UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
-------------------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission file number 1-3793
CANADA SOUTHERN PETROLEUM LTD.
(Exact name of registrant as specified in its charter)
NOVA SCOTIA, CANADA 98-0085412
State or other jurisdiction of (I.R.S. Employer
incorporation or organization Identification No.)
Suite 1410, One Palliser Square
125 Ninth Avenue, S.E.
Calgary, Alberta CANADA T2G 0P6
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (403) 269-7741
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Limited Voting Shares, Boston Stock Exchange
$1 (Canadian) per share Pacific Exchange, Inc.
Toronto Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Limited Voting Shares, NASDAQ SmallCap Market
$1 (Canadian) per share
(Title of Class)
<PAGE>
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
|X| Yes |_| No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K(s.229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. |X|
The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately U.S. $112,272,000 at March 17, 2000.
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
Limited Voting Shares, par value $1.00 (Canadian) per share, 14,284,970
shares outstanding as of March 17, 2000.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement of Canada Southern Petroleum Ltd. related to the Annual
Meeting of Shareholders for the year ended December 31, 1999, which is
incorporated into Part III of this Form 10-K.
<PAGE>
TABLE OF CONTENTS
Page
PART I
Item 1. Business 4
Item 2. Properties 13
Item 3. Legal Proceedings 20
Item 4. Submission of Matters to a Vote of Security Holders 24
PART II
Item 5. Market for the Company's Limited Voting Shares and Related
Stockholder Matters 25
Item 6. Selected Financial Data 27
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 35
Item 8. Financial Statements and Supplementary Data 36
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 58
PART III
Item 10. Directors and Executive Officers of the Company 58
Item 11. Executive Compensation 58
Item 12. Security Ownership of Certain Beneficial Owners and Management 58
Item 13. Certain Relationships and Related Transactions 58
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 59
- ----------------------------
Unless otherwise indicated, all dollar figures set forth are expressed in
Canadian currency. The exchange rate at March 17, 2000 was $1.00 Canadian =
U.S. $.68.
<PAGE>
PART I
Item 1. Business
The nature of Canada Southern Petroleum Ltd.'s (the "Company" or
"Canada Southern") business is described at Item 1(c) herein, and a description
of its principal crude oil and gas properties in Canada appears in Item 2
herein. For additional information regarding the development of the Company's
business, see "Properties" and "Supplemental Information on Oil and Gas
Activities".
(a) General Development of Business
Yukon Territory - The Kotaneelee Field
The Company's principal asset is a 30% carried interest in the
Kotaneelee natural gas field located on Exploration Permit 1007 in the Yukon
Territory, Canada. The permit consists of 31,888 gross acres (9,566 net acres)
which is partially developed by two natural gas wells that had combined gross
productive capability at December 31, 1999 of 65 million cubic feet per day
(19.2 million cubic feet per day net). Gross natural gas sales were
approximately 45 million cubic feet per day (net 13.5 million cubic feet per
day) at December 31,1999 as a result of shrinkage and fuel gas requirements.
Anderson Exploration Ltd. (the "Operator") operates the Kotaneelee field. See
Item 3 - "Legal Proceedings" for a discussion of the Kotaneelee Litigation
concerning this asset.
Production at Kotaneelee commenced in February 1991. According to
government reports, total production in billion cubic feet ("bcf") from the
Kotaneelee gas field since 1991 has been as follows:
Calendar Year Production (bcf)
------------- ----------------
1991 8.1
1992 18.0
1993 17.5
1994 16.7
1995 15.7
1996 15.2
1997 14.4
1998 16.0
1999 22.3
----
Total 143.9
=====
<PAGE>
A carried interest owner such as the Company is entitled to receive its
share of field revenues after the working interest parties recover their
operating and capital costs. The Operator reported that as of November 30, 1999
development costs totaling $96.7 million had been incurred and repaid. As of
December 31, 1999, the Operator also reported that the Company's share of net
revenues due to the Company totaled $412,374. The amount of recoverable costs is
one of the issues being contested in the Kotaneelee litigation. The Company
claims, and the defendants deny, that the defendants have made improper charges
to the carried interest account and one defendant (Amoco Canada) maintains that
the carried interest account should be charged additional amounts for gas
processing fees. Amoco Canada claims that the remaining costs to be recovered at
July 31, 1999 were either $72,369,000 or $33,911,000 depending on inclusion of
interest. At this time, it is not possible to determine whether Amoco Canada
will be successful in its claim that gas processing fees should be charged to
the carried interest account.
Although, according to the Operator's reports, the Kotaneelee gas field
reached pay out status on November 10, 1999, the Operator has notified the
Company that it will not make any payments to the carried interest owners,
including the Company, until the issue of the amount of recoverable costs under
the carried interest account has been resolved by the Court of Queens Bench in
Calgary, Canada. The Operator has stated that it will deposit the Company's
share of net production proceeds in an interest bearing account with an escrow
agent. During March 2000, the Operator deposited $136,728 in the escrow account
which represents the Operator's share of December 1999 gas sales less January
and February 2000 operating and capital expenditures. A motion was filed in
December 1999 by the plaintiffs in Canada to direct all of the defendants to
make timely payments of all current and future amounts due from the Company's
share of field revenues. The Company expects that the Court will hear the motion
in April 2000.
British Columbia Properties
The Company's major source of income has been from the sale of crude
oil and natural gas from its properties located in northeast British Columbia
where the Company has working and carried interests.
In addition to its producing properties, the Company has various
petroleum and natural gas leases in northeast British Columbia. As a result of
the geological and geophysical work performed on these leases, various drilling
prospects were identified. Certain of these prospects were farmed-out to other
operators and five wells were drilled in 1999 of which three wells were
successful. There are also other prospects which have not been drilled. The
cumulative dry hole costs to drill these prospects is estimated to be
approximately $1.75 million. The Company continues to evaluate and attempt to
acquire additional petroleum and natural gas leases in British Columbia.
Presently, the Company has interests in 49,013 gross developed acres (7,977 net
acres) and 28,820 gross undeveloped acres (15,091 net acres).
Arctic Islands
As of December 31, 1999, the Company held working interests in 45,100
gross acres (1,817 net acres) and carried interests in 133,260 gross acres
(37,257 net acres) in the Sverdrup Basin, located in the Arctic Islands. The
Hecla, Whitefish, Drake Point, Roche Point, Kristoffer, Romulus and Bent Horn
fields have been designated significant discovery lands ("SDL" ) by the Canadian
Federal Government. The Company's interests in the SDL's have been retained
pending development.
Panarctic Oils Ltd. ("Panarctic"), the operator, received Federal
government regulatory approvals for a pilot project to move shipments of crude
oil from the Bent Horn field by tanker through the Northwest Passage to southern
Canada in 1985. Through December 31, 1996, approximately 2.7 million barrels of
Bent Horn crude had been sold. In 1996, the operator shut down production from
the field and dismantled the production facilities because of economic
uncertainties. The Company has a 5% carried interest in the area which has not
yet reached pay out status. The timing of any pay out is uncertain.
Northwest Territories Properties
The Company has a 45% carried interest in the Northwest Territories in
the Celibeta field, designated as SDL by the Federal Government (1,594 gross
acres and 717 net acres). The gas field is presently shut-in.
Because of the recent activity in the Northwest Territories, the
Company is reviewing its holdings in the area to take advantage of any potential
opportunities.
Alberta
During 1999, the Company's primary Alberta asset and revenue
producing property was its heavy crude oil production and related facilities at
Kitscoty. Due to the requirement of significant additional investment, the
prospect of low prices for heavy oil and a shift in its business strategy, the
Company sold its 10 % working interest to the operator for $336,000 effective
October 1, 1999. The transaction was completed during February 2000 and the
proceeds of sale will be credited to oil and gas properties in fiscal 2000.
The Company continues to invest in petroleum and natural gas leases in
Alberta and has a current land inventory of 21,637 gross acres (7,354 net
acres). Its interests range from 10% to 100% in these leases. The Company is
presently performing geological and geophysical work on these leases to
determine the prospects for commercial petroleum and natural gas production. As
prospects are identified, the Company may participate in drilling or,
alternatively, farm out the prospects to other operators for drilling
commitments.
Saskatchewan
The Company has a 3.75% working interest in five sections in
Saskatchewan. During 1999, there was no activity on these properties and the
lands remain undeveloped.
United States
Texas
In 1999, the Company participated in the drilling and completion of two
wells in Stephens County, Texas at a cost of $382,000. This resulted in one dry
hole and one nominal crude oil/natural gas producer. The Company will attempt to
farm out its remaining undrilled acreage and expects to make minimal additional
investment during the year 2000.
California
During 1999, the Company sold its investment in its heavy crude oil
recovery project in California because of dissatisfaction with the progress of
the program to develop the field reserves. The consideration received for its
30% interest was the purchaser's common stock (presently unmarketable) and a
promissory note which together approximated the carrying costs ($196,000) of the
property prior to the costs being written down in 1998 to a nominal value of $1.
(b) Financial Information about Industry Segments
Since the Company is primarily engaged in only one industry, oil and
gas exploration and development, this item is not applicable to the Company. See
Item 8 - "Financial Statements and Supplemental Data" for general financial
information concerning the Company.
(c) (1) Narrative Description of the Business
The Company was incorporated in 1954 under the Canada
Corporations Act. In 1979, it became subject to the Canadian Business
Corporations Act, and in 1980, was continued under the Nova Scotia Companies
Act.
The Company is, either in its own right, or through other entities,
engaged in the exploration for and development of properties containing or
believed to contain recoverable oil and gas reserves and the sale of oil and gas
from these properties. Although many of the properties in which the Company has
interests are undeveloped, all properties with proved reserves are partially or
fully developed. The Company's interests in exploratory ventures are on
properties located in Alberta, British Columbia, Saskatchewan, the Northwest and
Yukon Territories and the Arctic Islands in Canada and in the United States. The
Company's principal asset is its 30% carried interest in the Kotaneelee field, a
partially developed gas field (See Item 3 - "Legal Proceedings".) The Company
also has interests in producing properties in British Columbia and Alberta.
Most of this acreage is covered by carried interest agreements, which
provide that revenues are not payable to the Company until expenditures by the
carrying partners have been recouped from production, and that operating
decisions are made by the carrying partners. Generally, the Company may, at any
time, as to each block or economic unit, elect to convert from a carried
interest position to a working interest position by paying its share of the
unrecouped expenditures for the unit (i.e., expenditures not recouped from
production revenues). At December 31, 1999, the Company's share of unrecouped
expenditures was as follows:
British Columbia:
Ex-permit 149 $4,019,000
Ex-permit 102 (Siphon) 980,000(At May 31, 1999)
Yukon and Northwest Territories:
Ex-permit 2713 (Celibeta) 321,000
(i) Principal Products
The majority of the Company's oil and gas interests
are carried interests. The Company also participates in the production and sale
of crude oil and natural gas derived from its working interests.
(ii) Status of Product or Segment
At present, some of the properties in which the
Company has interests are undeveloped and/or nonproducing.
(iii) Raw Materials
Not applicable.
(iv) Patents, Licenses, Franchises and Concessions Held
Permits and concessions are important to the
Company's operations, since they allow the search for and extraction of any
crude oil and natural gas discovered on the areas covered. See the schedule of
properties under Item 2 - "Properties"
(v) Seasonality of Business
The Company's business is not seasonal, except
that sales of natural gas peak during the winter heating season. Exploration and
development activities are restricted in certain areas on a seasonal basis
because extreme weather conditions affect transportation and the ability to
pursue these activities.
(vi) Working Capital Items
Not applicable.
(vii) Customers
Most of the natural gas produced from Company
carried interest properties is being sold by the operators, Anderson Exploration
Ltd. and Petro-Canada Oil and Gas, to various gas marketers. The production
from the Kotaneelee gas field is being sold by the working interest partners who
have not disclosed the purchasers.
(viii) Backlog
Not applicable.
(ix) Renegotiation of Profits or Termination of Contracts
or Subcontracts at the Election of the Government
Not applicable.
(x) Competitive Conditions in the Business
The exploration for and production of crude oil and
gas are highly competitive operations, both internally within the oil and gas
industry and externally with producers of other types of energy. The ability to
exploit a discovery of crude oil or gas is dependent upon considerations such as
the ability to finance development costs, the availability of equipment, and the
ability to overcome engineering and construction delays and difficulties. The
Company must compete with companies which have substantially greater resources
available to them. Because the majority of Company interests are in remote
areas, operation of its properties is more difficult and costly than those in
more accessible areas.
