As filed with the Securities and Exchange Commission on September 25, 2000
Registration No. 333-_______
________________________________________________________________________________
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------------
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
---------------------------
CANADA SOUTHERN PETROLEUM LTD.
(Exact Name of Registrant as Specified in its Charter)
NOVA SCOTIA, CANADA 1330 98-0085412
------------------- ---- ----------
(State or other Jurisdiction of (Primary Standard Industrial (I.R.S. Employer
Incorporation or Organization) Classification Number) Identification Number)
Suite 505, 706 Seventh Avenue, S.W., Calgary, Alberta,
Canada T2P 0Z1, (403) 269-7741
-------------------------------------------------------------------------------
(Address, including Zip Code, and Telephone Number, including Area Code,
of Registrant's Principal Executive Offices)
Copy to:
Timothy L. Largay
Murtha Cullina LLP
CityPlace I, 185 Asylum Street, 29th Floor
Hartford, Connecticut 06103-3469
(860) 240-6017
(Name, Address, including Zip Code, and Telephone Number,
including Area Code, of Agent for Service)
---------------------------
Approximate date of the start of proposed sale to the public: As soon after the
effective date as practicable.
If any of the securities being registered on this Form are to be offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933 check the following box. [X]
If this Form is filed to register additional securities for an offering pursuant
to Rule 462(b) under the Securities Act, please check the following box and list
the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under
the Securities Act, check the following box and list the Securities Act
registrations statement number of the earlier effective registration statement
for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under
the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
<TABLE>
CALCULATION OF REGISTRATION FEE
---------------------------------------------- ---------------- ----------------- ----------------- -----------------
Title of each class of securities to be Amount to be Proposed Proposed Amount of
registered registered maximum maximum registration fee
offering price aggregate
per share offering price
---------------------------------------------- ---------------- ----------------- ----------------- -----------------
Limited Voting Shares, par value $1 Canadian
<S> <C> <C> <C> <C>
per share 3,000,000(1) $ 5.00(1) $15,000,000(1) $3,960.00
Rights to Purchase Limited Voting Shares 3,000,000 $0.00 $0.00 $0.00
---------------------------------------------- ---------------- ----------------- ----------------- -----------------
</TABLE>
(1) Estimated in accordance with Rule 457(c) under the Securities Act of 1933,
solely for the purpose of calculating the registration fee.
The registrant amends this registration statement on such date or dates as may
be necessary to delay its effective date until the registrant shall file a
further amendment which specifically states that this registration statement
shall thereafter become effective in accordance with Section 8(a) of the
Securities Act of 1933 or until the registration statement shall become
effective on the date as the Commission, acting pursuant to said Section 8(a),
may determine.
<PAGE>
The information in this prospectus is not complete and may be changed. These
securities may not be sold until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an offer
to sell nor does it seek an offer to buy these securities in any jurisdiction
where the offer or sale is not permitted.
PROSPECTUS
[______________] LIMITED VOTING SHARES
[_________] RIGHTS TO PURCHASE LIMITED VOTING SHARES
Canada Southern Petroleum Ltd.
This prospectus relates to the sale by us of a total of [______] of our
limited voting shares by subscription right to our existing shareholders. See "
Description of our Limited Voting Shares" at page __.
For every one (1) share held as of _______, 2000, each shareholder will
receive one transferable right. For every ___ transferable rights, each
shareholder will be entitled to purchase from us one (1) limited voting share at
a price of $ [____] Canadian or $ [__] U.S. dollars per share. In addition, each
shareholder who purchases his/her full allotment of shares is entitled to
purchase additional shares which are unsubscribed by other shareholders.
Per Share Total
Price to shareholders $_________ $_________
Proceeds, before expenses, to us $_________ $_________
Our shares are traded on The Toronto Stock Exchange, the Boston Stock Exchange
and the Pacific Exchange, Inc. (symbol CSW) and in the NASDAQ SmallCap Market
(symbol CSPLF). On __________ __, 2000, the last reported sale price of our
common stock as reported on The Toronto Stock Exchange was Can. $____ per share
and U.S. $ per share on the NASDAQ SmallCap Market.
The shares offered hereby involve a high degree of risk. You should
purchase shares only if you can afford a complete loss. See "Risk Factors"
beginning on page 7 for a discussion of certain factors that you should consider
before you purchase any of our shares.
Neither the Securities and Exchange Commission nor any state or
provincial securities commission has approved or disapproved of these securities
or determined if this prospectus is truthful or complete. Any representation to
the contrary is a criminal offense.
The date of this prospectus is __________________, 2000.
<PAGE>
TABLE OF CONTENTS
PAGE
Prospectus Summary............................................................3
Selected Financial Data.......................................................5
About Canada Southern Petroleum Ltd...........................................6
Risk Factors..................................................................7
Cautionary Statement about Forward-Looking Statements........................12
Management's Discussion and Analysis of Financial
Condition And Results of Operations..........................................13
Use of Proceeds..............................................................23
Dilution.....................................................................23
Terms of Offering and Selling Arrangements...................................24
United States Tax Consequences of the Offering...............................26
Canadian Tax Consequences of the Offering....................................27
Capitalization...............................................................30
Market Information...........................................................31
Performance Graph............................................................33
Our Business.................................................................34
Properties...................................................................41
Legal Proceedings............................................................48
Our Management...............................................................51
Principal Stockholders.......................................................55
Certain Business Relationships...............................................56
Description of Our Limited Voting Shares.....................................56
Legal Matters................................................................57
Experts......................................................................57
Where You Can Find More Information..........................................58
Index to Consolidated Financial Statements..................................F-1
Supplemental Information on Oil and Gas Activities.........................F-21
<PAGE>
PROSPECTUS SUMMARY
This summary highlights some of the information in this prospectus. The summary
may not contain all of the information that is important to you. This prospectus
and the documents we incorporate by reference contain forward-looking statements
which involve risks and uncertainties. You should carefully read the entire
prospectus, including the risk factors which begin on page 7 and the financial
statements which begin at page F-2, before deciding whether to invest in our
shares.
The Company o We are a Nova Scotia company engaged in the exploration for
and development of oil and gas reserves, primarily in
Canada. Our principal asset is our 30% carried interest
in the Kotaneelee gas field in the Yukon territory
which has been the subject of prolonged and costly
litigation against a number of defendants. Our producing
properties are located primarily in British Columbia
and Alberta. We also have interests in exploratory
ventures on properties located in the Northwest Territories
and the Arctic Islands.
Our Operating o We have been engaged in the oil and gas exploration
History and development business since 1954. We incurred a net
loss of $1,790,000 for the six months ended June 30, 2000,
a net loss of $3,001,000 for the year 1999, a net loss of
$2,328,000 for the year 1998 and a net loss of $1,588,000
for the year 1997. We had a deficit of $ 27,332,000 at June
30, 2000.
The Offering o [ ] limited voting shares, par value $1.00 Canadian
per share.
Subscription o Each shareholder will receive one right for every one (1)
Privilege share held on the record date. For every ___rights, each
shareholder will be entitled to purchase one (1) limited
voting share from us at a price of $[____] Canadian or
$[____] U.S. dollars per share.
Transferability o You should complete Form ___ of the Rights Certificate if
of Rights you wish to transfer your Rights to a third party. The
Rights will not be listed on any U.S. national securities
exchange and will not be admitted for quotation in any
automated, inter-dealer quotation system, but may be traded
on whatever market may develop for them, if any. The
Rights are listed on The Toronto Stock Exchange.
Record Date o _____________, 2000.
Expiration Date o Rights must be exercised prior to 4:30 PM, Eastern
Standard Time, on _______, 2000. All rights unexercised
at such time will become void.
Oversubscription o Each shareholder who purchases the entire guaranteed
Privilege subscription amount will be permitted to subscribe pro rata
for additional shares not purchased by other shareholders
prior to the expiration date.
How to Exercise o If you wish to purchase shares, you should complete Form 1
on the Rights Certificate and deliver it, accompanied by
full payment of the purchase price, prior to the
expiration date to either one of our subscription agents.
Agent in Canada o Montreal Trust Company, 15 King Street West, Toronto,
Ontario, Canada, M5H 1B4, telephone (416) 860-5555.
Agent in United o American Stock Transfer & Trust Co., 40 Wall Street,
States 46th Floor, New York, NY 10005, Telephone: (800) 937-5449.
Limited Voting o 14,284,940 limited voting shares were outstanding at
Shares September 20, 2000. If all shares offered are sold, there
Outstanding will be [________] shares outstanding.
Dividends o We have never paid a dividend and we do not intend to pay a
dividend until our deficit ($27,332,000 at June 30, 2000)
is eliminated.
Use of Proceeds o The proceeds of the offering will be used for general
corporate purposes, including working capital, exploration
and development and to continue the Kotaneelee litigation.
Litigation o We are currently involved in litigation regarding our 30%
carried interest against the operator and working interest
partners of the Kotaneelee gas field. We contend that the
defendants failed to meet their obligations to market gas
from the field. We also contend that the defendants have
improperly charged certain expenses to our carried interest
account. The trial, which commenced in 1996, has been
lengthy, complex and costly. We do not expect a decision
in the litigation before 2001. We are unable to determine
whether we will prevail in the litigation, or whether an
award of costs, assessable against a non-prevailing party
under Canadian law, will be assessed against us.
<PAGE>
SELECTED FINANCIAL DATA
The following selected consolidated financial information (in thousands
except per share and exchange rate data) insofar as it relates to each of the
fiscal periods shown has been extracted from our consolidated financial
statements. Financial data for the years prior to 1999 have been restated to
reflect a change from the deferral method of tax allocation accounting to the
liability method of accounting for income taxes. (See Note 1 to the Consolidated
Financial Statements, at page F-9). The information for the six month periods
ended June 30, 2000 and 1999 is unaudited but includes all adjustments which
Canada Southern considers necessary for a fair presentation of the results of
operations for those periods.
<TABLE>
Six months
ended June 30, Year ended December 31,
____________________ ______________________________________________________________
2000 1999 1999 1998 1997 1996 1995
---- ---- ---- ---- ---- ---- ----
($) ($) ($) ($) ($) ($) ($)
(Unaudited) (Unaudited) (Restated) (Restated) (Restated) (Restated)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenues 602 220 777 1,810 2,120 1,755 1,657
=== === === ===== ===== ===== =====
Total revenues 683 365 1,030 3,409 2,515 2,228 1,793
=== === ===== ===== ===== ===== =====
Net loss (1,790) (1,784) (3,001) (2,328) (1,588) (1,236) (1,001)
======= ======= ======= ======= ======= ======= =======
Net loss per share (.13) (.13) (.21) (.16) (.11) (.09) (.08)
===== ===== ===== ===== ===== ===== =====
Working capital 2,412 4,758 3,629 6,876 5,573 8,403 1,510
===== ===== ===== ===== ===== ===== =====
Total assets 14,302 15,799 16,073 18,854 22,772 22,021 13,801
====== ====== ====== ====== ====== ====== ======
Shareholders' Equity:
Capital stock 40,787 40,787 40,787 40,489 40,489 38,888 29,635
Deficit (27,332) (24,324) (25,542) (22,540) (18,625) (17,037) (15,801)
-------- -------- -------- -------- -------- -------- --------
13,455 16,463 15,245 17,949 21,864 21,851 13,834
====== ====== ====== ====== ====== ====== ======
Average number of
shares outstanding 14,285 14,234 14,253 14,253 14,084 13,362 12,622
====== ====== ====== ====== ====== ====== ======
Exchange rates:
Period-end .6759 .6789 .6924 .6535 .6992 .7297 .7300
===== ===== ===== ===== ===== ===== =====
Average for the period .6821 .6704 .6733 .6749 .7224 .7335 .7289
===== ===== ===== ===== ===== ===== =====
Range .66-.70 .66-.69 .67-.69 .63-.67 .69-.75 .72-.75 .70-.75
======= ======= ======= ======= ======= ======= =======
</TABLE>
<PAGE>
About Canada Southern Petroleum Ltd.
We are a Nova Scotia company engaged in the exploration for and
development of oil and gas reserves, primarily in Canada. We were originally
incorporated in 1954 under the Canada Corporations Act. In 1979, we became
subject to the Canadian Business Corporations Act and, in 1980, continued under
the Nova Scotia Companies Act.
We are engaged, directly or indirectly, in the exploration and
development of properties containing or believed to contain recoverable oil and
gas reserves and the sale of oil and gas from these properties. Our principal
asset is a 30% carried interest in the Kotaneelee field, a partially developed
field, producing gas (See "Our Business" and "Properties"). Substantially all of
our assets are in Canada. Our interests in exploratory ventures are on
properties located in Alberta, British Columbia, Saskatchewan, the Northwest
Territories, the Yukon Territory and the Arctic Islands in Canada. We also have
producing properties in the Yukon Territory, British Columbia and Alberta.
Our principal executive offices are located at Suite 505, 706 - Seventh
Avenue S.W., Calgary, Alberta, Canada T2P 0Z1. Our telephone number at that
address is (403) 269-7741. Our internet web address is http: //www.cansopet.com.
The contents of our web site are not incorporated into this prospectus. Our
limited voting shares are traded on the Boston Stock Exchange, the Pacific
Exchange and The Toronto Stock Exchange under the symbol CSW and in the NASDAQ
SmallCap Market under the symbol CSPLF. We have two full time employees, one
part-time employee and rely heavily on outside consultants for technical, legal,
accounting and administrative services.
In this prospectus, "Canada Southern," "we," "us," and "our" refer to
Canada Southern Petroleum Ltd. and its subsidiaries, unless the context
otherwise dictates. Unless otherwise indicated, all references in this
prospectus to "dollars" or "$" are to Canadian dollars. The exchange rate on
____________, 2000 as reported by the Wall Street Journal was $1.00 Canadian
equals U.S. $----.
<PAGE>
RISK FACTORS
An investment in our limited voting shares involves a high degree of
risk. You should carefully consider the following risk factors and other
information in this prospectus and the documents we incorporate by reference in
evaluating our company before you purchase any shares of our common stock. If
any of the following risks actually occur, our business, financial condition or
results of operations could be materially adversely affected. In this case, the
trading price of our shares could decline and you may lose all or part of your
investment.
RISKS RELATED TO OUR BUSINESS
We have a deficit and anticipate further losses, which could jeopardize
our business.
We have been engaged in the oil and gas exploration and development
business since 1954 and have a deficit of $27,332,000 at June 30, 2000. We
incurred a net loss of $1,790,000 for the six months ended June 30, 2000, a net
loss of $3,001,000 for the year 1999, a net loss of $2,328,000 for the year 1998
and a net loss of $1,588,000 for the year 1997. We cannot assure you that
hereafter we will be able to achieve or sustain revenue growth, profitability or
positive cash flow. If we are unable to achieve or sustain profitability, we may
not be financially viable in the future and may have to curtail, suspend or
cease operations.
Our principal asset has been the subject of costly and protracted
litigation. If we do not prevail in the litigation, our business could
suffer significant harm.
