FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission file number 1-3793
CANADA SOUTHERN PETROLEUM LTD.
(Exact name of registrant as specified in its charter)
NOVA SCOTIA, CANADA 98-0085412
State or other jurisdiction of (I.R.S. Employer
incorporation or organization Identification No.)
Suite 1410, One Palliser Square
125 Ninth Avenue, S.E.
Calgary, Alberta CANADA T2G OP6
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (403) 269-7741
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
Limited Voting Shares, $1 (Canadian) per share Pacific Stock Exchange
Boston Stock Exchange
Toronto Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
(Title of Class)
NONE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. |X| Yes |_| No
<PAGE>
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K ss.229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. [ X ]
The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately U.S. $95,781,000 at March 18, 1997.
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
Limited Voting Shares, par value $1.00 (Canadian) per share, 13,956,
540 shares outstanding as of March 18, 1997.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy Statement of Canada Southern Petroleum Ltd. related to
the Annual Meeting of Shareholders for the year ended December 31, 1996, which
is incorporated into Part III of this Form 10-K.
<PAGE>
TABLE OF CONTENTS
Page
PART I
Item 1. Business 4
Item 2. Properties 15
Item 3. Legal Proceedings 23
Item 4. Submission of Matters to a Vote of Security Holders 26
PART II
Item 5. Market for the Company's Limited Voting Shares and
Related Stockholder Matters 27
Item 6. Selected Financial Data 29
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 30
Item 8. Financial Statements and Supplementary Data 36
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 56
PART III
Item 10. Directors and Executive Officers of the Company 56
Item 11. Executive Compensation 56
Item 12. Security Ownership of Certain Beneficial Owners
and Management 56
Item 13. Certain Relationships and Related Transactions 56
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K 57
Unless otherwise indicated, all dollar figures set forth are expressed in
Canadian currency. The exchange rate at March 18, 1997 was $1.00 Canadian = U.S.
$.7281.
<PAGE>
PART I
Item 1. Business.
The nature of Canada Southern Petroleum Ltd.'s (the "Company" or
"Canada Southern") business is described at Item 1(c) herein, and a description
of its oil and gas properties in Canada appears in Item 2 herein. For additional
information regarding the development of the Company's business, see
"Properties" and "Supplemental Information on Oil and Gas Activities".
(a) General Development of Business
Yukon Territory - The Kotaneelee Field
The Company's principal asset is a 30% carried interest in the
Kotaneelee gas field located on Ex-Permit 1007 (31,888 gross acres or 9,566 net
acres) in the extreme southeastern corner of the Yukon Territory. This partially
developed field is connected to a major pipeline system. Only three wells have
been completed to date and are capable of an estimated output of in excess of 60
million cubic feet per day, the capacity of the field dehydration plant. Present
production is approximately 40-45 million cubic feet ("mcf") per day. The
operator is Anderson Exploration Ltd., which acquired all of Columbia Gas
Development of Canada's interests. See "Legal Proceedings " for a discussion of
the Kotaneelee Litigation concerning this asset.
Production at Kotaneelee commenced in February 1991. According to
government reports, total production in billion cubic feet ("bcf") from the
Kotaneelee gas field since 1991 has been as follows:
Calendar Year Production (bcf)
- ------------------------------
1991 8.1
1992 18.0
1993 17.5
1994 16.7
1995 15.7
1996 15.2
In a 1989 application to the National Energy Board, a reserve study by
the operator estimated total gas in place at 1.6 trillion cubic feet with proved
and probable recoverable reserves of 781 BCF.
<PAGE>
At present, the Company does not receive any cash payments from
production but is credited with 30% of the gross revenues until a like percent
of the working interest costs, exclusive of any interest expense, are recovered
by the operator. The Company will not receive any payment from production
revenues until its share of the working interest costs are recovered. When the
deferred costs are recovered, 30% of gross revenues (net of gross overriding
royalties) less 30% of current working interest costs will be paid to the
Company. Gross overriding royalties amount to 10% to the Canadian Federal
government and 4.06% to certain individuals. The operator has reported to the
Company development costs totaling approximately $88,000,000 and, of that
amount, approximately $21,800,000 remained to be recovered at December 31, 1996.
The Company has contested the amount of costs that have been charged to the
carried interest account. It is expected that the Company will begin to receive
proceeds from the Kotaneelee gas field commencing in 1999, based upon a price of
$1.34 per mcf (average 1996 price) and current production rates. The period
before payment to the Company begins may be shorter or longer, depending on
prevailing market conditions and the results of the Kotaneelee Litigation. Under
ordinary circumstances, increased natural gas prices would result in a shorter
period to payout.
British Columbia Properties
The Company's major source of income is from oil and gas fields in
northeast British Columbia. These fields, developed in the 1950's and 1960's,
produce revenue through both working and carried interest agreements. The major
working interests in these fields are operated by Canadian Natural Resources
Ltd. ("CNRL"). Petro Canada is the operator of the Company's carried interest
lands in British Columbia.
In addition to the producing properties, since 1988 the Company has
acquired a number of leases in northeast British Columbia by participating in
British Columbia land sales. To date three wells have been drilled on the lands
resulting in two oil discoveries and one dry hole. Currently, the Company is
defining the prospects by geophysics. Work completed to date indicates that
seven of the prospects justify drilling. The Company estimates that the drilling
costs (excluding completion costs) of the seven prospects would be $1,625,000.
However, as most of these wells would be wildcat wells (exploratory wells), the
Company plans to reduce its risk by selling or farming out part of its interest.
The timing of the drilling is dependent on the availability of funds and the
Company anticipates that its average net cost per well (assuming a farmout or
sale) would be approximately $75,000, or a total of $525,000, for drilling and
completion costs.
<PAGE>
On the working interest lands, the most successful of these wells was
in the West Peejay field in British Columbia (Company interest 27.75%). This
field has been produced for many years, without any attempt to explore the
field's limits. The 1993 sale of the field by the majority owner and the
appointment of a new operator resulted in three new producing oil wells in 1994.
The operator has applied to unitize and waterflood the West Peejay field.
Preliminary approval has been received and work is underway with one well
drilled and a seismic program completed. The first well encountered oil and gas
and it is expected that at least three more wells will be drilled in 1997. Once
unitization is completed, the Company will have a 14.0152% working interest in
the oil and 14.1113% working interest in the gas in the whole field rather than
a 27.75% working interest in a part of the field.
CNRL operates the lands which also include the Company's working
interest in the Peejay and Weasel fields. As of December 31, 1996, the Company
held approximately 18,732 gross acres (4,434 net acres) in this area. The
Company owns interest in the following units:
Unit Company
Acreage %
Peejay Unit #1 4,529 3.1643
Weasel Unit #2 1,569 10.1775
Peejay Unit #3 5,923 15.4136
The Company also holds interests in 10 oil wells (2.64 net wells) and
10 gas wells. (2.28 net wells) not included in the above units. The Company
estimates that the capital costs for its interests in the West Peejay field will
aggregate approximately $750,000 for 1997.
The Company has a 33 1/3% working interest in the Paradise area. Two
oil discoveries in the area remain shut-in because at current oil prices their
production rates are uneconomic. The wells also encountered potential gas zones
which have not been tested. A portion of the lands have been farmed out on a
seismic option basis and the farmee has committed to drill a well on the lands,
as soon as a surface lease and rig have been acquired. The Company will retain
an overriding royalty before payout and a 6.67% working interest in the well
after payout.
There has been further drilling and development work on the Company's
carried interest properties at Buick Creek and Siphon. Initial production from
this work shows promise with a rate of 3.8 million cubic feet per day from a
horizontal well at Buick Creek. Capital costs charged to the carried interest
account in 1996 were $375,000. During 1996, the Siphon area properties were sold
by the operator and a new operator appointed. The Wargen area is also expected
to change operators in 1997. The new owners of these fields are expected to
aggressively exploit the properties with increased capital expenditures.
Carried interest lands are also held by the Company in the Ekwan,
Clarke Lake, Siphon and Wargen fields. The Company retains a 21.25 % carried
interest with a right to convert to a 21.25 % working interest in most of these
fields. Interests in some of these wells are less than 21.25 % because of
pooling or side agreements. As of December 31, 1996, there were 36 gas wells in
these fields which are producing wells or wells considered to be capable of
production.
Arctic Islands
As of December 31, 1996, the Company held working interests in 45,100
gross acres (1,817 net acres) and carried interests in 133,260 gross acres
(37,255 net acres) in the Sverdrup Basin, located in the Arctic Islands. The
Hecla, Whitefish, Drake Point, Roche Point, Kristoffer, Romulus and Bent Horn
fields have been designated significant discovery lands ("SDL" ) by the Federal
Government. The Company's interests in the SDL's have been retained pending
development.
Marketing of Bent Horn Production
Panarctic Oils Ltd. ("Panarctic"), the operator, received Federal
government regulatory approvals for a pilot project to move shipments of crude
oil from the Bent Horn field by tanker through the Northwest Passage to southern
Canada in 1985. Through December 31, 1996, approximately 2.7 million barrels of
Bent Horn crude had been sold with deliveries being made at northern Canadian
and European markets as well as the eastern seaboard market. In 1996, the
operator decided to shut down production from the field and dismantle the
production facilities because of economic uncertainties. The Company has a 5%
carried interest in the area which has not yet reached payout status. The timing
of payout is uncertain.
Northwest Territories Properties
The Company has a 45% carried interest in the Northwest Territories in
the Celibeta field designated as Significant Discovery Lands ("SDL") by the
Federal Government (1,594 gross acres and 717 net acres). The field is presently
a shut-in gas field.
Alberta
The Company participated in 9 wells on the Alberta lands in 1996
which resulted in 6 oil wells, 1 gas well and 2 dry holes.
<PAGE>
In 1994, the Company purchased a 5% working interest in the Kitscoty
heavy oil field and the related facilities. Oil recovery from this field is
being enhanced by steam injection. Two horizontal holes were drilled for
production with the steam being injected through vertical holes. Production has
increased from 60 bpd to 300 bpd.
In 1996, the Company purchased an additional 5% working interest in the
Kitscoty field. Three more wells were drilled in 1996, two horizontal wells and
one vertical well. All the wells encountered oil and are now on production. One
well also discovered three potential gas zones which will be evaluated for
future use as fuel for the steam generation needed to enhance the oil
production.
The other successful wells in Alberta were at Atlee and Leduc. At
Atlee, two horizontal wells were drilled and placed on production at a combined
rate of 500 bpd. The operator plans to complete a 3D seismic program with the
possibility of drilling six additional wells in 1997. The Company has a 12.5%
working interest in the two producing wells.
At Leduc, three wells were drilled of which two were completed as oil
and gas wells and one well was a dry hole. One well encountered two potential
producing zones and is currently producing at the allowable rate of 68 bpd. The
second zone containing oil and gas will be produced from a follow-up well to be
drilled in early 1997. The other successful well was completed as a gas well and
is producing 1.5 million cubic feet per day. The Company has a 15% working
interest in these wells. The operator has indicated that is expects that at
least two wells will be drilled on the Leduc properties in 1997, once the
results of the 1996 3D seismic program have been evaluated.
The Company also acquired a 10-20% working interest in over 12,000
acres in four other areas of Alberta. These lands were purchased on the basis of
seismic work which showed a number of promising prospects. Subsequently,
additional seismic work has confirmed the potential of those prospects. One well
will be drilled as soon as a rig is available and at least two additional wells
are planned for 1997.
The Company's gas well at Drumheller remains shut-in and the Company
has agreed to sell its interest in the Sylvan Lake well.
The Company has working interests ranging from 10% to 45% in a total of
40,702 gross (11,178 net) acres.