Furthermore, competitive conditions may be
substantially affected by various forms of energy legislation which may have
been or may be proposed in the United States and Canada; however, it is not
possible to predict the nature of any such legislation which may ultimately be
adopted or its effects upon the future operations of the Company. For a further
discussion of Canadian governmental regulation of the petroleum industry, see
Item 1(d)(2) - "Risks Attendant to Foreign Operations".
(xi) Research and Development
Not applicable.
(xii) Environmental Regulation
See Government ReguIation of the Canadian Oil and
Gas Industry - Environmental Regulation.
(xiii) Number of Persons Employed by Company
The Company currently has three full time employees,
all of whom are located in Canada. The Company also relies to a great extent on
consultants (approximately 10)for technical, legal, accounting and
administrative services. The Company uses consultants because it is more cost
effective than employing a larger full time staff.
(d) Financial Information about Foreign and Domestic Operations
and Export Sales
(1) Revenues, Operating Losses and Identifiable Assets
Substantially all of the Company's operating assets
and revenues are attributable to its operations in Canada. Operating losses are
substantially attributable to the ongoing Kotaneelee litigation.
(2) Risks Attendant to Foreign Operations
The properties in which the Company has interests are
located primarily in Canada and are subject to certain risks involved in the
ownership and development of such foreign property interests. These risks
include but are not limited to those of: nationalization; expropriation;
confiscatory taxation; native rights; changes in foreign exchange controls;
currency revaluation; burdensome royalty terms; export sales restrictions;
limitations on the transfer of interests in exploration licenses; and other laws
and regulations which may adversely affect the Company's properties, such as
those providing for conversion, proration, curtailment, cessation or other forms
of limiting or controlling production of, or exploration for, hydrocarbons.
Thus, an investment in the Company represents an exposure to risks in addition
to those inherent in petroleum exploratory ventures.
Governmental Regulation of the Canadian Oil and Natural Gas Industry
The oil and natural gas industry in Canada is subject to extensive
controls and regulations imposed by various levels of government relating to
land tenure, production, production facilities, pricing and marketing,
royalties, environmental protection and other matters. Outlined below are some
of the more significant aspects of the legislation, regulations and agreements
governing the oil and natural gas industry in Canada. All current legislation is
a matter of public record and the Company is unable to predict whether any
additional legislation or amendments may be enacted.
Land Tenure
Crude oil and natural gas located in the western provinces is owned
predominantly by the respective provincial governments. Provincial governments
grant rights to explore for and produce crude oil and natural gas pursuant to
leases, licenses and permits for varying terms from two years and on terms and
conditions set forth in provincial legislation including requirements to perform
specific work or make payments. Crude oil and natural gas located in such
provinces can also be privately owned and rights to explore for and produce such
crude oil and natural gas are granted by lease on such terms and conditions as
may be negotiated. The term of both Crown and freehold leases will generally
continue as long as crude oil or natural gas is produced from the property.
Crude oil and natural gas rights on federal lands outside of the
provinces is generally regulated by the Government of Canada unless authority
has been delegated by agreement to the territorial government or the government
of the province adjacent to the federal offshore area. In May 1993, the Canada
Yukon Oil and Gas Accord was signed which allowed for the transfer to the Yukon
of authority to administer and control crude oil and natural gas resources
within that territory and for the establishment of an Oil and Gas Management
Regime. The transfer has been completed and the lands are now administered by
the Yukon Government.
Production and Production Facilities
The Governments of Canada, Alberta, British Columbia and Saskatchewan
have enacted statutory provisions regulating the production of crude oil and
natural gas. These regulations may restrict the maximum allowable production
from a well based on reservoir engineering and/or conservation practices. The
construction and operation of facilities to recover and process crude oil and
natural gas are also subject to regulation.
Pricing and Marketing - Crude oil
In Canada, producers of crude oil negotiate sales contracts directly
with crude oil purchasers, with the result that the market determines the price
of crude oil. Certain purchasers periodically advertise for volumes of crude oil
they are prepared to purchase and the price being offered for such volumes. The
price depends in part on crude oil quality, prices of competing fuels, distance
to market and the value of refined products.
Pricing and Marketing - Natural Gas
In Canada, the price of natural gas is determined by negotiation
between buyers and sellers, with the result that the market determines the price
of natural gas. Natural gas exported from Canada is subject to regulation by the
National Energy Board ("NEB") and the Government of Canada. Exporters are free
to negotiate prices and other terms with purchasers, provided that the export
contracts must continue to meet certain criteria prescribed by the NEB and the
Government of Canada. As is the case with crude oil, natural gas exports for a
term of less than two years must be made pursuant to an NEB order, or, in the
case of exports for a longer duration, pursuant to an NEB license and Governor
in Council approval.
The Governments of Alberta, British Columbia and Saskatchewan also
regulate the volume of natural gas which may be removed from those provinces for
consumption elsewhere based on such factors as reserve availability,
transportation arrangements and market considerations.
Royalties and Incentives
The royalty regime is a significant factor in the profitability of
crude oil and natural gas production. Royalties payable on production from lands
other than Crown lands are determined by negotiations between the mineral owner
and the lessee, although production from such lands may also be subject to
provincial taxes and regulations. Crown royalties are determined by government
regulation and are generally calculated as a percentage of the value of the
gross production, and the rate of royalties payable generally depends in part on
prescribed reference prices, well productivity, geographical location, field
discovery date and the type or quality of the product produced. The value of the
gross production for royalty purposes may be based on a deemed value for the
product rather than the actual value received by the interest holder.
From time to time the Governments of Canada, Alberta, British Columbia
and Saskatchewan have established incentive programs which have included royalty
rate reductions, royalty holidays and tax credits for the purpose of encouraging
natural gas and crude oil exploration or enhanced recovery projects. Incentives
are intended to enhance the existing cash flow of the crude oil and natural gas
industry and to improve the economics of finding and developing new and more
costly crude oil and natural gas reserves. Crude oil royalty holidays for
specific wells and royalty reductions reduce the amount of Crown royalties paid
by the interest holder to the respective government. Tax credit programs provide
a rebate on Crown royalties paid.
Environmental Regulation
The oil and natural gas industry is subject to environmental regulation
pursuant to local, provincial and federal legislation. Environmental legislation
provides for restrictions and prohibitions on spills, releases or emissions of
various substances produced in association with certain crude oil and natural
gas industry operations. An environmental assessment and review may be required
prior to initiating exploration or development projects or undertaking
significant changes to existing projects. In addition, legislation requires that
well and facility sites be abandoned and reclaimed to the satisfaction of the
appropriate authorities. A breach of such legislation may result in the
imposition of fines or penalties. Federal environmental regulations also apply
to the use and transport of certain restricted and prohibited substances. The
Company is committed to meeting its responsibilities to protect the environment
wherever it operates and believes that it is in material compliance with
applicable environmental laws and regulations. The Company has not been required
to spend significant sums to comply with clean up laws and regulations.
Compliance by the Company with governmental provisions regulating the discharge
of materials to the environment or otherwise relating to the protection of the
environment are not expected to have a material effect on the capital
expenditures, earnings or competitive position of the Company.
(3) Data which Are Not Indicative of Current or Future Operations
Not applicable.
Item 2. Properties
(a) The principal asset of the Company is its 30% carried interest in
the Kotaneelee field, a partially developed gas field in the Yukon Territory.
See Item 3 - "Legal Proceedings." The Company also has interests in producing
properties in British Columbia and Alberta and in several exploration prospects.
The exploratory ventures are properties located in British Columbia, Alberta,
Saskatchewan, the Yukon and Northwest Territories and the Arctic Islands in
Canada and in the United States. Geophysical, geological and drilling work on
the Company's properties is conducted by the operators under various agreements
with the Company. The results of this work are reviewed by Company personnel and
consultants retained by the Company.
(b) (1) The information regarding reserves, costs of oil and gas
activities, capitalized costs, discounted future net cash flows and results of
operations is contained in Item 8 - "Financial Statements and Supplementary
Data."
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of Canada showing key Company properties
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of N.E. British Columbia and Yukon, Northwest Territories
showing Company interest lands
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map showing the Kotaneelee Field
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of the Arctic Island Fields
showing the Company interest lands
<PAGE>
(2) Reserves Reported to Other Agencies
Not applicable.
(3) Production
Average sales price per unit and average production cost for oil and
gas produced during the periods are shown below. Production costs are allocated
based on the weighted average of oil and gas sales. In 1999, oil production was
primarily heavy crude oil with high lifting costs. In prior years, oil
production consisted of a mix of light and heavy crude oil.
Average Sales Price Average Production Costs
Year Oil (per bbl) Gas (per mcf) Oil (per bbl) Gas (per mcf)
($) ($) ($) ($)
1999 17.38 1.83 12.82 1.45
1998 14.84 2.17 8.41 1.41
1997 22.50 2.31 8.70 1.30
(4) Productive Wells and Acreage
Productive wells and acreage on working and carried interest properties
as of December 31, 1999 are as follows:
Gross Wells Net Wells
Oil Gas Oil Gas
36 72 3.536 12.264
Gross and Net Developed Acres
Gross Acres Net Acres
Alberta 5,420 669
British Columbia 49,013 7,977
Yukon Territory 3,350 1,005
Arctic Islands 3,060 153
Texas, USA 40 16
--------- -------
60,883 9,820
====== =====
<PAGE>
(5) Undeveloped Acreage
Total developed and undeveloped acreage in which the Company has
interests is summarized by geographic area in the table below:
<TABLE>
Gross and Net Petroleum Acreage as of December 31, 1999
Developed Acres Undeveloped Acres
Gross Net Gross Net
Acres Acres % Acres Acres %
Canada:
British Columbia:
<S> <C> <C> <C> <C> <C> <C>
Carried Interests 30,130 6,410 21.3 5,708 1213 21.3
Working Interests 5,622 910 16.2 18,473 13,804 74.7
Overriding royalty interest 13,261 657 5.0 4,639 74 1.6
------ ------ ------- ---------
Total British Columbia 49,013 7,977 28,820 15,091
------ ----- ------ -------
Saskatchewan:
Working Interests 3,200 120 3.8
------- --------
Alberta:
Working Interests 3,511 645 18.4 21,477 7,349 34.2
Overriding Royalty Interest 1,909 24 1.3 160 5 3.1
------- ------- -------- ----------
Total Alberta 5,420 669 21,637 7,354
------- ------ ------ -------
Yukon & Northwest Territories:
Carried Interests 3,350 1,005 30.0 31,726 9,757 30.8
Arctic Islands:
Carried Interests 3,060 153 5.0 130,200 37,104 28.5
Working Interests - - 45,100 1,817 4.0
----------- --------- -------- -------
Total Arctic Islands 3,060 153 175,300 38,921
------- ------ ------- ------
Total Canada 60,843 9,804 260,683 71,243
Texas, USA 40 16 40.0 460 245 53.3
------- ------- --------- --------
TOTAL 60,883 9,820 261,143 71,488
====== ===== ======= ======
</TABLE>
(6) Drilling activity
Productive and dry net wells drilled during the following periods:
Gross Net
Year Productive Dry Productive Dry
1999 4 2 1.127 .798
1998 9 2 1.440 .200
1997 25 2 3.606 .250
<PAGE>
(7) Present Activities
There were no wells drilling at December 31, 1999.
(8) Delivery Commitments
None.
Item 3. Legal Proceedings
The Company, which has a 30% interest in the Kotaneelee gas field,
believes that the working interest owners in the field have not adequately
pursued the attainment of contracts for the sale of Kotaneelee gas. In October
1989 and in March 1990, the Company filed statements of claim in the Court of
Queens Bench of Alberta, Judicial District of Calgary, Canada, against the
working interest partners in the Kotaneelee gas field. The named defendants were
Amoco Canada Petroleum Corporation, Ltd., Dome Petroleum Limited (now Amoco
Canada Resources Ltd.), and Amoco Production Company (collectively the "Amoco
Dome Group"), Columbia Gas Development of Canada Ltd. ("Columbia"), Mobil Oil
Canada Ltd. ("Mobil") and Esso Resource of Canada Ltd. ("Esso") (collectively
the "Defendants"). In 1991, Anderson Exploration Ltd. acquired all of the shares
in Columbia and changed its name to Anderson Oil & Gas Inc. ("Anderson").
Anderson is now the sole operator (the "Operator") of the field and is a direct
defendant in the Canadian lawsuit. Columbia's previous parent, The Columbia Gas
System, Inc., which was reorganized in a bankruptcy proceeding in the United
States, is contractually liable to Anderson in the legal proceedings currently
at trial.