Our principal asset is a 30% carried interest in the Kotaneelee gas
field (located in the Yukon Territory, Canada) which has been the subject of
prolonged and costly litigation which commenced in 1990. We cannot assure you
that we will be successful on the merits of our claims which have been
vigorously defended by the working interest partners in the Kotaneelee gas
field. If we do not prevail on our claims, we will not receive an award of
damages.
Even if we are awarded damages against the defendants, we cannot assure
you that the court will apply a measure of damages that we claim should be
applied. In such a case, the recovery on our claims may not be sufficient to
cover our costs of prosecuting the litigation. The market price of our stock
could be significantly affected by any adverse judgment in the litigation. In
addition, our stock price could be adversely affected if we are awarded a
judgment in the litigation in an amount below our claimed damages amount.
If we do not prevail in the Kotaneelee litigation, we could be forced
to pay some or all of the defendants' litigation costs.
Under Canadian law, certain costs of litigation are assessed against
the losing party. These costs consist primarily of attorney and expert witness
fees incurred during the action which has been ongoing for approximately four
years. If the court determines to assess the defendants' litigation costs
against us, we may be required to sell company assets or raise additional funds
through the issuance of debt or equity securities to fund the award of costs,
which could be substantial. We can give no assurances that in such event we
would be able to sell assets at other than distress prices or raise additional
funds on favorable terms.
Even if we prevail in the Kotaneelee litigation at trial, we expect
that the defendants will appeal.
If we are awarded a judgment in the Kotaneelee litigation, we expect
that the defendants will appeal. The appeal period is estimated to be at least
one year and could result in any judgment in our favor being reversed.
Our limited cash and cash equivalents could be depleted by our
operating and litigation expenses which could cause us to discontinue
our efforts to enforce our contractual rights through litigation.
At June 30, 2000 we had cash and cash equivalents and marketable
securities of $2,477,000. We incurred net losses of $1,790,000 for the six
months ended June 30, 2000, a net loss of $3,001,000 for the year 1999,
$2,328,000 for the year 1998 and a net loss of $1,588,000 for the year 1997,
primarily as a result of substantial litigation expenses. If our losses
continue, we may have insufficient funds to continue our efforts to enforce our
contractual rights in the Kotaneelee litigation.
The Kotaneelee litigation continues to be a costly cash drain on our
operations. During the years 1997 to 1999, we expended approximately $6,364,000
on legal expenses incurred primarily in the Kotaneelee litigation. Our other
general and administrative expenses and rent have totaled $3,805,000 during the
same three year period. Although the Kotaneelee gas field reached pay out status
in November 1999, the defendants have refused to pay us our share of the net
revenues from the field. We currently estimate that we will continue to spend at
least $4,000,000 annually on such operating and litigation expenses.
If we continue to incur operating and litigation expenses which
significantly exceed our revenues, we may never achieve profitability
and may be forced to curtail, suspend or cease operations.
Based on our ongoing litigation and operating expenses, we will need to
generate significant revenues in the future to achieve profitability. We cannot
assure you that we will be able to achieve or sustain revenues, profitability or
positive cash flow on either a quarterly or annual basis or that profitability,
if achieved, will be sustained. Continuing losses and our current financial
condition could also adversely impact our ability to obtain future financing and
may force us to curtail, suspend or cease operations.
We may never receive any share of the net revenues from the Kotaneelee
gas field.
The operator of the Kotaneelee gas field has advised us that the
carried interest account reached pay out status in November 1999. However, Amoco
Canada claims that there should be a processing fee on the gas produced and that
the carried interest account balance as of December 31, 1999 was $58,711,000 or
$19,235,000 depending on inclusion of interest. None of the defendants is paying
us our share of net revenues from the field and they may never pay us in the
future if the Court determines that the processing fee claimed by Amoco Canada
is appropriate.
Further development of the Kotaneelee gas field may be impeded by the
working interest partners.
We believe that the Kotaneelee gas field should be further developed.
The cooperation of the working interest partners may be necessary for further
development to take place. Based upon our experience with the working interest
partners in the Kotaneelee litigation, we do not believe that they would be
cooperative in any further development efforts. If the working interest partners
fail to further develop the resources which we believe are contained in the
Kotaneelee gas field, we may never receive any revenues that might result from
such further development of the field. We have filed a lawsuit in the Court of
Queen's Bench of Alberta, Canada against the working interest partners seeking
damages for their failure to develop the field beyond the two currently
producing wells.
Despite recent encouraging market trends, our Canadian Arctic Island
properties may never generate any significant revenues.
We continue to retain our interest in more than 175,000 acres of the
Canadian Arctic Islands which have not, to date, generated any revenues. Major
gas operators and industry investors have recently indicated interest in
exploring the Canadian Arctic Islands region to develop additional gas reserves
and productive capacity. If the major operators do not explore and develop the
natural gas fields of the Canadian Arctic Island region, or are unable to
develop gas reserves from such properties in commercially viable amounts, we may
never receive any significant revenues from our interests in these properties.
RISKS RELATED TO OUR INDUSTRY
We face strong competition from larger oil and gas companies which may
negatively affect our ability to continue our operations.
We operate in the highly competitive areas of oil and gas exploration,
development and production. Our competitors include major integrated oil
companies, substantial independent energy companies, affiliates of major
interstate and intrastate pipelines and national and local gas gatherers, many
of which possess greater financial and other resources than we do. If we are
unable to compete successfully, we may face increased losses and be forced to
curtail, suspend or cease operations.
We cannot assure you that we will be able to compete with, or enter
into cooperative relationships with, any such firms. Factors which affect our
ability to successfully compete in the marketplace include:
o the financial resources of our competitors;
o the availability of alternate fuel sources; and
o the costs related to the extraction and transportation of oil and gas.
In addition, our ability to exploit an oil or gas discovery is
dependent upon considerations such as the ability to finance development costs,
the availability of equipment, and engineering and construction delays and
difficulties. Because the majority of our interests are located in remote areas,
transportation of oil and gas is difficult and costly. Furthermore, competitive
conditions may be substantially affected by various forms of energy legislation
that may be considered in the United States and Canada. However, we are unable
to predict the nature of any such legislation which may ultimately be adopted or
its effects upon our future operations.
Any violations by us of existing environmental laws and regulations
could be costly and could negatively impact our business.
The Canadian oil and gas industry is continually subject to
environmental regulation pursuant to local, provincial and federal legislation.
A breach of such legislation may result in the imposition of fines or penalties.
If any such fines or penalties are assessed against us or the working interest
partners on properties in which we hold an interest, our losses could increase
and our business could be harmed.
Environmental laws and regulations provide 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. Federal environmental regulations also apply to the use and
transport of certain restricted and prohibited substances. We cannot assure you
that we can avoid being assessed any costs or penalties on account of any (1)
spills, releases or emissions, (2) assessment reviews, (3) necessary abandonment
or reclamation efforts or (4) problems associated with the use and transport of
restricted or prohibited substances.
If the current deregulatory trend in Canada does not continue, our
losses could increase.
The Canadian federal government over the past few years has
substantially deregulated the Canadian gas and oil industry. Although the trend
seems likely to continue, no assurance can be given that such will be the case,
and the Canadian federal government could increase regulation of our oil and gas
industry at any time. If the Canadian government increases regulation of our
business, our costs may be increased and our prospects of generating any
significant revenues may be significantly harmed.
All of our operations are conducted in Canada, and most of our
shareholders are residents outside of Canada which subjects
shareholders to risks attendant to operations outside of the United
States.
The properties in which we have interests are located in Canada and are
subject to certain risks involved in the ownership and development of such
foreign property interests. Thus, an investment in our shares represents an
exposure to risks in addition to those inherent in petroleum exploratory
ventures. If any of theses risks occur, we could suffer losses and be forced to
curtail, suspend or cease our operations. These risks include:
o nationalization or expropriation of our assets by the Canadian
federal or provincial governments;
o confiscatory taxation;
o the assertion of land ownership or use rights relating to properties
in which we have an interest;
o changes in foreign exchange controls applicable in Canada;
o currency fluctuations;
o burdensome royalty terms imposed by the Canadian federal or
provincial governments;
o export sales restrictions imposed by the Canadian federal or
provincial governments;
o limitations on the transfer of interests in exploration licenses; and
o and other laws and regulations which may adversely affect our
properties, such as those providing for conversion, proration,
curtailment, cessation or other forms of limited or controlling
production of, or exploration for, hydrocarbons.
RISKS RELATED TO THE OFFERING
If you are unable to bring actions under the federal securities laws
of the United States against our directors, officers and experts who
are not citizens or residents of the United States, you may suffer
losses which you may not be able to recover.
We are incorporated under the laws of Nova Scotia and our officers and
two of our directors are residents of Canada and are not citizens of the United
States. In addition, our petroleum engineers named under "Experts" are residents
of Canada and not of the United States. As a result, it may be difficult for our
U.S. shareholders to effect service of process on those directors, officers, or
experts within the United States or to enforce against those directors,
officers, or experts judgments of U.S. courts predicated on the civil
liabilities provided to investors under the Securities Act of 1933 and the
Securities Exchange Act of 1934.
We have been advised by the law firm of Blake, Cassels & Graydon LLP of
Toronto, Canada that there is no assurance that the courts in Canada would
enforce civil liabilities, whether in original actions in Canada or in the form
of final judgments of U.S. courts, arising under the federal securities laws of
the United States. against us us or the persons signing the registration
statement, or the experts.
Our shares carry limited voting rights. As a result, if you own more
than 1,000 shares you will not be entitled to a vote that equals the
economic interest of your investment.
Article 8 of our Articles of Continuance provides that no person, as
defined, shall vote more than 1,000 shares of our limited voting shares. As a
consequence, an owner of a substantial number of our limited voting shares is
unable to materially influence our policies through shareholder votes. The 1,000
share voting limitation also may make it less likely a takeover not supported by
management could occur.
Our dividend policy could depress our stock price.
We have never declared or paid dividends on our limited voting shares
We do not intend to pay dividends until our deficit ($27,332,000 at June 30,
2000) is eliminated. As a result, our dividend policy could depress the market
price for our common stock and cause investors to lose some or all of their
investment. We plan to retain any future earnings to reduce our deficit
You will experience an immediate dilution in net book value per share
after this offering.
By purchasing limited voting shares offered by this prospectus, you
will experience an immediate dilution in net book value per share of $[____] per
share on your purchase price of $[____] per share. This is because the tangible
net book value per share prior to the offering is $.[__] per share and this
amount will be increased to only $[____] per share after the offering. See
"Dilution" at page __.
CAUTIONARY STATEMENT ABOUT
FORWARD-LOOKING STATEMENTS
In this prospectus and the documents that we incorporate by reference,
we make statements that relate to our future plans, objectives, expectations and
intentions that involve risks and uncertainties. We have based these statements
on our current expectations and projections about future events. These
statements may be identified by the use of words such as "expect," "anticipate,"
"intend," "plan," "believe" and "estimate" and similar expressions. Any
statements that refer to expectations, projections or other characterizations of
future events or circumstances are forward-looking statements within the meaning
of the Private Securities Litigation Reform Act of 1995, and are subject to the
safe harbor created by that Act.
Forward-looking statements necessarily involve risks and uncertainties.
Our actual results could differ materially from those discussed in, or implied
by, these forward-looking statements. Factors that could contribute to such
differences include, but are not limited to, those discussed in the "Risk
Factors" section beginning at page 7 and elsewhere in this prospectus. The
factors set forth in the Risk Factors section and other cautionary statements
made in this prospectus should be read and understood as being applicable to all
related forward-looking statements wherever they appear in this prospectus.
All subsequent written and oral forward-looking statements attributable
to us are expressly qualified in their entirety by the cautionary statements.
You are cautioned not to place undue reliance on these forward-looking
statements, which speak only as of their dates. We undertake no obligations to
publicly update or revise any forward-looking statements, whether as a result of
new information, future events or otherwise.
Management's Discussion and Analysis of Financial
Condition And Results of Operations
Liquidity and Capital Resources
At June 30, 2000, we had approximately $2,477,000 of cash and cash
equivalents and marketable securities on hand. Of this amount, approximately
$875,000 are held in U.S. marketable securities which are subject to exchange
fluctuations. These funds are expected to be used for general corporate
purposes, including exploration and development and to continue the Kotaneelee
field litigation. We estimate that we currently have adequate working capital
for the year 2000. However, we may be required to raise additional funds through
the sale of properties or other means in order to complete the Kotaneelee
litigation.
Net cash used in operations during the six months ended June 30, 2000
decreased by $396,000 compared to the six months ended June 30, 1999 and net
cash used in operations during the year 1999 increased by $379,000 compared to
the year 1998. The differences between the periods was caused primarily by the
following:
<TABLE>
Six months ended Year ended
June 30, 2000 December 31, 1999
---------------- -----------------
<S> <C> <C>
Decrease (Increase) in loss from operations $ 360,000 $ (125,000)
Changes in accounts receivable and other (11,000) (965,000)
Net change in current liabilities 47,000 711,000
------- -------
Decrease (Increase) in net cash used in operations $ 396,000 $ (379,000)
========= ===========
</TABLE>
In December 1999, the Company filed a motion to have the Court of
Queen's Bench direct the operator of the Kotaneelee gas field to make timely
payments of all current and future amounts due from its share of the Kotaneelee
gas field revenues. The motion was subsequently amended to include all of the
defendants. On April 10, 2000, the trial court dismissed the Company's motion
pending the Court's ultimate determination of the issues surrounding the
Kotaneelee field carried-interest account. The Company has filed a notice of
appeal of the dismissal with the Alberta Court of Appeal.
In view of the trial court's dismissal of the Company's motion, the
Company will not accrue any revenues from the Kotaneelee gas field until
collection of the amounts due is reasonably assured.
Since March 2000, the operator of the Kotaneelee field has been
reporting the amount of the Company's share of net revenues being deposited in
escrow. The September 2000 report provided information for production during the
month of June 2000. Based on the reported data, the Company believes the total
amount due the Company is $5,526,365 of which $1,832,335 has been deposited in
escrow. None of these amounts have been recognized as revenue by the Company.
A significant proportion of our 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 our cash flow from
operations as no revenues are reported or received until the capital costs have
been recovered by the operator. The Kotaneelee gas field and certain properties
in the Fort St. John, British Columbia area in which we have carried interests
have reached pay out status. Proceeds from these carried interests plus oil and
gas royalties are our major sources of working capital.
We are currently evaluating and expect to continue to evaluate oil and
gas properties and may make investments in such properties utilizing cash on
hand. We anticipate that our capital expenditures for land acquisitions and
drilling for the year 2000 will be approximately $600,000 ($246,000 spent
through June 30, 2000). In addition, substantial continuing expenses are
expected to be incurred in connection with the Kotaneelee litigation. During
1999, we expended approximately $2.1 million in connection with the Kotaneelee
litigation which has been the principal cause of our losses since 1991.