Saskatchewan
Under the Company's land acquisition program, it acquired a 3.75%
working interest (2,560 gross acres - 96 net acres) in 4 sections in
Saskatchewan in late 1994.
<PAGE>
Two wells were drilled on these properties in early 1995, and, although both
were abandoned, indications are that the leases have good oil potential and
further seismic work was completed in 1996. A well was drilled on the basis of
the new seismic program and the well tested over three million cubic feet per
day from a gas zone. The well is currently shut-in.
Australia
The Company has a .08% working interest in 115,596 gross (90 net) acres
in the Amadeus Basin in the Northern Territory in Australia. Because of the
limited potential of the only remaining property, the Dingo gas field, the
interest was written down to a nominal value in 1992. The Dingo gas field is a
shut-in gas field which is not connected to a gas pipeline. Initial discussions
have been held with a potential gas purchaser for the sale of approximately 7.4
BCF of gas over 10 years with a possible contract for 20 years. Magellan
Petroleum Australia Limited ("MPAL") is presently operator of this property.
Benjamin W. Heath and C. Dean Reasoner, directors of the Company, are also
directors of MPAL. Mr. Reasoner resigned as a director of the Company on March
11, 1997.
United States
The Company has agreed to participate in the drilling of five wells in
Texas. The first two wells drilled in 1996 resulted in oil discoveries, however,
the wells are currently shut-in awaiting remedial work.
Two more wells will be drilled by mid 1997.
(b) Financial Information about Industry Segments.
Since the Company is primarily engaged in only one industry, oil and
gas exploration and development, this item is not applicable to the Company. See
Item 8 for general financial information concerning the Company.
(c) (1) Narrative Description of the Business.
The Company was incorporated in 1954 under the Canada
Corporations Act. In 1979, it became subject to the Canadian Business
Corporations Act and in 1980, was continued under the Nova Scotia Companies Act.
The Company is, either in its own right, or through other entities,
engaged in the exploration for and development of properties containing or
believed to contain recoverable oil and gas reserves and the sale of oil and gas
from these properties. Although many of the properties in which the Company has
interests are undeveloped, all properties with proved reserves are partially or
fully developed. The Company's interests in exploratory ventures are on
properties located in Alberta, British Columbia, the Northwest and Yukon
Territories and the Arctic Islands in Canada, and the Northern Territory of
Australia. A principal asset of the Company is its 30% carried interest in the
Kotaneelee field, a partially developed gas field (See Item 3 - "Legal
Proceedings".) The Company also has interests in producing properties in British
Columbia and Alberta. Most of this acreage is covered by carried interest
agreements, which provide that revenues are not payable to the Company until
expenditures by the carrying partners have been recouped from production, and
that operating decisions are made by the carrying partners. Generally, the
Company may, at any time, as to each block or economic unit, elect to convert
from a carried interest position to a working interest position by paying its
share of the unrecouped expenditures for the unit, i.e., expenditures not
recouped from production revenues. At December 31, 1996, the Company's share of
unrecouped expenditures were as follows:
British Columbia:
Ex-permit 149 $3,216,000
Yukon and Northwest Territories:
Ex-permit 1007 (Kotaneelee)* 6,534,000
Ex-permit 2713 (Celibeta) 321,000
*See Item 3 - Legal Proceedings
(i) Principal Products.
The majority of the Company's interests are
carried interests. The Company also participates in the production and sale
of crude oil, natural gas and natural gas liquids derived from its working
interests.
(ii) Status of Product or Segment.
At present, some of the properties in which
the Company has interests are undeveloped and/or nonproducing.
(iii) Raw Materials.
Not applicable.
(iv) Patents, Licenses, Franchises and
Concessions Held.
Permits and concessions are important to the
Company's operations, since they allow the search for and extraction of any
oil, gas and minerals discovered on the areas covered. See the detailed
schedule of properties under Item 2, "Properties."
<PAGE>
(v) Seasonality of Business.
The Company's business is not seasonal,
except that sales of natural gas peak during the winter heating season.
Exploration and development activities are restricted in certain areas on a
seasonal basis because extreme weather conditions affect transportation and
the ability to pursue these activities.
(vi) Working Capital Items.
Not applicable.
(vii) Customers.
Substantially all oil production from the
Company's properties for the current year was purchased by CNRL, the operator
of the majority of the producing properties. Most of the natural gas produced
from Company properties was sold by the operator, Petro Canada, to a company
owned by certain British Columbia gas producers, Can West Gas Supply Inc. Th
production from the Kotaneelee gas field is also being sold to CanWest Gas
Supply, Inc.
(viii) Backlog.
Not applicable.
(ix) Renegotiation of Profits or Termination of
Contracts or Subcontracts at the Election of
the Government.
Not applicable.
(x) Competitive Conditions in the Business.
The exploration for and production of oil
and gas are highly competitive operations, both internally within the oil and
gas industry and externally with producers of other types of energy. The ability
to exploit a discovery of oil or gas is dependent upon considerations such as
the ability to finance development costs, the availability of equipment, and
engineering and construction delays and difficulties. The Company must
compete with companies which have substantially greater resources available
to them. Because the majority of Company interests are in remote areas,
operation of its properties is more difficult and costly than in more accessible
areas.
<PAGE>
Furthermore, competitive conditions may be
substantially affected by various forms of energy legislation which may have
been or may be proposed in the United States and Canada; however, it is not
possible to predict the nature of any such legislation which may ultimately be
adopted or its effects upon the future operations of the Company. For a further
discussion of Canadian governmental regulation of the petroleum industry, see
Item 1(d)(2).
(xi) Research and Development.
Not applicable.
(xii) Environmental Regulation.
In the exploration for and development of
natural resources, the Company is required to comply with significant
environmental laws and regulations which add to the expense of those activities.
The Company has not been required to spend significant sums to comply with clean
up laws and regulations. Compliance by the Company with governmental provisions
regulating the discharge of materials to the environment or otherwise relating
to the protection of the environment are not expected to have a material effect
on the capital expenditures, earnings or competitive position of the Company.
(xiii) Number of Persons Employed by Company.
The Company currently has three full time
employees, all of whom are located in Canada. The Company also relies to a
great extent on consultants for technical, legal, accounting and administrative
services. The Company uses consultants because it is more cost effective than
employing a larger full time staff.
(d) Financial Information about Foreign and Domestic Operations
and Export Sales.
(1) Identifiable Assets.
Substantially all of the Company's operating assets
are in Canada.
All of the Company's revenues are attributable to its
operations in Canada.
(2) Risks Attendant to Foreign Operations.
The properties in which the Company has interests
are located in Canada and are subject to certain risks involved in the ownership
and development of such foreign property interests. These risks include but are
not limited to those of: nationalization; expropriation; confiscatory taxation;
native rights; changes in foreign exchange controls; currency revaluation;
burdensome royalty terms; export sales restrictions; limitations on the
transfer of interests in exploration licenses; and other laws and regulations
which may adversely affect the Company's properties, such as those providing
for conversion, proration, curtailment, cessation or other forms of limiting or
controlling production of, or exploration for, hydrocarbons. Thus, an investment
in the Company represents an exposure to risks in addition to those inherent in
petroleum exploratory ventures.
Governmental Regulation of the Canadian Oil and Natural Gas Industry
The oil and natural gas industry in Canada is subject to extensive
controls and regulations imposed by various levels of government relating to
land tenure, production, production facilities, pricing and marketing,
royalties, environmental protection and other matters. Outlined below are some
of the more significant aspects of the legislation, regulations and agreements
governing the oil and natural gas industry in Canada. All current legislation is
a matter of public record and the Company is unable to predict whether any
additional legislation or amendments may be enacted.
Land Tenure
Crude oil and natural gas located in the western provinces is owned
predominantly by the respective provincial governments. Provincial governments
grant rights to explore for and produce oil and natural gas pursuant to leases,
licenses and permits for varying terms from two years and on terms and
conditions set forth in provincial legislation including requirements to perform
specific work or make payments. Oil and natural gas located in such provinces
can also be privately owned and rights to explore for and produce such oil and
natural gas are granted by lease on such terms and conditions as may be
negotiated. The term of both Crown and freehold leases will generally continue
as long as oil or natural gas is produced from the property.
Oil and natural gas rights on federal lands outside of the provinces is
generally regulated by the Government of Canada unless authority has been
delegated by agreement to the territorial government or the government of the
province adjacent to the federal offshore area. In May 1993, the Canada Yukon
Oil and Gas Accord was signed which allows for the transfer to the Yukon of
authority to administer and control oil and natural gas resources within that
territory and for the establishment of an Oil and Gas Management Regime. The
National Energy Board ("NEB") is working with Yukon officials to facilitate the
transfer of oil and natural gas regulatory responsibilities in accordance with
the Yukon Accord Implementation Agreement.
<PAGE>
Production and Production Facilities
The Governments of Canada, Alberta, British Columbia and Saskatchewan
have enacted statutory provisions regulating the production of oil and natural
gas. These regulations may restrict the maximum allowable production from a well
based on reservoir engineering and/or conservation practices. The construction
and operation of facilities to recover and process oil and natural gas are also
subject to regulation.
Pricing and Marketing - Oil
In Canada, producers of oil negotiate sales contracts directly with oil
purchasers, with the result that the market determines the price of oil. Certain
purchasers periodically advertise for volumes of oil they are prepared to
purchase and the price being offered for such volumes. The price depends in part
on oil quality, prices of competing fuels, distance to market and the value of
refined products. Oil exports may be made pursuant to export contracts with
terms not exceeding one year in the case of light crude, and not exceeding two
years in the case of heavy crude, provided that an order approving any such
export has been obtained from the NEB. Any oil export to be made pursuant to a
contract of longer duration requires an exporter to obtain an export license
from the NEB and the issue of such a license requires the approval of the
Governor in Council.
Pricing and Marketing - Natural Gas
In Canada, the price of natural gas is determined by negotiation
between buyers and sellers, with the result that the market determines the price
of natural gas. Natural gas exported from Canada is subject to regulation by the
NEB and the Government of Canada. Exporters are free to negotiate prices and
other terms with purchasers, provided that the export contracts must continue to
meet certain criteria prescribed by the NEB and the Government of Canada. As is
the case with oil, natural gas exports for a term of less than two years must be
made pursuant to an NEB order, or, in the case of exports for a longer duration,
pursuant to an NEB license and Governor in Council approval.
The Governments of Alberta, British Columbia and Saskatchewan also
regulate the volume of natural gas which may be removed from those provinces for
consumption elsewhere based on such factors as reserve availability,
transportation arrangements and market considerations.
Royalties and Incentives
The royalty regime is a significant factor in the profitability of oil
and natural gas production. Royalties payable on production from lands other
than Crown lands are determined by negotiations between the mineral owner and
the lessee, although production from such lands may also be subject to
provincial taxes and regulations. Crown royalties are determined by government
regulation and are generally calculated as a percentage of the value of the
gross production, and the rate of royalties payable generally depends in part on
prescribed reference prices, well productivity, geographical location, field
discovery date and the type or quality of the product produced. The value of the
gross production for royalty purposes may be based on a deemed value for the
product rather than the actual value received by the interest holder.
From time to time the Governments of Canada, Alberta, British Columbia
and Saskatchewan have established incentive programs which have included royalty
rate reductions, royalty holidays and tax credits for the purpose of encouraging
natural gas and oil exploration or enhanced recovery projects. Incentives are
intended to enhance the existing cash flow of the oil and natural gas industry
and to improve the economics of finding and developing new and more costly oil
and natural gas reserves. Oil royalty holidays for specific wells and royalty
reductions reduce the amount of Crown royalties paid by the interest holder to
the respective government. Tax credit programs provide a rebate on Crown
royalties paid.