The Company claims that the Defendants breached a contract obligation
and/or a fiduciary duty owed to the Company to market gas from the Kotaneelee
gas field when it was possible to so do. The Company asserts that marketing the
Kotaneelee gas was possible in 1984 and that the Defendants deliberately failed
to do so. The Company seeks money damages and the forfeiture of the Kotaneelee
gas field. The Company presented evidence at trial that the money damages
sustained by the Company were approximately $100 million.
In addition, the Company has claimed that the Company's carried
interest account should be reduced because of improper charges to the carried
interest account by the Defendants. The Company claims that when the Defendants
in 1980 suspended production from the field's gas wells, they failed to take
precautionary measures necessary to protect and maintain the wells in good
operating condition. The wells thereafter deteriorated, which caused unnecessary
expenditures to be incurred, including expenditures to redrill one well. In
addition, the Company claims that expenditures made to repair and rebuild the
field's dehydration plant should not have been necessary had the facilities been
properly constructed and maintained by the Defendants. The expenditures, the
Company claims, were inappropriately charged to the field's carried interest
account. The effect of an increased carried interest account is to extend the
period before pay out begins to the carried interest account owners.
The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million. The Company claims that by 1993 at least $34 million of unnecessary
expenses had been wrongfully charged to the carried interest account. The
Company's 30% share of these expenses would be approximately $10.2 million. The
Company further claims that if production had commenced in 1984, the carried
interest account would have been paid out in approximately two years and the
Company would have begun to receive revenues from the field in 1986. The
Operator has reported that as of November 30, 1999 development costs totaling
$96.7 million had been incurred and repaid. As of December 31, 1999, based on
the Operator's report, the Company's share of net revenues due to the Company by
all the defendants totaled $412,374.
The amount of recoverable costs is one of the issues being contested in
the Kotaneelee litigation. The Company claims, and the defendants deny, that the
defendants have made improper charges to the carried interest account and one
defendant (Amoco Canada) maintains that the carried interest account should be
charged additional amounts for gas processing fees. Amoco Canada claims that the
remaining costs to be recovered at July 31, 1999 were either $72,369,000 or
$33,911,000 depending on inclusion of interest. At this time, it is not possible
to determine whether Amoco Canada will be successful in its claim that gas
processing fees should be charged to the carried interest account.
Although, according to the Operator's reports, the Kotaneelee gas field
reached pay out status on November 10, 1999, the Operator has notified the
Company that it will not make any payments to the carried interest owners,
including the Company, until the issue of the amount of recoverable costs under
the carried interest account has been resolved by the Court of Queens Bench in
Calgary, Canada. The Operator has stated that it will deposit the Company's
share of net production proceeds in an interest bearing account with an escrow
agent. During March 2000, the Operator deposited $136,728 in the escrow account
which represents the Operator's share of December 1999 gas sales less January
and February 2000 operating and capital expenditures. A motion was filed in
December 1999 by the plaintiffs in Canada to direct all of the defendants to
make timely payments of all current and future amounts due from the Company's
share of field revenues. The Company expects that the Court will hear the motion
in April 2000.
Columbia has filed a counterclaim against the Company seeking, if the
Company is successful in its claim for the forfeiture of the field, repayment
from the Company of all unrecovered sums Columbia has expended on the Kotaneelee
lands before the Company is entitled to its interest.
The parties to the litigation conducted extensive discovery since the
filing of the claims. The trial began on September 3, 1996 and the Plaintiffs
completed the presentation of their case against the Defendants during
September, 1998. The Defendants completed their case during February 2000. The
Company estimates that its rebuttal evidence will be completed during March
2000. Both parties to the suit will then have several months to file their
written closing arguments with the Court, which probably will hear closing oral
arguments in the fall of 2000.
Based upon newly discovered evidence, the Company filed a new claim
during May 1998 that the Defendants failed to develop the field in a timely
manner. The Company is unable to estimate the time necessary to conclude the
litigation.
Matters Ancillary to Kotaneelee Litigation
In its 1989 statement of claim, the Company sought a declaratory
judgment regarding two issues:
(1) whether interest accrued on the carried interest account; and
(2) whether expenditures for gathering lines and dehydration
equipment are expenditures chargeable to the carried interest
account or whether the Company will be assessed a processing
fee on gas throughput.
With respect to the first issue, the Company maintains that no interest
should accrue on the account and the Defendants have not contested this
position. With regard to the second issue, the Company maintains that the
expenditures are chargeable to the carried interest account. Mobil, Esso and
Columbia have essentially agreed to the Company's position while the Amoco Dome
Group continues to contest this issue.
On January 22, 1996, the Company settled two claims outstanding against
the Company in the Court of Queens Bench, Calgary, Alberta, which related to a
suit brought against AlliedSignal Inc. ("AlliedSignal") in Florida which was
dismissed on the basis that Canada was the appropriate forum for the litigation.
AlliedSignal had sought additional relief against the Company in Canada to
preclude other types of suits by the Company and to recover the costs of the
defense of the initial action. The settlement bars AlliedSignal from making a
claim against the Company for any costs in connection with the Kotaneelee
Litigation. The Company agreed not to bring any action against AlliedSignal in
connection with the Kotaneelee gas field. Neither party made any monetary
payment to the other party.
The working interest owners have reported that they have been selling
Kotaneelee gas since February 1991.
Under Canadian law, certain costs (known as "taxable costs") of the
litigation may be assessed against the non-prevailing party. Previously, the
Company had reported that while such costs were not determinable, the Company
estimated that taxable costs, assuming a twelve month trial, could be
approximately $1.5 million and noted that the judge in complex and lengthy
trials has the discretion to increase an award.
Effective September 1, 1998, the Alberta Rules of Court were amended to
provide for a material increase in the costs which may be awarded to the
prevailing party in matters before the Court. In addition, the Company believes
that the trial will extend well beyond its original time estimates and,
therefore, potentially assessable costs would increase accordingly.
The trial has been lengthy, complicated and costly to all parties and
the Company believes that the prevailing party or parties in the litigation will
argue for a substantial assessment of costs against the non-prevailing party or
parties. The Court has very broad discretion as to whether to award costs and
disbursements and as to the calculation of any amounts to be awarded.
Accordingly, the Company is unable to determine whether, in the event that it
does not prevail on its claims in the litigation, costs will be assessed against
it or in what amounts. However, since the costs incurred by the Defendants have
been substantial, and since the Court has broad discretion in the awarding of
costs, an award to the Defendants potentially could be material. A cost award
against the Company could be of sufficient magnitude to necessitate a sale of
Company assets or a debt or equity financing to fund such an award. There are no
assurances that any such sale or financing would be consummated.
There is no assurance whatever that the Company will be successful on
the merits of its claims, which have been vigorously defended by the Defendants.
There is also no assurance that the Company will be awarded any damages, or
that, if damages are awarded, the Court will apply the measure of damages the
Company claims should be applied.
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
Executive Officers of the Company
The following information with respect to the executive officers of the
Company is furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.
Length of Other Positions
Service Held with
Name Age Office in this Office Company
M. Anthony Ashton 64 President Since 1997 Director
All officers of the Company are elected annually by the Board of
Directors and serve at the pleasure of the Board of Directors.
The Company is aware of no arrangement or understanding between the
individual named above and any other person pursuant to which any individual was
selected as an officer.
<PAGE>
PART II
Item 5. Market for the Company's Limited Voting Shares and Related
Stockholder Matters
(a) Principal Markets
The Company's Limited Voting Shares, par value $1.00 per share, are
traded on The Toronto, Pacific and Boston Stock Exchanges [Symbol: CSW], and in
the NASDAQ SmallCap Market [Symbol: CSPLF].
The quarterly high and low closing prices (in Canadian dollars) on The
Toronto Stock Exchange during the calendar periods indicated were as follows:
1998 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 11.75 10.50 9.00 10.00
Low 9.00 8.00 5.50 6.25
1999 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 11.00 11.00 16.00 12.35
Low 6.00 7.50 10.75 8.00
The quarterly high and low closing prices (in United States dollars) on
the NASDAQ SmallCap Market during the calendar periods indicated were as
follows:
1998 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 8.50 7.88 6.63 6.75
Low 6.25 5.63 3.31 3.94
1999 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 7.63 7.50 11.50 8.50
Low 4.50 5.38 6.50 5.09
<PAGE>
(b) Approximate Number of Holders of Limited Voting
Shares at March 17 , 2000
Approximate
Title of Class Number of Record Holders
Limited Voting Shares, par value 4,500
$1.00 per share.
(c) Dividends
The Company has never paid a dividend on its Limited Voting Shares. Any
future dividends will be dependent on the Company's earnings, financial
condition, and business prospects. The Company is legally restricted from paying
any dividend or making any other payment to shareholders (except by way of
return of capital) on the Limited Voting Shares until its deficit($25,542,920)
at December 31, 1999) is eliminated.
Current Canadian law does not restrict the remittance of dividends to
persons not resident of Canada. Under current Canadian tax law and the United
States-Canada tax treaty, any dividends paid to U.S. shareholders are currently
subject to a 15% Canadian withholding tax.
(d) Recent Sales of Unregistered Securities
None.
<PAGE>
Item 6. Selected Financial Data
The following selected consolidated financial information (in thousands
except per share and exchange rate data) of the Company insofar as it relates to
each of the fiscal periods shown has been extracted from the Company's
consolidated financial statements. Financial data for the years prior to 1999
have been restated to reflect a change from the deferral method of tax
allocation accounting to the liability method of accounting for income taxes.
(See Note 1 of Notes to the Consolidated Financial Statements)
<TABLE>
Year ended December 31,
- ------------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
($) ($) ($) ($) ($)
(Restated) (Restated) (Restated) (Restated)
<S> <C> <C> <C> <C> <C>
Operating revenues 777 1,810 2,120 1,755 1,657
======== ======= ======= ======= =======
Total revenues 1,030 3,409 2,515 2,228 1,793
======= ======= ======= ======= =======
Net loss (3,001) (2,328) (1,588) (1,236) (1,001)
======== ======== ======== ======== ========
Net loss per share (.21) (.16) (.11) (.09) (.08)
===== ========= ========= ========= =========
Working capital 3,629 6,876 5,573 8,403 1,510
======= ======= ======= ======= =======
Total assets 17,216 19,740 22,772 22,021 13,801
====== ====== ====== ====== =======
Shareholders' Equity:
Capital stock 40,787 40,489 40,489 38,888 29,635
Deficit (25,542) (22,540) (18,625) (17,037) (15,801)
-------- -------- -------- -------- --------
15,245 17,949 21,864 21,851 13,834
======= ======= ======= ======= =======
Average number of
shares outstanding 14,253 14,235 14,084 13,362 12,622
======= ======= ======= ======= =======
Exchange rates:
Year-end .6924 .6535 .6992 .7297 .7329
===== ===== ===== ===== =====
Average for the period .6733 .6749 .7224 .7335 .7289
===== ===== ===== ===== =====
Range .67-.68 .63-.67 .69-.75 .72-.75 .70-.75
======= ======= ======= ======= =======
</TABLE>
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Statements included in Management's Discussion and Analysis of
Financial Condition and Results of Operations which are not historical in nature
are intended to be, and are hereby identified as, "forward looking statements"
for purposes of the "Safe Harbor" Statement under the Private Securities
Litigation Reform Act of 1995. The Company cautions readers that forward looking
statements are subject to certain risks and uncertainties that could cause
actual results to differ materially from those indicated in the forward looking
statements.
Among these risks and uncertainties are:
o uncertainties as to the costs, length and outcome of the Kotaneelee
litigation;
o uncertainty as to when or if the Company will receive its share of
revenue from the Kotaneelee gas field.
(1) Liquidity and Capital Resources
At December 31, 1999, the Company had approximately $3.6 million of cash
and marketable securities. These funds are expected to be used for general
corporate purposes, including exploration and development and to continue the
Kotaneelee field litigation. The Company estimates that it currently has
adequate working capital for the year 2000. However, it might be required to
raise additional funds through the sale of properties or other means in order to
complete the Kotaneelee Litigation.
Cash flow used in operations during 1999 increased to $2,730,000
compared to $2,351,000 during the 1998 period. The $379,000 difference between
the periods was caused primarily by the following:
Increase in loss from operations $ (125,000)
Increase in accounts receivable and other (965,000)
Net change in current liabilities 711,000
-------------
Increase in net cash used in operations $ (379,000)
==================
A significant proportion of the Company's property interests are
covered by carried interest agreements, which provide that expenditures made by
the operator are recouped solely out of revenues from production. Major capital
expenditures made by the operators have an impact on the Company's cash flow
from operations as no revenues are reported or received until the capital costs
have been recovered by the operator. The Kotaneelee gas field and certain
properties in the Fort Nelson, British Columbia area in which the Company has
carried interests have reached pay out status. Proceeds from these carried
interests plus oil and gas sales from working interest properties are the
Company's major sources of working capital.