We have established a provision for our potential share of future site
restoration costs which totaled $146,000 at June 30, 2000. The estimated amount
of these costs at June 30, 2000, which total $147,000, is being provided on a
unit of production basis in accordance with existing legislation and industry
practice.
Results of Operations
Accounting policy changes
In 1999, under new recommendations of the Canadian Institute of
Chartered Accountants, we retroactively adopted the liability method of
accounting for income taxes. Under this method, we record income taxes to give
effect to temporary differences between the carrying amount and the tax basis of
our assets and liabilities. Temporary differences arise when the realization of
an asset or the settlement of a liability would give rise to either an increase
or decrease in our income taxes payable for the year or later period. Future
income taxes are recorded at the enacted income tax rates that are expected to
apply when the future tax liability is settled or the future tax asset is
realized. Income tax expense is the tax payable for the period and the change
during the period in future income tax and liabilities. The adoption of this
standard has resulted in the recognition of future tax assets and a reduction of
the deficit at December 31, 1999 of $1,583,475 (1998 - $1,308,505; 1997 -
$930,138) and a reduction in the net loss for 1999 of $274,970 (1998 - $378,367;
1997 - $170,158). This new standard is consistent with the accounting principles
generally accepted in the United States.
<PAGE>
Six month period ended June 30, 2000 vs. June 30, 1999
The net loss for the six month period ended June 30, 2000 was
$1,790,143 ($.13 per share) compared to a net loss of $1,783,598 ($.13 per
share) for the 1999 period. A summary of revenue and expenses during the periods
is as follows:
<TABLE>
2000 1999 Net Change
---- ---- ----------
<S> <C> <C> <C>
Revenues $ 683,462 $ 364,826 $ 318,636
Costs and expenses (2,716,130) (2,221,620) (494,510)
Income tax recovery 242,525 73,196 169,329
------- ------ -------
Net loss $(1,790,143) $ (1,783,598) $ (6,545)
============ ============= =========
</TABLE>
Oil sales decreased by 87% due primarily to a 97% decrease in the
number of units sold which was partially offset by a 156% increase in the
average prices of crude oil sold. There was also a corresponding decrease in
royalties paid by the Company. In 2000, royalty income increased from nil in
1999 to $2,000. The Company sold the majority of its crude oil producing
properties in 1998 and also sold its remaining heavy oil production in February
2000. Since the Company has disposed of most of its producing properties, future
oil sales are expected to be minimal unless additional producing properties are
drilled or purchased. Crude oil unit sales in barrels ("bbls") (before deducting
royalties) and the average price per barrel sold during the periods indicated
were as follows:
<TABLE>
Six month period ended June 30,
2000 1999
Average price Average price
bbls per bbl Total Bbls per bbl Total
---- ------- ----- ---- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Oil sales 178 $34.34 $6,000 5,093 $13.44 $68,000
Royalty income 2,000
Royalties paid - (4,000)
------- -------
Total $ 8,000 $64,000
======= =======
</TABLE>
Gas sales increased 56% in 2000. There was a 13% increase in the
average price for gas. Gas sales include royalty income which increased 30% in
2000. 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>
Six month period ended June 30,
2000 1999
Average price Average price
mmcf per mcf Total mmcf per mcf Total
---- ------- ----- ---- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Gas sales 5.0 $2.32 $ 11,000 5.0 $2.06 $ 9,000
Royalty income 35,000 27,000
Royalties paid (2,000) (8,000)
------- -------
Total $44,000 $28,000
======= =======
</TABLE>
Proceeds from carried interests increased 330% to $550,000 during 2000
compared to $128,000 in 1999 because gas prices increased 38%. Capital
expenditures decreased 93% in 2000 to $15,000 from $222,000 during 1999. Unit
sales decreased 1% and partially offset the increase in revenues above. 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>
Six month period ended June 30,
2000 1999
Average price Average price
mmcf per mcf Total mmcf per mcf Total
---- ------- ----- ---- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Gas sales 281 $3.51 $ 979,000 285 $2.55 $708,000
Oil Sales 5,000 20,000
Royalty paid (218,000) (155,000)
Operating costs (201,000) (223,000)
Capital costs (15,000) (222,000)
-------- ---------
Total $ 550,000 $128,000
========= ========
</TABLE>
Interest and other income was 44% lower in 2000. Interest income
decreased 42% from $132,000 in 1999 to $76,000 in the 2000 period because less
funds were available for investment. In addition, the 2000 period includes
proceeds from the sale of seismic data in the amount of $6,000 which is
unchanged from 1999.
General and administrative costs increased 16% in 2000 to $844,000 from
$725,000 in 1999. The Company hired a new executive vice president effective
January 1, 2000 which increased salary expense by approximately $66,000. In
addition the 2000 period includes a $38,000 severance payment to the former
Secretary-Treasurer. The costs of printing and mailing in connection with the
annual meeting also increased by $45,000 during the 2000 period.
Legal expenses decreased 1% during 2000 to $1,109,000 from $1,119,000
during 1999. These expenses are related primarily to the cost of the Kotaneelee
litigation. During the 2000 period, the Company presented its rebuttal evidence
and completed and filed its written closing argument.
Lease operating costs decreased 69% from $68,000 in 1999 to $21,000 in
the 2000 period. The Company sold its remaining heavy oil production properties
during February 2000.
Depletion, depreciation and amortization expense decreased 37% in 2000
to $119,000 from $188,000 in 1999. The depletion rate in 2000 decreased by 32%
from the 1999 rate. Also, the capital asset base in 2000 decreased 6% from 1999.
A foreign exchange gain of $40,000 was recorded in 2000, compared to a loss
of $92,000 in 1999 on the Company's U.S. investments. The value of the Canadian
dollar was U.S. $.6924 at December 31, 1999 compared to U.S. $.6759 at June 30,
2000.
Abandonments and write downs increased to $635,000 during the 2000
period. The Company's investment in the Texas project was written down to a
nominal value during the second quarter because the project was deemed to be
uneconomic.
Income tax recovery increased by 231% to $ 243,000 in 2000 compared to
$73,000 in 1999. The largest component of the increased income tax recovery is
due to adjustments in finalizing the 1999 income tax return.
1999 vs. 1998
The net loss for the year 1999 was $3,001,424 ($.21 per share) compared
to a net loss of $2,328,170 ($.16 per share) for 1998. A summary of revenue and
expenses during the periods is as follows:
<TABLE>
1999 1998 Net Change
---- ---- ----------
<S> <C> <C> <C>
Revenues $ 1,029,899 $3,409,361 $(2,379,462)
Costs and expenses (4,306,293) (6,115,898) 1,809,605
Income tax recovery 274,970 378,367 (103,397)
------- ------- ---------
Net loss $(3,001,424) $(2,328,170) $ (673,254)
============ ============ ===========
</TABLE>
Oil sales decreased by 83% due primarily to a 86% decrease in
production which was partially offset by a 17% increase in the average prices of
crude oil sold. There was also a corresponding decrease in royalties paid by us.
We sold the majority of our crude oil producing properties in two separate
transactions effective July 1, 1998 and September 1, 1998. Since we have
disposed of most of our producing properties, future oil sales are expected to
be minimal unless additional producing properties are acquired through drilling
or purchase. The 1999 royalties paid amount includes a provincial royalty tax
credit in the amount of $4,782. Crude oil unit sales in barrels ("bbls") (before
deducting royalties) and the average price per barrel sold during the periods
indicated were as follows:
<TABLE>
1999 1998
Average price Average price
Bbls per bbl Total bbls per bbl Total
---- ------- ----- ---- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Crude oil sales 9,171 $17.38 $159,000 64,954 $14.84 $964,000
Royalties paid (8,000) (66,000)
------- --------
Total $ 151,000 $898,000
========= ========
</TABLE>
Gas sales decreased 95% because of a 93% decrease in number of units
sold and a 16% decrease in the average price for gas. In addition, gas sales
include royalty income which decreased 49% in 1999. We sold the majority of our
working interest gas properties effective July 1, 1998, which accounts for the
decrease in gas sales. Royalties paid include a $59,000 amount as part of a
settlement for royalties due for the 1991 to 1998 period. The volumes in million
cubic feet ("mmcf") and the average price of gas per thousand cubic feet ("mcf")
sold during the periods indicated were as follows:
<TABLE>
1999 1998
Average price Average price
Mmcf per mcf Total mmcf per mcf Total
---- ------- ----- ---- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Gas sales 21 $1.83 $ 37,000 304 $2.17 $660,000
Royalty income 64,000 127,000
Royalties paid (63,000) (82,000)
-------- --------
Total $ 38,000 $705,000
======== ========
</TABLE>
Proceeds from carried interests increased 184% to $587,000 during 1999
compared to $207,000 in 1998 primarily because gas prices increased 58%.
Operating costs also decreased 20% during 1999. The volumes in million cubic
feet ("mmcf") and the average price of gas per thousand cubic feet ("mcf") sold
during the periods indicated were as follows:
<TABLE>
1999 1998
Average price Average price
mmcf per mcf Total mmcf per mcf Total
---- ------- ----- ---- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Gas sales 563 $2.79 $ 1,572,000 575 $1.77 $1,016,000
Royalty paid (327,000) (238,000)
Operating costs (417,000) (522,000)
Capital costs (241,000) (49,000)
--------- --------
Total $ 587,000 $207,000
========= ========
</TABLE>
Share of Kotaneelee net revenues for 1999. Although, according to the
reports of the operator of the Kotaneelee gas field, the Kotaneelee gas field
carried interest reached pay out status during November 1999, no revenue has
been accrued for 1999. In order to bring its billing practices in line with the
industry standard, the operator of the field changed the prior method of
reporting the revenue and expenditures of the field. This resulted in two months
of capital expenditures and operating expenses (December 1999 and January 2000)
being charged against a single month of revenue (November 1999). This change in
reporting is consistent with the reporting of other carried interests currently
held by us. In the future, we expect that the reporting of Kotaneelee gas sales
will continue to lag two months behind actual operating expenses and capital
expenditures. In addition, the production revenue from the two last months of
each quarter is accrued during the following quarter because the data is not
usually available.
As of December 31, 1999, based on the operator's reports, our share of
net revenues due to us by all the defendants totaled $412,374. This amount was
computed as follows:
<PAGE>
<TABLE>
Net Revenues (after royalties):
<S> <C>
November 1999 (after pay out) $864,506
December 1999 1,212,821
---------
Total Revenues 2,077,327
---------
Operating Expenses:
November 1999 (after pay out) 264,848
December 1999 393,389
January 2000 54,889
------
Total Operating Expenses 713,126
-------
Capital Expenditures:
December 1999 368,963
January 2000 539,899
February 2000 42,965
------
Total Capital Expenditures 951,827
-------
Company share of net revenues $ 412,374
=========
</TABLE>
The operator reported that it deposited during March 2000 the amount of
$136,728 in an escrow account for our benefit. This deposit represents the
operator's share of the $412,374 amount due.
The Kotaneelee field working interest partners have approved the
expenditure of an estimated $4.1 million for the installation of a compression
unit in the field to maintain current production levels. The schedule above
reflects a charge of $951,827 against our share of revenues for our share of
these costs which total $1,372,000. The remaining balance of $420,173 will be
deducted from our share of the year 2000 production revenues. Therefore, the
share of Kotaneelee net revenues may fluctuate each year depending on both
capital expenditures and any audit adjustments which are attributable to prior
years.
Interest and other income increased 14% in 1999. Interest income
increased from $194,000 to $230,000 in 1999 due to an increase in funds
available for investment during 1999 because of the proceeds of sale of the
crude oil and gas properties in 1998. In addition, the 1999 period includes
proceeds from the sale of seismic data in the amount of $16,000 compared to
$27,000 from such sales in 1998. It is not possible for us to estimate the
amount of future seismic data sales which are dependent on a purchaser's need
for the seismic data that we own.
Gain on the sale of properties in 1999. There were no properties sold
in 1999. In 1998, there was a gain of $1,378,000 from the sale of our heavy
crude oil properties in Alberta and the sale of certain working interest
properties in British Columbia.
General and administrative costs decreased 7% in 1999 to $1,209,000
from $1,301,000 in 1998.
Legal expenses decreased 11% during 1999 to $2,108,000 compared to
$2,358,000 during 1998. These expenses are related primarily to the cost of the
Kotaneelee litigation. During 1998, we completed the presentation of our case
against the working interest partners. The 1998 costs represent both legal fees
and the cost of our various experts who testified, were being prepared for
testimony, or assisted in the cross-examination of defense witnesses. During
1999, we continued our cross-examination of defense witnesses.
Lease operating costs decreased 85% from $976,000 in 1998 to $147,000
in the 1999 period. We sold the majority of our oil and gas producing properties
during the second half of 1998.
Depletion, depreciation and amortization expense decreased 19% in 1999
to $707,000 from $870,000 in 1998. Although we sold the majority of our oil and
gas producing properties during 1998, the increased production from the pay out
of the Kotaneelee carried interest increased the 1999 depletion expense by
approximately $420,000.
A foreign exchange loss of $77,000 was recorded in 1999, contrasted
with a gain of $179,000 on our U.S. investments in 1998. In 1999 the value of
the Canadian dollar increased from U.S. $.65 to U.S. $.69. In 1998, the gain was
attributable to the continuing strengthening of the U.S. dollar as compared to
the Canadian dollar on our U.S. investments.
Abandonments and write downs. There were no abandonments and write
downs in 1999. The 1998 amount of $685,000 resulted from a write down of certain
of our properties in California and Texas.
Income tax recovery decreased by 27% to $275,000 in 1999 compared to
$378,000 in 1998. The income tax recovery in 1999 decreased because the loss in
1999 was less than the loss in 1998 after giving effect to the $1,378,000 gain
on sale of assets in 1998 which was not recognized for income tax purposes.
1998 vs. 1997
The net loss for the year 1998 was $2,328,170 ($.16 per share) compared
to a net loss of $1,587,506 ($.11 per share) for the 1997 period. A summary of
revenue and expenses during the periods is as follows:
<TABLE>
1998 1997 Net Change
---- ---- ----------
<S> <C> <C> <C>
Revenues $ 3,409,361 $ 2,514,978 $ 894,383
Costs and expenses (5,737,531) (4,102,484) (1,635,047)
----------- ----------- -----------
Net loss $(2,328,170) $(1,587,506) $ (740,664)
============ ============ ===========
</TABLE>
Crude oil sales decreased by 20% due primarily to a 34% decrease in the
average prices of crude oil sold which was partially offset by a 2% increase in
production. There was also a decrease in royalties paid by us. We sold the
majority of our oil producing properties in two separate transactions effective
July 1, 1998 and September 1, 1998. The 1998 royalties paid amount includes a
provincial royalty tax credit in the amount of $117,000. Our oil unit sales in
barrels ("bbls") (before deducting royalties) and the average price per barrel
sold during the periods indicated were as follows:
<TABLE>
1998 1997
Average price Average price
bbls per bbl Total bbls per bbl Total
---- ------- ----- ---- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Crude oil sales 64,954 $14.84 $964,000 63,783 $22.50 $1,436,000
Royalties paid (66,000) (315,000)
-------- ---------
Total $898,000 $1,121,000
======== ==========
</TABLE>
Gas sales increased 35% because of a 52% increase in number of units
sold which was partially offset by a 6% decrease in the average price for gas.