Environmental Regulation
The oil and natural gas industry is subject to environmental regulation
pursuant to local, provincial and federal legislation. Environmental legislation
provides for restrictions and prohibitions on spills, releases or emissions of
various substances produced in association with certain oil and natural gas
industry operations. An environmental assessment and review may be required
prior to initiating exploration or development projects or undertaking
significant changes to existing projects. In addition, legislation requires that
well and facility sites be abandoned and reclaimed to the satisfaction of the
appropriate authorities. A breach of such legislation may result in the
imposition of fines or penalties. Federal environmental regulations also apply
to the use and transport of certain restricted and prohibited substances. The
Company is committed to meeting its responsibilities to protect the environment
wherever it operates and believes that it is in material compliance with
applicable environmental laws and regulations. The Company has not been required
to spend significant sums to comply with clean up laws and regulations.
Compliance by the Company with governmental provisions regulating the discharge
of materials to the environment or otherwise relating to the protection of the
environment are not expected to have a material effect on the capital
expenditures, earnings or competitive position of the Company.
(3) Data which Are Not Indicative of Current or Future Operations
Not applicable.
Item 2. Properties.
(a) The principal asset of the Company is its 30% carried interest in
the Kotaneelee field, a partially developed gas field in the Yukon Territory.
See Item 3. "Legal Proceedings." The Company also has interests in producing
properties in British Columbia and Alberta. Finally, the Company has interests
in several exploration prospects. These interests are in exploratory ventures in
properties located in Alberta, the Northwest Territories and the Arctic Islands
in Canada, and the Northern Territory of Australia. Geophysical, geological and
drilling work on the Company's properties is conducted by the operators under
various agreements with the Company. The results of this work are reviewed by
Company personnel and consultants retained by the Company.
The properties in Australia in which the Company has a minor interest
are undeveloped and nonproducing, and the Company has not incurred significant
costs in connection with these properties.
(b) (1) The information regarding reserves, costs of oil
and gas activities, capitalized costs, discounted future net cash flows
and results of operations is contained in Item 8. "Financial Statements and
Supplementary Data."
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of Canada showing key Company properties
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of N.E. British Columbia and Yukon, Northwest Territories
showing Company interest lands
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map showing the Kotaneelee Field
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of the Arctic Island Fields
showing the Company interest lands
<PAGE>
(2) Reserves Reported to Other Agencies.
Not applicable.
(3) Production
Average sales price per unit and average production cost for oil and
gas produced during the periods shown below are as follows:
Average Sales Price Average Production Costs
Year Oil (per bbl.) Gas (per mcf.) Oil (per bbl.) Gas (per mcf.)
($) ($) ($) ($)
1996 25.47 1.64 8.67 .79
1995 22.39 1.30 10.08 .77
1994 19.14 1.84 7.49 .98
(4) Productive Wells and Acreage
Productive wells and acreage on working and carried interest properties
as of December 31, 1996:
Gross Wells Net Wells
Oil Gas Oil Gas
71 83 11.69 14.91
Gross and Net Developed Acres
Gross Acres Net Acres
Alberta 5,697 844
Saskatchewan 640 24
British Columbia 66,360 16,113
Yukon Territory 3,350 1,005
Arctic Islands 3,060 153
Texas, USA 80 7
--------- ----------
79,187 18,146
====== ======
<PAGE>
(5) Undeveloped Acreage.
Total developed and undeveloped acreage in which the Company has
interests is summarized by geographic area in the table below:
<TABLE>
<CAPTION>
Gross and Net Petroleum Acreage as of December 31, 1996
Developed Acres Undeveloped Acres
Gross Net Gross Net
Acres Acres % Acres Acres %
<S> <C> <C> <C> <C> <C> <C>
Canada:
British Columbia:
Carried Interests 39,508 7,455 18.9 12,211 932 7.6
Working Interests 23,042 4,848 21.9 37,861 11,932 31.5
Overriding royalty interest 3,810 3,810 3.0 - -
------- ------- ------- -------
Total British Columbia 66,360 16,113 50,072 12,864
------ ------ ------ ------
Saskatchewan:
Working Interests 640 24 3.8 2,560 96 3.8
-------- --------- ------ ---------
Alberta:
Working Interests 5,697 844 14.8 36,285 9,929 27.4
----- ------- ------ ------
Yukon & Northwest Territories:
Carried Interests 3,350 1,005 30.0 31,726 9,757 30.8
------- ----- ------ ------
Arctic Islands:
Carried Interests 3,060 153 5.0 130,200 37,102 28.5
Working Interests - - 45,100 1,817 4.0
---------- ---------- ------- ------
Total Arctic Islands 3,060 153 175,300 38,919
------- ------- ------- ------
Total Canada 79,107 18,139 295,943 71,565
Texas, USA 80 7 8.8 - -
Australia - - 115,596 90 .1
---------- ---------- ------- ---------
TOTAL 79,187 18,146 411,539 71,655
====== ====== ======= ======
</TABLE>
(6) Drilling activity.
Productive and dry net wells drilled during the following periods (no
drilling in Australia):
Gross Net
--------------------- ----------------------
Year/Period Ended Productive Dry Productive Dry
- ----------------- ---------- --- ---------- ---
1996 10 2 1.044 .150
1995 1 3 .033 .258
1994 8 - 1.000 -
<PAGE>
(7) Present Activities.
There was no drilling activity at December 31, 1996.
(8) Delivery Commitments.
None.
Item 3. Legal Proceedings.
The Company, which has a 30% interest in the Kotaneelee gas field,
believes that the working interest owners in the field have not adequately
pursued the attainment of contracts for the sale of Kotaneelee gas. In October
1989 and in March 1990, the Company filed statements of claim in the Court of
Queens Bench of Alberta, Judicial District of Calgary, Canada, against the
working interest partners in the Kotaneelee gas field. The named defendants were
Amoco Canada Petroleum Corporation, Ltd., Dome Petroleum Limited (now Amoco
Canada Resources Ltd.), and Amoco Production Company (collectively the "Amoco
Dome Group"), Columbia Gas Development of Canada Ltd. ("Columbia"), Mobil Oil
Canada Ltd. ("Mobil") and Esso Resource of Canada Ltd. ("Esso") (collectively
the "Defendants").
The Company claims that the Defendants breached either a contract
obligation or a fiduciary duty owed to the Company to market gas from the
Kotaneelee gas field when it was possible to so do. The Company asserts that
marketing the Kotaneelee gas was possible in 1984 and that the Defendants
deliberately failed to do so. The Company seeks money damages and the forfeiture
of the Kotaneelee gas field. The Company expects to argue at trial that the
money damages sustained by the Company are at least $86 million.
In addition, the Company has claimed that the Company's carried
interest account should be reduced because of the negligent operation of the
field and improper charges to the carried interest account by the Defendants.
The Company claims that when the Defendants in 1980 suspended production from
the field's gas wells, they failed to take precautionary measures necessary to
protect and maintain the wells in good operating condition. The wells thereafter
deteriorated, which caused unnecessary expenditures to be incurred, including
expenditures to redrill one well. In addition, the Company claims that
expenditures made to repair and rebuild the field's dehydration plant should not
have been necessary had the facilities been properly constructed and maintained
by the Defendants. The expenditures, the Company claims, were inappropriately
charged to the field's carried interest account. The effect of an increased
carried interest account is to extend the period before payout begins to the
carried interest account owners.
<PAGE>
The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million. The Company claims that by 1993 at least $34 million of unnecessary
expenses had been wrongfully charged to the carried interest account. The
Company's 30% share of these expenses would be approximately $10.2 million. The
Company further claims that if production had commenced in 1984, the carried
interest account would have been paid off in approximately two years and the
Company would have begun to receive revenues from the field in 1986. At present,
the Company does not expect to receive revenues before 1999 based on a price of
$1.34 per mcf and current production rates.
Columbia has filed a counterclaim against the Company seeking, if the
Company is successful in its claim for the forfeiture of the field, repayment
from the Company of all sums Columbia has expended on the Kotaneelee lands
before the Company is entitled to its interest.
The parties to the litigation have conducted extensive discovery since
the filing of the claims. The trial began on September 3, 1996. The trial was
suspended after approximately three weeks of testimony pending resolution of the
Company's motion to disqualify Amoco's litigation counsel on the basis that a
partner in the firm representing Amoco had served as the Company's Canadian
securities counsel for many years. The Company's motion was denied and the
denial was upheld on appeal. The Company has filed with the Supreme Court of
Canada an application for leave to appeal that decision. The parties have agreed
to expedite the application and a decision whether the Supreme Court will review
the decision is expected by the end of April. If the Supreme Court refuses to
hear the case, trial is expected to resume on May 5, 1997.
Matters Ancillary to Kotaneelee Litigation
In its 1989 statement of claim, the Company sought a declaratory
judgment regarding two issues:
(1) whether interest accrued on the carried interest account; and
(2) whether expenditures for gathering lines and dehydration
equipment are expenditures chargeable to the carried interest
account or whether the Company will be assessed a processing
fee on gas throughput.
With respect to the first issue, the Company maintains that no interest
should accrue on the account and the Defendants have not contested this
position. With regard to the second issue, the Company maintains that the
expenditures are chargeable to the carried interest account. Mobil, Esso and
Columbia have essentially agreed to the Company's position while the Amoco Dome
Group continues to contest this issue.
<PAGE>
On January 22, 1996, the Company settled two claims outstanding against
the Company in the Court of Queens Bench, Calgary, Alberta, which related to a
suit brought against AlliedSignal Inc. ("AlliedSignal") in Florida which was
dismissed on the basis that Canada was the appropriate forum for the litigation.
AlliedSignal had sought additional relief against the Company in Canada to
preclude other types of suits by the Company and to recover the costs of the
defense of the initial action. The settlement bars Allied Signal from making a
claim against the Company for any costs in connection with the Kotaneelee
Litigation. The Company agreed not to bring any action against AlliedSignal in
connection with the Kotaneelee gas field. Neither party made any monetary
payment to the other party.
In 1991, Anderson Exploration Ltd. acquired all of the shares in
Columbia and changed its name to Anderson Oil & Gas Inc. ("Anderson"). Anderson
is now the sole operator of the field and is a direct defendant in the Canadian
lawsuit. Columbia's previous parent, The Columbia Gas System, Inc., which was
reorganized in a bankruptcy proceeding in the United States, is contractually
liable to Anderson in the legal proceeding described above.
The working interest owners have reported that they have been selling
Kotaneelee gas since February 1991.
Under Canadian law certain costs of the litigation are assessed against
the nonprevailing party. These costs consist primarily of attorney's and expert
witness fees during trial. The trial is presently scheduled to last twelve
months, therefore, these costs could be substantial. While the costs are not now
determinable, the Company estimates that such costs, assuming a twelve month
trial, could be approximately $1.5 million. However, a judge in complex and
lengthy trials has the discretion to double an award of costs. There are no
assurances however, that such costs will not exceed this amount or that the
duration of the trial will not exceed twelve months.
There is no assurance that the Company will be successful on the merits
of its claims, which have been vigorously defended by the Defendants. There is
also no assurance that the Company will be awarded any damages, or that, if
damages are awarded, the Court will apply the measure of damages the Company
claims should be applied.
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
Executive Officers of the Company.
The following information with respect to the executive officers of the
Company is furnished pursuant to Instruction 3 to Item 401(b) of Regulation S-K.
Length of Other Positions
Service Held with
Name Age Office in this Office Company
Charles J. Horne 71 President Since 1980 Director
M. A. Ashton 61 Executive Vice President Since 1993 Director
All officers of the Company are elected annually by the Board of
Directors and serve at the pleasure of the Board of Directors.
The Company is aware of no arrangement or understanding between any of
the individuals named above and any other person pursuant to which any
individual named above was selected as an officer.