The Company is currently evaluating and expects to continue to evaluate
oil and gas properties and may make investments in such properties utilizing
cash on hand. The Company anticipates that its capital expenditures for land
acquisitions and drilling for the year 1999 will be approximately $600,000. In
addition, substantial continuing expenses are expected to be incurred in
connection with the Kotaneelee Litigation. During 1999, the Company expended
approximately $2.1 million in connection with the Kotaneelee Litigation which
has been the principal cause of the Company's losses since 1991.
The Company has established a provision for its potential share of
future site restoration costs which totals $175,000. The estimated amount of
these costs, which total $228,000, is being provided on a unit of production
basis in accordance with existing legislation and industry practice.
(2) Results of Operations
Accounting policy changes
In 1999, under new recommendations of the Canadian Institute of Chartered
Accountants, the Company retroactively adopted the liability method of
accounting for income taxes. Under this method, the Company records income taxes
to give effect to temporary differences between the carrying amount and the tax
basis of the Company's assets and liabilities. Temporary differences arise when
the realization of an asset or the settlement of a liability would give rise to
either an increase or decrease in the Company's income taxes payable for the
year or later period. Future income taxes are recorded at the enacted income tax
rates that are expected to apply when the future tax liability is settled or the
future tax asset is realized. Income tax expense is the tax payable for the
period and the change during the period in future income tax and liabilities.
The adoption of this standard has resulted in the recognition of future tax
assets and a reduction of the deficit at December 31, 1999 of $2,726,613 (1998 -
$2,194,197; 1997 - $1,815,830) and a reduction in the net loss for 1999 of
$274,970 (1998 - $378,367; 1997 - $170,158). This new standard is consistent
with the accounting principles generally accepted in the United States.
1999 vs. 1998
The net loss for the year 1999 was $3,001,424 ($.21 per share)
compared to a net loss of $2,328,170 ($.16 per share) for the 1998 period. A
summary of revenue and expenses during the periods is as follows:
1999 1998 Net Change
---- ---- ----------
Revenues $ 1,029,899 $ 3,409,361 $ (2,379,462)
Costs and expenses (4,031,323) (5,737,531) 1,706,208
-------------- ------------- -------------
Net loss $ (3,001,424) $(2,328,170) $ (673,254)
============= ============ ==============
Oil sales decreased by 83% due primarily to a 86% decrease in
production which was partially offset by a 17% increase in the average prices of
crude oil sold. There was also a corresponding decrease in royalties paid by the
Company. The Company sold the majority of its crude oil producing properties in
two separate transactions effective July 1, 1998 and September 1, 1998.
Since the Company has disposed of most of its producing properties, future oil
sales are expected to be minimal unless additional producing properties are
acquired through drilling or purchase. The 1999 royalties paid amount includes a
provincial royalty tax credit in the amount of $4,782. Crude oil unit sales in
barrels ("bbls") (before deducting royalties) and the average price per barrel
sold during the periods indicated were as follows:
1999 1998
Average price Average price
bbls per bbl Total bbls per bbl Total
Crude oil 9,171 $17.38 $ 159,000 64,954 $14.84 $964,000
sales
Royalties paid (8,000) (66,000)
------------- -----------
Total $ 151,000 $898,000
========= ========
Gas sales decreased 95% because of a 93% decrease in number of units
sold and a 16% decrease in the average price for gas. In addition, gas sales
include royalty income which decreased 49% in 1999. The Company sold the
majority of its working interest gas properties effective July 1, 1998, which
accounts for the decrease in gas sales. Royalties paid includes a $59,000 amount
as part of a settlement for royalties due for the 1991 to 1998 period. The
volumes in million cubic feet ("mmcf") and the average price of gas per thousand
cubic feet ("mcf") sold during the periods indicated were as follows:
1999 1998
Average price Average price
mmcf per mcf Total mmcf per mcf Total
Gas sales 21 $1.83 $ 37,000 304 $2.17 $660,000
Royalty income 64,000 127,000
Royalties paid (63,000) (82,000)
---------- -----------
Total $ 38,000 $705,000
======== ========
Proceeds from carried interests increased 184% to $587,000 during 1999
compared to $207,000 in 1998 primarily because gas prices increased 58%.
Operating costs also decreased 20% during 1999 . The volumes in million cubic
feet ("mmcf") and the average price of gas per thousand cubic feet ("mcf") sold
during the periods indicated were as follows:
<PAGE>
1999 1998
Average price Average price
mmcf per mcf Total mmcf per mcf Total
Gas sales 563 $2.79 $ 1,572,000 575 $1.77 $1016,000
Royalty paid (327,000) (238,000)
Operating costs (417,000) (522,000)
Capital costs (241,000) (49,000)
-------- --------
Total $ 587,000 $207,000
========= ========
Share of Kotaneelee net revenues for 1999. Although, according to the
Operator's reports, the Kotaneelee gas field carried interest reached pay out
status during November 1999, no revenue has been accrued for 1999. In order to
bring its billing practices in line with the industry standard, the Operator of
the field changed the prior method of reporting the revenue and expenditures of
the field. This resulted in two months of capital expenditures and operating
expenses (December 1999 and January 2000) being charged against a single month
of revenue (November 1999). This change in reporting is consistent with the
reporting of other carried interests currently held by the Company. In the
future, the Company expects that the reporting of Kotaneelee gas sales will
continue to lag two months behind actual operating expenses and capital
expenditures. In addition, the production revenue from the two last months of
each quarter is accrued during the following quarter because the data are not
usually available.
As of December 31, 1999, based on the Operator's reports, the Company's
share of net revenues due the Company by all the defendants totaled $412,374.
This amount was computed as follows:
Net Revenues (after royalties):
November 1999 (after pay out) $ 864,506
December 1999 1,212,821
----------
Total Revenues 2,077,327
Operating Expenses:
November 1999 (after pay out) 264,848
December 1999 393,389
January 2000 54,889
-----------
Total Operating Expenses 713,126
Capital Expenditures:
December 1999 368,963
January 2000 539,899
February 2000 42,965
------------
Total Capital Expenditures 951,827
Company share of net revenues $ 412,374
===========
The Operator reported that it deposited during March 2000 the amount of
$136,728 in an escrow account for the benefit of the Company. This deposit
represents the Operator's share of the $412,374 amount due.
The Kotaneelee field working interest partners have approved the
expenditure of an estimated $4.1 million for the installation of a compression
unit in the field to maintain current production levels. The schedule above
reflects a charge of $951,827 against the Company's share of revenues for its
share of these costs which total $1,372,000. The remaining balance of $420,173
will be deducted from the Company's share of the year 2000 production revenues.
Therefore, the share of Kotaneelee net revenues may fluctuate each year
depending on both capital expenditures and any audit adjustments which are
attributable to prior years.
Interest and other income increased 14% in 1999. Interest income
increased from $194,000 to $230,000 in 1999 due to an increase in funds
available for investment during 1999 because of the proceeds of sale of the
crude oil and gas properties in 1998. In addition, the 1999 period includes
proceeds from the sale of seismic data in the amount of $16,000 compared to
$27,000 from such sales in 1998. It is not possible for the Company to estimate
the amount of future seismic data sales which are dependent on a purchaser's
need for the seismic data that the Company owns.
Gain on the sale of properties in 1999. There were no properties sold
in 1999. In 1998, there was a gain of $1,378,000 from the sale of the Company's
heavy crude oil properties in Alberta and the sale of certain working interest
properties in British Columbia.
General and administrative costs decreased 7% in 1999 to $1,209,000
from $1,301,000 in 1998.
Legal expenses decreased 11% during 1999 to $2,108,000 compared to
$2,358,000 during 1998. These expenses are related primarily to the cost of the
Kotaneelee litigation. During 1998, the Company completed the presentation of
its case against the working interest partners. The 1998 costs represent both
legal fees and the cost of various Company experts who testified, were being
prepared for testimony, or assisted in the cross-examination of defense
witnesses. During 1999, the Company continued its cross-examination of defense
witnesses.
Lease operating costs decreased 85% from $976,000 in 1998 to $147,000
in the 1999 period. The Company sold the majority of its oil and gas producing
properties during the second half of 1998.
Depletion, depreciation and amortization expense decreased 19% in 1999
to $707,000 from $870,000 in 1998. Although, the Company sold the majority of
its oil and gas producing properties during 1998, the increased production from
the pay out of the Kotaneelee carried interest increased the 1999 depletion
expense by approximately $420,000.
A foreign exchange loss of $77,000 was recorded in 1999, contrasted
with a gain of $179,000 on the Company's U.S. investments in 1998. In 1999 the
value of the Canadian dollar increased from U.S. $.65 to U.S. $.69. In 1998, the
gain was attributable to the continuing strengthening of the U.S. dollar as
compared to the Canadian dollar on the Company's U.S. investments.
Abandonments and write downs. There were no abandonments and write
downs in 1999. The 1998 amount of 685,000 resulted from a write down of certain
of the Company's properties in California and Texas.
Income tax recovery decreased by 27% to $275,000 in 1999 compared to
$378,000 in 1998. The income tax recovery in 1999 decreased because the loss in
1999 was less than the loss in 1998 after giving effect to the $1,378,000 gain
on sale of assets in 1998 which was not recognized for income tax purposes.
1998 vs. 1997
The net loss for the year 1998 was $2,328,170 ($.16 per share) compared
to a net loss of $1,587,506 ($.11 per share) for the 1997 period. A summary of
revenue and expenses during the periods is as follows:
1998 1997 Net Change
---- ---- ----------
Revenues $ 3,409,361 $ 2,514,978 $ 894,383
Costs and expenses (5,737,531) (4,102,484) (1,635,047)
------------- ------------- -------------
Net loss $(2,328,170) $(1,587,506) $ (740,664)
============ ============ =============
Crude oil sales decreased by 20% due primarily to a 34% decrease in the
average prices of crude oil sold which was partially offset by a 2% increase in
production. There was also a decrease in royalties paid by the Company. The
Company sold the majority of its oil producing properties in two separate
transactions effective July 1, 1998 and September 1, 1998. The 1998 royalties
paid amount includes a provincial royalty tax credit in the amount of $117,000.
Oil unit sales in barrels ("bbls") (before deducting royalties) and the average
price per barrel sold during the periods indicated were as follows:
1998 1997
Average price Average price
bbls per bbl Total bbls per bbl Total
Crude oil sales 64,954 $14.84 $964,000 63,783 $22.50 $1,436,000
Royalties paid (66,000) (315,000)
----------- -------------
Total $898,000 $1,121,000
======== ==========
Gas sales increased 35% because of a 52% increase in number of units
sold which was partially offset by a 6% decrease in the average price for gas.
In addition, gas sales include royalty income which decreased 13% in 1998. The
Company sold the majority of its working interest gas properties effective July
1, 1998. The primary increase in gas production was the pay out of two wells
that had been in a penalty position. These wells were included in the properties
sold. The volumes in million cubic feet ("mmcf") and the average price of gas
per thousand cubic feet ("mcf") sold during the periods indicated were as
follows:
1998 1997
Average price Average price
mmcf per mcf Total mmcf per mcf Total
Gas sales 304 $2.17 $660,000 200 $2.31 $462,000
Royalty income 127,000 146,000
Royalties paid (82,000) (85,000)
----------- -----------
Total $705,000 $523,000
======== ========
Proceeds from carried interests decreased 57% to $207,000 during 1998
compared to $476,000 in 1997. During 1998, there were significant expenditures
made by the operators of the carried interest properties
Interest and other income decreased 44% in 1998. Interest income
decreased from $336,000 to $194,000 in 1998 due to the decrease in funds
available for investment and lower interest rates. In addition, the 1998 period
includes proceeds from the sale of seismic data in the amount of $27,000
compared to $59,000 from such sales in 1997.
Gain on the sale of properties in 1998 amounted to $1,378,000 primarily
represents the sale of the Company's heavy crude oil properties in Alberta and
the sale of certain working interest properties in British Columbia.
General and administrative costs increased 18% in 1998 to $1,301,000
from $1,105,000 in 1997 primarily as a result of increased Company activity in
connection with the Kotaneelee litigation and the Company's exploration program.
In addition, the expenses increased in the United States because of the 7%
increase in the value of the U.S. dollar compared to the Canadian dollar during
1998.
Legal expenses increased 24% during 1998 to $2,358,000 compared to
$1,898,000 during 1997. These expenses are related primarily to the cost of the
Kotaneelee litigation. During 1998, the Company continued the presentation of a
major part of its case against the working interest partners. The Company's case
was completed on September 16, 1998 and Defendants' case is now proceeding. The
1998 costs represent both legal fees and the cost of various Company experts who
testified, were being prepared for testimony, or assisted in the
cross-examination of defense witnesses.
