertainties that could cause
actual results to differ materially from those indicated in the forward looking
statements.
At December 31, 1997, the Company had approximately $5.5 million of
cash and securities available. These funds are expected to be used for general
corporate purposes, including exploration and development and to continue the
Kotaneelee field litigation. The Company estimates that it has adequate working
capital for 1998 and 1999 and may be required to raise additional funds through
the sale of properties or other means in order to complete the Kotaneelee
Litigation.
Cash flow used in operations during 1997 increased to $1,003,00
compared to $775,000 during the 1996 period. The $228,000 difference between
the periods was caused primarily by the following:
Increase in loss from operations $(311,000)
Increase in accounts receivable and other (433,000)
Net change in current liabilities 516,000
----------
Difference in net cash used in operations $(228,000)
==========
A significant proportion of the Company's property interests are
covered by carried interest agreements, which provide that expenditures made by
the operator are recouped solely out of revenues from production. Major capital
expenditures made by the operators have an impact on the Company's cash flow
from operations as no revenues are reported or received until the capital costs
have been recovered by the operator. Properties in the Fort Nelson, British
Columbia area in which the Company has carried interests have reached payout
status. Proceeds from these carried interests plus oil and gas sales from
working interest properties are the Company's major sources of working capital.
The Company is currently evaluating and expects to continue to evaluate
oil and gas properties and may make investments in such properties utilizing
cash on hand. The Company anticipates that its capital expenditures for land
acquisitions and drilling for the year 1998 will be approximately $750,000. In
addition, substantial continuing expenses are expected to be incurred in
connection with the Kotaneelee Litigation. During 1997, the Company expended
approximately $1.8 million in connection with the Kotaneelee Litigation which
has been the principal cause of the Company's losses since 1991.
<PAGE>
The Company has established a reserve for its potential share of future
site restoration costs. The estimated amount of these costs, which total
$804,000, is being provided on a unit of production basis in accordance with
existing legislation and industry practice.
The Company has determined that the year 2000 century change will have
no material impact on the Company's internal operations or financial results.
However, it will be dependent on its suppliers, partners and customers to make
their systems year 2000 compliant.
(2) Results of Operations
1997 vs. 1996
The net loss for the year 1997 was $1,671,164, ($.12 per share)
compared to a net loss of $1,461,283 ($.11 per share) for the 1996 period. A
summary of revenue and expenses during the periods is as follows:
1997 1996 Net Change
---- ---- ----------
Revenues $2,514,978 $2,228,393 $286,585
Costs and expenses (4,272,642) (3,689,676) (582,966)
----------- ----------- ---------
Net loss $(1,757,664) $(1,461,283) $(296,381)
============ ============ ==========
Oil sales increased by 46% due primarily to an 85% increase in
production which was partially offset by a 12% decrease in the average prices of
oil sold. There was also a 184% increase in royalties paid by the Company. Oil
unit sales in barrels ("bbls") (before deducting royalties) and the average
price per barrel sold during the periods indicated were as follows:
<TABLE>
<CAPTION>
1997 1996
Average price Average price
bbls per bbl Total bbls per bbl Total
<S> <C> <C> <C> <C> <C> <C>
Oil sales 63,783 $22.50 $1,436,000 34,565 $25.47 $880,000
Royalties paid (315,000) (111,000)
----------- ---------
Total $1,121,000 $769,000
========== ========
</TABLE>
Gas sales increased 33%. There was a 41% increase in the average price
for gas and a 2% increase in number of units sold. In addition, gas sales
include royalty income which increased 35% in 1997. The volumes in million cubic
feet ("mmcf") and the average price of gas per thousand cubic feet ("mcf") sold
during the periods indicated were as follows:
<PAGE>
<TABLE>
<CAPTION>
1997 1996
Average price Average price
mmcf per mcf Total mmcf per mcf Total
<S> <C> <C> <C> <C> <C> <C>
Gas sales 200 2.31 $462,000 197 $1.64 $323,000
Royalty income 146,000 108,000
Royalties paid (85,000) (36,000)
--------- ---------
Total $523,000 $395,000
======== ========
</TABLE>
Proceeds under carried interest agreements decreased 20% to $476,000
during 1997 compared to $591,000 in 1996. The operator of the Company's carried
interest properties increased its development activities during late 1996,
thereby incurring additional capital costs which were deducted in 1997. Proceeds
under carried interest agreements are derived from net production revenues after
payout of capital costs.
Interest and other income decreased 17% in 1997. Interest income
increased from $259,000 to $336,000 in 1997 due to the increase in funds
available for investment from the June 1996 rights offering to shareholders. In
addition, the 1997 period includes proceeds from the sale of seismic data in the
amount of $59,000 compared to $215,000 from such sales in 1996.
General and administrative costs increased 23% in 1997 to $1,105,000
from $895,000 in 1996. Capital taxes, which are based on the Company's net
worth, increased $48,000 in 1997. Directors' fees increased $44,000 in 1997
because four nonemployee directors are being paid fees in 1997 compared to 1996
when only two directors were paid fees. Geological and engineering expenses
increased $23,000 in 1997 because of the Company's active exploration program.
Shareholders' expenses increased $32,000 in 1997 compared to 1996 because of
increased printing and mailing costs. Salaries increased $39,000 in 1997 with
the addition of a new employee.
Legal expenses increased 18% during 1997 to $1,898,000 compared to
$1,610,000 during 1996. These expenses are related primarily to the cost of the
Kotaneelee litigation. During 1997, the Company presented a major part of its
case against the working interest partners. The 1997 costs represent both legal
fees and the cost of various Company experts who testified or were being
prepared for testimony.
Lease operating costs increased 68% from $477,000 in 1996 to $799,000
in the 1997 period. The increased costs are relative to the 85% increase in oil
production. Although the revenue on these properties also increased during the
period, the costs are not yet proportional to revenue because some of the new
wells are awaiting installation of production facilities.
<PAGE>
A foreign exchange gain of $231,000 was recorded in 1997, contrasted
with a gain of $25,000 on the Company's U.S. investments in 1996. In 1997, the
gain was attributable to a strengthening of the U.S. dollar as compared to the
Canadian dollar on the Company's U.S. investments.
Income taxes. No provision for income taxes is required for the current
period.