<PAGE>
PART II
Item 5. Market for the Company's Limited Voting Shares and Related
Stockholder Matters.
(a) Principal Markets.
The Company's Limited Voting Shares, par value $1.00 per share, are
traded on The Toronto Stock Exchange and the Pacific and Boston Stock Exchanges,
and in the NASDAQ SmallCap market.
The quarterly high and low closing prices (in Canadian dollars) on The
Toronto Stock Exchange during the calendar periods indicated were as follows:
1995 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 7.875 7.75 9.00 10.25
Low 6.00 6.75 6.25 8.375
1996 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 11.25 11.50 11.55 10.25
Low 7.75 8.00 8.50 8.50
The quarterly high and low closing prices (in United States dollars) on
the Pacific Stock Exchange during the calendar periods indicated were as
follows:
1995 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 5 5/8 6 6 3/4 7 1/2
Low 4 3/8 4 13/16 4 5/8 6 1/4
1996 1st quarter 2nd quarter 3rd quarter 4th quarter
- ---- ----------- ----------- ----------- -----------
High 8 1/8 8 1/4 8 1/2 7 5/8
Low 6 6 1/8 6 3/8 6 1/2
<PAGE>
(b) Approximate Number of Holders of Limited Voting
Shares at March 3, 1997.
Approximate
Title of Class Number of Record Holders
Limited Voting Shares, par value
$1.00 per share. 6,500
(c) Dividends.
The Company has never paid a dividend on its Limited Voting Shares. Any
future dividends will be dependent on the Company's earnings, financial
condition, and business prospects. The Company is legally restricted from paying
any dividend or making any other payment to shareholders (except by way of
return of capital) on the Limited Voting Shares until its accumulated deficit
($19,385,000 at December 31, 1996) is eliminated.
Current Canadian law does not restrict the remittance of dividends to
persons not resident of Canada. Under current Canadian tax law and the United
States-Canada tax treaty, any dividends paid to U.S. shareholders are currently
subject to a 15% Canadian withholding tax.
<PAGE>
Item 6. Selected Financial Data.
The following selected consolidated financial information (in thousands
except per share and exchange rate data) of the Company insofar as it relates to
each of the fiscal periods shown has been extracted from the Company's
consolidated financial statements. Effective July 1, 1993, the Company changed
its year end from June 30 to December 31.
<TABLE>
<CAPTION>
Year ended Year ended
December 31, June 30,
1996 1995 1994 1993 1993
---- ---- ---- ---- ----
($) ($) ($) ($) ($)
<S> <C> <C> <C> <C> <C>
Operating revenues 1,755 1,657 1,691 1,915 2,061
======= ======= ====== ======= ======
Total revenues 2,228 1,793 1,942 2,103 2,389
======= ======= ====== ======= =======
Net loss (1,461) (1,162) (1,210) (977) (613)
======== ======== ======== ======== =========
Net loss per share (.11) (.09) (.10) (.08) (.05)
========= ========= ========= ======== ==========
Working capital 8,403 1,510 2,417 3,890 3,750
======= ======= ====== ======= ======
Total assets 20,375 12,380 13,390 14,484 14,104
====== ======= ====== ====== ======
Shareholders' Equity:
Capital stock 38,888 29,635 29,513 29,513 28,739
Deficit (19,385) (17,923) (16,762) (15,552) (14,999)
-------- -------- -------- -------- --------
19,503 11,712 12,751 13,961 13,740
======= ======= ====== ====== ======
Average number of
shares outstanding 13,362 12,622 12,613 12,453 12,363
======= ======= ====== ====== ======
Exchange rates:
Year-end .7297 .7329 .7129 .7554 .7801
===== ===== ===== ===== =====
Average for the period .7335 .7289 .7324 .7757 .8013
===== ===== ===== ===== =====
Range .7234-.7520 .7026-.7480 .7098-7634 .7436-.8045 .7768-.8458
</TABLE>
U.S. GAAP Information
Under U.S. generally accepted accounting principles ("GAAP"), the above selected
information would be as follows (See Note 6 in Notes to Consolidated Financial
Statements):
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
Net loss (1,236) (1,001) (1,140) (673) (613)
======= ======= ======== ===== =====
Net loss per share (.09) (.08) (.09) .05 (.05)
===== ===== ===== === =====
</TABLE>
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.
(1) Liquidity and Capital Resources.
At December 31, 1996, the Company had approximately $8.4 million of
cash and securities available. These funds are expected to be used for general
corporate purposes, including exploration and development and to continue the
Kotaneelee field litigation.
Cash flow used in operations during 1996 decreased to $775,000 compared
to $783,000 during the 1995 period. The $8,000 difference between the periods
was caused primarily by the following:
Increase in loss from operations $217,000
Increase in accounts receivable 220,000
Increase in accounts payable and accrued liabilities (247,000)
Decrease in prepaid insurance and deferred costs (198,000)
---------
Difference in net cash used in operations $ (8,000)
===========
A significant proportion of the Company's property interests are
covered by carried interest agreements, which provide that expenditures made by
the operator are recouped solely out of revenues from production. Major capital
expenditures made by the operators have an impact on the Company's cash flow
from operations as no revenues are reported or received until the capital costs
have been recovered by the operator. Properties in the Fort Nelson, British
Columbia area in which the Company has carried interests have reached payout
status. Proceeds from these carried interests plus oil and gas sales from
working interest properties are the Company's major sources of working capital.
During 1996, however, capital expenditures in the Fort Nelson area resulted in a
temporary suspension of carried interest revenue.
The Company is currently evaluating and expects to continue to evaluate
oil and gas properties and may make investments in such properties utilizing
cash on hand. The Company anticipates that its capital expenditures for land
acquisitions and drilling for the year 1997 will be approximately $2,300,000.
The $1,110,000 increase in net cash used in investing activities during the 1996
period compared to the 1995 period reflects the Company's effort to expand its
oil and gas exploration program. In addition, substantial continuing expenses
are expected to be incurred in connection with the Kotaneelee Litigation. The
expense of the Kotaneelee Litigation has been the principal cause of the
Company's losses since 1991.
The Company has established a reserve for its potential share of future
site restoration costs. The estimated amount of these costs, which total
$728,000, is being provided on a unit of production basis in accordance with
existing legislation and industry practice.
(2) Results of Operations.
1996 vs. 1995
The net loss for the year 1996 was $1,461,283, ($.11 per share)
compared to a net loss of $1,161,763 ($.09 per share) for the 1995 period.
A summary of revenue and expenses during the periods is as follows:
1996 1995 Net Change
---- ---- ----------
Revenues $2,228,393 $1,793,112 $435,281
Costs and expenses 3,689,676 2,954,875 734,801
--------- --------- --------
Net loss $(1,461,283) $(1,161,763) $(299,520)
============ ============ ==========
Oil sales increased by 38% due primarily to a 14% increase in the
average price of oil sold with an 18% increase in production. There was also a
13% increase in royalties paid. Oil unit sales in barrels ("bbls") (before
deducting royalties) and the average price per barrel sold during the periods
indicated were as follows:
<TABLE>
<CAPTION>
1996 1995
----- ----
Average price Average price
bbls per bbl Total bbls per bbl Total
<S> <C> <C> <C> <C> <C> <C>
Oil sales 34,565 $25.47 $880,000 29,198 $22.39 $654,000
Royalties paid (111,000) (98,000)
--------- ----------
Total $769,000 $556,000
======== ========
</TABLE>
<PAGE>
Gas sales increased 8%. There was a 26% increase in the average price
for gas which was partially offset by a 22% decrease in units sold. In addition,
gas sales include royalty income which increased 17% in 1996. The volumes in
million cubic feet ("mmcf") and the average price of gas per thousand cubic feet
("mcf") sold during the periods indicated were as follows:
<TABLE>
<CAPTION>
1996 1995
----- ----
Average price Average price
mmcf per mcf Total mmcf per mcf Total
<S> <C> <C> <C> <C> <C> <C>
Gas sales 197 $1.64 $323,000 252 $1.30 $327,000
Royalty income 108,000 92,000
Royalties paid (36,000) (52,000)
--------- ---------
Total $395,000 $367,000
======== ========
</TABLE>
Proceeds under carried interest agreements decreased 20% to $591,000
during 1996 compared to $734,000 in 1995. The operator of the Company's carried
interest properties increased its development activities during late 1996,
thereby incurring additional expenses. Proceeds under carried interest
agreements are derived from gross production revenues after payout of these
expenses.
Interest and other income was 247% higher in 1996. Interest income
increased from $90,000 to $258,000 in 1996 due to the increase in funds
available for investment from the June 1996 rights offering to shareholders. In
addition, the 1996 period includes proceeds from the sale of seismic data in the
amount of $215,000 compared to $46,000 in 1995.
General and administrative costs decreased 10% in 1996 to $895,000 from
$988,000 in 1995. The 1995 period included higher salary expenses related to
retired personnel. In addition, accounting and administrative expenses also
decreased in 1996 due to cost reduction efforts.
Lease operating costs decreased 5% from $504,000 to $477,000 in 1996.
The decrease represents lower charges by the operators of the Company's
properties during 1996.
Legal expenses increased 83% to $1,610,000 from $880,000 in 1995. These
expenses are related primarily to the cost of the Kotaneelee litigation which
increased as a result of trial preparation and the actual costs of the trial
which began on September 3, 1996.
Depletion, depreciation and amortization expense increased 31% in 1996
to $655,000 from $500,000 in 1995. The increase in depletion is the result of a
decrease in gas reserves and an increase in estimated capital costs.
<PAGE>
Provision for restoration costs increased to $24,600 in 1996 compared
to $16,800 in 1995. During 1996, a charge of $81,000 was made to the future site
restoration costs account for certain abandonments costs. The Company has
re-evaluated its potential liability and accordingly increased its provision for
restoration costs.
A foreign exchange gain of $25,000 was recorded in 1996, contrasted
with a loss of $14,000 on the Company's U.S. investments in 1995. In 1996, the
gain was attributable to a strengthening of the U.S. dollar as compared to the
Canadian dollar on the Company's U.S. investments.
Income taxes. No provision for income taxes is required for the current
period.
Fiscal Year Ended December 31, 1995 vs. 1994
The net loss for the year 1995 was $1,161,763, ($.09 per share)
compared to a net loss of $1,210,109 ($.10 per share) for the 1994 period. A
summary of revenue and expenses during the periods is as follows:
1995 1994 Net Change
---- ---- ----------
Revenues $1,793,112 $1,942,289 $(149,177)
Costs and expenses 2,954,875 3,152,398 197,523
--------- --------- ---------
Net loss $(1,161,763) $(1,210,109) $ 48,346
============ ============ ==========
Oil sales increased by 2% due primarily to a 17% increase in the
average price of oil sold which offset a 16% decrease in production. There was
also a 16% decrease in royalties paid. Oil unit sales in barrels ("bbls")
(before deducting royalties) and the average price per barrel sold during the
periods indicated were as follows:
<TABLE>
<CAPTION>
1995 1994
----- ----
Average price Average price
bbls per bbl Total bbls per bbl Total
<S> <C> <C> <C> <C> <C> <C>
29,198 $22.39 $654,000 34,711 $19.14 $664,000
Royalties paid (98,000) (116,000)
---------- ---------
Total $556,000 $548,000
======== ========
</TABLE>
<PAGE>
Gas sales decreased 25%. There was a 29% decrease in the average price
for gas which was partially offset by a 8% increase in units sold. In addition,
gas sales includes royalty income which decreased 31% in 1995. The volumes in
million cubic feet ("mmcf") and the average price of gas per thousand cubic feet
("mcf") sold during the periods indicated were as follows:
<TABLE>
<CAPTION>
1995 1994
----- ----
Average price Average price
mmcf per mcf Total mmcf per mcf Total
<S> <C> <C> <C> <C> <C> <C>
Gas sales 252 $1.30 $327,000 234 $1.84 $431,000
Royalty income 92,000 134,000
Royalties paid (52,000) (78,000)
--------- ---------
Total $367,000 $487,000
======== ========
</TABLE>
Proceeds under carried interest agreements increased 12% to $734,066
during 1995 compared to $656,303 in 1994. The operator of the Company's carried
interest properties significantly increased its development activities during
the late 1994 and early 1995, thereby incurring additional expenses. Proceeds
under carried interest agreements are derived from gross production revenues
after payout of these expenses. The latter part of 1995 benefited from these
development activities by increased production.