Lease operating costs increased 22% from $799,000 in 1997 to $976,000
in the 1998 period. The increase represents the charges by the operators of the
Company's properties which is related to the increased production. In addition,
the Company's share of production costs in producing Alberta heavy crude oil
increased.
Depletion, depreciation and amortization expense increased 39% in 1998
to $870,000 from $624,000 in 1997. The increase in depletion in 1998 is the
result of increased production and the amount of additional costs being
depleted.
A foreign exchange gain of $179,000 was recorded in 1998, contrasted
with a gain of $231,000 on the Company's U.S. investments in 1997. In 1998, the
gain was attributable to the continuing strengthening of the U.S. dollar as
compared to the Canadian dollar on the Company's U.S. investments.
Abandonments and write downs were $685,000 which resulted from a write
down of certain of the Company's properties in California and Texas. There were
no abandonments and write downs in 1997.
Income tax recovery increased 122% to $378,000 in 1998 compared to
$170,000 in 1997. The increase in the 1998 income tax recovery reflects a
similar increase in the loss in 1998 after giving effect to the $1,378,000 gain
on sale of assets in 1998 which was not recognized for income tax purposes.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
The Company does not have any significant exposure to market risk as
the only market risk sensitive instruments are its investments in marketable
securities. At December 31, 1999, the carrying value of such investments was
approximately $ 3.2 million which was approximately equal to fair value and face
value of the investments. Since the Company expects to hold the investments to
maturity, the maturity value should be realized. In addition, the Company's
investments in marketable securities included investments held in the United
States which are subject to foreign exchange fluctuations. At December 31, 1999,
the investments in the United States totaled $ 1.1 million.
<PAGE>
Item 8. Financial Statements and Supplementary Data
AUDITORS' REPORT
To the Shareholders of
Canada Southern Petroleum Ltd.
We have audited the consolidated balance sheets of Canada Southern Petroleum
Ltd. as at December 31, 1999 and 1998, and the consolidated statements of
operations and deficit, cash flows and limited voting shares and contributed
surplus for each of the years in the three year period ended December 31, 1999.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in Canada. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, the consolidated financial statements present fairly, in all
material respects, the financial position of Canada Southern Petroleum Ltd. as
at December 31, 1999 and 1998 and the results of its operations and its cash
flows for each of the years in the three year period ended December 31, 1999, in
accordance with accounting principles generally accepted in Canada.
Calgary, Canada /s/ ERNST & YOUNG LLP
March 10, 2000 Chartered Accountants
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
(Incorporated under the laws of Nova Scotia)
CONSOLIDATED BALANCE SHEETS
(Expressed in Canadian dollars)
<TABLE>
As at December 31,
1999 1998
Assets (Restated)
Current assets
<S> <C> <C>
Cash and cash equivalents (Note 2) $ 3,045,530 $ 6,208,634
Marketable securities (Note 3) 568,374 751,511
Accounts receivable (Notes 4 and 7) 360,752 266,116
Accounts receivable - Kotaneelee (Note 8) - -
Other assets 307,519 319,697
------------ --------------
Total current assets 4,282,175 7,545,958
----------- -------------
Oil and gas properties and equipment
(full cost method) (Note 4) 10,207,294 10,000,010
Future tax asset (Note 6) 1,583,475 1,308,505
------------- -------------
Total assets $16,072,944 $18,854,473
=========== ===========
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable $ 634,600 $ 375,554
Accrued liabilities (Note 10) 18,256 294,491
--------------- --------------
Total current liabilities 652,856 670,045
-------------- --------------
Future site restoration costs 174,696 236,045
-------------- --------------
Contingencies (Note 8) - -
Shareholders' Equity
Limited Voting Shares, par value
$1 per share (Note 5)
Authorized -100,000,000 shares
Outstanding -14,284,970 (1999) 14,234,740 (1998) shares 14,284,970 14,234,740
Contributed surplus 26,502,342 26,254,139
------------ ------------
Total capital 40,787,312 40,488,879
Deficit (25,541,920) (22,540,496)
------------- -------------
Total shareholders' equity 15,245,392 17,948,383
------------ ------------
Total liabilities and shareholders' equity $16,072,944 $18,854,473
=========== ===========
</TABLE>
See accompanying notes.
Approved on behalf of the Board
/s/ M. Anthony Ashton /s/ Arthur B. O'Donnell
Director Director
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
(Expressed in Canadian dollars)
<TABLE>
Year ended December 31,
1999 1998 1997
(Restated) (Restated)
Revenues:
<S> <C> <C> <C>
Oil sales (Notes 9 and 10) $ 151,137 $ 897,878 $ 1,120,789
Gas sales (Notes 9 and 10) 38,324 705,277 523,433
Proceeds from carried interests 587,073 206,503 475,697
Share of Kotaneelee net revenues (Note 8)
- - -
Interest and other income 253,365 221,523 395,059
Gain on sale of assets 1,378,180
- -
-------------- -------------- ---------------
Total revenues 1,029,899 3,409,361 2,514,978
-------------- -------------- --------------
Costs and expenses:
General and administrative 1,209,325 1,300,595 1,104,535
Legal (Note 8) 2,108,521 2,357,707 1,897,506
Lease operating costs 147,332 975,899 799,372
Depletion, depreciation and amortization 707,200 869,600 623,600
Foreign exchange (gains) losses 77,475 (178,850) (231,457)
Provision for future site restoration costs 600 29,500 21,500
Rent 55,840 76,812 57,586
Abandonments and write downs - 684,635 -
-------------- -------------- --------------
Total costs and expenses 4,306,293 6,115,898 4,272,642
-------------- -------------- --------------
Loss before income taxes (3,276,394) (2,706,537) (1,757,664)
Income tax recovery (Note 6) 274,970 378,367 170,158
---------------- --------------- ---------------
Net loss (3,001,424) (2,328,170) (1,587,506)
Deficit - beginning of year (22,540,496) (20,212,326) (18,624,820)
-------------- -------------- --------------
Deficit - end of year $(25,541,920) $(22,540,496) $(20,212,326)
============= ============= =============
Net loss per share (Basic & Fully Diluted) $(.21) $(.16) $(.11)
====== ====== ======
Average number of shares
Outstanding (Basic & Fully Diluted) 14,252,574 14,234,740 14,084,294
========== ========== ==========
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Expressed in Canadian dollars)
<TABLE>
Year ended December 31,
1999 1998 1997
(Restated) (Restated)
Cash flows from operating activities:
<S> <C> <C> <C>
Net loss $(3,001,424) $(2,328,170) $(1,587,506)
Adjustments to reconcile net loss
to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization 707,200 869,600 623,600
Future site restoration costs (net) (61,349) 25,071 (39,300)
Gain on sale of assets - (1,378,180) -
Abandonments and write downs - 684,635 -
Future tax recovery (274,970) (378,367) (170,158)
Change in assets and liabilities:
Accounts receivable (94,636) 959,970 (590,863)
Other assets 12,178 (77,419) (14,910)
Accounts payable 259,045 (744,967) 680,684
Accrued liabilities (276,235) 16,776 95,611
------------- ------------- -------------
Net cash used in operations (2,730,191) (2,351,051) (1,002,842)
------------- ------------ ------------
Cash flows from investing activities:
Additions to oil and gas properties and (914,483) (1,942,474) (3,258,426)
equipment
Sale (purchase) of marketable securities 183,137 2,621,823 2,079,452
Proceeds from the sale of properties - 5,751,180 -
------------- ----------- ------------
Net cash provided by (used in) investing activities (731,346) 6,430,529 (1,178,974)
------------- ----------- ------------
Cash flows from financing activities:
Exercise of stock options 298,433 - 1,601,375
------------- ------------ -----------
Net cash from financing activities 298,433 - 1,601,375
------------- ------------ -----------
Increase (decrease) in cash
and cash equivalents (3,163,104) 4,079,478 (580,441)
Cash and cash equivalents at the
beginning of period 6,208,634 2,129,156 2,709,597
----------- ----------- -----------
Cash and cash equivalents at the
end of period (Note 2) $3,045,530 $6,208,634 $2,129,156
========== ========== ==========
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF LIMITED VOTING SHARES
AND CONTRIBUTED SURPLUS
(Expressed in Canadian dollars)
<TABLE>
Limited
Number Voting Shares Contributed
of shares $1 par value surplus Total
--------- ------------ ------- -----
<S> <C> <C> <C> <C>
Balance as at December 31, 1996 13,956,540 $13,956,540 $24,930,964 $38,887,504
Exercise of stock options 278,200 278,200 1,323,175 1,601,375
------------ -------------- ------------- -------------
Balance as at December 31, 1997 and 1998 14,234,740 14,234,740 26,254,139 40,488,879
Exercise of stock options and other sales
50,230 50,230 248,203 298,433
------------- -------------- -------------- --------------
Balance as at December 31, 1999 14,284,970 $14,284,970 $26,502,342 $40,787,312
========== =========== =========== ===========
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in Canadian dollars)
December 31, 1999, 1998 and 1997
1. Summary of significant accounting policies
Accounting principles
The Company prepares its accounts in accordance with accounting principles
generally accepted in Canada which conform in all material respects with United
States generally accepted accounting principles ("U.S. GAAP").
Consolidation
The consolidated financial statements include the accounts of Canada
Southern Petroleum Ltd. and its wholly-owned subsidiaries, Canpet Inc. and
C.S. Petroleum Limited.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the amounts reported in the financial statements and
accompanying notes. Specifically estimates were utilized in calculating
depletion, depreciation and amortization, site restoration costs, and
abandonments and write downs. Actual results could differ from those estimates.
Cash and cash equivalents
For the purposes of the statement of cash flows, the Company considers
all highly liquid investments with a maturity of three months or less to be cash
equivalents.
Oil and gas properties and equipment
The Company, which is engaged primarily in one industry, the
exploration for and the development of oil and gas properties, principally in
Canada, follows the full cost method of accounting for oil and gas properties,
whereby all costs associated with the exploration for and the development of oil
and gas reserves are capitalized. Such costs include land acquisition, drilling,
geological, geophysical and overhead expenses. The Company's cost centers are
Canada and the United States.
The Company periodically reviews the costs associated with undeveloped
properties and mineral rights to determine whether they are likely to be
recovered. When such costs are not likely to be recovered, such costs are
transferred to the depletable pool of oil and gas costs.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in Canadian dollars)
December 31, 1999, 1998 and 1997
1. Summary of significant accounting policies (Cont'd)
The net carrying cost of the Company's oil and gas properties in
producing cost centers is limited to an estimated recoverable amount. This
amount is the aggregate of future net revenues from proved reserves and the
costs of undeveloped properties, net of impairment allowances, less future
general and administrative costs, financing costs and income taxes. Future net
revenues are calculated using year end prices that are not escalated or
discounted. For Canadian GAAP future net revenues are undiscounted, whereas, for
U.S. GAAP future net revenues are discounted at 10%.
The costs of the Company's 30% carried interest in the Kotaneelee gas
field are included in oil and gas properties and in the cost center for the
purpose of computing depletion. In addition, the Company's share of estimated
net reserves after pay out are also included in the proved oil and gas reserves
base for the purpose of computing depletion. During November 1999, the field
achieved pay out status.
Gains or losses are not recognized upon disposition of oil and gas
properties unless crediting the proceeds against accumulated costs would result
in a change in the rate of depletion of 20% or more.
Depletion is provided on costs accumulated in producing cost centers
including production equipment using the unit of production method. For purposes
of the depletion calculation, gross proved oil and gas reserves as determined by
outside consultants are converted to a common unit of measure on the basis of
their approximate relative energy content.
Depreciation has been computed for equipment, other than production
equipment, on the straight-line method based on estimated useful lives of four
to ten years.
Substantially all of the Company's exploration and development
activities related to oil and gas are conducted jointly with others and
accordingly the consolidated financial statements reflect only the Company's
proportionate interest in such activities.
Revenue recognition
The Company recognizes revenue on its working interest properties from
the production of oil and gas in the period the oil and gas are sold.
<PAGE>
1. Summary of significant accounting policies (Cont'd)
Revenue under carried interest agreements is recorded in the period
when the proceeds become receivable. The Company is entitled to participate in
oil and gas net revenues after the repayment of exploration, drilling and
completion expenses to the party or parties bearing these costs. Each carried
interest account is subject to an independent audit. In the past, these audits
have resulted in both positive and negative adjustments which are attributable
to prior year periods. For these reasons, the proceeds under carried interest
agreements may fluctuate each year depending on both capital expenditures and
any audit adjustments.