In addition, gas sales include royalty income which decreased 13% in 1998. We
sold the majority of our working interest gas properties effective July 1, 1998.
The primary increase in gas production was the pay out of two wells that had
been in a penalty position. These wells were included in the properties sold.
The volumes in million cubic feet ("mmcf") and the average price of gas per
thousand cubic feet ("mcf") sold during the periods indicated were as follows:
<TABLE>
1998 1997
Average price Average price
mmcf per mcf Total mmcf per mcf Total
---- ------- ----- ---- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Gas sales 304 $2.17 $660,000 200 $2.31 $462,000
Royalty income 127,000 146,000
Royalties paid (82,000) (85,000)
-------- --------
Total $705,000 $523,000
======== ========
</TABLE>
Proceeds from carried interests decreased 57% to $207,000 during 1998
compared to $476,000 in 1997. During 1998, there were significant expenditures
made by the operators of the carried interest properties.
Interest and other income decreased 44% in 1998. Interest income
decreased from $336,000 to $194,000 in 1998 due to the decrease in funds
available for investment and lower interest rates. In addition, the 1998 period
includes proceeds from the sale of seismic data in the amount of $27,000
compared to $59,000 from such sales in 1997.
Gain on the sale of properties in 1998 amounted to $1,378,000 primarily
representing the sale of our heavy crude oil properties in Alberta and the sale
of certain working interest properties in British Columbia.
General and administrative costs increased 18% in 1998 to $1,301,000
from $1,105,000 in 1997 primarily as a result of our increased activity in
connection with the Kotaneelee litigation and our exploration program. In
addition, the expenses increased in the United States because of the 7% increase
in the value of the U.S. dollar compared to the Canadian dollar during 1998.
Legal expenses increased 24% during 1998 to $2,358,000 compared to
$1,898,000 during 1997. These expenses are related primarily to the cost of the
Kotaneelee litigation. During 1998, we continued the presentation of a major
part of our case against the working interest partners. Our case was completed
on September 16, 1998 and the defendants' case proceeded. The 1998 costs
represent both legal fees and the cost of our various experts who testified,
were being prepared for testimony, or assisted in the cross-examination of
defense witnesses.
Lease operating costs increased 22% from $799,000 in 1997 to $976,000
in the 1998 period. The increase represents the charges by the operators of our
properties which is related to the increased production. In addition, our share
of production costs in producing Alberta heavy crude oil increased.
Depletion, depreciation and amortization expense increased 39% in 1998
to $870,000 from $624,000 in 1997. The increase in depletion in 1998 is the
result of increased production and the amount of additional costs being
depleted.
A foreign exchange gain of $179,000 was recorded in 1998, contrasted
with a gain of $231,000 on our U.S. investments in 1997. In 1998, the gain was
attributable to the continuing strengthening of the U.S. dollar as compared to
the Canadian dollar on our U.S. investments.
Abandonments and write downs were $685,000 which resulted from a write
down of certain of our properties in California and Texas. There were no
abandonments and write downs in 1997.
Income tax recovery increased 122% to $378,000 in 1998 compared to
$170,000 in 1997. The increase in the 1998 income tax recovery reflects a
similar increase in the loss in 1998 after giving effect to the $1,378,000 gain
on sale of assets in 1998 which was not recognized for income tax purposes.
Quantitative and Qualitative Disclosure About Market Risk
We do not have any significant exposure to market risk as the only
market risk sensitive instruments are our investments in marketable securities.
At June 30, 2000, the carrying value of such investments (including those
classified as cash and cash equivalents) was approximately $2.2 million which
was approximately equal to the fair value and face value of the investments.
Since we expect to hold the investments to maturity, the maturity value should
be realized. In addition, our investments in marketable securities included
investments held in the United States which are subject to foreign exchange
fluctuations. At June 30, 2000, our investments in the United States totaled
$875,000.
<PAGE>
USE OF PROCEEDS
The proceeds will be used for general corporate purposes, including
working capital, exploration and development and continuation of the Kotaneelee
litigation. See "Legal Proceedings" and "Our Business." Currently, we have
sufficient funds and a line of credit to meet our current working capital
needs. Assuming all of the shares offered by this prospectus are sold at a
price of $_____ U.S. per share, we would realize net proceeds (after estimated
expenses of the offering of $______) of approximately $______. The net proceeds
of the offering would be added to our general funds and would not be expressly
designated for any particular purpose. However, we currently expect that the
net proceeds would be used for the following purposes:
<TABLE>
United States Canada
<S> <C> <C>
Working capital to operate the company $__________ $__________
Costs of Kotaneelee litigation $__________ $__________
Exploration and development $__________ $__________
Total: $__________ $__________
</TABLE>
Litigation expenses may vary depending on the progress of the cases in
which we are involved. If the net proceeds of the offering are substantially
less than the estimated amounts, and if we are unable to obtain additional
funds, we will be unable to pursue exploration and development activities or the
Kotaneelee litigation. If the gross proceeds of the offering do not exceed the
costs of this offering, the excess costs over gross proceeds would be paid by us
from our current assets.
DILUTION
You will experience immediate and substantial dilution in net tangible
book value of your shares as a result of this offering. The following table
illustrates the per share dilution to purchasers of shares giving effect to the
sale of all of the shares in the offering at a price of $____ per share.
<TABLE>
<S> <C>
Offering price attributable to each limited voting share ______
Net tangible book value per share before the offering(1) ______
Increase attributable to payments for limited voting shares ______
Pro forma net tangible book value per share after the offering ______
Dilution to purchasers of the shares (2)(3) ______
</TABLE>
(1) We calculate net tangible book value per share by dividing the number of
limited voting shares outstanding into our tangible net worth (tangible assets
less liabilities) at June 30, 2000.
(2) We calculate dilution to new investors by subtracting net tangible book
value per share of our limited voting shares after the offering from the per
share price attributable to each limited voting share purchased.
(3) This estimate of dilution does not reflect the results of operations since
June 30, 2000 nor does it give any effect to the outstanding options to purchase
our limited voting shares. There are _______ shares reserved for share options
granted to our officers, directors and consultants. If the options to acquire
the _________ shares had been exercised at June 30, 2000, then the dilution to
purchasers would be $.___ per share.
TERMS OF OFFERING AND SELLING ARRANGEMENTS
Issuance of the Rights; Guaranteed Amount
We are offering a total of [____________] limited voting shares to our
existing shareholders. For every one (1) share held of record at the close of
business on __________, 2000, shareholders will receive one transferable right.
For every transferable rights, each shareholder will be entitled to purchase
from us at a price of $ U.S. _________ or $ Canadian ______, one additional
share.
How the Contingent Right Operates
If you purchase all of the shares that you are guaranteed the right to
buy, you will also have the right to purchase additional shares which are
contingent on the number of shares that are not purchased by the other
shareholders. This contingent right to purchase additional shares is limited to
times the guaranteed number of shares that you are entitled to purchase. The
shares being offered for sale will first be allocated to satisfy your guaranteed
right to purchase shares. If there are unsold shares remaining after these
allocations, then any unsold shares will be allocated proportionately among the
shareholders who exercised their contingent right to purchase the unsold shares.
To illustrate how the offering works, assume a shareholder owned
[_____] shares of limited voting shares as of the record date. He will receive
_______ rights and is guaranteed the right to purchase [_____] shares. In
addition, if he purchases the total [_____] shares, then he may also exercise
his contingent right for up to [_____] additional shares. In the event that the
offering is oversubscribed, we will accept subscriptions by shareholders for the
guaranteed shares first. Any remaining shares unsold will then be allocated
proportionately among the shareholders who subscribed for the purchase of shares
on a contingent basis.
For example, assume in the aggregate that our shareholders subscribe
for a total of [___________] shares, [___________] shares of which are
guaranteed. Under the terms of the offering [_________] shares are being offered
for sale, [_____________] shares would be issued to shareholders who purchased
their guaranteed shares. The remaining shares offered for sale (_________ minus
[________]) would be available for the shareholders who exercised their
contingent right to purchase shares on a pro rata basis. Each shareholder who
exercised his contingent right would receive ____% (_________ available divided
by [____________] contingent right) of the contingent amount of available
shares.
Transferability and Listing of the Rights
Rights will be evidenced by a Rights Certificate in registered form.
You may transfer the rights you receive to third parties by delivering the
Rights Certificate to them, provided that the Right has been properly executed
and assigned by the registered holder to the third party. The Rights will not be
listed on any U.S. national securities exchange and will not be admitted for
quotation in any automated, inter-dealer quotation system, but may be traded
through any registered investment dealer or broker on whatever market may
develop for them, if any. The Rights are listed on the Toronto Stock Exchange.
Expiration of the Rights
The offering will end at 4:30 P.M. Eastern Standard Time, on
_________, 2000. The date and time when the offering expires is referred to in
this prospectus as the expiration date.
How to Subscribe for Shares and/or How to Revoke Your Subscription
The Rights Certificate which indicates the number of your rights, will
be issued in the name and address of the holders of limited voting shares of
record on _______, 2000 and mailed to shareholders as soon as practicable after
the record date. All rights certificates received prior to the expiration date
will be held by our subscription agents in the United States and Canada
identified in the accompanying Rights Certificate and instructions. Prior to the
formal acceptance of any or all of such subscriptions, all payments will be held
by the agent(s).
Subscriptions may be revoked by delivery of written notice of
revocation to us prior to the expiration date. Subscriptions will be accepted
promptly after the expiration date by our delivery of written confirmation of
acceptance to our agents. They will then be authorized to issue the shares and
make any refunds, without interest, to the extent that the offering is
oversubscribed. A three-day period is necessary to permit the agents to process
all subscriptions received by the expiration date, so that the total number of
guaranteed and contingent shares to be issued can be determined. We reserve the
right to reject any subscription, absent proof in writing from you that all
terms of the offering have been complied with on a timely basis. We will notify
you promptly of any rejection.
Determination of Purchase Price; How to Purchase Shares
In establishing the purchase price, our board of directors considered
recent market prices for our shares. The purchase price is intended by the
directors to be attractive to our shareholders and result in a higher
subscription rate. The purchase price does not reflect our assessment of the
actual value of our assets. All interpretations of matters relating to the
offering will be made by our management and will be final.
You may pay the purchase price either in Canadian or U.S. dollars at
the rates indicated above. We are permitting the payment of the purchase price
in either of these currencies solely for shareholders' convenience. The exchange
rate on ______________, 2000 as reported by the Wall Street Journal was $1.00
Canadian equals U.S. $_____. You may not purchase fractional shares, and only
whole shares will be issued.
Shares may be purchased by surrendering the Rights Certificate to the
agent, along with a signed subscription agreement, together with full payment of
the purchase price for both the shareholder's guaranteed and contingent amounts.
Payment of the purchase price must be made by check, bank draft or money order
payable to the order of one of our subscription agents. Any subscriptions
satisfying these conditions will be accepted; however, subscriptions received
after the expiration date will not be honored and we will not be responsible for
subscriptions not delivered by that time. You are advised to choose a reliable
method (e.g., such as overnight courier service) for the delivery of your
subscriptions to the agents.
You may also purchase your shares by delivering to one of the
subscription agents before the expiration date each of the following:
o the full purchase price together with a signature guarantee in
writing or by facsimile from a bank or trust company or a
member firm of any U.S. registered stock exchange that a
Rights Certificate with respect to shares subscribed for has
been or will be promptly delivered to the agent within three
business days, and
o information setting forth the name of the subscriber and the
serial number of the Rights Certificate. Subscriptions
satisfying these conditions will be accepted subject to prompt
receipt by the agent of the duly executed Rights Certificate,
within three business days.
Issuance and Delivery of the Shares
As soon as practicable after the expiration date, we will issue the
limited voting shares to be issued with respect to all accepted subscriptions to
you, together with any applicable refund. The shares will be registered in the
name and manner set forth on the subscription agreement which you provide to us.
UNITED STATES TAX CONSEQUENCES OF THE OFFERING
Your receipt of the subscription rights will have certain federal
income tax consequences for U.S. resident shareholders. The following discussion
is the likely position of the Internal Revenue Service regarding the tax
consequences of the receipt of your subscription rights. This discussion is not
intended to serve as tax advice to you, and you should consult your personal tax
advisor for advice relating to your personal tax situation.
The mere receipt of these rights alone will not result in the
recognition of taxable income under the Internal Revenue Code. While you will
not have to report taxable income upon the receipt of your subscription rights,
you may have to allocate a portion of the adjusted basis of your original shares
to any shares that you purchase in the offering.
If you do not exercise your subscription rights, you will not be
allowed to claim a loss, and no adjustment will be made to the tax basis of your
shares. If the subscription rights are exercised, you may be required to
allocate a portion of the basis of your original shares to the shares that you
purchase in the offering, depending on whether the fair market value of the
rights equals or exceeds 15% of the fair market value of your original shares at
the time of receipt of your rights.
If the fair market value of your subscription rights is 15% or more of
the fair market value of the shares you currently own, you must allocate to the
purchased shares part of the basis of your original stock, in the same
proportion which the fair market value of the subscription rights bears to the
total of the fair market value of your original shares and the fair market value
of the subscription rights. The total tax basis of your newly purchased shares
will equal the allocated basis attributable to the subscription rights plus the
purchase price of the purchased shares. The holding period for shares acquired
by exercise of the subscription rights will begin from the date the subscription
rights are exercised.
If the fair market value of the subscription rights is less than 15% of
the fair market value of the shares you currently own, you may elect to allocate
a portion of your current tax basis to the shares that you purchase as discussed
above. If you do not elect to allocate your tax basis, then your tax basis in
the purchased shares will be your purchase price of the offered stock.
The above discussion is not applicable to a rights holder who is not a
shareholder when the rights are received. Such right holders who purchase rights
and purchase shares of our limited voting shares should apply the general rules
that are applicable to the purchase and sale of such securities.
CANADIAN TAX CONSEQUENCES OF THE OFFERING
The following is a summary of the principal Canadian federal income tax
considerations generally applicable to the rights being distributed to you. This
discussion applies to shareholders who at all relevant times for purposes of the
Canadian Income Tax Act deal at arm's length with us, are not affiliated with
us, hold their rights and shares as capital property and do not, and are not
deemed to, use or hold their rights or shares in or in the course of carrying on
business in Canada. This summary does not apply to an insurer whose rights or
shares are designated insurance property within the meaning of the Income Tax
Act. The summary is based on the current provisions of the Income Tax Act and
the regulations, all specific proposals to amend the Income Tax Act and the
regulations publicly announced by the Minister of Finance as of September 21,
2000, and Canadian counsel's understanding of the current administrative
policies and assessing practices of the Canada Customs and Revenue Agency. This
summary does not consider or anticipate any changes in law whether by
legislative, governmental or judicial decision or action, nor does it consider
the tax legislation or considerations of any province or territory or
jurisdiction outside Canada. This summary does not apply to a non-resident that
is an insurer carrying on business in Canada and elsewhere. This summary assumes
that the shares are listed on a prescribed stock exchange for purposes of the
Income Tax Act at all relevant times. The Toronto Stock Exchange, the Pacific
Stock Exchange and Nasdaq are prescribed stock exchanges.