1996 vs. 1995
The net loss for the year 1996 was $1,461,283, ($.11 per share)
compared to a net loss of $1,161,763 ($.09 per share) for the 1995 period. A
summary of revenue and expenses during the periods is as follows:
1996 1995 Net Change
---- ---- ----------
Revenues $2,228,393 $1,793,112 $435,281
Costs and expenses 3,689,676 2,954,875 734,801
--------- --------- --------
Net loss $(1,461,283) $(1,161,763) $(299,520)
============ ============ ==========
Oil sales increased by 38% due primarily to a 14% increase in the
average price of oil sold with an 18% increase in production. There was also a
13% increase in royalties paid. Oil unit sales in barrels ("bbls") (before
deducting royalties) and the average price per barrel sold during the periods
indicated were as follows:
<TABLE>
<CAPTION>
1996 1995
Average price Average price
bbls per bbl Total bbls Per bbl Total
<S> <C> <C> <C> <C> <C> <C>
Oil sales 34,565 $25.47 $880,000 29,198 $22.39 $654,000
Royalties paid (111,000) (98,000)
--------- ---------
Total $769,000 $556,000
======== ========
</TABLE>
Gas sales increased 8%. There was a 26% increase in the average price
for gas which was partially offset by a 22% decrease in units sold. In addition,
gas sales include royalty income which increased 17% in 1996. The volumes in
million cubic feet ("mmcf") and the average price of gas per thousand cubic feet
("mcf") sold during the periods indicated were as follows:
<PAGE>
<TABLE>
<CAPTION>
996 1995
Average price Average price
mmcf per mcf Total mmcf per mcf Total
<S> <C> <C> <C> <C> <C> <C>
Gas sales 197 $1.64 $323,000 252 $1.30 $327,000
Royalty income 108,000 92,000
Royalties paid (36,000) (52,000)
--------- ---------
Total $395,000 $367,000
======== ========
</TABLE>
Proceeds under carried interest agreements decreased 20% to $591,000
during 1996 compared to $734,000 in 1995. The operator of the Company's carried
interest properties increased its development activities during late 1996,
thereby incurring additional expenses. Proceeds under carried interest
agreements are derived from gross production revenues after payout of these
expenses.
Interest and other income was 247% higher in 1996. Interest income
increased from $90,000 to $259,000 in 1996 due to the increase in funds
available for investment from the June 1996 rights offering to shareholders. In
addition, the 1996 period includes proceeds from the sale of seismic data in the
amount of $215,000 compared to $46,000 in 1995.
General and administrative costs decreased 10% in 1996 to $895,000 from
$988,000 in 1995. The 1995 period included higher salary expenses related to
retired personnel. In addition, accounting and administrative expenses also
decreased in 1996 due to cost reduction efforts.
Lease operating costs decreased 5% from $504,000 to $477,000 in 1996.
The decrease represents lower charges by the operators of the Company's
properties during 1996.
Legal expenses increased 83% to $1,610,000 from $880,000 in 1995. These
expenses are related primarily to the cost of the Kotaneelee litigation which
increased as a result of trial preparation and the actual costs of the trial
which began on September 3, 1996.
Depletion, depreciation and amortization expense increased 31% in 1996
to $655,000 from $500,000 in 1995. The increase in depletion is the result of a
decrease in gas reserves and an increase in estimated capital costs.
Provision for restoration costs increased to $24,600 in 1996 compared
to $16,800 in 1995. During 1996, a charge of $81,000 was made to the future site
restoration costs account for certain abandonments costs. The Company has
re-evaluated its potential liability and accordingly increased its provision for
restoration costs.
<PAGE>
A foreign exchange gain of $25,000 was recorded in 1996, contrasted
with a loss of $14,000 on the Company's U.S. investments in 1995. In 1996, the
gain was attributable to a strengthening of the U.S. dollar as compared to the
Canadian dollar on the Company's U.S. investments.
Income taxes. No provision for income taxes is required for the current
period.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
The information required by this item is not applicable to the Company
until the fiscal year ending December 31, 1998.
<PAGE>
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT AUDITORS
To the Shareholders of
Canada Southern Petroleum Ltd.
We have audited the accompanying consolidated balance sheets of Canada Southern
Petroleum Ltd. as at December 31, 1997 and 1996, and the consolidated statements
of operations and deficit, cash flows and limited voting shares and contributed
surplus for each of the years in the three year period ended December 31, 1997.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Canada Southern
Petroleum Ltd. as at December 31, 1997 and 1996 and the results of its
operations and the changes in its financial position for each of the years in
the three year period ended December 31, 1997, in accordance with accounting
principles generally accepted in Canada.
Calgary, Canada ERNST & YOUNG
March 20, 1998 Chartered Accountants
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
(Incorporated under the laws of Nova Scotia)
CONSOLIDATED BALANCE SHEETS
(Expressed in Canadian dollars)
December 31,
1997 1996
----------- -----------
Assets
Cash and cash equivalents (Note 2) $ 2,129,156 $ 2,709,597
Marketable securities (Note 3) 3,373,334 3,404,213
Accounts receivable (Note 4) 1,226,086 635,223
Prepaid insurance and other 227,368
Other assets 242,278 -
----------- -----------
Total current assets 6,970,854 6,976,401
----------- -----------
Marketable securities (Note 3) - 2,048,573
----------- -----------
Oil and gas properties and equipment
(full cost method) (Note 4) 13,984,771 11,349,945
----------- -----------
Total assets $20,955,625 $20,374,919
=========== ===========
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable $ 1,120,521 $ 439,837
Accrued liabilities (Notes 10 and 11) 277,715 182,104
----------- -----------
Total current liabilities 1,398,236 621,941
----------- -----------
Future site restoration costs 210,974 250,274
----------- -----------
Contingencies (Note 8) - -
Shareholders' Equity
Limited Voting Shares, par value
$1 per share (Note 5)
Authorized - 100,000,000 shares
Outstanding - 14,234,740 (1996 - 13,956,540) shares 14,234,740 13,956,540
Contributed surplus 26,254,139 24,930,964
----------- -----------
Total capital 40,488,879 38,887,504
----------- -----------
Deficit (21,142,464) (19,384,800)
----------- -----------
Total shareholders' equity 19,346,415 19,502,704
----------- -----------
Total liabilities and shareholders' equity $20,955,625 $20,374,919
=========== ===========
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
Consolidated Statements of Operations and Deficit
(Expressed in Canadian dollars)
<TABLE>
<CAPTION>
Year ended December 31,
1997 1996 1995
------------ ------------ ------------
Revenues:
<S> <C> <C> <C>
Oil sales $ 1,120,789 $ 768,576 $ 555,894
Gas sales 523,433 395,068 366,700
Proceeds under carried
interest agreements 475,697 590,935 734,066
Interest and other income 395,059 473,814 136,452
------------ ------------ ------------
Total revenues 2,514,978 2,228,393 1,793,112
------------ ------------ ------------
Costs and expenses:
General and administrative 1,104,535 894,766 988,395
Legal (Note 9) 1,897,506 1,610,477 879,821
Lease operating costs 799,372 476,562 503,648
Depletion, depreciation,
and amortization 623,600 654,982 499,630
Foreign exchange (gains) (231,457) (24,693) 13,915
Provision for future site
restoration costs 21,500 24,600 16,800
Rent 57,586 52,982 52,666
------------ ------------ ------------
Total costs and expenses 4,272,642 3,689,676 2,954,875
------------ ------------ ------------
Loss before income taxes (1,757,664) (1,461,283) (1,161,763)
Income taxes (Note 6) - - -
------------ ------------ ------------
Net loss (1,757,664) (1,461,283) (1,161,763)
Deficit - beginning of period (19,384,800) (17,923,517) (16,761,754)
------------- ------------- -------------
Deficit - end of period $(21,142,464) $(19,384,800) $(17,923,517)
============= ============= =============
Net loss per share (Basic & Diluted) $(.12) $(.11) $(.09)
====== ====== ======
Average number of shares
Outstanding (Basic & Diluted) 14,084,294 13,362,410 12,621,560
========== ========== ==========
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
Consolidated Statements of Cash Flows
(Expressed in Canadian dollars)
<TABLE>
<CAPTION>
Year ended
December 31,
1997 1996 1995
----------- ----------- -----------