Interest and other income was 46% lower in 1995. Interest income was
lower in 1995 due to the decrease in funds available to invest during 1995
compared to the prior year. In addition, 1995 includes proceeds from the sale of
seismic data in the amount of $46,124 compared to $125,368 in 1994.
General and administrative costs decreased 18% in 1995. The 1994 period
included the additional expenses of the Special Meeting of Shareholders held in
July 1994 and associated costs. The 1994 period also included higher salary
expenses related to retired personnel.
Legal expenses were 5% lower in 1995 compared to the prior year. These
expenses are related primarily to the Kotaneelee litigation in which discovery
is now substantially complete. These expenses are expected to increase in 1996
as a result of trial preparation and the conduct of the trial scheduled to
commence on September 3, 1996.
Depletion, depreciation and amortization expense was 13% higher in 1995
due to an increase in estimated future capital costs to develop existing
reserves.
<PAGE>
A foreign exchange loss of $13,915 was recorded in 1995, contrasted
with a gain of $57,791 on U.S. cash investments in 1994. During 1995, the
Company had a minimal amount invested in the United States. In 1994, the
significant gain was attributable to a strengthening of the U.S. dollar as
compared to the Canadian dollar on the Company's U.S. investments.
Provision for restoration costs decreased to $16,800 in 1995 compared
to $76,656 in 1994. The Company has re-evaluated its potential liability and
accordingly reduced its provision for restoration costs.
Rent expense was 7% lower in the 1995 period as a result of lower pass-
through operating costs under the lease.
Income taxes. No provision for income taxes was required for 1995.
<PAGE>
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT AUDITORS
To the Shareholders of
Canada Southern Petroleum Ltd.
We have audited the accompanying consolidated balance sheets of Canada Southern
Petroleum Ltd. as at December 31, 1996 and 1995, and the consolidated statements
of operations and deficit, cash flows and limited voting shares and contributed
surplus for each of the years in the three year period ended December 31, 1996.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Canada Southern
Petroleum Ltd. as at December 31, 1996 and 1995 and the results of its
operations and the changes in its financial position for each of the years in
the three year period ended December 31, 1996, in accordance with accounting
principles generally accepted in Canada.
Calgary, Canada ERNST & YOUNG
March 6, 1997 Chartered Accountants
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
(Incorporated under the laws of Nova Scotia)
CONSOLIDATED BALANCE SHEETS
(Expressed in Canadian dollars)
<TABLE>
<CAPTION>
December 31, December 31,
1996 1995
----- ----
Assets
<S> <C> <C>
Cash and cash equivalents (Note 2) $2,709,597 $ 1,181,581
U.S. Government securities (Note 3) 3,404,213 -
Accounts and interest receivable 635,223 350,598
Prepaid insurance and other 227,368 226,539
Other - 112,903
----------- -------------
Total current assets 6,976,401 1,871,621
---------- ------------
U.S. Government securities (Note 3) 2,048,573 -
--------- -------------
Oil and gas properties and equipment
(full cost method) (Note 4) 11,349,945 10,508,619
---------- ----------
$20,374,919 $12,380,240
=========== ===========
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable $ 439,837 $ 125,509
Accrued liabilities (Note 10) 182,104 236,332
------------ -------------
Total current liabilities 621,941 361,841
------------ -------------
Future site restoration costs 250,274 306,728
------------ -------------
Contingencies (Notes 8 and 11) - -
Shareholders' Equity
Limited Voting Shares, par value
$1 per share (Note 5)
Authorized - 100,000,000 shares
Outstanding -13,956,540 (1995 - 12,645,791) shares 13,956,540 12,645,791
Contributed surplus 24,930,964 16,989,397
---------- -----------
38,887,504 29,635,188
---------- ----------
Deficit (19,384,800) (17,923,517)
------------ ------------
Total shareholders' equity 19,502,704 11,711,671
----------- -----------
$20,374,919 $12,380,240
=========== ===========
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
Consolidated Statements of Operations and Deficit
(Expressed in Canadian dollars)
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
----- ----- ----
<S> <C> <C> <C>
Revenues:
Oil sales $ 768,576 $ 555,894 $ 547,509
Gas sales 395,068 366,700 486,764
Proceeds under carried
interest agreements 590,935 734,066 656,303
Interest and other income 473,814 136,452 251,713
----------- ----------- ------------
2,228,393 1,793,112 1,942,289
---------- ---------- ----------
Costs and expenses:
General and administrative 894,766 988,395 1,204,565
Legal (Note 9) 1,610,477 879,821 928,560
Lease operating costs 476,562 503,648 502,452
Depletion, depreciation,
and amortization 654,982 499,630 441,033
Foreign exchange
(gains) (24,693) 13,915 (57,791)
Provision for future site
restoration costs 24,600 16,800 76,656
Rent 52,982 52,666 56,923
----------- ------------ ------------
3,689,676 2,954,875 3,152,398
Loss before income taxes (1,461,283) (1,161,763) (1,210,109)
Income taxes (Note 6) - - -
---------------- ---------------- ----------------
Net loss (1,461,283) (1,161,763) (1,210,109)
Deficit - beginning of period (17,923,517) (16,761,754) (15,551,645)
------------- ------------- -------------
Deficit - end of period $(19,384,800) $(17,923,517) $(16,761,754)
============= ============= =============
Average number of shares
outstanding 13,362,410 12,621,560 12,612,791
========== ========== ===========
Net loss per share $(.11) $(.09) $(.10)
====== ====== ======
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
Consolidated Statements of Cash Flows
(Expressed in Canadian dollars)
<TABLE>
<CAPTION>
Year ended
December 31,
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Cash flows from operating activities:
Net loss $(1,461,283) $(1,161,763) $(1,210,109)
Adjustments to reconcile net loss
to net cash provided by
(used in) operating activity:
Depreciation, depletion and
amortization 654,982 499,630 441,033
Future site restoration costs (net) (56,454) 16,800 76,656
Change in assets and liabilities:
Accounts and interest receivable (284,625) (64,491) 143,390
Prepaid insurance and other 112,074 (85,775) (40,034)
Accounts payable 314,328 (38,583) (27,797)
Accrued liabilities (54,228) 51,620 67,723
----------- ---------- -----------
Net cash used in operations (775,206) (782,562) (549,138)
---------- ---------- -----------
Cash flows from investing activities:
Additions to oil and gas properties (net) (1,496,308) (383,519) (1,090,969)
U.S. Government securities purchased (5,452,786) - -
Repayments of loans due Company - - 310,000
------------ ------------ ------------
Net cash used in investing activities (6,949,094 (383,519) (780,969)
---------- ---------- ------------
Cash flows from Financing Activities:
Sale of common stock less expenses 9,019,609 - -
Exercise of stock options 232,707 121,780 -
---------- --------- ----------------
Net cash from financing activities 9,252,316 121,780 -
--------- --------- ----------------
Increase (decrease) in cash
and cash equivalents 1,528,016 (1,044,301) (1,330,107)
Cash and cash equivalents at the
beginning of period 1,181,581 2,225,882 3,555,989
--------- --------- ---------
Cash and cash equivalents at the
end of period (Note 2) $2,709,597 $1,181,581 $2,225,882
========== ========== ==========
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF LIMITED VOTING SHARES
AND CONTRIBUTED SURPLUS
(Expressed in Canadian dollars)
<TABLE>
<CAPTION>
Limited
Number Voting Shares Contributed
of shares $1 par value surplus Total
--------- ------------ ------- -----
<S> <C> <C> <C> <C>
Balance at December 31, 1993 and
1994 12,612,791 12,612,791 16,900,617 29,513,408
Exercise of stock options 33,000 33,000 88,780 121,780
---------- ------------- ------------- -------------
Balance at December 31, 1995 12,645,791 $12,645,791 $16,989,397 $29,635,188
Sale of common stock 1,268,549 1,268,549 7,751,060 9,019,609
Exercise of stock options 42,200 42,200 190,507 232,707
------ ------------ ------------ -------------
Balance at December 31, 1996 $13,956,540 $13,956,540 $24,930,964 $38,887,504
=========== =========== =========== ===========
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in Canadian dollars)
December 31, 1996
1. Summary of significant accounting policies
Accounting principles
The Company prepares its accounts in accordance with accounting
principles generally accepted in Canada which, except as described in Note 6,
conform in all material respects with United States generally accepted
accounting principles ("U.S.
GAAP").
Consolidation
The consolidated financial statements include the accounts of Canada
Southern Petroleum Ltd. and its wholly-owned subsidiaries, Canpet Inc. and C.S.
Petroleum Limited.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the amounts reported in the financial statements and
accompanying notes. Actual results could differ from those estimates.
Cash and cash equivalents
For the purposes of the statement of cash flows, the Company considers
all highly liquid investments with a maturity of three months or less to be cash
equivalents.
Oil and gas properties and equipment
The Company, which is engaged primarily in one industry, the
exploration for and the development of oil and gas properties, principally in
Canada, follows the full cost method of accounting for oil and gas properties,
whereby all costs associated with the exploration for and the development of oil
and gas reserves are capitalized.
The Company periodically reviews the costs associated with undeveloped
properties and mineral rights to determine whether they are likely to be
recovered. When such costs are not likely to be recovered, such costs are
transferred to the depletable pool of oil and gas costs.
<PAGE>
1. Summary of significant accounting policies (Cont'd)
The net carrying cost of the Company's oil and gas properties in
producing cost centers is limited to an estimated recoverable amount. This
amount is the aggregate of future net revenues from proved reserves and the
costs of undeveloped properties, net of impairment allowances, less future
general and administrative costs, financing costs and income taxes. Future net
revenues are calculated using year end prices that are not escalated or
discounted.
The costs of the Company's 30% carried interest in the Kotaneelee gas
field are included in oil and gas properties and in the cost center for the
purpose of computing depletion. In addition, the Company's share of estimated
net reserves after payout are also included in the proved oil and gas reserves
base for the purpose of computing depletion. However, no revenue production data
will be reported for financial statement purposes until the Company is entitled
to participate in the field's revenue after payout status is achieved.
Gains or losses are not recognized upon disposition of oil and gas
properties unless crediting the proceeds against accumulated costs would result
in a change in the rate of depletion of 20% or more.
Depletion is provided on costs accumulated in producing cost centers
including well equipment using the unit of production method. For purposes of
the depletion calculation, gross proved oil and gas reserves as determined by
outside consultants are converted to a common unit of measure on the basis of
their approximate relative energy content.
Depreciation has been computed for equipment, other than well
equipment, on the straight-line method based on estimated useful lives of four
to ten years.
Substantially all of the Company's exploration and development
activities related to oil and gas are conducted jointly with others and
accordingly the consolidated financial statements reflect only the Company's
proportionate interest in such activities.
Revenue recognition
The Company recognizes revenue on its working interest properties from
the production of oil and gas in the period the oil and gas are sold.