Issuance of Rights
If you are a resident of Canada for the purposes of the Income Tax Act, you
will not be required to include any amount in income upon the issuance of the
rights to you. If you are not resident (or deemed to be resident) in Canada for
purposes of the Income Tax Act, you will not be subject to Canadian federal
income tax on the issuance of the rights and there will be no Canadian
non-resident withholding tax applicable on the issuance of the rights to you.
The rights distributed to you will have a "nil" cost to the initial holder
for the purposes of the Income Tax Act. The cost of the rights acquired must be
averaged with the adjusted cost base to the shareholder of all other identical
rights held as capital property by that shareholder immediately before the
acquisition in order to determine the adjusted cost base to the shareholder of
each right held by the shareholder.
Exercise of Rights
You will not realize any capital gain or loss when you exercise your
rights. Each limited voting share acquired by you as a result of the exercise of
rights will have a cost to you equal to the aggregate of the subscription price
paid for such share and the adjusted cost base to you of the rights exercised.
This cost will then generally be averaged with the adjusted cost base of all of
our other limited voting shares owned by you as capital property and acquired
after December 31, 1971 for the purpose of determining the adjusted cost base to
you of each such share held by you.
Disposition of Rights
Upon the disposition or deemed disposition of a right by you, a capital
gain (or capital loss) will be realized to the extent that your proceeds of
disposition of the right exceed (or are exceeded by) the aggregate of your
adjusted cost base of the right and any reasonable costs of disposition.
If you are a resident in Canada for purposes of the Income Tax Act, based
on proposed amendments to the Income Tax Act, two-thirds of a capital gain
must be included in computing your income under the Income Tax Act, and
two-thirds of a capital loss may be deducted against taxable capital gains in
accordance with the detailed provisions of the Income Tax Act and the proposed
amendments. If you are a Canadian-controlled private corporation, you may be
liable to pay an additional refundable tax of 6 2/3% on taxable capital gains.
If you are an individual, other than certain trusts, you may be subject to an
alternative minimum tax for realized capital gains.
If you are not resident (or deemed to be resident) in Canada for purposes
of the Income Tax Act, you will generally not be subject to Canadian tax on the
disposition of rights unless, the rights constitute taxable Canadian property.
In general, a right will not be taxable Canadian property to you unless, at any
time during the 60 month period immediately before the disposition, you, persons
with whom you did not deal at arm's length, or you and such persons owned (or
had the right to acquire through the offering or otherwise) not less than 25% of
the issued shares of any class or series of our capital stock. In certain
circumstances, rights may be deemed to be taxable Canadian property. In certain
circumstances, you may be entitled to relief under an applicable international
tax treaty between Canada and your country of residence.
Upon the expiration of an unexercised right, if you are a resident of
Canada for purposes of the Income Tax Act, you will realize a capital loss equal
to the adjusted cost base of the right to you. If you hold an unexercised right
and have not received any right other than through this offering, your right
will have an adjusted cost base of nil and the expiration of the right will not
give rise to a capital loss.
THE FOREGOING DISCUSSIONS RELATING TO UNITED STATES AND CANADIAN TAXES
ARE NOT INTENDED TO SERVE AS LEGAL OR TAX ADVICE TO ANY PARTICULAR SHAREHOLDER.
TO DETERMINE THE TAX CONSIDERATIONS APPLICABLE TO THEM, SHAREHOLDERS SHOULD
CONSULT THEIR OWN TAX ADVISORS.
<PAGE>
CAPITALIZATION
The following table shows our cash and cash equivalents, investments
and total capitalization:
o on an actual basis as of June 30, 2000; and
o as adjusted to reflect the sale of [__________] shares offered
by this prospectus at an assumed public offering price of
$[____] per share, after deducting the estimated offering
expenses payable by us.
You should read this information together with our financial statements
and the notes relating to those statements and "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and "Use of Proceeds"
appearing elsewhere in this prospectus.
<TABLE>
As of June 30, 2000
Actual As adjusted
<S> <C> <C>
Cash and cash equivalents $2,185,918 $____________
Marketable securities 291,342
Short-Term Debt - -
Long-Term Debt - -
Stockholders' Equity (Deficit):
Limited Voting Shares, par value $1.00 per share:
Limited Voting Shares $ 14,284,970 $____________
Contributed surplus 26,502,342 $____________
Deficit (27,332,063) $____________
------------
Total Shareholders' Equity $ 13,455,249 $____________
============
</TABLE>
The number of shares as adjusted for this offering excludes 598,500 shares
issuable upon the exercise of outstanding options held by our directors,
officers and consultants as of June 30, 2000.
<PAGE>
MARKET INFORMATION
Our limited voting shares are traded on The Toronto, Pacific and Boston
Stock Exchanges [Symbol: CSW], and in the NASDAQ SmallCap Market [Symbol:
CSPLF].
The quarterly high and low closing prices in Canadian dollars on The
Toronto Stock Exchange during the calendar periods indicated were as follows:
<PAGE>
<TABLE>
1998 1st quarter 2nd quarter 3rd quarter 4th quarter
---- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
High 11.75 10.50 9.00 10.00
Low 9.00 8.00 5.50 6.25
1999 1st quarter 2nd quarter 3rd quarter 4th quarter
---- ----------- ----------- ----------- -----------
High 11.00 11.00 16.00 12.35
Low 6.00 7.50 10.75 8.00
2000 1st quarter 2nd quarter 3rd quarter*
---- ----------- ------------ ------------
High 12.50 10.50 10.50
Low 8.25 6.30 8.00
---------------------------
* Through August 31, 2000
</TABLE>
<PAGE>
The quarterly high and low closing prices in U. S. dollars on the NASDAQ
SmallCap Market during the calendar periods indicated were as follows:
<TABLE>
1998 1st quarter 2nd quarter 3rd quarter 4th quarter
---- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
High 8.50 7.88 6.63 6.75
Low 6.25 5.63 3.31 3.94
1999 1st quarter 2nd quarter 3rd quarter 4th quarter
---- ----------- ----------- ----------- -----------
High 7.63 7.50 11.50 8.50
Low 4.50 5.38 6.50 5.09
2000 1st quarter 2nd quarter 3rd quarter*
---- ----------- ------------ ------------
High 8.44 7.50 7.06
Low 5.63 4.25 5.13
------------------------------
* Through September 19, 2000
</TABLE>
<PAGE>
<TABLE>
Trading Volume Shares
2000 1999 1998 1997
----- ---- ---- ----
<S> <C> <C> <C> <C>
NASDAQ SmallCap Market * 9,476,820 6,359,187 4,868,392 5,744,756
Pacific Exchange, Inc. ** 8,300 156,300 876,100 1,674,600
Toronto Stock Exchange ** 138,426 177,576 71,218 131,131
* Through September 19, 2000
** Through August 31, 2000
</TABLE>
As of September 1, 2000, we had approximately 4,400 record holders of
our limited voting shares. We have never paid a dividend on our limited voting
shares. Any future dividends will be dependent on our earnings, financial
condition, and business prospects. We are 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 our accumulated deficit ($27,332,000
at June 30, 2000) is eliminated. Current Canadian law does not restrict the
payment of dividends to persons not resident of Canada. Under current Canadian
tax law and the Canada-United States Income Tax Convention (1980), any dividends
paid to U.S. resident shareholders under the Convention are generally subject to
a 15% Canadian withholding tax.
<PAGE>
PERFORMANCE GRAPH
The graph below compares the cumulative total returns, including
reinvestment of dividends, if applicable, of our shares with companies in the
NASDAQ Market Index and an Industry Group Index. (Media General's Independent
Oil and Gas Industry Group). The chart displayed below is presented in
accordance with SEC requirements. Shareholders are cautioned against drawing any
conclusions from the data contained therein, as past results are not necessarily
indicative of future performance.
<TABLE>
COMPARISON OF CUMULATIVE TOTAL RETURN
January 1, 1995 to June 30, 2000
---------------------------------- ------------- ------------ ------------ ------------- ------------ ------------ -------------
June
1994 1995 1996 1997 1998 1999 2000
---------------------------------- ------------- ------------ ------------ ------------- ------------ ------------ -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Canada Southern 100 144.32 151.35 179.73 105.41 127.03 140.54
---------------------------------- ------------- ------------ ------------ ------------- ------------ ------------ -------------
Independent Oil & Gas 100 109.42 141.00 131.27 85.03 119.12 149.24
---------------------------------- ------------- ------------ ------------ ------------- ------------ ------------ -------------
NASDAQ Market Index 100 129.71 161.18 197.16 278.08 490.46 479.98
---------------------------------- ------------- ------------ ------------ ------------- ------------ ------------ -------------
</TABLE>
<PAGE>
OUR BUSINESS
General
We incorporated in 1954 under the Canada Corporations Act. In 1979, we
became subject to the Canada Business Corporations Act, and in 1980, we
continued under the Nova Scotia Companies Act.
We are, either in our own right, or through other entities, engaged in
the exploration 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 we have interests are
undeveloped, all properties with proved reserves are partially or fully
developed. Our interests in exploratory ventures are on properties located in
Alberta, British Columbia, Saskatchewan, the Northwest and Yukon Territories and
the Arctic Islands in Canada. Our principal asset is our 30% carried interest in
the Kotaneelee field, a partially developed gas field (See "Legal Proceedings"
at page 47). We also have interests in producing properties in British Columbia
and Alberta.
The majority of our oil and gas interests are carried interests
pursuant to agreements which provide that revenues are not payable to us until
expenditures by the carrying partners have been recouped from production, and
that operating decisions are made by the carrying partners. Generally, we 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 our share of the
unrecouped expenditures for the unit (i.e., expenditures not recouped from
production revenues). If we convert to a working interest, we will receive our
share of production revenues currently, but we must also pay for our share of
operating and capital expenditures currently. At June 30, 2000, our share of
unrecouped expenditures was as follows:
British Columbia:
Ex-permit 149 $4,009,000
Ex-permit 102 (Siphon) 980,000
Yukon and Northwest Territories:
Ex-permit 2713 (Celibeta) 321,000
We currently have two full-time employee and one part-time employee,
all of whom are located in Canada. We also rely to a great extent on consultants
(approximately 7) for technical, legal, accounting and administrative services.
We use consultants because it is more cost effective than employing a larger
full time staff.
Yukon Territory - The Kotaneelee Field
Our principal asset is a 30% carried interest in the Kotaneelee natural
gas field located on Exploration Permit 1007 in the Yukon Territory, Canada. The
permit consists of 31,888 gross acres (9,566 net acres) which is partially
developed by two natural gas wells that had combined gross productive capability
at June 30, 2000 of 65 million cubic feet per day (19.2 million cubic feet per
day net). Gross natural gas sales were approximately 45 million cubic feet per
day (net 13.5 million cubic feet per day) at June 30, 2000 as a result of
shrinkage and fuel gas requirements. Anderson Exploration Ltd. operates the
Kotaneelee field. See "Legal Proceedings" at page 47 for a discussion of the
Kotaneelee litigation concerning this asset.
Production at Kotaneelee commenced in February 1991. According to
reports filed with the Yukon government, total production in billion cubic feet
("bcf") from the Kotaneelee gas field since 1991 has been as follows:
Calendar Year Production (bcf)
------------- ----------------
1991 8.1
1992 18.0
1993 17.5
1994 16.7
1995 15.7
1996 15.2
1997 14.4
1998 16.0
1999 22.3
2000 (6 months) 10.6
----
Total through June 30, 2000 154.5
=====
As a carried interest owner, we are entitled to receive our share of
field revenues after the working interest parties recover their operating and
capital costs. The operator reported that as of November 30, 1999 development
costs totaling $96.7 million had been incurred and repaid. As of December 31,
1999, the operator also reported that our share of net revenues due to us
totaled $412,374. The amount of recoverable costs is one of the issues being
contested in the Kotaneelee litigation. We claim, and the defendants deny, that
the defendants have made improper charges to the carried interest account and
one defendant (Amoco Canada) maintains that the carried interest account should
be charged additional amounts for gas processing fees. Amoco Canada claims that
the remaining costs to be recovered at December 31, 1999 were either $58,711,000
or $19,235,000 depending on inclusion of interest. At this time, it is not
possible to determine whether Amoco Canada will be successful in its claim that
gas processing fees should be charged to the carried interest account.
Although, according to the operator's reports, the Kotaneelee gas field
reached pay out status on November 10, 1999, the operator has notified us that
it will not make any payments to the carried interest owners, including us,
until the issue of the amount of recoverable costs under the carried interest
account has been resolved by the Court of Queen's Bench of Alberta, Canada. The
operator has stated that it will deposit our share of net production proceeds in
an interest bearing account with an escrow agent. A motion was filed in December
1999 by us to direct all of the defendants to make timely payments of all
current and future amounts due from our share of field revenues. On April 10,
2000, the Court dismissed the motion. We have filed a notice of appeal of the
dismissal with the Alberta Court of Appeal. Net production proceeds are unlikely
to be paid to us until final resolution of the Kotaneelee litigation.
Since March 2000, the operator of the Kotaneelee field has been
reporting the amount of our share of net revenues being deposited in escrow. The
September 2000 report provided information for production during the month of
June 2000. Based on the reported data, we believe the total amount due to us is
$5,526,365 of which $1,832,335 has been deposited in escrow.
British Columbia
Our major source of income has been from the sale of crude oil and
natural gas from our properties located in northeast British Columbia where we
have royalties and carried interests. In addition to our producing properties,
we have various petroleum and natural gas leases in northeast British Columbia.
As a result of the geological and geophysical work performed on these leases,
various drilling prospects have been identified. The cumulative dry hole costs
to drill these prospects are estimated to be approximately $2 million. We
continue to evaluate and attempt to acquire additional petroleum and natural gas
leases in British Columbia. Presently, we have interests in 49,013 gross
developed acres (7,977 net acres) and 28,820 gross undeveloped acres (15,091 net
acres). We believe that these prospects will be drilled by us or others.
Canadian Arctic Islands
As of June 30, 2000, we held working interests in 45,100 gross acres
(1,817 net acres) and carried interests in 133,260 gross acres (37,257 net
acres) in the Sverdrup Basin, located in the Arctic Islands. The Hecla,
Whitefish, Drake Point, Roche Point, Kristoffer, Romulus and Bent Horn fields
have been designated Significant Discovery Lands by the Canadian Federal
Government. There interests are being retained under Significant Discovery
Licenses pending development.