Cash flows from operating activities:
<S> <C> <C> <C>
Net loss $(1,757,664) $(1,461,283) $(1,161,763)
Adjustments to reconcile net loss
to net cash provided by
(used in) operating activity:
Depreciation, depletion and
amortization 623,600 654,982 499,630
Future site restoration costs (net) (39,300) (56,454) 16,800
Change in assets and liabilities:
Accounts and interest receivable (590,863) (284,625) (64,491)
Other assets (14,910) 112,074 (85,775)
Accounts payable 680,684 314,328 (38,583)
Accrued liabilities 95,611 (54,228) 51,620
----------- ----------- -----------
Net cash used in operations (1,002,842) (775,206) (782,562)
----------- ----------- -----------
Cash flows from investing activities:
Additions to oil and gas properties (net) (3,258,426) (1,496,308) (383,519)
Sale (purchase) of marketable securities 2,079,452 (5,452,786) -
----------- ----------- -----------
Net cash used in investing activities (1,178,974) (6,949,094 (383,519)
----------- ----------- -----------
Cash flows from Financing Activities:
Sale of common stock less expenses - 9,019,609 -
Exercise of stock options 1,601,375 232,707 121,780
----------- ----------- -----------
Net cash from financing activities 1,601,375 9,252,316 121,780
----------- ----------- -----------
Increase (decrease) in cash
and cash equivalents (580,441) 1,528,016 (1,044,301)
Cash and cash equivalents at the
beginning of period 2,709,597 1,181,581 2,225,882
----------- ----------- -----------
Cash and cash equivalents at the
end of period (Note 2) $ 2,129,156 $ 2,709,597 $ 1,181,581
=========== =========== ===========
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF LIMITED VOTING SHARES
AND CONTRIBUTED SURPLUS
(Expressed in Canadian dollars)
<TABLE>
<CAPTION>
Limited
Number Voting Shares Contributed
of shares $1 par value surplus Total
---------- ------------ ----------- -----------
<S> <C> <C> <C> <C>
Balance at December 31, 1994 12,612,791 $12,612,791 $16,900,617 $29,513,408
Exercise of stock options 33,000 33,000 88,780 121,780
---------- ----------- ----------- -----------
Balance at December 31, 1995 12,645,791 12,645,791 16,989,397 29,635,188
Sale of common stock 1,268,549 1,268,549 7,751,060 9,019,609
Exercise of stock options 42,200 42,200 190,507 232,707
---------- ----------- ----------- -----------
Balance at December 31, 1996 13,956,540 13,956,540 24,930,964 38,887,504
Exercise of stock options 278,200 278,200 1,323,175 1,601,375
---------- ----------- ----------- -----------
Balance at December 31, 1997 14,234,740 $14,234,740 $26,254,139 $40,488,879
========== =========== =========== ===========
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in Canadian dollars)
December 31, 1997
1. Summary of significant accounting policies
Accounting principles
The Company prepares its accounts in accordance with accounting
principles generally accepted in Canada which, except as described in Note 6,
conform in all material respects with United States generally accepted
accounting principles ("U.S. GAAP").
Consolidation
The consolidated financial statements include the accounts of Canada
Southern Petroleum Ltd. and its wholly-owned subsidiaries, Canpet Inc. and C.S.
Petroleum Limited.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the amounts reported in the financial statements and
accompanying notes. Actual results could differ from those estimates.
Cash and cash equivalents
For the purposes of the statement of cash flows, the Company considers
all highly liquid investments with a maturity of three months or less to be cash
equivalents.
Oil and gas properties and equipment
The Company, which is engaged primarily in one industry, the
exploration for and the development of oil and gas properties, principally in
Canada, follows the full cost method of accounting for oil and gas properties,
whereby all costs associated with the exploration for and the development of oil
and gas reserves are capitalized.
The Company periodically reviews the costs associated with undeveloped
properties and mineral rights to determine whether they are likely to be
recovered. When such costs are not likely to be recovered, such costs are
transferred to the depletable pool of oil and gas costs.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in Canadian dollars)
December 31, 1997
1. Summary of significant accounting policies (Cont'd)
The net carrying cost of the Company's oil and gas properties in
producing cost centers is limited to an estimated recoverable amount. This
amount is the aggregate of future net revenues from proved reserves and the
costs of undeveloped properties, net of impairment allowances, less future
general and administrative costs, financing costs and income taxes. Future net
revenues are calculated using year end prices that are not escalated or
discounted.
The costs of the Company's 30% carried interest in the Kotaneelee gas
field are included in oil and gas properties and in the cost center for the
purpose of computing depletion. In addition, the Company's share of estimated
net reserves after payout are also included in the proved oil and gas reserves
base for the purpose of computing depletion. However, no revenue production data
will be reported for financial statement purposes until the Company is entitled
to participate in the field's revenue after payout status is achieved.
Gains or losses are not recognized upon disposition of oil and gas
properties unless crediting the proceeds against accumulated costs would result
in a change in the rate of depletion of 20% or more.
Depletion is provided on costs accumulated in producing cost centers
including well equipment using the unit of production method. For purposes of
the depletion calculation, gross proved oil and gas reserves as determined by
outside consultants are converted to a common unit of measure on the basis of
their approximate relative energy content.
Depreciation has been computed for equipment, other than well
equipment, on the straight-line method based on estimated useful lives of four
to ten years.
Substantially all of the Company's exploration and development
activities related to oil and gas are conducted jointly with others and
accordingly the consolidated financial statements reflect only the Company's
proportionate interest in such activities.
Revenue recognition
The Company recognizes revenue on its working interest properties from
the production of oil and gas in the period the oil and gas are sold.
Revenue under carried interest agreements is recorded in the period
when the proceeds become receivable. The Company is entitled to participate in
oil and gas net revenues after the repayment of exploration, drilling and
completion expenses to the party or parties bearing these costs. The carried
interest accounts are subject to independent audits which are performed in
subsequent years. In the past, these audits have resulted in both positive and
negative adjustments. For these reasons, the proceeds under carried interest
agreements may fluctuate each year depending on both capital expenditures and
any audit adjustments.
<PAGE>
1. Summary of significant accounting policies (Cont'd)
Earnings per share
Earnings per common share is based upon the weighted average number of
common and common equivalent shares outstanding during the period. In February
1997, the FASB issued Statement No. 128, Earnings per Share ("EPS"), which the
Company adopted retroactively in 1997. The Company's basic and diluted
calculations of EPS are the same for both U.S. and Canadian GAAP.
Future site restoration costs
Estimated future site restoration costs which are estimated to be
$804,000 are being provided on a unit of production basis. The provision is
based on current costs of complying with existing legislation and industry
practice for site restoration and abandonment. At December 31, 1997,
approximately $598,000 in such costs have not been accrued.
Deferred income taxes
The Company follows the deferral method of tax allocation accounting
whereby the income tax provision is based on pre-tax income reported in the
accounts. Under this method, full provision is made for deferred income taxes
resulting from claiming deductions at the rates permitted by income tax
legislation, which may differ from those used in the accounts.
Foreign currency translation
Transactions for settlement in U.S. dollars have been translated at
average monthly exchange rates. Assets and liabilities in U.S. dollars have been
translated at the year end exchange rates. Exchange gains or losses resulting
from these adjustments are included in costs and expenses.