Revenue under carried interest agreements is recorded in the period
when the proceeds become receivable. The Company is entitled to participate in
oil and gas net revenues after the repayment of exploration, drilling and
completion expenses to the party or parties bearing these costs. The carried
interest accounts are subject to independent audits which are performed in
subsequent years. In the past, these audits have resulted in both positive and
negative adjustments. For these reasons, the proceeds under carried interest
agreements may fluctuate each year depending on both capital expenditures and
any audit adjustments.
<PAGE>
1. Summary of significant accounting policies (Cont'd)
Earnings per share
Earnings per limited voting share is based upon the weighted average of
shares outstanding during the period. Primary and fully diluted earnings per
share are the same.
Future site restoration costs
Estimated future site restoration costs which are estimated to be
$728,000 are being provided on a unit of production basis. The provision is
based on current costs of complying with existing legislation and industry
practice for site restoration and abandonment. At December 31, 1996,
approximately $478,000 in such costs have not been accrued.
Deferred income taxes
The Company follows the deferral method of tax allocation accounting
whereby the income tax provision is based on pre-tax income reported in the
accounts. Under this method, full provision is made for deferred income taxes
resulting from claiming deductions at the rates permitted by income tax
legislation, which may differ from those used in the accounts.
Foreign currency translation
Transactions for settlement in U.S. dollars have been translated at
average monthly exchange rates. Assets and liabilities in U.S. dollars have
been translated at the year end exchange rates. Exchange gains or losses
resulting from these adjustments are included in costs and expenses.
2. Cash and cash equivalents
The Company considers all highly liquid short term investments with
maturities of three months or less at date of acquisition to be cash
equivalents. Cash equivalents are carried at cost which approximates market
value.
1996 1995
------------ -----------
Cash $ 319,616 $ 326,031
Canadian bankers acceptances (2.65%) 1,441,170 855,550
U.S. Treasury Bills (4.75%) 948,811 -
----------- -----------
$2,709,597 $1,181,581
========== ==========
<PAGE>
3. U.S. Government Securities
At December 31,1996, the Company has the following amounts invested in
U.S. government securities which are expected to be held until maturity:
<TABLE>
<CAPTION>
Amortized
Security Par value Maturity Date Cost Fair value
-------- --------- ------------- ---- ----------
<S> <C> <C> <C> <C>
U.S. Treasury Bill $ 822,256 Mar. 27, 1997 $ 801,637 $ 812,570
U.S. Treasury Bill 685,213 Apr. 3, 1997 657,599 676,271
U.S. Treasury Bill 2,055,639 Jun. 26, 1997 1,944,977 2,004,289
--------- --------- ---------
Total short term 3,563,108 3,404,213 3,493,130
--------- --------- ---------
U.S. Treasury Bill 2,055,639 Jun. 26, 1998 2,048,573 2,056,914
--------- --------- ---------
Total $5,618,747 $5,452,786 $5,550,044
========== ========== ==========
</TABLE>
4. Oil and gas properties and equipment
<TABLE>
<CAPTION>
Accumulated
Provisions and Net Book
Cost Writedowns Value
<S> <C> <C> <C>
Balance December 31, 1996
Oil and gas properties-developed $18,555,130 $7,227,874 $11,327,256
Oil and gas properties-undeveloped 1 - 1
Seismic data 112,000 112,000
----------- ------------ -------------
-
18,667,131 7,339,874 11,327,257
Equipment 62,172 39,484 22,688
------------ ------------ -------------
$18,729,303 $7,379,358 $11,349,945
=========== ========== ===========
Balance December 31, 1995
Oil and gas properties - developed $17,069,321 $6,590,176 $10,479,145
Oil and gas properties - undeveloped 1 - 1
Seismic data 112,000 104,508 7,492
----------- ------------ --------------
17,181,322 6,694,684 10,486,638
Equipment 57,865 35,884 21,981
------------ ------------ -------------
$17,239,187 $6,730,568 $10,508,619
=========== ========== ===========
</TABLE>
Substantially all gas sales were made to CanWest Gas Supply Inc. and
oil sales were made to Canadian Natural Resources Ltd.
5. Limited voting shares and stock options
The Memorandum of Association (Articles of Continuance) of the Company
provides that no person (as defined) shall vote more than 1,000 shares.
5. Limited voting shares and stock options (Cont'd)
Under the terms of the Company's 1985 and 1992 stock option plans, the
Company is authorized to grant certain key employees and consultants options to
purchase limited voting shares at prices based on the market price of the shares
as determined on the date of the grant. The options are exercisable for five
years from the date of grant.
On June 24, 1996, the Company concluded its offering of approximately
1.3 million shares to its shareholders at $7.50 per share. The offering was
oversubscribed and the proceeds to the Company were $9,019,609 after deducting
the $494,509 cost of the offering.
Following is a summary of option transactions which reflects
adjustments of the stock option prices and the number of shares subject to stock
options as discussed above:
Options outstanding Number of shares Option Prices
($)
December 31, 1993 159,700 3.45 - 4.06
Granted 335,000 7.00
-------
December 31, 1994 494,700 3.45 - 7.00
Exercised (33,000) 3.45 - 4.06
----------
December 31, 1995 461,700
=======
Canceled (137,000) 3.45 - 7.00
Exercised (42,200) 3.45 - 8.75
Granted 150,700 3.15 - 6.37
Granted 12,500 8.75
---------
December 31, 1996 445,700
=======
Options reserved for future grants 212,134
On July 8, 1996, 137,000 options to purchase limited voting shares of
the Company which were previously granted were canceled and reissued to reflect
the June 1996 rights offering.
For U.S. GAAP, the Company has elected to follow Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB No. 25)
and related interpretations in accounting for its stock options because the
alternative fair value accounting provided under FASB Statement No. 123,
"Accounting for Stock Based Compensation," requires use of option valuation
models that were not developed for use in valuing stock options. Under APB No.
25, because the exercise price of the Company's stock options equals the market
price of the underlying stock on the date of grant, no compensation expense is
recognized.
<PAGE>
5. Limited voting shares and stock options (Cont'd)
Pro forma information regarding net income and earnings per share is
required by Statement 123, and has been determined as if the Company had
accounted for its stock options under the fair value method of that Statement.
The fair value for these options was estimated at the date of grant using a
Black-Scholes option pricing model.
Option valuation models require that input of highly subjective
assumptions including the expected stock price volatility. The assumptions used
in the valuation model were: risk free interest rate - 6.7%, expected life - 5
years and expected volatility - .396.
Because the Company's stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its stock options.
For the purpose of pro forma disclosures, the estimated fair value of
the stock options is expensed in the year of grant since the options are
immediately exercisable. The Company's pro forma information follows:
Amount Per Share
Net loss as reported - December 31, 1996 $(1,461,283) $(.11)
Stock option expense 49,373 -
------------- -----
Pro forma net loss $(1,510,656) $(.11)
============ ======
6. Income taxes
Income taxes vary from the amounts that would be computed by applying
the Canadian federal and provincial income tax rates as follows:
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
---- ---- ----
44.84% 44.84% 44.84%
====== ====== ======
<S> <C> <C> <C>
Provision for income taxes based on combined basic
Canadian federal and provincial income tax $(577,532) $(520,935) $(542,614)
Nondeductible crown charges 61,599 60,354 72,577
Other 478 948 1,707
Unrealized tax loss 515,455 459,633 468,330
-------- -------- -------
Actual provision for income taxes $ - $ - $ -
========= ========= =========
</TABLE>
At December 31, 1996, the Company had net operating losses for income
tax purposes of approximately $3,217,000 which are available to be carried
forward to future periods. These losses expire in the following years: 1998 -
$563,000, 1999 - $194,000, 2000 - $294,000, 2001 - $545,000, 2002 - $569,000 and
2003 - $1,052,000.
<PAGE>
6. Income taxes (Cont'd)
At December 31, 1996, the following oil and gas tax deductions are
available to reduce future taxable income, subject to a final determination by
taxation authorities.
Drilling, exploration and lease acquisition costs $11,103,000
Earned depletion 1,975,000
Undepreciated capital costs 1,463,000
Cumulative eligible capital losses 407,000
Share issue costs 495,000
The tax benefits attributable to the above accumulated expenditures
will not be reflected in the consolidated financial statements until such
benefits are realized.
Under U.S. GAAP, the provisions for income taxes would have differed
for the reasons set out below:
In February 1992, the United States Financial Accounting Standards
Board issued Statement No. 109, "Accounting for Income Taxes", effective for
fiscal years beginning after December 15, 1993. Under U.S. GAAP, the Company
would have been required to adopt Statement No. 109 commencing July 1, 1993.
Under Statement No. 109, the liability method is used in accounting for
income taxes. Under this method, deferred tax assets and liabilities are
determined based on differences between financial reporting and tax bases of
assets and liabilities and are measured using the enacted tax rates and laws
that will be in effect when the differences are expected to reverse. Under
Canadian GAAP and previously under U.S. GAAP, income tax expense is determined
using the deferral method. Deferred tax expense is based on items of income and
expense that are reported in different years in the financial statements and tax
returns and are measured at the tax rate in effect in the year the differences
originated.
The following schedule summarized the Company's income tax expense and
deferred tax liability under U.S. GAAP. If Statement No. 109 was adopted, the
Company would have had a deferred tax asset which primarily represents the
excess of available resource deductions for income tax purposes over the
recorded value of oil and gas properties together with operating and capital
income tax loss carryforwards. These amounts are expected to be recovered from
the production of current oil and gas reserves when the Kotaneelee litigation
expenditures have ended. As certain of the resource deductions are restricted
and the operating loss carryforwards are subject to expiration, there is
considerable risk that certain of these deductions will not be utilized.
Accordingly, the Company would have established a valuation allowance to
recognize this uncertainty. Income taxes computed in accordance with U.S. GAAP,
would have resulted in a credit to the provision of taxes.
<PAGE>
6. Income taxes (Cont'd)
December 31,
1996 1995 1994
---- ---- ----
Deferred tax asset $3,233,506 $2,351,550 $2,169,085
Valuation reserve (2,473,526) (1,816,792) (1,795,307)
----------- ----------- -----------
Net deferred tax asset $ 759,980 $ 534,758 $ 373,778
------- ======= =======
Deferred tax recovery $ 225,222 $ 160,980 $ 69,995
======= ======= ======
Net loss under U.S. GAAP, in total, and per share based on average
number of shares outstanding during the periods shown is as follows:
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Net loss under Canadian GAAP before income taxes $(1,461,283) $(1,161,763) $(1,210,109)
Income tax adjustment 225,222 160,980 69,995
------------ ------------ -------------
Net loss under U.S. GAAP $(1,236,061) (1,000,783) $(1,140,114)
============ =========== ============
Per Share Basis:
Net loss under Canadian GAAP before income taxes $(.11) $(.09) $(.10)
Income tax adjustment .02 .01 .01
--- --- --- --- --- ---
Net loss under U.S. GAAP $(.09) $(.08) $(.09)
====== ====== ======
</TABLE>
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in Canadian dollars)
December 31, 1996
The deficit under U.S. GAAP would have been $18,624,820 and
$17,388,759 at December 31, 1996 and 1995, respectively.
7. Line of credit
The Company has a line of credit with a Canadian chartered bank which
provides for a loan of $500,000. The line of credit provides for a $125,000
operating loan and $375,000 for letters of credit as part of the directors'
indemnification agreements. The interest rate on borrowing is at 3/4% above the
bank's prime lending rate. The line of credit is subject to annual review and is
secured by a general assignment of accounts receivable and an undertaking to
provide security in the form of assignment of future working interest proceeds.
No drawings were made under this line during 1996 or 1995.