The Company follows the industry practice of reporting its revenues
from carried interest agreements, whereby a single month of revenues is charged
for the operating and capital expenditures for the following two months. In
addition, the production revenue from the last two months of each quarter is
reported during the following quarter because the data are not usually
available.
Earnings per share
Earnings per common share ("EPS") is based upon the weighted average
number of common and common equivalent shares outstanding during the period. The
Company's basic and diluted calculations of EPS are the same for both U.S. and
Canadian GAAP.
Future site restoration costs
Total future site restoration costs are estimated to be $228,000 and
are being provided on a unit of production basis. The provision is based on
current costs of complying with existing legislation and industry practice for
site restoration and abandonment. At December 31, 1999, approximately $53,000 in
such costs have yet to be accrued. The estimated costs of abandoning the two
producing wells in the Kotaneelee field are not included in future site
restoration costs. These costs would be paid by the working interest partners
and charged to the carried interest account.
<PAGE>
1. Summary of significant accounting policies (Cont'd)
Future income taxes
In 1999, under new recommendations of the Canadian Institute of Chartered
Accountants, the Company retroactively adopted the liability method of
accounting for income taxes. Under this method, the Company records income taxes
to give effect to temporary differences between the carrying amount and the tax
basis of the Company's assets and liabilities. Temporary differences arise when
the realization of an asset or the settlement of a liability would give rise to
either an increase or decrease in the Company's income taxes payable for the
year or later period. Future income taxes are recorded at the enacted income tax
rates that are expected to apply when the future tax liability is settled or the
future tax asset is realized. Income tax expense is the tax payable for the
period and the change during the period in future income tax and liabilities.
Adoption of the liability method of accounting for income taxes
resulted in changes to previously reported net income, net income per share and
the balance sheet accounts, as follows:
<TABLE>
1998 1997
<S> <C> <C>
Net loss previously reported $(2,706,537) $(1,757,664)
Adjustment for the effect of the change in accounting method 378,367 170,158
------------- -------------
Net loss as restated $(2,328,170) $(1,587,506)
============= ============
Net loss per share previously reported $(.19) $(.12)
Adjustment for the effect of the change in accounting method .03 .01
--- ---
Net loss per share as restated $(.16) $(.11)
====== ======
Future tax asset previous reported $ - $ -
Adjustment for the effect of the change in accounting method 1,308,505 930,138
------------ -----------
Future tax asset as restated $1,308,505 $ 930,138
============= ============
Deficit previously reported $(23,849,001) $(21,142,464)
Adjustment for the effect of the change in accounting method 1,308,505 930,138
------------- -------------
Deficit as restated $(22,540,496) $(20,212,326)
============= =============
</TABLE>
If the tax allocation method of accounting for income taxes had been
retained, the Company would have reported a net loss of $(3,276,394) or $(.23)
per share for 1999.
Foreign currency translation
Transactions for settlement in U.S. dollars have been translated at
average monthly exchange rates. Monetary assets and liabilities in U.S. dollars
have been translated at the year end exchange rates. Exchange gains or losses
resulting from these adjustments are included in costs and expenses.
<PAGE>
1. Summary of significant accounting policies (Cont'd
Financial instruments
The carrying value for cash and cash equivalents, accounts receivable
and accounts payable approximates fair value based on anticipated cash flows and
current market conditions.
Comprehensive income
The Company has no items of other comprehensive income for U.S. GAAP.
Comprehensive loss for all periods presented is equal to the net loss.
2. Cash and cash equivalents
The Company considers all highly liquid short term investments with
maturities of three months or less at date of acquisition to be cash
equivalents. Cash equivalents are carried at cost which approximates market
value.
<TABLE>
1999 1998
<S> <C> <C>
Cash $ 398,884 $ 269,918
Canadian and U.S. bankers acceptances (Yield: 1999-5.0%, 2,076,663 4,880,833
1998-4.9%)
U.S. Government securities (Yield: 1999-5.4%, 1998-4.8%) 569,983 1,057,883
----------- -----------
$3,045,530 $6,208,634
========== ==========
</TABLE>
3. Marketable Securities
At December 31, 1999 and 1998, the Company held the following
marketable securities which were expected to be held until maturity:
Security Par value Maturity Date Amortized Cost Fair value
1999
U.S. Federal Home Loan
Bank Disc. Note $577,700 Jan. 18, 2000 $568,374 $576,300
======== ======== ========
1998
U.S. Federal National
Mortgage Assoc. $765,100 Apr. 7, 1999 $751,500 $751,700
======== ======== ========
<PAGE>
4. Oil and gas properties and equipment
<TABLE>
Less
Accumulated
Depreciation,
Depletion
and Net Book
Cost Writedowns Value
Balance December 31, 1999
<S> <C> <C> <C>
Oil and gas properties - developed $19,009,974 $9,422,066 $ 9,587,908
Oil and gas properties (U.S.) - undeveloped 1,266,334 684,635 581,699
Seismic data 112,000 112,000
-------------- ------------
-
20,388,308 10,218,701 10,169,607
Equipment 89,567 51,880 37,687
--------------- ------------- ----------------
$20,477,875 $10,270,581 $10,207,294
=========== =========== ===========
Balance December 31, 1998
Oil and gas properties-developed $18,524,670 $8,720,066 $ 9,804,605
Oil and gas properties (U.S.) - undeveloped 851,651 684,635 167,016
Seismic data 112,000 112,000
-------------- ------------
-
19,488,321 9,516,701 9,971,621
Equipment 75,073 46,684 28,389
--------------- ------------- ----------------
$19,563,394 $9,563,385 $10,000,010
=========== ========== ===========
</TABLE>
Substantially all gas sales were made to CanWest Gas Supply Inc. and oil
sales were made to Probe Exploration, Inc. ("Probe"). The gain on sale of assets
and the amount of abandonments and write downs are same under both Canadian and
U.S. GAAP. During 1999, a total of $73,000 ($95,000 in 1998 and $91,000 in 1997)
of general and administrative expenses were capitalized.
Included in the amount of accounts receivable is $269,000 due from various
industry partners which include Berkley Petroleum Ltd., PetroCanada, Alberta
Treasury, Oil For America - Exploration and Farries Engineering.
During 1999, the Company's primary Alberta asset and revenue producing
property was its heavy crude oil production and related facilities at Kitscoty.
The Company sold its 10 % working interest to the operator for $336,000
effective October 1, 1999. The transaction was completed during February 2000
and the proceeds of sale will be credited to oil and gas properties in fiscal
2000.
5. Limited Voting Shares and stock options
The Memorandum of Association (Articles of Continuance) of the Company
provides that no person (as defined) shall vote more than 1,000 shares.
Under the terms of the Company's 1985, 1992 and 1998 stock option
plans, the Company is authorized to grant certain employees, directors and
consultants options to purchase Limited Voting Shares at prices based on the
market price of the shares as determined on the date of the grant. The options
are normally exercisable immediately and issued for a period of five years from
the date of grant.
During 1998, the Company adopted a stock option plan that permits the
granting of both stock options and stock appreciation rights. A total of 700,000
Limited Voting Shares are reserved for issuance under the plan.
Following is a summary of option transactions which reflects
adjustments of the stock option prices and the number of shares subject to stock
options as discussed above:
Options Outstanding Expiration Dates Number of Shares Option Prices ($)
- ------------------- ---------------- ---------------- -----------------
December 31, 1996 Oct. 1999 - Jun. 2001 445,700
Exercised (278,200) 3.70 - 8.75
Granted 35,000 13.50
December 31, 1997 Aug. 1999 - Oct. 2002 202,500 6.37 - 13.50
Granted 7,500 10.25
---------
December 31, 1998 Aug. 1999 - Apr. 2003 210,000 ($7.94 weighted average)
Granted 362,500 7.02
Exercised (49,000) 6.37-7.00
---------
December 31, 1999 Nov. 2000 - Jan. 2004 523,500 ($6.92 weighted average)
=======
Summary of Options Outstanding at December 31, 1999
Granted 1994 Nov. 2000 80,000 7.00
Granted 1996 Nov. 2000 62,500 6.37
Granted 1999 Jan. 2004 381,000 7.00
-------
Total - December 31, 1999 523,500
=======
Options reserved for future grants 507,134
=======
For U.S. GAAP, the Company has elected to follow Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB No. 25)
and related interpretations in accounting for its stock options. This method,
which is consistent with the Company's accounting under Canadian GAAP, has been
chosen because the alternative fair value accounting provided under FASB
Statement No. 123, "Accounting for Stock Based Compensation," requires use of
option valuation models that were not developed for use in valuing stock
options. Under APB No. 25, because the exercise price of the Company's stock
options equals the market price of the underlying stock on the date of grant, no
compensation expense is recognized.
Pro forma information regarding net income and earnings per share is
required by FASB Statement No. 123, and has been determined as if the Company
had accounted for its stock options under the fair value method of that
Statement. The fair value for these options was estimated at the date of grant
using a Black-Scholes option pricing model.
Option valuation models require that input of highly subjective
assumptions including the expected stock price volatility. All of the valuations
assumed no expected 5.
<PAGE>
Limited Voting Shares and stock options (Cont'd)
dividend. The assumptions used in the 1997 valuation model were: risk free
interest rate - 5.7%, expected life - 5 years and expected volatility - .459.
The assumptions used in the 1998 valuation model were: risk free interest rate -
4.45%, expected life - 5 years and expected volatility - .328. The assumptions
used in the 1999 valuation model were: risk free interest rate - 4.65%, expected
life - 5 years and expected volatility - .503.
Because the Company's stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its stock options.
For the purpose of pro forma disclosures, the estimated fair value of
the stock options is expensed in the year of grant since the options are
immediately exercisable. The Company's pro forma information is as follows:
Amount Per Share
Net loss as reported - December 31, 1997 $(1,587,506) $(.11)
Stock option expense 225,400 (.02)
------------ -------
Pro forma net loss - December 31, 1997 $(1,362,106) $(.13)
============ ======
Net loss as reported - December 31, 1998 $(2,328,170) $(.16)
Stock option expense 29,600 -
------------ -------
Pro forma net loss - December 31, 1998 $(2,298,570) $(.16)
============ ======
Net loss as reported - December 31, 1999 $(3,001,424) $(.21)
Stock option expense 1,247,000 (.09)
------------- ------
Pro forma net loss - December 31, 1999 $(4,248,424) $(.30)
============ ======
6. Income taxes
Income taxes vary from the amounts that would be computed by applying
the Canadian federal and provincial income tax rates as follows:
<TABLE>
1999 1998 1997
44.84% 44.84% 44.84%
====== ====== ======
Recovery for income taxes based on combined basic
Canadian federal and provincial income tax
<S> <C> <C> <C>
$(1,469,135) $(1,213,611) $ (788,137)
Nondeductible crown charges 11,249 104,663 154,463
Resource allowance 383,663 403,270 232,922
Other (47,601) 24,919 21,106
Nontaxable portion of capital gain - (20,049) (20,743)
Unrealized tax loss 846,854 322,441 170,158
------------- ------------ -----------
Actual income tax recovery $ (274,970) $ (378,367) $ (230,231)
=========== =========== ===========
</TABLE>
6. Income taxes (Cont'd)
At December 31, 1999, the Company had net operating losses for income tax
purposes of approximately $6,597,000 which are available to be carried forward
to future periods. These losses expire in the following years: 2000 - $294,000,
2001 - $545,000, 2002 - $569,000, 2003 - $1,077,000, 2004 - $544,000, 2005 -
$1,711,000 and 2006 - $1,857,000.
At December 31, 1999, the Company has the following oil and gas tax
deductions available to reduce future taxable income, subject to a final
determination by taxation authorities.
Canada
Drilling, exploration and lease acquisition costs $ 10,570,000
Earned depletion 1,975,000
Undepreciated capital costs 2,336,000
Cumulative eligible capital losses 407,000
Share issue costs 99,000
United States
Exploration and lease acquisition costs $ 1,234,000
As a result of these deductions, the Company has a future tax asset
which primarily represents the excess of available resource deductions for
income tax purposes over the recorded value of oil and gas properties together
with operating and capital income tax loss carryforwards. These amounts are
expected to be recovered from the production of current oil and gas reserves. As
certain of the resource deductions are restricted and the operating loss
carryforwards are subject to expiration, there is considerable risk that certain
of these deductions will not be utilized. Accordingly, the Company has
established a valuation allowance to recognize this uncertainty.