Financial instruments
The carrying value for cash and cash equivalents, accounts receivable,
marketable securities and accounts payable approximates fair value based on
anticipated cash flows and current market conditions.
<PAGE>
1. Summary of significant accounting policies (Cont'd)
Comprehensive income
In 1997, the Financial Accounting Standards Board issued FASB Statement
No. 130, Reporting Comprehensive Income. As the Company has no items of other
comprehensive income, the net loss for all periods presented is equal to the
comprehensive loss.
2. Cash and cash equivalents
The Company considers all highly liquid short term investments with
maturities of three months or less at date of acquisition to be cash
equivalents. Cash equivalents are carried at cost which approximates market
value.
1997 1996
---------- ----------
Cash $ 436,030 $ 319,616
Canadian bankers acceptances (2.9%) 988,437 1,441,170
U.S. Treasury Bills (5.6%) 704,689 948,811
$2,129,156 $2,709,597
========== ==========
3. Marketable Securities
At December 31, 1997 and 1996, the Company held the following
marketable securities which were expected to be held until maturity:
<TABLE>
<CAPTION>
1997
Security Par value Maturity Date Amortized Cost Fair value
-------- ---------- ------------- -------------- ----------
<S> <C> <C> <C> <C>
U.S. Federal Home Bank Note $ 143,021 Mar. 6, 1998 $ 140,418 $ 141,247
U.S. Federal Home Bank Note 286,041 Apr. 6, 1998 278,324 280,925
U.S. Federal Farm Credit Bank Note 143,021 May 4, 1998 139,600 139,469
U.S. Treasury Note 2,145,309 May 31, 1998 2,137,934 2,149,321
U.S. Federal Home Loan Bank Note 715,103 Jun. 19, 1998 677,058 683,411
---------- ---------- ----------
Total $3,432,495 $3,373,334 $3,394,373
========== ========== ==========
1996
U.S. Treasury Bill $ 822,256 Mar. 27, 1997 $ 801,637 $ 812,570
U.S. Treasury Bill 685,213 Apr. 3, 1997 657,599 676,271
U.S. Treasury Bill 2,055,639 Jun. 26, 1997 1,944,977 2,004,289
---------- ---------- ----------
Total short term 3,563,108 3,404,213 3,493,130
---------- ---------- ----------
U.S. Treasury Bill 2,055,639 Jun. 26, 1998 2,048,573 2,056,914
---------- ---------- ----------
Total $5,618,747 $5,452,786 $5,550,044
========== ========== ==========
</TABLE>
<PAGE>
4. Oil and gas properties and equipment
<TABLE>
<CAPTION>
Accumulated
Provisions and Net Book
Cost Writedowns Value
----------- ---------- -----------
Balance December 31, 1997
<S> <C> <C> <C>
Oil and gas properties - developed 21,192,037 7,854,066 13,337,971
Oil and gas properties (U.S.) - undeveloped 616,980 - 616,980
Seismic data 112,000 112,000
----------- ---------- -----------
-
21,921,017 7,966,066 13,954,951
Equipment 67,769 37,949 29,820
----------- ---------- -----------
$21,988,786 $8,004,015 $13,984,771
=========== ========== ===========
Balance December 31, 1996
Oil and gas properties-developed $18,555,130 $7,227,874 $11,327,256
Oil and gas properties-undeveloped 1 - 1
Seismic data 112,000 112,000
----------- ---------- -----------
-
18,667,131 7,339,874 11,327,257
Equipment 62,172 39,484 22,688
----------- ---------- -----------
$18,729,303 $7,379,358 $11,349,945
=========== ========== ===========
</TABLE>
Substantially all gas sales were made to CanWest Gas Supply Inc. and
oil sales were made to Canadian Natural Resources Ltd. and Probe Exploration,
Inc. ("Probe"). At December 31, 1997, a cash call in the amount of $616,000
from Probe is included in accounts receivable.
5. Limited voting shares and stock options
The Memorandum of Association (Articles of Continuance) of the Company
provides that no person (as defined) shall vote more than 1,000 shares.
Under the terms of the Company's 1985 and 1992 stock option plans, the
Company is authorized to grant certain key employees and consultants options to
purchase limited voting shares at prices based on the market price of the shares
as determined on the date of the grant. The options are exercisable for five
years from the date of grant.
On January 27, 1998, the Company's Board of Directors approved a stock
option plan that permits the granting of both stock options and stock
appreciation rights. Under the plan, which must be approved by the Company's
shareholders at the June 1998 Annual Meeting, a total of 700,000 shares are
being authorized.
In 1996, the Company sold 1.3 million shares to its shareholders at
$7.50 per share. The proceeds to the Company from the rights offering were
$9,019,609 after deducting the $494,509 cost of the offering.
<PAGE>
5. Limited voting shares and stock options (Cont'd)
Following is a summary of option transactions which reflects
adjustments of the stock option prices and the number of shares subject to stock
options as discussed above:
Options outstanding Number of shares Option Prices
($)
December 31, 1994 494,700 3.45 - 7.00
Exercised (33,000) 3.45 - 4.06
-------
December 31, 1995 461,700
=======
Canceled (137,000) 3.45 - 7.00
Exercised (42,200) 3.45 - 8.75
Granted 150,700 3.15 - 6.37
Granted 12,500 8.75
-------
December 31, 1996 445,700
=======
Exercised (278,200) 3.70 - 8.75
Granted 35,000 13.50
December 31, 1997 202,500 6.37 - 13.50
=======
Options reserved for future grants 212,134
On July 8, 1996, 137,000 options to purchase limited voting shares of
the Company which were previously granted were canceled and reissued to reflect
the June 1996 rights offering.
For U.S. GAAP, the Company has elected to follow Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB No. 25)
and related interpretations in accounting for its stock options because the
alternative fair value accounting provided under FASB Statement No. 123,
"Accounting for Stock Based Compensation," requires use of option valuation
models that were not developed for use in valuing stock options. Under APB No.
25, because the exercise price of the Company's stock options equals the market
price of the underlying stock on the date of grant, no compensation expense is
recognized.
Pro forma information regarding net income and earnings per share is
required by Statement 123, and has been determined as if the Company had
accounted for its stock options under the fair value method of that Statement.
The fair value for these options was estimated at the date of grant using a
Black-Scholes option pricing model.
Option valuation models require that input of highly subjective
assumptions including the expected stock price volatility. The assumptions used
in the 1996 valuation model were: risk free interest rate - 6.7%, expected life
- - 5 years and expected volatility - .396. The assumptions used in the 1997
valuation model were: risk free interest rate - 5.7%, expected life - 5 years
and expected volatility - .459.
<PAGE>
5. Limited voting shares and stock options (Cont'd)
Because the Company's stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its stock options.