8. Litigation
The Company, which has a 30% interest in the Kotaneelee gas field,
believes that the working interest owners in the field have not adequately
pursued the attainment of contracts for the sale of Kotaneelee gas. In October
1989 and in March 1990, the Company filed statements of claim in the Court of
Queens Bench of Alberta, Judicial District of Calgary, Canada, against the
working interest partners in the Kotaneelee gas field. The named defendants were
Amoco Canada Petroleum Corporation, Ltd., Dome Petroleum Limited (now Amoco
Canada Resources Ltd.), and Amoco Production Company (collectively the "Amoco
Dome Group"), Columbia Gas Development of Canada Ltd. ("Columbia"), Mobil Oil
Canada Ltd. ("Mobil") and Esso Resource of Canada Ltd. ("Esso") (collectively
the "Defendants").
The Company claims that the Defendants breached either a contract
obligation or a fiduciary duty owed to the Company to market gas from the
Kotaneelee gas field when it was possible to so do. The Company asserts that
marketing the Kotaneelee gas was possible in 1984 and that the Defendants
deliberately failed to do so. The Company seeks money damages and the forfeiture
of the Kotaneelee gas field. The Company expects to argue at trial that the
money damages sustained by the Company are at least $86 million.
In addition, the Company has claimed that the Company's carried
interest account should be reduced because of the negligent operation of the
field and improper charges to the carried interest account by the Defendants.
The Company claims that when the Defendants in 1980 suspended production from
the field's gas wells, they failed to take precautionary measures necessary to
protect and maintain the wells in good operating condition. The wells thereafter
deteriorated, which caused unnecessary expenditures to be incurred, including
expenditures to redrill one well. In addition, the Company claims that
expenditures made to repair and rebuild the field's dehydration plant should not
have been necessary had the facilities been properly constructed and maintained
by the Defendants. The expenditures, the Company claims, were inappropriately
charged to the field's carried interest account. The effect of an increased
carried interest account is to extend the period before payout begins to the
carried interest account owners.
The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million. The Company claims that by 1993 at least $34 million of unnecessary
expenses had been wrongfully charged to the carried interest account. The
Company's 30% share of these expenses would be approximately $10.2 million. The
Company further claims that if production had commenced in 1984, the carried
interest account would have been paid off in approximately two years and the
Company would have begun to receive revenues from the field in 1986. At present,
the Company does not expect to receive revenues before 1999 based on a price of
$1.34 per mcf (average 1996 price) and current production rates.
Columbia has filed a counterclaim against the Company seeking, if the
Company is successful in its claim for the forfeiture of the field, repayment
from the Company of all sums Columbia has expended on the Kotaneelee lands
before the Company is entitled to its interest.
<PAGE>
8. Litigation (Cont'd)
The parties to the litigation have conducted extensive discovery since
the filing of the claims. The trial began on September 3, 1996. The trial was
suspended after approximately three weeks of testimony pending resolution of the
Company's motion to disqualify Amoco's litigation counsel on the basis that a
partner in the firm representing Amoco had served as the Company's Canadian
securities counsel for many years. The Company's motion was denied and the
denial was upheld on appeal. The Company has filed with the Supreme Court of
Canada an application for leave to appeal that decision. The parties have agreed
to expedite the application and a decision whether the Supreme Court will review
the decision is expected by the end of April. If the Supreme Court refuses to
hear the case, trial is expected to resume on May 5, 1997.
Matters Ancillary to Kotaneelee Litigation
In its 1989 statement of claim, the Company sought a declaratory
judgment regarding two issues:
(1) whether interest accrued on the carried interest account; and
(2) whether expenditures for gathering lines and dehydration
equipment are expenditures chargeable to the carried interest
account or whether the Company will be assessed a processing
fee on gas throughput.
With respect to the first issue, the Company maintains that no interest
should accrue on the account and the Defendants have not contested this
position. With regard to the second issue, the Company maintains that the
expenditures are chargeable to the carried interest account. Mobil, Esso and
Columbia have essentially agreed to the Company's position while the Amoco Dome
Group continues to contest this issue.
On January 22, 1996, the Company settled two claims outstanding against
the Company in the Court of Queens Bench, Calgary, Alberta, which related to a
suit brought against AlliedSignal Inc. ("AlliedSignal") in Florida which was
dismissed on the basis that Canada was the appropriate forum for the litigation.
AlliedSignal had sought additional relief against the Company in Canada to
preclude other types of suits by the Company and to recover the costs of the
defense of the initial action. The settlement bars Allied Signal from making a
claim against the Company for any costs in connection with the Kotaneelee
Litigation. The Company agreed not to bring any action against AlliedSignal in
connection with the Kotaneelee gas field. Neither party made any monetary
payment to the other party.
In 1991, Anderson Exploration Ltd. acquired all of the shares in
Columbia and changed its name to Anderson Oil & Gas Inc. ("Anderson"). Anderson
is now the sole operator of the field and is a direct defendant in the Canada
Court lawsuits. Columbia's previous parent, The Columbia Gas System, Inc., which
was reorganized in a bankruptcy proceeding in the United States, is
contractually liable to Anderson in the legal proceeding described above.
<PAGE>
8. Litigation (Cont'd)
The working interest owners have reported that they have been selling
Kotaneelee gas since February 1991.
Under Canadian law certain costs of the litigation are assessed against
the nonprevailing party. These costs consist primarily of attorney's and expert
witness fees during trial. The trial is presently scheduled to last twelve
months, therefore, these costs could be substantial. While the costs are not now
determinable, the Company estimates that such costs, assuming a twelve month
trial, could be approximately $1.5 million. However, a judge in complex and
lengthy trials has the discretion to double an award of costs. There are no
assurances however, that such costs will not exceed this amount or that the
duration of the trial will not exceed twelve months.
There is no assurance that the Company will be successful on the
merits of its claims, which have been vigorously defended by the Defendants.
There is also no assurance that the Company will be awarded any damages, or
that, if damages are awarded, the Court will apply the measure of damages the
Company claims should be applied.
9. Related party transactions
Fees paid or accrued for legal services rendered to the Company by
Reasoner, Davis & Fox, (of which firm Mr. C. Dean Reasoner, a director of the
Company, is a partner,) were U.S. $111,000, $133,000 and $111,000 for the years
1996, 1995 and 1994, respectively. Mr. Reasoner resigned as a director on
March 11, 1997.
In 1991, the Company granted interests to certain of its officers,
employees, directors, counsel and consultants amounting to an aggregate of 7.8%
of any and all benefits to the Company after expenses from the litigation in
Canada relating to the Kotaneelee gas field. The Company has reserved a 2.2%
interest in such net benefits for possible future grants to persons who may
include officers and directors of the Company.
Directors Heath and Reasoner have royalty interests in certain of the
Company's oil and gas properties, (present and past) which were received
directly or indirectly through the Company. During the years 1996,1995 and 1994,
the Company and third-party operators and/or owners of properties made payments
pursuant to these royalties for the benefit of Mr. Reasoner and Mr. Heath in the
amounts of U.S. $5,342, $6,159 and $13,263 and U.S. $10,844, $12,777 and
$28,604, respectively.
<PAGE>
10. Other financial information
Accrued liabilities
1996 1995
---- ----
Accrued liabilities due to working
interest partners $ 12,050 $ 23,830
Accrued accounting and legal expenses 52,793 107,228
Accrued royalties 116,415 99,405
Other 846 5,869
---------- ----------
$182,104 $ 236,332
======== =========
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Royalty payments (1) $146,673 $150,224 $191,785
======== ======== ========
Interest payments (2) $ 7,099 $ 10,000 $ 10,746
========== ========= =========
Large corporation tax payments $ 2,741 $ 4,527 $ 7,740
========== ========== ==========
</TABLE>
- --------------------
(1) Oil and gas sales are reported net of royalties paid.
(2) Bank line of credit charges.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in Canadian dollars)
December 31, 1994
(Information for the year ended December 31, 1993 and
for the six months ended December 31, 1992 is unaudited)
11. Contingency
The operator of one of the Company's carried interest properties, which
includes approximately 36 wells, is claiming that certain payments made in 1995
and 1996 were outside the area of mutual interest. The Company is disputing the
claim of $319,000 at December 31, 1996 and a resolution of the claim is not
expected until an independent audit of the carried interest account is
completed. If it is subsequently determined that the operator's claim is valid,
then any overpayment will be recovered from the future revenues of these
properties.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
SUPPLEMENTAL INFORMATION ON OIL AND GAS ACTIVITIES
(unaudited)
The following information includes estimates which are subject to
rapid and unanticipated change. Therefore, these estimates may not accurately
reflect future net income to the Company.
The Company has no proved oil and gas reserves in Australia that
require disclosure under SEC regulations and no revenues from oil and gas
production in that country. All amounts below except for costs, acreage, wells
drilled and present activities relate to Canada. Oil and gas reserve data and
the information relating to cash flows were provided by Paddock Lindstrom &
Associates Ltd., independent consultants.
Estimated net quantities of proved oil and gas reserves:
Oil Gas
(bbls) (bcf)
Proved reserves:
December 31, 1993 441,000 33.831
Revisions of previous estimates 66,488 0.207
Production* (33,888) (1.081)
---------- --------
December 31, 1994 473,600 32.957
Revisions of previous estimates (157,908) 1.559
Production* (30,892) (1.311)
---------- --------
December 31,1995 284,800 33.205
Revisions of previous estimates 178,448 (2.655)
Production (37,448) (1.519)
-------- -------
December 1996 425,800 29.031
======= ======
Proved developed reserves:
December 31, 1994 473,600 32.957
======= ======
December 31, 1995 284,800 33.205
======= ======
December 31, 1996 358,400 28.265
======= ======
- -----------------
* Production data includes oil and gas sales and the proceeds from the
carried interest properties.
<PAGE>
Results of oil and gas operations:
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Income:
Oil and gas sales 1,163,644 $ 922,594 $1,034,273
Proceeds under carried
interest agreements 590,935 734,066 656,303
--------- ----------- -----------
1,754,579 1,656,660 1,690,576
--------- ---------- ----------
Costs and expenses:
Production costs 476,562 503,648 502,452
Depletion depreciation, and
amortization 654,982 499,630 441,033
Provision for future site
restoration costs 24,600 16,800 76,656
Income tax expense - - -
----------- ------------- ------------
1,156,144 1,020,078 1,020,141
--------- ----------- ----------
Net income from operations $ 598,453 $ 636,582 $ 670,435
========== ============= ===========
</TABLE>
Costs of oil and gas activities:
<TABLE>
<CAPTION>
Year ended
Year ended December 31,
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Acquisition costs $484,000 $ 49,000 $395,000
Exploration 146,000 92,000 253,000
Development 866,000 243,000 443,000
</TABLE>
Standardized measure of discounted future net cash flows relating to proved oil
and gas reserve quantities during the following period (in thousands of
dollars):
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Future cash inflows $ 49,410 $ 48,298 $56,981
Future development and
production costs (20,813) (18,473) (20,796)
--------- --------- ---------
28,597 29,825 36,185
Future income tax expense* (2,931) (4,218) (6,778)
---------- -------- ----------
Future net cash flows 25,666 25,607 29,407
10% annual discount (9,691) (10,679) (12,890)
---------- --------- --------
Standardized measure of
discounted future net
cash flows $ 15,975 $ 14,928 $16,517
======== ======== =======
</TABLE>
* Reflects tax benefit for the year ended December 31, 1996 and 1995, from
carryforward of exploration, development and lease acquisition costs,
undepreciated capital costs and book earned depletion of $17,032,000,
$13,679,000 and $13,520,000.
Current prices used in the foregoing estimates were based upon selling
prices at the wellhead in the last month of each fiscal period. Current costs
were based upon estimates made by consulting engineers at the end of each year.