1999 1998 1997
Future tax asset $6,749,358 $5,728,699 $ 4,642,765
Valuation reserve (5,165,883) (4,420,194) (3,712,627)
----------- ----------- -----------
Net future tax asset $1,583,475 $1,308,505 $ 930,138
=========== =========== ===========
Future tax recovery $ 274,970 $ 378,367 $ 170,158
=========== =========== ============
<PAGE>
7. Line of credit
The Company has an operating line of credit with a Canadian chartered
bank which provides for a loan of $500,000. The interest rate on borrowing is at
3/4% above the bank's prime lending rate. The line of credit is subject to
annual review and is secured by a general assignment of accounts receivable and
an undertaking to provide security in the form of assignment of future working
interest proceeds. No drawings were made under this line during 1999 or 1998.
8. Litigation
The Company, which has a 30% interest in the Kotaneelee gas field,
believes that the working interest owners in the field have not adequately
pursued the attainment of contracts for the sale of Kotaneelee gas. In October
1989 and in March 1990, the Company filed statements of claim in the Court of
Queens Bench of Alberta, Judicial District of Calgary, Canada, against the
working interest partners in the Kotaneelee gas field. The named defendants were
Amoco Canada Petroleum Corporation, Ltd., Dome Petroleum Limited (now Amoco
Canada Resources Ltd.), and Amoco Production Company (collectively the "Amoco
Dome Group"), Columbia Gas Development of Canada Ltd. ("Columbia"), Mobil Oil
Canada Ltd. ("Mobil") and Esso Resource of Canada Ltd. ("Esso") (collectively
the "Defendants"). In 1991, Anderson Exploration Ltd. acquired all of the shares
in Columbia and changed its name to Anderson Oil & Gas Inc. ("Anderson").
Anderson is now the sole operator (the "Operator") of the field and is a direct
defendant in the Canadian lawsuit. Columbia's previous parent, The Columbia Gas
System, Inc., which was reorganized in a bankruptcy proceeding in the United
States, is contractually liable to Anderson in the legal proceedings currently
at trial.
The Company claims that the Defendants breached a contract obligation
and/or a fiduciary duty owed to the Company to market gas from the Kotaneelee
gas field when it was possible to so do. The Company asserts that marketing the
Kotaneelee gas was possible in 1984 and that the Defendants deliberately failed
to do so. The Company seeks money damages and the forfeiture of the Kotaneelee
gas field. The Company presented evidence at trial that the money damages
sustained by the Company were approximately $100 million.
In addition, the Company has claimed that the Company's carried interest
account should be reduced because of improper charges to the carried interest
account by the Defendants. The Company claims that when the Defendants in 1980
suspended production from the field's gas wells, they failed to take
precautionary measures necessary to protect and maintain the wells in good
operating condition. The wells thereafter deteriorated, which caused unnecessary
expenditures to be incurred including expenditures to redrill one well. In
addition, the Company claims that expenditures made to repair and rebuild the
field's dehydration plant should not have been necessary had the facilities been
properly constructed and maintained by the Defendants. The expenditures, the
Company claims, were inappropriately charged to the field's carried interest
account. The effect of an increased carried interest account is to extend the
period before pay out begins to the carried interest account owners.
The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million. The Company claims that by 1993 at least $34 million of unnecessary
expenses had been wrongfully charged to the carried interest account. The
Company's 30% share of these expenses would be approximately $10.2 million. The
Company further claims that if production had commenced in 1984, the carried
interest account would have been paid out in approximately two years and the
Company would have begun to receive revenues from the field in 1986. The
Operator reported that as of November 30, 1999 development costs totaling $96.7
million had been incurred and repaid. As of December 31, 1999, based on the
Operator's report, the Company's share of net revenues due to the Company by all
of the defendants totaled $412,374.
The amount of recoverable costs is one of the issues being contested in
the Kotaneelee litigation. The Company claims, and the defendants deny, that the
defendants have made improper charges to the carried interest account and one
defendant (Amoco Canada) maintains that the carried interest account should be
charged additional amounts for gas processing fees. Amoco Canada claims that the
remaining costs to be recovered at July 31, 1999 were either $72,369,000 or
$33,911,000 depending on inclusion of interest. At this time, it is not possible
to determine whether Amoco Canada will be successful in its claim that gas
processing fees should be charged to the carried interest account.
Although, according to the Operator's reports, the Kotaneelee gas field
reached pay out status on November 10, 1999, the Operator has notified the
Company that it will not make any payments to the carried interest owners,
including the Company, until the issue of the amount of recoverable costs under
the carried interest account has been resolved by the Court of Queens Bench in
Calgary, Canada. The Operator has stated that it will deposit the Company's
share of net production proceeds in an interest bearing account with an escrow
agent. During March 2000, the Operator deposited $136,728 in the escrow account
which represents the Operator's share of December 1999 gas sales less January
and February 2000 operating and capital expenditures. A motion was filed in
December 1999 by the plaintiffs in Canada to direct all of the defendants to
make timely payments of all current and future amounts due from the Company's
share of field revenues. The Company expects that the Court will hear the motion
in April 2000.
Columbia has filed a counterclaim against the Company seeking, if the
Company is successful in its claim for the forfeiture of the field, repayment
from the Company of all unrecovered sums Columbia has expended on the Kotaneelee
lands before the Company is entitled to its interest.
The parties to the litigation conducted extensive discovery since the
filing of the claims. The trial began on September 3, 1996 and the Plaintiffs
completed the presentation of their case against the Defendants during
September, 1998. The Defendants completed their case during February 2000. The
Company estimates that its rebuttal evidence will be completed during March
2000. Both parties to the suit will then have several months to file their
written closing arguments with the Court, which probably will hear closing oral
arguments in the fall of 2000.
Based upon newly discovered evidence, the Company filed a new claim
during May 1998 that the Defendants failed to develop the field in a timely
manner. The Company is unable to estimate the time necessary to conclude the
litigation.
Matters Ancillary to Kotaneelee Litigation
In its 1989 statement of claim, the Company sought a declaratory
judgment regarding two issues:
(1) whether interest accrued on the carried interest account; and
(2) whether expenditures for gathering lines and dehydration
equipment are expenditures chargeable to the carried interest
account or whether the Company will be assessed a processing
fee on gas throughput.
With respect to the first issue, the Company maintains that no interest
should accrue on the account and the Defendants have not contested this
position. With regard to the second issue, the Company maintains that the
expenditures are chargeable to the carried interest account. Mobil, Esso and
Columbia have essentially agreed to the Company's position while the Amoco Dome
Group continues to contest this issue.
On January 22, 1996, the Company settled two claims outstanding against the
Company in the Court of Queens Bench, Calgary, Alberta, which related to a suit
brought against AlliedSignal Inc. ("AlliedSignal") in Florida which was
dismissed on the basis that Canada was the appropriate forum for the litigation.
AlliedSignal had sought additional relief against the Company in Canada to
preclude other types of suits by the Company and to recover the costs of the
defense of the initial action. The settlement bars AlliedSignal from making a
claim against the Company for any costs in connection with the Kotaneelee
Litigation. The Company agreed not to bring any action against AlliedSignal in
connection with the Kotaneelee gas field. Neither party made any monetary
payment to the other party.
The working interest owners have reported that they have been selling
Kotaneelee gas since February 1991.
Under Canadian law, certain costs (known as "taxable costs") of the
litigation may be assessed against the non-prevailing party. Previously, the
Company had reported that while such costs were not determinable, the Company
estimated that taxable costs, assuming a twelve month trial, could be
approximately $1.5 million and noted that the judge in complex and lengthy
trials has the discretion to increase an award.
Effective September 1, 1998, the Alberta Rules of Court were amended to
provide for a material increase in the costs which may be awarded to the
prevailing party in matters before the Court. In addition, the Company believes
that the trial will extend well beyond its original time estimates and,
therefore, potentially assessable costs would increase accordingly.
The trial has been lengthy, complicated and costly to all parties and
the Company believes that the prevailing party or parties in the litigation will
argue for a substantial assessment of costs against the non-prevailing party or
parties. The Court has very broad discretion as to whether to award costs and
disbursements and as to the calculation of any amounts to be awarded.
Accordingly, the Company is unable to determine whether, in the event that it
does not prevail on its claims in the litigation, costs will be assessed against
it or in what amounts. However, since the costs incurred by the Defendants have
been substantial, and since the Court has broad discretion in the awarding of
costs, an award to the Defendants potentially could be material. A cost award
against the Company could be of sufficient magnitude to necessitate a sale of
Company assets or a debt or equity financing to fund such an award. There are no
assurances that any such sale or financing would be consummated.
There is no assurance whatever that the Company will be successful on
the merits of its claims, which have been vigorously defended by the Defendants.
There is also no assurance that the Company will be awarded any damages, or
that, if damages are awarded, the Court will apply the measure of damages the
Company claims should be applied.
<PAGE>
9. Related party transactions
In 1991, the Company granted interests to certain of its officers,
employees, directors, counsel and consultants amounting to an aggregate of 7.8%
of any and all benefits to the Company after expenses from the litigation in
Canada relating to the Kotaneelee gas field. The Company has reserved a 2.2%
interest in such net benefits for possible future grants to persons who may
include officers and directors of the Company.
Mr. Heath, a director of the Company, has royalty interests in certain
of the Company's oil and gas properties, (present and past) which were received
directly or indirectly through the Company. The Company and third-party
operators and/or owners of properties made payments pursuant to these royalties
for the benefit of Mr. Heath totaling U.S. $15,435, $8,324 and $11,158 in 1999,
1998 and 1997, respectively.
10. Other financial information
Accrued liabilities
1999 1998
---- ----
Accrued accounting and legal expenses $ 18,256 $ 69,890
Accrued royalties - 141,575
Other - 83,026
---------- ----------
$ 18,256 $294,491
========= ========
Year ended December 31,
1999 1998 1997
Royalty payments (1) $ 71,838 $146,161 $366,661
=========== ======== ========
Interest payments (2) $ 2,600 $ 1,625 $ 1,775
========== ========== ==========
Large corporation tax payments $ 15,108 $ 22,837 $ 27,388
========= ========= =========
- --------------------
(1) Oil and gas sales are reported net of royalties paid.
(2) Bank line of credit charges.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
SUPPLEMENTARY INFORMATION ON OIL AND
GAS PRODUCING ACTIVITIES
(unaudited)
The following information includes estimates which are subject to
rapid and unanticipated change. Therefore, these estimates may not accurately
reflect future net income to the Company.
All amounts below except for costs, acreage, wells drilled and present
activities relate to Canada. Oil and gas reserve data and the information
relating to cash flows were provided by Paddock Lindstrom & Associates Ltd.,
independent consultants.
Estimated net quantities of proved oil and gas reserves:
<TABLE>
Oil Gas
(bbls) (bcf)
Proved reserves:
<S> <C> <C> <C> <C>
December 31, 1996 425,800 29.031
Revisions of previous estimates 179,333 (3.802)
Production* (71,333) (.838)
---------- ---------
December 31, 1997 533,800 24.391
Sale of properties (350,800) (2.632)
Revisions of previous estimates (73,419) (2.088)
Production* (73,381) (1.263)
---------- --------
December 31, 1998 36,200 18.408
Revisions of previous estimates 5,050 6.786
Production* (11,650) (1.710)
---------- --------
December 31,1999 29,600 23.484
======== ======
Proved developed reserves:
December 31, 1996 358,400 28.265
======= ======
December 31, 1997 508,200 24.391
======= ======
December 31, 1998 36,200 18.408
======== ======
December 31, 1999 29,600 23.484
======== ======
- -----------------
* Production data includes oil and gas sales and the proceeds from the
carried interest properties.
</TABLE>
<PAGE>
<TABLE>
Results of oil and gas operations:
1999 1998 1997
(Restated) (Restated)
Income:
<S> <C> <C> <C>
Oil and gas sales $ 189,461 $1,603,155 $1,644,222
Proceeds from carried interests 587,073 206,503 475,697
Gain on sale of assets - 1,378,180 -
----------------- ---------- -----------------
776,534 3,187,838 2,119,919
----------- ---------- ----------
Costs and expenses:
Production costs 147,332 975,899 799,372
Depletion depreciation, and amortization 707,200 869,600 623,600
Provision for future site restoration costs 600 29,500 21,500
Abandonments and write downs - 684,635 -
Income tax expense (recovery) (35,243) 281,687 302,870
-------------- ----------- ------------
819,889 2,841,321 1,747,342
------------ ---------- ----------
Net income (loss) from operations $ (43,355) $ 346,517 $ 372,577
============== ========== ==========
</TABLE>
<TABLE>
Capitalized costs of oil and gas activities:
1999 1998 1997
<S> <C> <C> <C>
Acquisition costs $ 241,000 $ 11,000 $ 399,000
Exploration 514,000 174,000 546,000
Development 145,000 1,758,000 2,313,000
</TABLE>
Standardized measure of discounted future net cash flows relating to proved oil
and gas reserve quantities during the following period (in thousands of
dollars):
<TABLE>
1999 1998 1997
<S> <C> <C> <C>
Future cash inflows $70,491 $28,052 $46,435
Future development and production costs (24,364) (14,030) (22,517)
-------- --------- ---------
46,127 14,022 23,918
Future income tax expense* (6,331) - (1,573)
--------- ------------- ----------
Future net cash flows 39,796 14,022 22,345
10% annual discount (8,758) (4,781) (7,836)
--------- ---------- ----------
Standardized measure of discounted
future net cash flows $31,038 $ 9,241 $ 14,509
======= ======== ========
</TABLE>
- ------
* Reflects tax benefit for the years 1999, 1998 and 1997, from carry forward of
exploration, development and lease acquisition costs, undepreciated capital
costs and book earned depletion of $18,940,000, $16,381,000 and $18,065,000.