For the purpose of pro forma disclosures, the estimated fair value of
the stock options is expensed in the year of grant since the options are
immediately exercisable. The Company's pro forma information follows:
Amount Per Share
Net loss as reported - December 31, 1996 $(1,461,283) $(.11)
Stock option expense 49,373 -
------------ ------
Pro forma net loss - December 31, 1996 $(1,510,656) $(.11)
============ ======
Net loss as reported - December 31, 1997 $(1,757,664) $(.12)
Stock option expense 225,400 (.02)
------------ ------
Pro forma net loss - December 31, 1997 $(1,983,064) $(.14)
============ ======
6. Income taxes
Income taxes vary from the amounts that would be computed by applying
the Canadian federal and provincial income tax rates as follows:
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ---------
44.84% 44.84% 44.84%
====== ====== ======
Provision for income taxes based on combined
<S> <C> <C> <C>
basic Canadian federal and provincial income tax $(788,137) $(655,239) $(520,935)
Nondeductible crown charges 154,463 61,599 60,354
Resource allowance 232,922 - -
Other 21,106 478 948
Nontaxable portion of capital gain (20,743) - -
Unrealized tax loss 400,389 593,162 459,633
--------- --------- ---------
Actual provision for income taxes $ - $ - $ -
========= ========= =========
</TABLE>
At December 31, 1997, the Company had net operating losses for income
tax purposes of approximately $3,821,000 which are available to be carried
forward to future periods. These losses expire in the following years: 1998 -
$563,000, 1999 - $194,000, 2000 - $294,000, 2001 - $545,000, 2002 - $569,000,
2003 - $1,077,000 and 2004 - $579,000.
At December 31, 1997, the following oil and gas tax deductions are
available to reduce future taxable income, subject to a final determination by
taxation authorities.
<PAGE>
6. Income taxes (Cont'd)
Canada
Drilling, exploration and lease acquisition costs $12,932,000
Earned depletion 1,975,000
Undepreciated capital costs 2,172,000
Cumulative eligible capital losses 407,000
Share issue costs 274,000
United States
Exploration and lease acquisition costs $610,000
The tax benefits attributable to the above accumulated expenditures
will not be reflected in the consolidated financial statements until such
benefits are realized.
Under U.S. GAAP, the provisions for income taxes would have differed
for the reasons set out below:
In February 1992, the United States Financial Accounting Standards
Board issued Statement No. 109, "Accounting for Income Taxes", effective for
fiscal years beginning after December 15, 1993. Under U.S. GAAP, the Company
would have been required to adopt Statement No. 109 commencing July 1, 1993.
Under Statement No. 109, the liability method is used in accounting for
income taxes. Under this method, deferred tax assets and liabilities are
determined based on differences between financial reporting and tax bases of
assets and liabilities and are measured using the enacted tax rates and laws
that will be in effect when the differences are expected to reverse. Under
Canadian GAAP and previously under U.S. GAAP, income tax expense is determined
using the deferral method. Deferred tax expense is based on items of income and
expense that are reported in different years in the financial statements and tax
returns and are measured at the tax rate in effect in the year the differences
originated.
The following schedule summarized the Company's income tax expense and
deferred tax liability under U.S. GAAP. If Statement No. 109 was adopted, the
Company would have had a deferred tax asset which primarily represents the
excess of available resource deductions for income tax purposes over the
recorded value of oil and gas properties together with operating and capital
income tax loss carryforwards. These amounts are expected to be recovered from
the production of current oil and gas reserves when the Kotaneelee litigation
expenditures have ended. As certain of the resource deductions are restricted
and the operating loss carryforwards are subject to expiration, there is
considerable risk that certain of these deductions will not be utilized.
<PAGE>
6. Income taxes (Cont'd)
Accordingly, the Company would have established a valuation allowance to
recognize this uncertainty. Income taxes computed in accordance with U.S. GAAP,
would have resulted in a credit to the provision of taxes.
1997 1996 1995
------------ ------------ ------------
Deferred tax asset $3,663,793 $3,233,506 $2,351,550
Valuation reserve (2,733,655) (2,473,526) (1,816,792)
---------- ---------- ----------
Net deferred tax asset $ 930,138 $ 759,980 $ 534,758
========== ========== ==========
Deferred tax recovery $ 170,158 $ 225,222 $ 160,980
========== ========== ==========
Net loss under U.S. GAAP, in total, and per share based on average
number of shares outstanding during the periods shown is as follows:
<TABLE>
<CAPTION>
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Net loss under Canadian GAAP before income taxes $(1,757,664) $(1,461,283) $(1,161,763)
Income tax adjustment 170,158 225,222 160,980
------------ ------------ ------------
Net loss under U.S. GAAP $(1,587,506) $(1,236,061) $(1,000,783)
============ ============ ============
Per Share Basis:
Net loss under Canadian GAAP before income taxes $(.12) $(.11) $(.09)
Income tax adjustment .01 .02 .01
------ ------ ------
Net loss under U.S. GAAP $(.11) $(.09) $(.08)
====== ====== ======
</TABLE>
The deficit under U.S. GAAP would have been $20,212,326 and
$18,624,820 at December 31, 1997 and 1996, respectively.
7. Line of credit
The Company has a line of credit with a Canadian chartered bank which
provides for a loan of $500,000. The line of credit provides for a $125,000
operating loan and $375,000 for letters of credit as part of the directors'
indemnification agreements. The interest rate on borrowing is at 3/4% above the
bank's prime lending rate. The line of credit is subject to annual review and is
secured by a general assignment of accounts receivable and an undertaking to
provide security in the form of assignment of future working interest proceeds.
No drawings were made under this line during 1997 or 1996.
<PAGE>
8. Litigation
The Company, which has a 30% interest in the Kotaneelee gas field,
believes that the working interest owners in the field have not adequately
pursued the attainment of contracts for the sale of Kotaneelee gas. In October
1989 and in March 1990, the Company filed statements of claim in the Court of
Queens Bench of Alberta, Judicial District of Calgary, Canada, against the
working interest partners in the Kotaneelee gas field. The named defendants were
Amoco Canada Petroleum Corporation, Ltd., Dome Petroleum Limited (now Amoco
Canada Resources Ltd.), and Amoco Production Company (collectively the "Amoco
Dome Group"), Columbia Gas Development of Canada Ltd. ("Columbia"), Mobil Oil
Canada Ltd. ("Mobil") and Esso Resource of Canada Ltd. ("Esso") (collectively
the "Defendants").
The Company claims that the Defendants breached either a contract
obligation or a fiduciary duty owed to the Company to market gas from the
Kotaneelee gas field when it was possible to so do. The Company asserts that
marketing the Kotaneelee gas was possible in 1984 and that the Defendants
deliberately failed to do so. The Company seeks money damages and the forfeiture
of the Kotaneelee gas field. The Company expects to argue at trial that the
money damages sustained by the Company are at least $86 million.
In addition, the Company has claimed that the Company's carried
interest account should be reduced because of the negligent operation of the
field and improper charges to the carried interest account by the Defendants.
The Company claims that when the Defendants in 1980 suspended production from
the field's gas wells, they failed to take precautionary measures necessary to
protect and maintain the wells in good operating condition. The wells thereafter
deteriorated, which caused unnecessary expenditures to be incurred, including
expenditures to redrill one well. In addition, the Company claims that
expenditures made to repair and rebuild the field's dehydration plant should not
have been necessary had the facilities been properly constructed and maintained
by the Defendants. The expenditures, the Company claims, were inappropriately
charged to the field's carried interest account. The effect of an increased
carried interest account is to extend the period before payout begins to the
carried interest account owners.