<PAGE>
Changes in the standardized measure during the following periods (in thousands
of dollars):
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Changes due to:
Prices and production costs $3,248 $(88) $ (21)
Future development costs (1,049) 83 4
Sales net of production costs (1,330) (1,428) (1,188)
Development costs incurred
during the year 866 243 443
Net change due to extensions,
discoveries and improved
recovery 1,458 - 358
Revisions of quantity estimates (4,229) (3,404) (214)
Accretion of discount 1,660 1,927 1,832
Net change in income taxes 423 1,078 740
Other - - 141
-------- ---------- --------
Net change $1,047 $(1,589) $2,095
====== ======== ======
</TABLE>
<PAGE>
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.
None.
PART III
For information concerning Item 10 - Directors and Executive Officers
of the Company, Item 11 - Executive Compensation, Item 12 - Security Ownership
of Certain Beneficial Owners and Management and Item 13 - Certain Relationships
and Related Transactions, see the Proxy Statement of Canada Southern Petroleum
Ltd. relative to the Annual Meeting of Shareholders for the fiscal year ended
December 31, 1996, which will be filed with the Securities and Exchange
Commission, which information is incorporated herein by reference. For
information concerning Item 10 - Executive Officers of the Company, see Part I.
Mr. C. Dean Reasoner resigned as a Director of the Company for health-
related reasons on March 11, 1997. On March 13, 1997, Mr. Arthur B. O'Donnell,
a former vice president of the Company, was elected to complete Mr. Reasoner's
term as a director. Mr. O'Donnell, a CPA, has over 40 years experience in the
oil and gas business.
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) (1) Financial Statements.
The financial statements listed below and included under Item
8, above are filed as part of this report.
Page Reference
Report of Independent Auditors 36
Consolidated balance sheets at December 31, 1996
and 1995 37
For the years ended December 31, 1996, 1995 and 1994
Consolidated statements of operations and deficit 38
Consolidated statements of cash flows 39
Consolidated statements of Limited Voting
Shares and Contributed Surplus for the three years
ended December 31, 1996 40
Notes to consolidated financial statements 41-52
Supplementary information on oil and gas activities
(unaudited) 53
(2) Consolidated Financial Statement Schedules.
All schedules have been omitted since the required
information is not presen or not present in amounts sufficient to require
submission of the schedule, or because the information required is included
in the consolidated financial statements or the notes thereto.
(3) Exhibits.
The following exhibits are filed as part of this
report:
Item Number.
2. Plan of acquisition, arrangement, liquidation or
succession
None
<PAGE>
3. Articles of Incorporation and By-Laws.
Memorandum of Association as amended on June 30,
1982, May 14, 1985 and April 7, 1988 and Bye-laws, as
amended, filed as Exhibit 3 to Registration Statement
No. 33-99052 as filed on November 7, 1995.
4. Instruments defining the rights of security holders,
including indentures.
None.
9. Voting trust agreement.
None.
10. Material contracts.
(a) Agreements relating to Kotaneelee.
(1.) Copy of Agreement dated May 28, 1959 between
the Company et al. and Home Oil Company Limited et al
and Signal Oil and Gas Company filed as Exhibit
10(a)(1) to Registration Statement No. 33-99052 as
filed on November 7, 1995 is incorporated herein by
reference.
(2.) Copies of Supplementary Documents to May 28,
1959 Agreement (see (1) above), dated June 24, 1959,
consisting of Guarantee by Home Oil Company Limited
and Pipeline Promotion Agreement, filed as Exhibit
10(a)(2) to Registration Statement No. 33-99052 as
filed on November 7, 1995 is incorporated herein by
reference.
(3.) Copy of Modification to Agreement dated May
28, 1959 (see (1) above), made as of January 31,
1961, filed as Exhibit 10(a)(3) to Registration
Statement No. 33-99052 as filed on November 7, 1995
is incorporated herein by reference.
(4.) Copy of Agreement dated April 1, 1966 among
the Company et al. and Dome Petroleum Limited et al.
filed as Exhibit 10(a)(4) to Registration Statement
No. 33-99052 as filed on November 7, 1995 is
incorporated herein by reference.
<PAGE>
(5.) Copy of Letter Agreement dated February 1,
1977 between the Company and Columbia Gas
Development of Canada, Ltd. for operation of the
Kotaneelee gas field filed as Exhibit 10(a) to
Registration Statement No. 33-99052 as filed on
November 7, 1995 is incorporated herein by reference.
(b) Copy of Agreement dated January 28, 1972 between
the Company and Panarctic Oils Ltd. for development
of the offshore Arctic Islands gas fields filed as
Exhibit 10(b) to Registration Statement No. 33-99052
as filed on November 7, 1995 is incorporated herein
by reference.
(c) Stock Option Plan adopted December 9, 1992 filed
as Exhibit 10(g) to Report on Form 10-K for the
fiscal year ended June 30, 1993 is incorporated
herein by reference.
11. Statement re computation of per share earnings.
Not applicable.
12. Statement re computation of ratios.
None.
13. Annual report to security holders.
Not applicable.
16. Letter re change in certifying accountant.
Not applicable.
18. Letter re change in accounting principles.
None.
20. Previously unfiled documents.
None.
21. Subsidiaries of the Company.
Canpet, Inc. incorporated in Delaware on August 3,
1973. C. S. Petroleum Limited incorporated in Nova
Scotia on December 15, 1981.
22. Published report regarding matters submitted to vote
of security holders.
None.
23. Consents of experts and counsel.
(a) Paddock Lindstrom & Associates, Ltd.
(b) Ernst & Young
24. Power of attorney.
Not applicable.
27. Financial Data Schedule.
Filed herein.
28. Information from reports furnished to state insurance
regulatory authorities.
Not applicable.
99. Additional exhibits.
(a) Complaint of Allied-Signal Inc. in its action against
Dome Petroleum Limited, Amoco Production Company,
and Amoco Canada Petroleum Company, Ltd. filed
September 2, 1988 in the Court of Queens Bench of
Alberta, Judicial District of Calgary, Canada, filed
as Exhibit 99(a) to Registration Statement No.
33-99052 as filed on November 7, 1995 is incorporated
herein by reference.
(b) Answer and Counterclaim of Dome Petroleum Limited,
Amoco Production Company, and Amoco Canada Petroleum
Company Ltd. filed September 21, 1988 in the Court of
Queen's Bench of Alberta, Judicial District of
Calgary, Canada, which answers the Allied-Signal
complaint in (b) above and which names the Company
and others as counterclaim defendants, filed as
Exhibit 99(b) to Registration Statement No. 33-99052
as filed on November 7, 1995 is incorporated herein
by reference.
<PAGE>
(c) Statement of Claim filed on October 27, 1989 against
Columbia Gas Development of Canada, Ltd., Amoco
Production Company, Dome Petroleum Limited, Amoco
Canada Petroleum Company Ltd., Mobil Oil Canada Ltd.
and Esso Resources of Canada Ltd. in the Court of
Queen's Bench of Alberta Judicial District of
Calgary, Alberta, Canada filed as Exhibit 99(c) to
Registration Statement No. 33-99052 as filed on
November 7, 1995 is incorporated herein by reference.
(d) Amended Statement of Claim, amending the October 27,
1989 Statement of Claim, filed on March 12, 1990 and
filed as Exhibit 99(d) to Registration Statement No.
33-99052 as filed on November 7, 1995 is incorporated
herein by reference.
(e) Amended Statement of Claim in the same action, filed
on November 17, 1993, filed as Exhibit 28(ii) to Form
8-K dated November 17, 1993 is incorporated herein by
reference.
(f) Amended Statement of Third Party Notice by Amoco
Canada Production Company Ltd. and Amoco Production
Company, filed November 17, 1993 in the same action,
and filed as Exhibit 99(e).
(g) Amended Statement of Defense to Third Party Notice by
Anderson Oil & Gas Inc. (formerly Columbia Gas
Development of Canada Ltd.) filed January 27, 1994 in
the same action, and filed as Exhibit 99(g) to Form
10-K dated for the period ended December 31, 1993, is
incorporated herein by reference.
(h) Documents regarding settlement with AlliedSignal,
Inc. as Exhibits to Form 8-K as filed on January 30,
1996 are incorporated herein by reference.
(1) Covenant Not to Sue.
(2) Discontinuance of Action. Action No.
8801-13549 Court of Queen's Bench of Alberta
Judicial District of Calgary.
(3) Order. Action No. 8801-123549 Court of
Queens Bench of Alberta Judicial istrict
of Calgary.
(4) Partial Discontinuance of Counterclaim.
Action No. 8801-13549 Court of Queens Bench
of Alberta Judicial District of Calgary.
(5) Notice of Discontinuance of Third Party
Proceedings as Against Allied-Signal Inc.
Action No. 9001-03466 Court of Queens Bench
of Alberta Judicial District of Calgary.
(b) Reports on Form 8-K.
On October 21, 1996, the Company filed a Current Report on
Form 8-K to report that the trial of its lawsuit against Amoco Canada and the
other Kotaneelee working interest partners was adjourned pending resolution of a
conflict of interest dispute involving Amoco Canada's law firm.
On December 23, 1996, the Company filed a Current Report on
Form 8-K to report that the Court of Queen's Bench in Calgary ruled in favor of
allowing Amoco Canada's law firm to continue to represent Amoco in the
Kotaneelee lawsuit. The Company expects to appeal this decision.
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.
CANADA SOUTHERN PETROLEUM LTD.
(Registrant)
Dated: March 21, 1997 By /s/ Charles J. Horne
- ----------------------------------- --------------------
Charles J. Horne
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
/s/ Charles J. Horne /s/ Beverley A. Scobie
Charles J. Horne, President Beverley A. Scobie, Treasurer,
and Director Chief Financial and Accounting
Officer
Dated: March 21, 1997 Dated: March 21, 1997
- ------------------------------------- ---------------------
/s/ Benjamin W. Heath /s/ M. Anthony Ashton
Benjamin W. Heath, Director M. Anthony Ashton, Director
Dated: March 21, 1997 Dated: March 21, 1997
- ------------------------------------- ---------------------
/s/ Eugene C. Pendery
Arthur B. O'Donnell, Director Eugene C. Pendery, Director
Dated: Dated: March 21, 1997
<PAGE>
Exhibit 23(a)
The undersigned firm of Independent Petroleum Engineers, of Calgary, Alberta,
Canada, knows that it is named as having prepared an evaluation of the interests
of Canada Southern Petroleum Ltd., prepared for filings with the SEC on Form
10-K 1996, dated March 12, 1997, 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
<PAGE>
Exhibit 23(b)
Consent of Independent Auditors
We consent to the incorporation by reference in the Registration Statement (Form
S-8) pertaining to the Stock Option Plan of Canada Southern Petroleum, Ltd. of
our report dated March 6, 1997, 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, 1996.
/s/ Ernst & Young
Chartered Accountants
Calgary, Canada
March 6, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000016804
<NAME> Canada Southern Petroleum, Ltd.
<MULTIPLIER> 1
<CURRENCY> Canadian Dollars
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<EXCHANGE-RATE> .7297
<CASH> 2,709,597
<SECURITIES> 3,404,213
<RECEIVABLES> 635,223
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 6,976,401
<PP&E> 11,349,945
<DEPRECIATION> 0
<TOTAL-ASSETS> 20,374,919
<CURRENT-LIABILITIES> 621,941
<BONDS> 0
0
0
<COMMON> 13,956,450
<OTHER-SE> 5,546,164
<TOTAL-LIABILITY-AND-EQUITY> 20,374,919
<SALES> 1,754,579
<TOTAL-REVENUES> 2,228,393
<CGS> 0
<TOTAL-COSTS> 3,689,676
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (1,461,283)
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,461,283)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,461,283)
<EPS-PRIMARY> (0.11)
<EPS-DILUTED> (0.11)
</TABLE>