Current prices used in the above estimates were based upon selling
prices at the wellhead at December of each year. The actual price ($2.83) of
Kotaneelee gas at December 31, 1999, was used in these estimates. Current costs
were based upon estimates made by consulting engineers at the end of each year.
<PAGE>
Changes in the standardized measure during the following periods (in thousands
of dollars):
<TABLE>
Year ended December 31,
1999 1998 1997
Changes due to:
<S> <C> <C> <C>
Sale of properties $ - $(4,374) $ -
Prices and production costs 17,776 (402) (579)
Future development costs (116) (1,204) (2,350)
Sales net of production costs (619) (906) (1,562)
Development costs incurred
during the year 145 1,758 2,313
Net change due to extensions,
discoveries and improved recovery - - 1,692
Revisions of quantity estimates 7,256 (872) (3,642)
Accretion of discount 924 1,045 1,723
Net change in income taxes (3,569) (313) 939
---------- ---------- ---------
Net change $21,797 $(5,268) $(1,466)
======= ======== ========
</TABLE>
<PAGE>
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None.
PART III
For information concerning Item 10 - "Directors and Executive Officers
of the Company," Item 11 - "Executive Compensation," Item 12 - "Security
Ownership of Certain Beneficial Owners and Management" and Item 13 - "Certain
Relationships and Related Transactions," see the Proxy Statement of Canada
Southern Petroleum Ltd. relative to the Annual Meeting of Shareholders for the
fiscal year ended December 31, 1999, which will be filed with the Securities and
Exchange Commission, which information is incorporated herein by reference. For
information concerning Item 10 - "Executive Officers of the Company," see Part
I.
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) Financial Statements
The financial statements and schedules listed below
and included under Item 8, above are filed as part of
this report.
Page
Reference
Auditors' Report 36
Consolidated Balance Sheets as at December 31, 1999 and 1998 37
For the years ended December 31, 1999, 1998 and 1997
Consolidated Statements of Operations and Deficit 38
Consolidated Statements of Cash Flows 39
Consolidated Statements of Limited Voting Shares and Contributed
Surplus for the three years ended December 31, 1999 40
Notes to Consolidated Financial Statements 41-54
Supplementary Information On Oil and Gas Producing Activities (unaudited) 55-57
(2) Consolidated Financial Statement Schedules
All schedules have been omitted since the required
information is not present or not present in amounts sufficient to require
submission of the schedule, or because the information required is included
in the consolidated financial statements or the notes thereto.
(3) Exhibits
List of each management contract or compensatory or
arrangement required to be filed as an exhibit pursuant to Item 14(c).
None.
(b) Reports on Form 8-K
(1) On November 2, 1999, the Company filed a Current Report on
Form 8-K to report the death of a director.
(2) On December 28, 1999, the Company filed a Current Report
on Form 8-K to report current developments in the Kotaneelee Litigation (See
Item 3. Legal Proceedings).
(c) Exhibits
The following exhibits are filed as part of this report:
Item Number
2. Plan of acquisition, reorganization, arrangement,
liquidation or succession
Not applicable.
3. Articles of Incorporation and By-Laws
(a) Memorandum of Association as amended on June 30,
1982, May 14, 1985 and April 7, 1988 filed as Exhibit
4B to Form S-8 as filed on November 25, 1998 is
incorporated by reference.
(b) By-laws, as amended, filed as Exhibit 4C to
Form S-8 as filed on November 25, 1998 are
incorporated by reference.
4. Instruments defining the rights of security holders,
including indentures
None.
9. Voting trust agreement
None.
10. Material contracts
(a) Agreements relating to Kotaneelee.
(1.) Copy of Agreement dated May 28, 1959 between
the Company et al. and Home Oil Company Limited et
al. and Signal Oil and Gas Company filed as Exhibit
10(a) to Report on Form 10-K for the year ended
December 31, 1998 is incorporated herein by
reference.
(2.) Copies of Supplementary Documents to May 28,
1959 Agreement (see (1) above), dated June 24, 1959,
consisting of Guarantee by Home Oil Company Limited
and Pipeline Promotion Agreement, filed as Exhibit
10(a) to Report on Form 10-K for the year ended
December 31, 1998 is incorporated herein by
reference.
(3.) Copy of Modification to Agreement dated May
28, 1959 (see (1) above), made as of January 31,
1961, filed as Exhibit 10(a) to Report of Form 10-K
for the year ended December 31, 1998 is incorporated
herein by reference.
(4.) Copy of Agreement dated April 1, 1966 among
the Company et al. and Dome Petroleum Limited et al.,
filed as Exhibit 10(a) to Report on Form 10-K for the
year ended December 31, 1998 is incorporated herein
by reference.
(5.) Copy of Letter Agreement dated February 1,
1977 between the Company and Columbia Gas Development
of Canada, Ltd. for operation of the Kotaneelee gas
field, filed as Exhibit 10(a) to Report on Form 10-K
for the year ended December 31, 1998 is incorporated
herein by reference.
(b) Copy of Agreement dated January 28, 1972 between
the Company and Panarctic Oils Ltd. for development
of the offshore Arctic Islands gas fields, filed as
Exhibit 10(b) to Report on Form 10-K for the year
ended December 31, 1998 is incorporated herein by
reference.
(c) Stock Option Plan adopted December 9, 1992, filed
as Exhibit 10(c) to Report on Form 10-K for the year
ended December 31, 1998 is incorporated herein by
reference.
(d) Stock Option Plan effective July 1, 1998 filed as
Exhibit A to Schedule 14A Information (Proxy
Statement) as filed on May 1, 1998 is incorporated by
reference.
11. Statement re computation of per share earnings
None.
12. Statement re computation of ratios
None.
13. Annual report to security holders, Form 10-Q or
quarterly report to security holders
Not applicable.
16. Letter re change in certifying accountant
Not applicable.
18. Letter re change in accounting principles
None.
21. Subsidiaries of the Company
Canpet Inc. incorporated in Delaware on August 3,
1973. C. S. Petroleum Limited incorporated in Nova
Scotia on December 15, 1981.
22. Published report regarding matters submitted to vote
of security holders
None.
23. Consents of experts and counsel
(a) Paddock Lindstrom & Associates, Ltd. filed
herein.
(b) Ernst & Young LLP filed herein.
24. Power of attorney
Not applicable.
27. Financial Data Schedule
Filed herein (EDGAR filing only).
99. Additional exhibits
(a) Statement of Claim filed on October 27, 1989 against
Columbia Gas Development of Canada Ltd., Amoco
Production Company, Dome Petroleum Limited, Amoco
Canada Petroleum Company Ltd., Mobil Oil Canada Ltd.
and Esso Resources of Canada Ltd. in the Court of
Queen's Bench of Alberta Judicial District of
Calgary, Alberta, Canada, filed as Exhibit 99(a) to
Report on Form 10-K for the year ended December 31,
1998 is incorporated herein by reference.
(b) Amended Statement of Claim, amending the October 27,
1989 Statement of Claim, filed on March 12, 1990,
filed as Exhibit 99(b) to Report on Form 10-K for the
year ended December 31, 1998 is incorporated herein
by reference.
(c) Amended Statement of Claim in the same action, filed
on November 17, 1993, filed as Exhibit 99(c) to
Report on Form 10-K for the year ended December 31,
1998 is incorporated herein by reference.
(d) Amended Statement of Third Party Notice by Amoco
Canada Production Company Ltd. and Amoco Production
Company, filed November 17, 1993 in the same action,
filed as Exhibit 99(d) to Report on Form 10-K for the
year ended December 31, 1998 is incorporated herein
by reference.
(e) Amended Statement of Defense to Third Party Notice by
Anderson Oil & Gas Inc. (formerly Columbia Gas
Development of Canada Ltd.) filed January 27, 1994 in
the same action, filed as Exhibit 99(e) to Report on
Form 10-K for the year ended December 31, 1998 is
incorporated herein by reference.
(d) Financial Statement Schedules
None.
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
CANADA SOUTHERN PETROLEUM LTD.
(Registrant)
Dated: March 28, 2000 By /s/ M. Anthony Ashton
------------------------ --------------------------------------
M. Anthony Ashton
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
By /s/ M. Anthony Ashton By /s/ Kelly B. Johnson
M. Anthony Ashton Kelly B. Johnson
President and Director Treasurer and Chief Financial and
Accounting Officer
Dated: March 28, 2000 Dated: March 28, 2000
------------------------ --------------------------------------
By /s/ Benjamin W. Heath By /s/ Timothy L. Largay
Benjamin W. Heath Timothy L. Largay
Director Director
Dated: March 28, 2000 Dated: March 28, 2000
------------------------ --------------------------------------
By /s/ Arthur B. O'Donnell
Arthur B. O'Donnell
Director
Dated: March 28, 2000
------------------------
<PAGE>
INDEX TO EXHIBITS
23. (a) Consent of Independent Petroleum Engineers
(b) Consent of Independent Auditors
27. Financial Data Schedule (EDGAR filing only)
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., dated March 10, 2000, prepared for filings
with the Securities and Exchange Commission on Form 10-K 1999, 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 inclusion in the Annual Report (Form 10-K) and 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 10, 2000, 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, 1999.
/s/ Ernst & Young LLP
Chartered Accountants
Calgary, Canada
March 30, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1
<CURRENCY> Canadian Dollars
<S> <C> <C> <C>
<PERIOD-TYPE> 12-MOS 12-MOS 12-MOS
<FISCAL-YEAR-END> DEC-31-1999 DEC-31-1998 DEC-31-1997
<PERIOD-START> JAN-01-1999 JAN-01-1997 JAN-01-1997
<PERIOD-END> DEC-31-1999 DEC-31-1998 DEC-31-1997
<EXCHANGE-RATE> 0.6924 0.6535 0.6992
<CASH> 3,045,530 6,208,634 2,129,156
<SECURITIES> 568,374 751,511 3,373,334
<RECEIVABLES> 360,752 266,116 1,226,086
<ALLOWANCES> 0 0 0
<INVENTORY> 0 0 0
<CURRENT-ASSETS> 4,282,175 7,545,958 6,970,854
<PP&E> 20,477,875 18,832,076 21,988,786
<DEPRECIATION> (10,270,581) (8,832,066) (8,004,015)
<TOTAL-ASSETS> 16,072,944 18,854,473 21,885,763
<CURRENT-LIABILITIES> 652,856 670,045 1,398,236
<BONDS> 0 0 0
0 0 0
0 0 0
<COMMON> 14,284,970 14,234,740 14,234,740
<OTHER-SE> 960,422 3,713,643 6,041,813
<TOTAL-LIABILITY-AND-EQUITY> 16,072,944 18,854,473 21,885,763
<SALES> 776,534 1,809,658 2,119,919
<TOTAL-REVENUES> 1,029,899 3,409,361 2,514,978
<CGS> 0 0 0
<TOTAL-COSTS> 4,306,293 6,115,898 4,272,642
<OTHER-EXPENSES> 0 0 0
<LOSS-PROVISION> 0 0 0
<INTEREST-EXPENSE> 0 0 0
<INCOME-PRETAX> (3,276,394) (2,706,537) (1,757,664)
<INCOME-TAX> (274,970) (378,367) (170,158)
<INCOME-CONTINUING> (3,001,424) (2,328,170) (1,587,506)
<DISCONTINUED> 0 0 0
<EXTRAORDINARY> 0 0 0
<CHANGES> 0 0 0
<NET-INCOME> (3,001,424) (2,328,170) (1,587,506)
<EPS-BASIC> (0.21) (0.16) (0.11)
<EPS-DILUTED> (0.21) (0.16) (0.11)
</TABLE>