The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million. The Company claims that by 1993 at least $34 million of unnecessary
expenses had been wrongfully charged to the carried interest account. The
Company's 30% share of these expenses would be approximately $10.2 million. The
Company further claims that if production had commenced in 1984, the carried
interest account would have been paid off in approximately two years and the
Company would have begun to receive revenues from the field in 1986. At present,
the Company does not expect to receive revenues before the year 2000, based on a
price of Cdn. $1.39 per mcf and current production rates.
<PAGE>
8. Litigation (Cont'd)
Columbia has filed a counterclaim against the Company seeking, if the
Company is successful in its claim for the forfeiture of the field, repayment
from the Company of all sums Columbia has expended on the Kotaneelee lands
before the Company is entitled to its interest.
The parties to the litigation have conducted extensive discovery since
the filing of the claims. The trial began on September 3, 1996 and is ongoing.
Based upon recently discovered evidence, the Company has petitioned the court
for leave to amend its complaint to add a claim that the Defendants failed to
develop the field in a timely manner. The Company is unable to estimate the time
necessary to conclude the litigation.
Matters Ancillary to Kotaneelee Litigation
In its 1989 statement of claim, the Company sought a declaratory
judgment regarding two issues:
(1) whether interest accrued on the carried interest account; and
(2) whether expenditures for gathering lines and dehydration
equipment are expenditures chargeable to the carried interest
account or whether the Company will be assessed a processing
fee on gas throughput.
With respect to the first issue, the Company maintains that no interest
should accrue on the account and the Defendants have not contested this
position. With regard to the second issue, the Company maintains that the
expenditures are chargeable to the carried interest account. Mobil, Esso and
Columbia have essentially agreed to the Company's position while the Amoco Dome
Group continues to contest this issue.
On January 22, 1996, the Company settled two claims outstanding against
the Company in the Court of Queens Bench, Calgary, Alberta, which related to a
suit brought against AlliedSignal Inc. ("AlliedSignal") in Florida which was
dismissed on the basis that Canada was the appropriate forum for the litigation.
AlliedSignal had sought additional relief against the Company in Canada to
preclude other types of suits by the Company and to recover the costs of the
defense of the initial action. The settlement bars AlliedSignal from making a
claim against the Company for any costs in connection with the Kotaneelee
Litigation. The Company agreed not to bring any action against AlliedSignal in
connection with the Kotaneelee gas field. Neither party made any monetary
payment to the other party.
<PAGE>
8. Litigation (Cont'd)
In 1991, Anderson Exploration Ltd. acquired all of the shares in
Columbia and changed its name to Anderson Oil & Gas Inc. ("Anderson"). Anderson
is now the sole operator of the field and is a direct defendant in the Canadian
lawsuit. Columbia's previous parent, The Columbia Gas System, Inc., which was
reorganized in a bankruptcy proceeding in the United States, is contractually
liable to Anderson in the legal proceeding described above.
The working interest owners have reported that they have been selling
Kotaneelee gas since February 1991.
Under Canadian law certain costs (known as "taxable costs") of the
litigation may be assessed against the nonprevailing party. Taxable costs
consist primarily of attorney's and expert witness fees during trial. The trial
is presently scheduled to last twelve months, therefore, taxable costs could be
substantial. While taxable costs are not now determinable, the Company estimates
that taxable costs, assuming a twelve month trial, could be approximately $1.5
million. However, a judge in complex and lengthy trials has the discretion to
increase an award of taxable costs. There are no assurances however, that
taxable costs will not exceed this amount or that the duration of the trial will
not exceed twelve months. The actual trial time through March 1998 is
approximately 5 months. During 1997, the Company was assessed approximately
$110,000 in taxable costs payable to the Defendants in connection with the
Company's motion to disqualify Amoco's legal counsel which was denied.
The amount is included in 1997 legal expenses.
There is no assurance whatever that the Company will be successful on
the merits of its claims, which have been vigorously defended by the Defendants.
There is also no assurance that the Company will be awarded any damages, or
that, if damages are awarded, the Court will apply the measure of damages the
Company claims should be applied.
9. Related party transactions
Fees paid or accrued for legal services rendered to the Company by
Reasoner, Davis & Fox, (of which firm Mr. C. Dean Reasoner, a director of the
Company until March 11, 1997, is a partner,) were U.S. $111,000 and $133,000 for
the years 1996 and 1995, respectively.
In 1991, the Company granted interests to certain of its officers,
employees, directors, counsel and consultants amounting to an aggregate of 7.8%
of any and all benefits to the Company after expenses from the litigation in
Canada relating to the Kotaneelee gas field. The Company has reserved a 2.2%
interest in such net benefits for possible future grants to persons who may
include officers and directors of the Company.
<PAGE>
9. Related party transactions (Cont'd)
Messrs. Heath and Reasoner have royalty interests in certain of the
Company's oil and gas properties, (present and past) which were received
directly or indirectly through the Company. The Company and third-party
operators and/or owners of properties made payments pursuant to these royalties
for the benefit of Mr. Reasoner were U.S. $5,342 and $6,159 in 1996 and 1995,
and for Mr. Heath U.S. $11,158, $10,844 and $12,777 in 1997, 1996 and 1995,
respectively.
10. Other financial information
Accrued liabilities
1997 1996
---- ----
Accrued liabilities due to working
interest partners $ - $ 12,050
Accrued accounting and legal expenses 137,650 52,793
Accrued royalties 139,645 116,415
Other 420 846
-------- --------
$277,715 $182,104
======== ========
Year ended December 31,
1997 1996 1995
Royalty payments (1) $366,661 $147,572 $150,224
======== ======== ========
Interest payments (2) $ 6,650 $ 7,099 $ 10,000
======== ======== ========
Large corporation tax payments $ 27,388 $ 2,741 $ 4,527
======== ======== ========
- --------------------
(1) Oil and gas sales are reported net of royalties paid.
(2) Bank line of credit charges.
11. Other commitments
During March 1998, the Company agreed to participate with two other
companies in a heavy oil recovery project in California. The field is estimated
to have approximately 12 million barrels of oil in place with only 13% of the
oil recovered to date. The initial purchase price for a 90% (75% APO) interest
in the project is $200,000 (Company share 30% - $60,000). There is also a
commitment to spend $600,000 to perform remedial work on the field and to
complete a pilot stream flood program during the first year of the project
(Company share $180,000). If the total amount of expenditures is less than
$600,000, the participants' interests will be reduced proportionately to an
amount which is not less than 10% (Company share - 3%).
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
SUPPLEMENTARY INFORMATION ON OIL AND GAS ACTIVITIES
(unaudited)
The following information includes estimates which are subject to
rapid and unanticipated change. Therefore, these estimates may not accurately
reflect future net income to the Company.
All amounts below except for costs, acreage, wells drilled and present
activities relate to Canada. Oil and gas reserve data and the information
relating to cash flows were provided by Paddock Lindstrom & Associates Ltd.,
independent consultants.