Panarctic Oils Ltd. ("Panarctic"), the operator, received Federal
government regulatory approvals for a pilot project to move shipments of crude
oil from the Bent Horn field by tanker through the Northwest Passage to southern
Canada in 1985. Through December 31, 1996, approximately 2.7 million barrels of
Bent Horn crude had been sold. In 1996, the operator shut down production from
the field and dismantled the production facilities because of economic
uncertainties. We have a 5% carried interest in the area which has not yet
reached pay out status. The timing of any pay out is uncertain.
Major operators and industry investors have recently indicated interest
in exploring the Canadian Arctic Islands region to develop additional gas
reserves and productive capacity. Recent statements by major oil and gas
producers indicate that technological developments and the sustained world
prices for natural gas may lead to expanded exploration and production efforts
in the Canadian Arctic Islands, as well as advance the construction of a natural
gas pipeline to the region in the future.
<PAGE>
Northwest Territories Properties
We have a 45% carried interest in the Northwest Territories in the
Celibeta field, designated as Significant Discovery Lands by the Federal
Government (1,594 gross acres and 717 net acres). The gas field is presently
shut-in. Because of the recent activity in the Northwest Territories, we are
reviewing our holdings in the area to take advantage of any potential
opportunities.
Alberta
During 1999, our primary Alberta asset and revenue producing property
was our heavy crude oil production and related facilities at Kitscoty. Due to
the requirement of significant additional investment, the prospect of low prices
for heavy oil and a shift in our business strategy, we sold our 10 % working
interest to the operator for $336,000 effective October 1, 1999. The transaction
was completed during February 2000 and the proceeds of sale were credited to oil
and gas properties in fiscal 2000. In 1999, the Company participated in the
drilling of 4 gross (.7 net) wells. Two wells were productive and two wells were
dry and abandoned. All of these wells were drilled on shallow natural gas
prospects.
We continue to invest in petroleum and natural gas leases in Alberta
and have a current land inventory of 21,477 gross acres (7,349 net acres). We
are presently performing geological and geophysical work on these leases to
determine the prospects for commercial petroleum and natural gas production. As
prospects are identified, we may participate in drilling or, alternatively, farm
out the prospects to other operators for drilling commitments.
Saskatchewan
We have a 3.75% working interest in five sections in Saskatchewan.
During 1999, there was no activity on these properties and the lands remain
undeveloped.
Texas
In 1999, we participated in the drilling and completion of two wells in
Stephens County, Texas. This resulted in one dry hole and one nominal crude
oil/natural gas producer. Our efforts to farm out our remaining undrilled
acreage have been unsuccessful and we expect to spend a minimal amount on the
investment during the year 2000. During the second quarter of fiscal 2000, the
carrying costs ($635,000) of the project on our books were written down to a
nominal value of $1.00
California
During 1999, we sold our investment in our heavy crude oil recovery
project in California because of dissatisfaction with the progress of the
program to develop the field reserves. The consideration received for our 30%
interest was the purchaser's common stock (presently unmarketable) and a
promissory note which together approximated the carrying costs ($196,000) of the
property prior to the costs being written down in 1998 to a nominal value of $1.
Patents, Licenses, Franchises and Concessions Held
Permits and concessions are important to our operations, since they
allow the search for and extraction of any crude oil and natural gas discovered
on the areas covered. See "Properties" at page 40.
Seasonality of Business
Our 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.
Customers
Most of the natural gas produced from our carried interest properties
is being sold by the operators, Anderson Exploration Ltd. and Petro-Canada Oil
and Gas, to various gas marketers. The production from the Kotaneelee gas field
is being sold by the working interest partners. They have not disclosed the
purchasers.
Supplemental Information on Oil & Gas Activities
For additional information regarding our business, see "Supplemental
Information on Oil and Gas Activities at page F-21."
Competitive Conditions in Our Business
The exploration for and production of crude oil and gas are highly
competitive operations, both internally within the oil and gas industry and
externally with producers of other types of energy. The ability to exploit a
discovery of crude oil or gas is dependent upon considerations such as the
ability to finance development costs, the availability of equipment, and the
ability to overcome engineering and construction delays and difficulties. We
must compete with companies which have substantially greater resources available
to them. Because the majority of our interests are in remote areas, operation of
our properties is more difficult and costly than those in more accessible areas.
Furthermore, competitive conditions may be substantially affected by
various forms of energy legislation which may have been or may be proposed in
the United States and Canada; however, it is not possible to predict the nature
of any such legislation which may ultimately be adopted or its effects upon our
future operations.
<PAGE>
Financial Information about Foreign and Domestic Operations and Export Sales
Revenues, Operating Losses and Identifiable Assets
Substantially all of our operating assets and revenues are attributable
to our operations in Canada. Operating losses are substantially attributable to
the ongoing Kotaneelee litigation.
Risks Attendant to Foreign Operations
The properties in which we have interests are located primarily in
Canada and are subject to certain risks involved in the ownership and
development of such foreign property interests. These risks include but are not
limited to those of: nationalization; expropriation; confiscatory taxation;
native rights; changes in foreign exchange controls; currency fluctuations;
burdensome royalty terms; export sales restrictions; limitations on the transfer
of interests in exploration licenses; and other laws and regulations which may
adversely affect our interests in these properties, such as those providing for
conversion, proration, curtailment, cessation or other forms of limiting or
controlling production of, or exploration for, hydrocarbons. Thus, an investment
in our shares 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 we are unable to predict whether any additional
legislation or amendments may be enacted.
Land Tenure
Crude oil and natural gas located in the western provinces is owned
predominantly by the respective provincial governments. Provincial governments
grant rights to explore for and produce crude oil and natural gas pursuant to
leases, licenses and permits for varying terms and on terms and conditions set
forth in provincial legislation including requirements to perform specific work
or make payments. Crude oil and natural gas located in such provinces can also
be privately owned and rights to explore for and produce such crude oil and
natural gas are granted by lease on such terms and conditions as may be
negotiated. The term of both provincial and freehold leases will generally
continue as long as crude oil or natural gas is produced from the property.
Crude oil and natural gas rights on federal lands is generally
regulated by the Government of Canada unless authority has been delegated by
agreement to the territorial government or the government of the province
adjacent to the federal offshore area. In May 1993, the Canada Yukon Oil and Gas
Accord was signed which allowed for the transfer to the Yukon of authority to
administer and control crude oil and natural gas resources within that territory
and for the establishment of an Oil and Gas Management Regime. The transfer has
been completed and the lands are now administered by the Yukon Government.
Production and Production Facilities
The Governments of Canada, Alberta, British Columbia and Saskatchewan
have enacted statutory provisions regulating the production of crude oil and
natural gas. These regulations may restrict the maximum allowable production
from a well based on reservoir engineering and/or conservation practices. The
construction and operation of facilities to recover and process crude oil and
natural gas are also subject to regulation.
Pricing and Marketing - Crude oil
In Canada, producers of crude oil negotiate sales contracts directly
with crude oil purchasers, with the result that the market determines the price
of crude oil. Certain purchasers periodically advertise for volumes of crude oil
they are prepared to purchase and the price being offered for such volumes. The
price depends in part on crude oil quality, prices of competing fuels, distance
to market and the value of refined products.
Pricing and Marketing - Natural Gas
In Canada, the price of natural gas is determined by negotiation
between buyers and sellers, with the result that the market determines the price
of natural gas. Natural gas exported from Canada is subject to regulation by the
National Energy Board ("NEB") and the Government of Canada. Exporters are free
to negotiate prices and other terms with purchasers, provided that the export
contracts must continue to meet certain criteria prescribed by the NEB and the
Government of Canada. As is the case with crude oil, natural gas exports for a
term of less than two years must be made pursuant to an NEB order, or, in the
case of exports for a longer duration, pursuant to an NEB license and Governor
in Council approval.
The Governments of Alberta, British Columbia and Saskatchewan also
regulate the volume of natural gas which may be removed from those provinces for
consumption elsewhere based on such factors as reserve availability,
transportation arrangements and market considerations.
Royalties and Incentives
The royalty regime is a significant factor in the profitability of
crude oil and natural gas production. Royalties payable on production from lands
other than Crown lands are determined by negotiations between the mineral owner
and the lessee, although production from such lands may also be subject to
provincial taxes and regulations. Crown royalties are determined by government
regulation and are generally calculated as a percentage of the value of the
gross production, and the rate of royalties payable generally depends in part on
prescribed reference prices, well productivity, geographical location, field
discovery date and the type or quality of the product produced. The value of the
gross production for royalty purposes may be based on a deemed value for the
product rather than the actual value received by the interest holder.
From time to time the Governments of Canada, Alberta, British Columbia
and Saskatchewan have established incentive programs which have included royalty
rate reductions, royalty holidays and tax credits for the purpose of encouraging
natural gas and crude oil exploration or enhanced recovery projects. Incentives
are intended to enhance the existing cash flow of the crude oil and natural gas
industry and to improve the economics of finding and developing new and more
costly crude oil and natural gas reserves. Crude oil royalty holidays for
specific wells and royalty reductions reduce the amount of Crown royalties paid
by the interest holder to the respective government. Tax credit programs provide
a rebate on Crown royalties paid.
Environmental Regulation
The oil and natural gas industry is subject to environmental regulation
pursuant to local, provincial and federal legislation. Environmental legislation
provides for restrictions and prohibitions on spills, releases or emissions of
various substances produced in association with certain crude oil and natural
gas industry operations. An environmental assessment and review may be required
prior to initiating exploration or development projects or undertaking
significant changes to existing projects. In addition, legislation requires that
well and facility sites be abandoned and reclaimed to the satisfaction of the
appropriate authorities. A breach of such legislation may result in the
imposition of fines or penalties. Federal environmental regulations also apply
to the use and transport of certain restricted and prohibited substances. We are
committed to meeting our responsibilities to protect the environment wherever we
operate and believe that we are in material compliance with applicable
environmental laws and regulations. We have not been required to spend
significant sums to comply with clean up laws and regulations. Compliance by us
with governmental provisions regulating the discharge of materials to the
environment or otherwise relating to the protection of the environment is not
expected to have a material effect on our capital expenditures, earnings or
competitive position.
PROPERTIES
Our principal asset is our 30% carried interest in the Kotaneelee
field, a partially developed gas field in the Yukon Territory. See "Legal
Proceedings" at page 47. We also have interests in producing properties in
British Columbia and Alberta and in several exploration prospects. The
exploratory ventures are properties located in British Columbia, Alberta,
Saskatchewan, the Yukon and Northwest Territories and the Arctic Islands in
Canada. Geophysical, geological and drilling work on our properties is conducted
by the operators under various agreements with us. The results of this work are
reviewed by our personnel and consultants retained by us. Information regarding
reserves, costs of oil and gas activities, capitalized costs, discounted future
net cash flows and results of operations is set forth in "Consolidated Financial
Statements" beginning at page F-21.
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of Canada showing Company Areas of Interest
<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 Kotaneelee field.
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map showing the Kotaneelee Permit Structure
<PAGE>
The following graphic presentation has been omitted, but the following is a
description of the omitted material:
Map of the Canadian Arctic Islands
showing the Company Lease Holdings
<PAGE>
Production
Average sales price per unit and average production cost for oil and
gas produced during the periods are shown below. Production costs are allocated
based on the weighted average of oil and gas sales. In 1999, oil production was
primarily heavy crude oil with high lifting costs. In prior years, oil
production consisted of a mix of light and heavy crude oil. We sold the majority
of our crude oil producing properties in 1998. The remaining heavy oil
production was sold in February 2000.
<TABLE>
Average Sales Price Average Production Costs
Period Oil (per bbl) Gas (per mcf) Oil (per bbl) Gas (per mcf)
------ ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Six months ended June 30, 2000 ($) 34.34 ($) 2.32 ($) 54.87 ($) 2.33
Year 1999 17.38 1.83 12.82 1.45
Year 1998 14.84 2.17 8.41 1.41
Year 1997 22.50 2.31 8.70 1.30
</TABLE>
Productive Wells and Acreage
Productive wells and acreage on working and carried interest properties
as of June 30, 2000 are as follows:
Gross Wells Net Wells
--------------------- --------------------
Oil Gas Oil Gas
1 65 .55 11.39
Gross and Net Developed Acres
Gross Acres Net Acres
----------- ---------
Alberta 4,780 605
British Columbia 49,013 7,977
Yukon Territory 3,350 1,005
Arctic Islands 3,060 153
Texas, USA 40 16
-------- -------
60,243 9,756
====== =====
<PAGE>
Undeveloped Acreage
Total developed and undeveloped acreage in which we have interests is
summarized by geographic area in the table below:
<TABLE>
Gross and Net Petroleum Acreage as of June 30, 2000
Developed Acres Undeveloped Acres
-------------------------------- -------------------------------
Gross Net Gross Net
Acres Acres % Acres Acres %
----- ----- - ----- ----- -
Canada:
British Columbia:
<S> <C> <C> <C> <C> <C> <C>
Carried Interests 30,130 6,410 21.3 5,708 1,213 21.3
Working Interests 5,622 910 16.2 18,473 13,804 74.7
Overriding royalty interest 13,261 657 5.0 4,639 74 1.6
------ ----- ---- ------ ------
Total British Columbia 49,013 7,977 28,820 15,091
------ ----- ------ ------
Saskatchewan:
Working Interests 3,200 120 3.8
----- ---
Alberta:
Working Interests 2,871 581 18.4 21,477 7,349 34.2
Overriding Royalty Interest 1,909 24 1.3 160 5 3.1
----- -- ------ -----
Total Alberta 4,780 605 21,637 7,354
----- --- ------ -----
Yukon & Northwest Territories:
Carried Interests 3,350 1,005 30.0 31,726 9,757 30.8
Arctic Islands:
Carried Interests 3,060 153 5.0 130,200 37,104 28.5
Working Interests - - 45,100 1,817 4.0
----- --- ------- ------
Total Arctic Islands 3,060 153 175,300 38,921
----- --- ------- ------
Total Canada 60,203 9,740 260,683 71,243
Texas, USA 40 16 40.0 460 245 53.3
----- ----- ------ -----
TOTAL 60,243 9,756 261,143 71,488
====== ===== ======= ======
</TABLE>
Drilling activity
Productive and dry net wells drilled during the following periods:
<TABLE>
Period Gross Net
------ ------------------------ ------------------------
Productive Dry Productive Dry
<S> <C> <C> <C> <C>
Six months ended June 30, 2000 - 1 .333
Year 1999 4 2 1.127 .798
Year 1998 9 2 1.440 .200
Year 1997 25 2 3.606 .250
</TABLE>
There were no wells drilling at June 30, 2000.
LEGAL PROCEEDINGS
We believe 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, we filed statements of claim in the Court of
Queen's 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, Columbia Gas Development
of Canada Ltd., Mobil Oil Canada Ltd. and Esso Resource of Canada Ltd. In 1991,
Anderson Exploration Ltd. acquired all of the shares in Columbia and changed its
name to Anderson Oil & Gas Inc. 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
proceedings currently at trial.