Estimated net quantities of proved oil and gas reserves:
Oil Gas
(bbls) (bcf)
Proved reserves:
December 31, 1994 473,600 32.957
Revisions of previous estimates (157,908) 1.559
Production* (30,892) (1.311)
-------- -------
December 31,1995 284,800 33.205
Revisions of previous estimates 178,448 (2.655)
Production* (37,448) (1.519)
-------- -------
December 31, 1996 425,800 29.031
Revisions of previous estimates 179,333 (3.802)
Production* (71,333) (.838)
-------- -------
December 31, 1997 533,800 24.391
======= ======
Proved developed reserves:
December 31, 1994 473,600 32.957
======= ======
December 31, 1995 284,800 33.205
======= ======
December 31, 1996 358,400 28.265
======= ======
December 31, 1997 508,200 24.391
======= ======
- -----------------
* Production data includes oil and gas sales and the proceeds from the
carried interest properties.
<PAGE>
Results of oil and gas operations:
<TABLE>
<CAPTION>
1997 1996 1995
---------- ---------- ----------
Income:
<S> <C> <C> <C>
Oil and gas sales $1,644,222 $1,163,644 $ 922,594
Proceeds under carried
interest agreements 475,697 590,935 734,066
---------- ---------- ----------
2,119,919 1,754,579 1,656,660
---------- ---------- ----------
Costs and expenses:
Production costs 799,372 476,562 503,648
Depletion depreciation, and
amortization 623,600 654,982 499,630
Provision for future site
restoration costs 21,500 24,600 16,800
Income tax expense - - -
---------- ---------- ----------
1,444,472 1,156,144 1,020,078
---------- ---------- ----------
Net income from operations $ 675,447 $ 598,453 $ 636,582
========== ========== ==========
Costs of oil and gas activities:
1997 1996 1995
---------- ---------- ----------
Acquisition costs $ 399,000 $ 484,000 $ 49,000
Exploration 546,000 146,000 92,000
Development 2,313,000 866,000 243,000
</TABLE>
Standardized measure of discounted future net cash flows relating to proved oil
and gas reserve quantities during the following period (in thousands of
dollars):
<TABLE>
<CAPTION>
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Future cash inflows $ 46,435 $ 49,410 $ 48,298
Future development and
production costs (22,517) (20,813) (18,473)
---------- ---------- ----------
23,918 28,597 29,825
Future income tax expense* (1,573) (2,931) (4,218)
---------- ---------- ----------
Future net cash flows 22,345 25,666 25,607
10% annual discount (7,836) (9,691) (10,679)
---------- ---------- ----------
Standardized measure of discounted
future net cash flows $ 14,509 $ 15,975 $ 14,928
========== ========== ==========
</TABLE>
* Reflects tax benefit for the years 1997, 1996 and 1995, from carryforward of
exploration, development and lease acquisition costs, undepreciated capital
costs and book earned depletion of $18,065,000, $17,032,000 and $13,679,000.
Current prices used in the foregoing estimates were based upon selling
prices at the wellhead in the last month of each fiscal period. Current costs
were based upon estimates made by consulting engineers at the end of each year.
<PAGE>
Changes in the standardized measure during the following periods (in thousands
of dollars):
Year ended December 31,
1997 1996 1995
-------- -------- --------
Changes due to:
Prices and production costs $ (579) $ 3,248 $ (88)
Future development costs (2,350) (1,049) 83
Sales net of production costs (1,562) (1,330) (1,428)
Development costs incurred
during the year 2,313 866 243
Net change due to extensions,
discoveries and improved recovery 1,692 1,458 -
Revisions of quantity estimates (3,642) (4,229) (3,404)
Accretion of discount 1,723 1,660 1,927
Net change in income taxes 939 423 1,078
------- ------- -------
Net change $(1,466) $ 1,047 $(1,589)
======== ======= ========
<PAGE>
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None.
PART III
For information concerning Item 10 - Directors and Executive Officers
of the Company, Item 11 - Executive Compensation, Item 12 - Security Ownership
of Certain Beneficial Owners and Management and Item 13 - Certain Relationships
and Related Transactions, see the Proxy Statement of Canada Southern Petroleum
Ltd. relative to the Annual Meeting of Shareholders for the fiscal year ended
December 31, 1997, which will be filed with the Securities and Exchange
Commission, which information is incorporated herein by reference. For
information concerning Item 10 - Executive Officers of the Company, see Part I.
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) (1) Financial Statements
The financial statements listed below and included under Item
8, above are filed as part of this report.
Page Reference
Report of Independent Auditors 35
Consolidated balance sheets at December 31, 1997 and 1996 36
For the years ended December 31, 1997, 1996 and 1995
Consolidated statements of operations and deficit 37
Consolidated statements of cash flows 38
Consolidated statements of Limited Voting Shares and Contributed
Surplus for the three years ended December 31, 1997 39
Notes to consolidated financial statements 40-52
Supplementary information on oil and gas activities (unaudited) 53
(2) Consolidated Financial Statement Schedules
All schedules have been omitted since the required
information is not present or not present in amounts sufficient to require
submission of the schedule, or because the information required is included in
the consolidated financial statements or the notes thereto.
(3) Exhibits
The following exhibits are filed as part of this
report:
Item Number
2. Plan of acquisition, arrangement, liquidation or
succession
None
<PAGE>
3. Articles of Incorporation and By-Laws
Memorandum of Association as amended on June 30,
1982, May 14, 1985 and April 7, 1988 and By-laws, as
amended, filed as Exhibit 3 to Registration Statement
No. 33-99052 as filed on November 7, 1995.
4. Instruments defining the rights of security holders,
including indentures
None.
9. Voting trust agreement
None.
10. Material contracts
(a) Agreements relating to Kotaneelee.
(1.) Copy of Agreement dated May 28, 1959 between
the Company et al. and Home Oil Company Limited
et al. and Signal Oil and Gas Company filed as
Exhibit 10 (a) (1) to Registration Statement No.
33-99052 as filed on November 7, 1995 is incorporated
herein by reference.
(2.) Copies of Supplementary Documents to May 28,
1959 Agreement (see (1) above), dated June 24, 1959,
consisting of Guarantee by Home Oil Company Limited
and Pipeline Promotion Agreement, filed as Exhibit
10(a)(2) to Registration Statement No. 33-99052 as
filed on November 7, 1995 is incorporated herein by
reference.
(3.) Copy of Modification to Agreement dated May
28, 1959 (see (1) above), made as of January 31,
1961, filed as Exhibit 10(a)(3) to Registration
Statement No. 33-99052 as filed on November 7, 1995
is incorporated herein by reference.
(4.) Copy of Agreement dated April 1, 1966 among
the Company et al. and Dome Petroleum Limited et al.
filed as Exhibit 10(a)(4) to Registration Statement
No. 33-99052 as filed on November 7, 1995 is
incorporated herein by reference.
<PAGE>
(5.) Copy of Letter Agreement dated February 1,
1977 between the Company and Columbia Gas Development
of Canada, Ltd. for operation of the Kotaneelee gas
field filed as Exhibit 10(a) to Registration
Statement No. 33-99052 as filed on November 7, 1995
is incorporated herein by reference.
(b) Copy of Agreement dated January 28, 1972 between
the Company and Panarctic Oils Ltd. for development
of the offshore Arctic Islands gas fields filed as
Exhibit 10(b) to Registration Statement No. 33-99052
as filed on November 7, 1995 is incorporated herein
by reference.
(c) Stock Option Plan adopted December 9, 1992 filed
as Exhibit 10(g) to Report on Form 10-K for the
fiscal year ended June 30, 1993 is incorporated
herein by reference.
11. Statement re computation of per share earnings
Not applicable.
12. Statement re computation of ratios
None.
13. Annual report to security holders
Not applicable.
16. Letter re change in certifying accountant
Not applicable.
18. Letter re change in accounting principles
None.
20. Previously unfiled documents
None.
21. Subsidiaries of the Company
Canpet Inc. incorporated in Delaware on August 3,
1973. C. S. Petroleum Limited incorporated in Nova
Scotia on December 15, 1981.
<PAGE>
22. Published report regarding matters submitted to vote
of security holders
None.
23. Consents of experts and counsel
(a) Paddock Lindstrom & Associates, Ltd. filed
herein.
(b) Ernst & Young filed herein.
24. Power of attorney
Not applicable.
27. Financial Data Schedule
Filed herein.
28. Information from reports furnished to state insurance
regulatory authorities
Not applicable.
99. Additional exhibits
(a) Complaint of Allied-Signal Inc. in its action against
Dome Petroleum Limited, Amoco Production Company, and
Amoco Canada Petroleum Company Ltd. filed September
2, 1988 in the Court of Queens Bench of Alberta,
Judicial District of Calgary, Canada, filed as
Exhibit 99(a) to Registration Statement No. 33-99052
as filed on November 7, 1995 is incorporated herein
by reference.
(b) Answer and Counterclaim of Dome Petroleum Limited,
Amoco Production Company, and Amoco Canada Petroleum
Company Ltd. filed September 21, 1988 in the Court of
Queen's Bench of Alberta, Judicial District of
Calgary, Canada, which answers the Allied-Signal
complaint in (b) above and which names the Company
and others as counterclaim defendants, filed as
Exhibit 99(b) to Registration Statement No. 33-99052
as filed on November 7, 1995 is incorporated herein
by reference.
<PAGE>
(c) Statement of Claim filed on October 27, 1989 against
Columbia Gas Development of Canada Ltd., Amoco
Production Company, Dome Petroleum Limited, Amoco
Canada Petroleum Company Ltd., Mobil Oil Canada Ltd.
and Esso Resources of Canada Ltd. in the Court of
Queen's Bench of Alberta Judicial District of
Calgary, Alberta, Canada filed as Exhibit 99(c) to
Registration Statement No. 33-99052 as filed on
November 7, 1995 is incorporated herein by reference.
(d) Amended Statement of Claim, amending the October 27,
1989 Statement of Claim, filed on March 12, 1990 and
filed as Exhibit 99(d) to Registration Statement No.
33-99052 as filed on November 7, 1995 is incorporated
herein by reference.
(e) Amended Statement of Claim in the same action, filed
on November 17, 1993, filed as Exhibit 28(ii) to Form
8-K dated November 17, 1993 is incorporated herein by
reference.
(f) Amended Statement of Third Party Notice by Amoco
Canada Production Company Ltd. and Amoco Production
Company, filed November 17, 1993 in the same action,
and filed as Exhibit 99(e).
(g) Amended Statement of Defense to Third Party Notice by
Anderson Oil & Gas Inc. (formerly Columbia Gas
Development of Canada Ltd.) filed January 27, 1994 in
the same action, and filed as Exhibit 99(g) to Form
10-K dated for the period ended December 31, 1993, is
incorporated herein by reference.
(h) Documents regarding settlement with AlliedSignal Inc.
as Exhibits to Form 8-K as filed on January 30, 1996
are incorporated herein by reference.
(1) Covenant Not to Sue.
(2) Discontinuance of Action. Action No. 8801-13549
Court of Queen's Bench of Alberta Judicial
District of Calgary.
(3) Order. Action No. 8801-123549 Court of Queens
Bench of Alberta Judicial District of Calgary.
(4) Partial Discontinuance of Counterclaim. Action
No. 8801-13549 Court of Queen Bench of Alberta
Judicial District of Calgary.
<PAGE>
(5) Notice of Discontinuance of Third Party
Proceedings as Against Allied-Signal Inc. Action
No. 9001-03466 Court of Queens Bench of Alberta
Judicial District of Calgary.
(b) Reports on Form 8-K
On October 1, 1997, the Company filed a Current Report on Form
8-K to report that Mr. Charles J. Horne resigned as a director of the Company
for primarily health reasons, and that Mr. Timothy L. Largay was elected a
director.
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
CANADA SOUTHERN PETROLEUM LTD.
(Registrant)
Dated: March 27, 1998 By /s/ M. Anthony Ashton
--------------------------- -----------------------
M. Anthony Ashton
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
By /s/ M. Anthony Ashton By /s/ Beverley A. Scobie
M. Anthony Ashton Beverley A. Scobie
President and Director Treasurer and Chief Financial and
Accounting Officer
Dated: March 27, 1998 Dated: March 27, 1998
------------------------------- -----------------------------
By /s/ Benjamin W. Heath By /s/ Timothy L. Largay
Benjamin W. Heath Timothy L. Largay
Director Director
Dated: March 27, 1998 Dated: March 27, 1998
------------------------------- -----------------------------
By /s/ Arthur B. O'Donnell By /s/ Eugene C. Pendery
Arthur B. O'Donnell Eugene C. Pendery
Director Director
Dated: March 27, 1998 Dated: March 27, 1998
------------------------------- -----------------------------
<PAGE>
Index to Exhibits
Exhibit 23(a) Consent of Independent Petroleum Engineers
Exhibit 23(b) Consent of Independent Auditors
Exhibit 27 Financial Data Schedule
Consent of Independent Petroleum Engineers
The undersigned firm of Independent Petroleum Engineers, of Calgary, Alberta,
Canada, knows that it is named as having prepared an evaluation of the interests
of Canada Southern Petroleum Ltd., prepared for filings with the SEC on Form
10-K 1997, dated March 25, 1998, and hereby gives its consent to the use of its
name and to the use of the said estimates.
Paddock Lindstrom & Associates Ltd.
/s/ L. K. Lindstrom
L. K. Lindstrom, P. Eng.
President
Consent of Independent Auditors
We consent to the incorporation by reference in the Registration Statement (Form
S-8) pertaining to the Stock Option Plan of Canada Southern Petroleum Ltd. of
our report dated March 20, 1998, with respect to the consolidated financial
statements of Canada Southern Petroleum Ltd. included in the Annual Report (Form
10-K) for the year ended December 31, 1997.
/s/ Ernst & Young
Chartered Accountants
Calgary, Canada
March 27, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1
<CURRENCY> Canadian Dollars
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<EXCHANGE-RATE> 0.6992
<CASH> 2,129,156
<SECURITIES> 3,373,334
<RECEIVABLES> 1,226,086
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 6,970,854
<PP&E> 21,988,786
<DEPRECIATION> (8,004,015)
<TOTAL-ASSETS> 20,955,625
<CURRENT-LIABILITIES> 1,398,236
<BONDS> 0
0
0
<COMMON> 14,234,740
<OTHER-SE> 5,111,675
<TOTAL-LIABILITY-AND-EQUITY> 20,955,625
<SALES> 2,119,919
<TOTAL-REVENUES> 2,514,978
<CGS> 0
<TOTAL-COSTS> 4,272,642
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (1,757,664)
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,757,664)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,757,664)
<EPS-PRIMARY> (0.12)
<EPS-DILUTED> (0.12)
</TABLE>