We claim that the defendants breached a contractual obligation and/or a
fiduciary duty owed to us to market gas from the Kotaneelee gas field when it
was possible to so do. We assert that marketing the Kotaneelee gas was possible
in 1984 and that the defendants deliberately failed to do so. We seek money
damages and the forfeiture of the Kotaneelee gas field. We presented evidence at
trial that the money damages sustained by us were approximately $100 million.
In addition, we have claimed that our carried interest account should
be reduced because of improper charges to the carried interest account by the
defendants. We claim 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, we claim 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, we claim, were inappropriately charged to the
field's carried interest account. The effect of an increased carried interest
account is to extend the period before pay out begins to the carried interest
account owners.
We claim that production from the field should have commenced in 1984.
At that time the field's carried interest account was approximately $63 million.
We claim that by 1993 at least $34 million of unnecessary expenses had been
wrongfully charged to the carried interest account. Our 30% share of these
expenses would be approximately $10.2 million. We further claim that if
production had commenced in 1984, the carried interest account would have been
paid out in approximately two years and we would have begun to receive revenues
from the field in 1986.
The amount of recoverable costs is one of the issues being contested in
the Kotaneelee litigation. We claim, and the defendants deny, that the
defendants have made improper charges to the carried interest account and one
defendant (Amoco Canada) maintains that the carried interest account should be
charged additional amounts for gas processing fees. Amoco Canada claims that the
remaining costs to be recovered at December 31, 1999 were either $58,711,000 or
$19,325,000 depending on inclusion of interest. It is not possible to determine
whether Amoco Canada will be successful in its claim that gas processing fees
should be charged to the carried interest account.
Although, according to the operator's reports, the Kotaneelee gas field
reached pay out status on November 10, 1999, the operator has notified us that
it will not make any payments to the carried interest owners, including us,
until the issue of the amount of recoverable costs under the carried interest
account has been resolved by the Court of Queen's Bench of Alberta, Canada. The
operator has stated that it will deposit our share of net production proceeds in
an interest bearing account with an escrow agent. A motion was filed in December
1999 by the plaintiffs in Canada to direct all of the defendants to make timely
payments of all current and future amounts due from our share of field revenues.
On April 10, 2000, the trial court dismissed our motion pending the Court's
ultimate determination of the issues surrounding the Kotaneelee field
carried-interest account. We have filed a notice of appeal of the dismissal with
the Alberta Court of Appeal. Net production proceeds are unlikely to be paid to
us until final resolution by the Courts of the Kotaneelee litigation.
Since March 2000, the operator of the Kotaneelee field has been
reporting the amount of the Company's share of net revenues being deposited in
escrow. The September 2000 report provided information for production during the
month of June 2000. Based on the reported data, we believe the total amount due
to us is $5,526,365 of which $1,832,335 has been deposited in escrow.
The parties to the litigation conducted extensive discovery since the
filing of the claims. The trial began on September 3, 1996 and we completed the
presentation of our case against the defendants during September 1998. We
completed our rebuttal evidence on April 24, 2000. On June 26, 2000, the we
filed our written closing argument with the court. The defendants filed their
written argument on August 28, 2000. Oral closing arguments will probably be
held in late December 2000 or early 2001. A decision in the litigation is not
expected before late 2001.
Columbia has filed a counterclaim against us seeking, if we are
successful in our claim for the forfeiture of the field, repayment from us of
all unrecovered sums Columbia has expended on the Kotaneelee lands before we are
entitled to our interest.
Based upon newly discovered evidence, we filed a new claim during May
1998 that the defendants failed to develop the field in a timely manner. We are
unable to estimate the time necessary to conclude this litigation.
Matters Ancillary to Kotaneelee Litigation
In our 1989 statement of claim, we 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 we will be assessed a processing fee on gas
throughput.
With respect to the first issue, we maintain that no interest should
accrue on the account and the defendants have not contested this position. With
regard to the second issue, we maintain that the expenditures are chargeable to
the carried interest account. Mobil, Esso and Columbia have essentially agreed
to our position in the original pleadings to the court while the Amoco Dome
Group continues to contest this issue.
On January 22, 1996, we settled two claims outstanding against us in
the Court of Queen's Bench of Alberta, which related to a suit brought against
AlliedSignal Inc. in Florida which was dismissed on the basis that Canada was
the appropriate forum for the litigation. AlliedSignal had sought additional
relief against us in Canada to preclude other types of suits by us and to
recover the costs of the defense of the initial action. The settlement bars
AlliedSignal from making a claim against us for any costs in connection with the
Kotaneelee Litigation. We 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.
Under Canadian law, certain costs (known as "taxable costs") of the
litigation may be assessed against the non-prevailing party. Effective September
1, 1998, the Alberta Rules of Court were amended to provide for a material
increase in the costs which may be awarded to the prevailing party in matters
before the Court.
The trial has been lengthy, complicated and costly to all parties and
we believe that the prevailing party or parties in the litigation will argue for
a substantial assessment of costs against the non-prevailing party or parties.
The Court has very broad discretion as to whether to award costs and
disbursements and as to the calculation of any amounts to be awarded.
Accordingly, we are unable to determine whether, in the event that we do not
prevail on our claims in the litigation, costs will be assessed against us or in
what amounts. However, since the costs incurred by the defendants have been
substantial, and since the Court has broad discretion in the awarding of costs,
an award to the defendants potentially could be material. A cost award against
us could be of sufficient magnitude to necessitate a sale of our assets or a
debt or equity financing to fund such an award. There are no assurances that any
such sale or financing would be consummated.
There is no assurance whatsoever that we will be successful on the
merits of our claims, which have been vigorously defended by the defendants.
There is also no assurance that we will be awarded any damages, or that, if
damages are awarded, the Court will apply the measure of damages we claim should
be applied.
<PAGE>
OUR MANAGEMENT
Our Directors and Executive Officers
Our board of directors includes five members, one of whom also serves
as our president and chief executive officer. Each director is elected for a
term of five years.
<TABLE>
Other Offices
Date Present Term Director Held with
Name of Office Expires Biographical Information Since Company
---- ----------------- ------------------------ ----- -------
<S> <C> <C> <C> <C>
Arthur B. O'Donnell 2001 Annual Meeting Mr. O'Donnell, a CPA, served as an officer of 1997 Audit Committee
the Company for many years prior to his
retirement in 1994. Age seventy-six.
Ben A. Anderson 2002 Annual Meeting Mr. Ben A. Anderson was elected President, 2000 President
Chief Executive Officer and a director of the
Company on April 1, 2000. Mr. Anderson, a
petroleum engineer, has been involved in
operations, reservoir engineering, reserve
evaluation, venture analyses, and marketing in
Western Canada as well as the United States
for the past 19 years. He has been associated
with Ranger Oil, Hillcrest Resources, and
Triumph Energy Corp. Most recently, he had been
President and Chief Executive Officer of
International Gryphon Resources Inc., a
Calgary-based publicly held petroleum exploration
and development company. Age forty-three.
Benjamin W. Heath 2003 Annual Meeting Mr. Heath is President and a director of 1956 Audit Committee
Coastal Caribbean Oils & Minerals, Ltd., and
a director of Magellan Petroleum Corporation.
Age eighty-six.
Timothy L. Largay 2004 Annual Meeting Mr. Largay has been a partner in the law firm 1997 Assistant
of Murtha Cullina LLP, Hartford, Connecticut Secretary
since 1974. Mr. Largay is also a director of
Magellan Petroleum Corporation. Age fifty-seven.
M. Anthony Ashton 2005 Annual Meeting Mr. Ashton served as President and Chief 1989
Executive Officer from June 1997 until his
retirement on June 30, 2000. He had been Vice
President-Exploration since December 1988 and
was elected a director in 1989. Mr. Ashton is
a professional petroleum geologist with more
than thirty years experience in exploration
projects in western Canada and the United
States. Age sixty-five.
</TABLE>
<PAGE>
Our other executive officer is the Chief Financial Officer, David Blain.
<TABLE>
<S> <C> <C>
David Blain Mr. Blain, a Canadian Chartered Accountant, Secretary,
was elected Secretary, Treasurer and Chief Treasurer and
Financial and Accounting Officer of the Company Chief Financial
on August 1, 2000. Mr. Blain has been involved and Accounting
with accounting, income taxes, corporate Officer
planning and finance matters in Western Canada
for the past 30 years. Mr. Blain is an
independent consultant to oil and gas companies
in the Calgary area and will serve the Company
on a part-time basis. He has been associated
with Clarkson Gordon & Co. and Hudson's Bay Oil
& Gas Ltd. He served with Star Oil & Gas Ltd.,
a Calgary based oil and gas company, in various
capacities from 1979 to 1997 and most recently
was Vice President, Finance of that company.
Age fifty-five.
</TABLE>
All of the named companies are engaged in oil, gas or mineral
exploration and/or development except where noted. There are no arrangements or
understandings between any director and any other person or persons pursuant to
which such director was or is to be selected as a director. There are no family
relationships between any director, executive officer, or person nominated or
chosen by the Company to become a director.
Committees of the Board of Directors: Attendance at Meetings
During 1999, we adopted an Audit Committee Charter. The Audit Committee
was comprised of Mr. O'Donnell and Mr. Eugene C. Pendery (until his death on
October 19, 1999). The principal duties of the Audit Committee are: the
engagement and discharge of auditors, reviewing with the auditors the plan and
results of the auditing engagement, reviewing the independence of the auditors
and reviewing the adequacy of the Company's system of internal accounting
controls. The Audit Committee met two times during the year ended December 31,
1999. Mr. Heath was elected to the Audit Committee on January 27, 2000.
We have no standing nominating or compensation committees. The
functions that would be performed by such committees are performed by the full
Board of Directors. During the year ended December 31, 1999, all of the
directors attended at least 75% of the aggregate number of meetings of the Board
of Directors and Committees on which they serve (a total of 10 meetings).
Executive Compensation
The following table sets forth certain summary information concerning the
compensation of Mr. M. Anthony Ashton, who was our President and Chief Executive
Officer until his retirement on March 31, 2000. No executive officer received or
earned any compensation in excess of U.S. $100,000 or Can. $100,000 during the
year 1999. Unless otherwise indicated, all dollar figures set forth herein are
expressed in Canadian currency.
<PAGE>
<TABLE>
---------------------------------------------------------------------------------------------------------------------
Summary Compensation Table
---------------------------------------------------------------------------------------------------------------------
Annual Compensation Long Term
Name and Compensation Award
Principal Position Year Salary ($) Options/SARs(#)
------------------------------------------------- ------------------- ------------------- ---------------------------
<S> <C> <C> <C>
M. Anthony Ashton 1999 50,000 60,000
President and Chief Executive Officer 1998 75,000 -
1997 50,000 -
------------------------------------------------- ------------------- ------------------- ---------------------------
</TABLE>
Stock Options
The following tables provide information about stock options granted
and exercised during 1999 and unexercised stock options held by the Named
Executive Officers at December 31, 1999.
<TABLE>
=======================================================================================================================
Options/SAR Grants in 1999
---------------------------------------------------------------------------------- ------------------------------------
Individual Grants Potential Realized Value at Assumed
Annual Rates of Stock
Price Appreciation for Option Terms
------------------------ ------------ -------------- ------------- --------------- ------------------ -----------------
Name Options/ % of Total Exercise Expiration 5% ($) 10% ($)
SARs Options/SARs or Base Date
Granted Granted to Price ($/Sh)
(#) Employees in
1999
------------------------ ------------ -------------- ------------- --------------- ------------------ -----------------
<S> <C> <C> <C> <C> <C> <C>
M. Anthony Ashton 60,000 13 7.00 Jan. 28, 2004 146,000 256,000
=======================================================================================================================
</TABLE>
<TABLE>
-----------------------------------------------------------------------------------------------------------------------
Aggregated Option/SAR Exercises in 1999 and at December 31, 1999
Option/SAR Values
-----------------------------------------------------------------------------------------------------------------------
Shares Number of Unexercised Value of Unexercised
Acquired Value Options/SARs (#) In-The-Money
On Exercise Realized ($) at December 31, 1999 Options/SARs ($)
(#) at December 31, 1999
-----------------------------------------------------------------------------------------------------------------------
Name Exercisable Unexercisable Exercisable Unexercisable
-----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
M. A. Ashton -0- -0- 70,000 - 116,000 -
-----------------------------------------------------------------------------------------------------------------------
M. A. Ashton -0- -0- 60,000 - 192,000 -
-----------------------------------------------------------------------------------------------------------------------
</TABLE>
Stock Incentive Plans
Under the terms of our 1992 and 1998 stock option plans, we are
authorized to grant certain employees, directors and consultants options to
purchase limited voting shares at prices based on the market price of the shares
as determined on the date of the grant. The options are normally exercisable
immediately and issued for a period of five years from the date of grant.
During 1998, we adopted a stock option plan that permits the granting
of both stock options and stock appreciation rights. A total of 700,000 limited
voting shares are reserved for issuance under the 1998 plan. The plan permits
the granting of both stock options and stock appreciation rights (SARs) to our
directors, officers, key employees and consultants, those of our subsidiaries,
and any business in which we have a substantial interest. The plan is
administered by the Board of Directors acting as a committee of the whole. The
Committee will determine the persons to whom options or SARs are to be granted,
the number of shares which may be acquired upon the exercise of each option or
SAR, the purchase price at which the options or SARs shall be granted, and the
time or times at which options or SARs can be exercised and whether in whole or
installments.
The plan provides for the grant of stock options subject to terms as
determined by the Committee. The purchase price of each option may not be less
than the greater of 1) the par value of the stock underlying the option grant
and 2) the fair market value of the stock on the date of grant. Unless
determined otherwise by the Committee or in an option agreement, options will
vest over a three year period. The options, which are nontransferable except as
specified in the plan, can have a maximum period of ten years, and may expire
earlier in the event that the optionee dies or, in the case of employees,
employment with us is terminated. The plan also includes provisions for the
cashless exercise of options and, at the Committee's discretion, the granting of
reload options when an optionee exercises an option granted under the plan and
makes payment using previously owned shares of stock.
The plan also provides for the grant of SARs subject to terms as
determined by the Committee and evidenced in a form also determined by the
Committee. SARs may be granted alone, simultaneously with a grant of options
under the Plan, or subsequent to a grant of options under the plan. The exercise
price of each SAR granted alone may not be less than the fair market value of
one share of the stock on the date of grant. SARs granted simultaneously with or
subsequent to a grant of options have the same exercise price as the related
option, but are exercisable only when the fair market value of stock subject to
the SAR and related option exceeds the exercise price thereof. Unless determined
otherwise by the Committee or in an SAR agreement, SARs vest over a three year
period and are nontransferable except as specified in the plan. SARs can have a
maximum period of ten years, and are deemed exercised at the end of ten years if
the fair market value of the stock exceeds the exercise price. SARs may expire
earlier in the event that the optionee dies or, in the case of employees,
employment with us is terminated.
We are subject to Canadian tax laws and will generally not be entitled
to an income tax deduction upon either the grant or the exercise of an Option or
SAR.
Compensation of Directors
Each of our directors receive an annual director's fee of $30,000, a
fee of $250 for each conference call meeting and $500 for each meeting requiring
travel. On January 29, 1999, the named directors were granted five year options
to purchase limited voting shares at a price of $7.00. The total directors fees
received and stock options granted in 1999 were as follows:
Director Fee ($) Stock Options Grants
-------- ------- --------------------
Benjamin W. Heath 33,000 20,000
Timothy L. Largay 33,500 75,000
Arthur B. O'Donnell 33,500 60,000
Eugene C. Pendery 27,500 60,000
<PAGE>
Compensation Agreements
Effective January 3, 2000, Ben A. Anderson was employed as Executive Vice
President for a two year period at an annual salary of $120,000. Mr. Anderson
also received 75,000 options to purchase limited voting shares with 1/3 of the
total vesting immediately, 1/3 vesting after one year and 1/3 vesting after two
years. Mr. Anderson will also receive an annual vehicle allowance payment of
$12,000. Mr. Anderson succeeded Mr. Ashton as President and Chief Executive
Officer on April 1, 2000.
Compensation Committee Interlocks and Insider Participation in Compensation
Committee
The entire board of directors serves as the compensation committee. M.
Anthony Ashton is a director and served as our President and Chief Executive
Officer until March 31, 2000.
PRINCIPAL STOCKHOLDERS
Security Ownership of Certain Beneficial Owners
We know of no person or group that owns beneficially more than 5% of
our outstanding limited voting shares.
Security Ownership of Management
The following table sets forth information as to the number of shares
of our limited voting shares owned beneficially on September 1, 2000 by our
directors and by all our executive officers and directors as a group:
<TABLE>
Amount and Nature of
Beneficial Ownership
Name of -------------------------------------
Individual Shares Held Percent of
or Group Directly Options Class
------------------------------------ --------------- --------------- ----------
<S> <C> <C> <C>
M. Anthony Ashton 3,000 130,000 *
Benjamin W. Heath 20,000 75,000 *
Timothy L. Largay 3,615 75,000 *
Arthur B. O'Donnell 1,654 60,000 *
Ben A. Anderson - 75,000 *
Directors and Officers as a
Group (a total of 5) 28,269 415,000 2.90%
------------------------
* The percent of class owned is less than 1%.
</TABLE>
<PAGE>
CERTAIN BUSINESS RELATIONSHIPS
Mr. Timothy L. Largay, a director of Canada Southern since October 1,
1997, is a member of the law firm of Murtha Cullina LLP, which firm has been
retained by us for more than five years and is being retained during the current
year.
On January 29, 1991, we granted interests to certain of our officers,
employees, directors, counsel and consultants amounting to an aggregate of 7.8%
of any and all benefits to Canada Southern after expenses from the litigation in
Canada relating to the Kotaneelee field. We have reserved a 2.2% interest in
such net recoveries for possible future grants to persons who may include our
officers and directors. The following interests were granted directly or
indirectly to our directors:
Party Interest Granted (%)
----- --------------------
Murtha Cullina LLP 1.00
Arthur B. O'Donnell .33 1/3
Benjamin W. Heath .25
Royalty Interests
The following director has royalty interests in certain of our oil and
gas properties (present or past) which were received directly or indirectly from
us: Benjamin W. Heath, interests ranging from 1.772% to 2%; and a trust (in
which Mr. Heath has a 54.4% beneficial interest), interests ranging from 7.603%
to 7.8%. In each case, the applicable percentage depends on the property on
which the royalty is paid.
During 1999, we and third-party operators and/or owners of properties
made payments to Mr. Heath in the amount of U.S. $15,435. During the six month
period ended June 30, 2000, Mr. Heath was paid $8,435.
DESCRIPTION OF OUR LIMITED VOTING SHARES
The following is a brief description of our limited voting shares (par
value $1.00 per share). All rights of our shareholders are determined by the
laws of Nova Scotia, Canada. Nova Scotia law does not, nor do our Articles of
Continuance or By-Laws, impose any limitations on the rights of persons
nonresident of Nova Scotia to vote and hold shares of our limited voting shares
by virtue of such nonresident status.
Voting Rights
Each shareholder is entitled to one vote for each share of limited
voting shares registered in his name on the books of Canada Southern, subject,
however, to a provision in our Articles of Continuance to the effect that no
person shall vote more than 1,000 shares beneficially owned by him or her.
Liquidation and Dividend Rights
Subject to the rights of creditors, all rights to the assets of Canada
Southern available for distribution upon liquidation or upon the payment of any
dividend are vested in the holders of the limited voting shares and each share
is entitled to participate equally with every other share. We are 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 our
accumulated deficit ($27,332,000 at June 30, 2000) is eliminated.
Current Canadian law does not restrict the payment of dividends to
persons not resident of Canada. Under current Canadian tax law and the
Canada-United States Income Tax Convention, any dividends paid to U.S.
resudent shareholders under the convention are generally subject to a 15%
Canadian withholding tax.
Pre-emptive Rights, Conversion Rights, Redemption Provisions. Assessments
The holders of the limited voting shares have no preemptive rights.
There are no conversion rights attached to our limited voting shares and there
are no provisions for sinking funds or redemption of shares. The holders of
outstanding shares of the limited voting shares are not liable to any further
calls or assessments by us.
LEGAL MATTERS
Legal matters relating to United States law in connection with this
offering have been passed upon by Murtha Cullina LLP, Hartford, Connecticut. All
matters relating to Nova Scotia Companies law in connection with the offering
have been passed upon by the firm of Patterson Palmer Hunt Murphy, Nova Scotia.
Blake Cassels & Graydon LLP, Toronto, Canada has passed upon the availability of
prospectus exemptions in Canada for this offering, Canadian federal income tax
consequences and the statement under "Risk Factors - Risks Related to the
Offering" attributed to them.
EXPERTS
The consolidated financial statements of Canada Southern Petroleum Ltd.
at December 31, 1999 and 1998 and for each of the three years in the period
ended December 31, 1999, appearing in this prospectus and registration statement
have been audited by Ernst & Young LLP, independent auditors as set forth in
their report included herein. See page F-2. These consolidated financial
statements are included in reliance upon such report given on their authority as
experts in auditing and accounting.
Paddock Lindstrom & Associates Ltd. has served from time to time as our
independent engineering consultants. We have relied on reports by these
consultants in the preparation of portions of this prospectus.
See "Risk Factors" at page 7 regarding the enforceability of civil
liabilities against foreign directors and officers of Canada Southern and
experts.
<PAGE>
WHERE YOU CAN FIND MORE INFORMATION
We are a public company and file annual, quarterly and special reports
and other information with the SEC. You may read and copy any documents we file
at the SEC's Public Reference Room, 450 Fifth Street, N.W., Washington, D.C.
20549. You may obtain further information on the operation of the Public
Reference Room by calling the SEC at 1-800-SEC-0330. You can obtain copies of
this material from the Public Reference Section of the SEC, Washington, D.C.
20549, at prescribed rates. Our reports, proxy and information statements and
other information are also available to the public at the SEC's web site. The
Internet address of that site is http://www.sec.gov. You may also obtain copies
of our reports, proxy and information statements and other information from our
web page at http:/www.cansopet.com.
Our limited voting shares are listed on the Boston Stock Exchange, the
Pacific Exchange, The Toronto Stock Exchange and in the NASDAQ SmallCap Market.
Copies of our reports, proxy statements and other information can also be
examined at each of these exchanges and at the offices of the National
Association of Securities Dealers, Inc.
This prospectus is only part of a registration statement on Form S-1
that we have filed with the SEC under the Securities Act and therefore omits
certain information contained in the registration statement. We have also filed
exhibits and schedules with the registration statement that are excluded from
this prospectus, and you should refer to the applicable exhibit or schedule for
a complete description of any statement referring to any contract or other
document. You may inspect a copy of the registration statement, including the
exhibits and schedules, without charge at the SEC's public reference room or
through its web site.
<PAGE>
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS
<TABLE>
Page
Reference
<S> <C>
Report of Independent Auditors F-2
Consolidated balance sheets at June 30, 2000 (unaudited), December 31, 1999
and 1998. F-3
Consolidated statements of operations and deficit for the
six months ended June 30, 2000 and 1999 (unaudited) and for each
of the three years in the period ended December 31, 1999. F-4
Consolidated statements of cash flows for the six months ended
June 30, 2000 and 1999 (unaudited) and for each of the three years in
the period ended December 31, 1999. F-5
Consolidated statement of Limited Voting Shares and Contributed Surplus for each
of the three years in the period ended
December 31, 1999 and the six months ended June 30, 2000 (unaudited) F-6
Notes to consolidated financial statements. F-7
Supplementary information on oil and gas activities F-21
</TABLE>
<PAGE>
AUDITORS' REPORT
To the Shareholders of
Canada Southern Petroleum Ltd.
We have audited the consolidated balance sheets of Canada Southern
Petroleum Ltd. as at December 31, 1999 and 1998, and the consolidated statements
of operations and deficit, cash flows and limited voting shares and contributed
surplus for each of the years in the three year period ended December 31, 1999.
These financial statements are the responsibility of Canada Southern's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in Canada. Those standards require that we plan and perform an audit to
obtain reasonable assurance whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation.
In our opinion, the consolidated financial statements present fairly,
in all material respects, the financial position of Canada Southern Petroleum
Ltd. as at December 31, 1999 and 1998 and the results of its operations and its
cash flows for each of the years in the three year period ended December 31,
1999, in accordance with accounting principles generally accepted in Canada.
/s Ernst & Young LLP
Chartered Accountants
Calgary, Canada
March 10, 2000 (except for note 8, which is as of April 10, 2000)
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
(Incorporated under the laws of Nova Scotia)
CONSOLIDATED BALANCE SHEETS
(Expressed in Canadian dollars)
<TABLE>
June 30, As at December 31,
2000 1999 1998
---------- -------------------------
Assets (Unaudited) (Restated)
Current assets
<S> <C> <C> <C>
Cash and cash equivalents (Note 2) $ 2,185,918 $ 3,045,530 $6,208,634
Marketable securities (Note 3) 291,342 568,374 751,511
Accounts receivable (Notes 4 and 7) 346,398 360,752 266,116
Other assets 289,155 307,519 319,697
------- ------- -------
Total current assets 3,112,813 4,282,175 7,545,958
--------- --------- ---------
Oil and gas properties and equipment
(full cost method) (Note 4) 9,363,434 10,207,294 10,000,010
Future tax asset (Note 6) 1,826,000 1,583,475 1,308,505
--------- --------- ---------
Total assets $14,302,247 $16,072,944 $18,854,473
=========== =========== ===========
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable $ 520,464 $ 634,600 $ 375,554
Accrued liabilities (Note 10) 180,600 18,256 294,491
------- ------ -------
Total current liabilities 701,064 652,856 670,045
------- ------- -------
Future site restoration costs 145,934 174,696 236,045
Contingencies (Note 8) - - -
Shareholders' Equity
Limited Voting Shares, par value
$1 per share (Note 5)
Authorized -100,000,000 shares
Outstanding -14,284,970 (2000) and (1999)
14,234,740 (1998) shares 14,284,970 14,284,970 14,234,740
Contributed surplus 26,502,342 26,502,342 26,254,139
---------- ---------- ----------
Total capital 40,787,312 40,787,312 40,488,879
Deficit (27,332,063) (25,541,920) (22,540,496)
------------ ------------ ------------
Total shareholders' equity 13,455,249 15,245,392 17,948,383
---------- ---------- ----------
Total liabilities and shareholders' equity $14,302,247 $16,072,944 $18,854,473
=========== =========== ===========
See accompanying notes.
</TABLE>
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
(Expressed in Canadian dollars)
<TABLE>
Six months ended
June 30, Year ended December 31,
----------------------------- ------------------------------------------
2000 1999 1999 1998 1997
(Unaudited) (Unaudited) (Restated) (Restated)
Revenues:
<S> <C> <C> <C> <C> <C>
Oil sales (Notes 4 and 10) $ 8,154 $ 63,675 $ 151,137 $ 897,878 $1,120,789
Gas sales (Notes 4 and 10) 44,215 28,358 38,324 705,277 523,433
Proceeds from carried interests 549,554 127,695 587,073 206,503 475,697
Interest and other income 81,539 145,098 253,365 221,523 395,059
Gain on sale of assets - - - 1,378,180 -
--------------- --------------- -------------- --------- --------------
Total revenues 683,462 364,826 1,029,899 3,409,361 2,514,978
--------------- --------------- -------------- --------- --------------
Costs and expenses:
General and administrative 843,627 725,095 1,209,325 1,300,595 1,104,535
Legal (Note 8) 1,109,488 1,119,213 2,108,521 2,357,707 1,897,506
Lease operating costs 21,331 68,116 147,332 975,899 799,372
Depletion, depreciation and amortization 119,000 188,200 707,200 869,600 623,600
Foreign exchange (gains) losses (39,973) 92,245 77,475 (178,850) (231,457)
Provision for future site restoration costs - - 600 29,500 21,500
Rent (Note 11) 28,075 28,751 55,840 76,812 57,586
Abandonments and write downs 634,582 - - 684,635 -
--------------- --------------- -------------- --------- --------------
Total costs and expenses 2,716,130 2,221,620 4,306,293 6,115,898 4,272,642
--------------- --------------- -------------- --------- --------------
Loss before income taxes (2,032,668) (1,856,794) (3,276,394) (2,706,537) (1,757,664)
Income tax recovery (Note 6) 242,525 73,196 274,970 378,367 170,158
-------------- --------------- ------------- ------------ --------------
Net loss (1,790,143) (1,783,598) (3,001,424) (2,328,170) (1,587,506)
Deficit - beginning of period (25,541,920) (22,540,496) (22,540,496) (20,212,326) (18,624,820)
------------ -- ------------ -------------- -- ------------ --------------
Deficit - end of period $(27,332,063) $(24,324,094) $(25,541,920) $(22,540,496) $(20,212,326)
============= ============= ============= ============= =============
Net loss per share (Basic & Fully Diluted) $(.13) $(.13) $(.21) $(.16) $(.11)
====== ====== ====== ====== ======
Average number of shares
Outstanding (Basic & Fully Diluted) 14,284,970 14,236,740 14,252,574 14,234,740 14,084,294
========== ========== ========== ========== ==========
See accompanying notes.
</TABLE>
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Expressed in Canadian dollars)
<TABLE>
Six months ended
June 30, Year ended December 31,
--------------------------- -----------------------------------------------
2000 1999 1999 1998 1997
(Unaudited) (Unaudited) (Restated) (Restated)
Cash flows from operating activities:
<S> <C> <C> <C> <C> <C>
Net loss $ (1,790,143) $ (1,783,598) $(3,001,424) $(2,328,170) $(1,587,506)
Adjustments to reconcile net loss
to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization 119,000 188,200 707,200 869,600 623,600
Future site restoration costs (net) (28,762) - (61,349) 25,071 (39,300)
Gain on sale of assets - - - (1,378,180) -
Abandonments and write downs 634,582 (73,196) - 684,635 -
Future tax recovery (242,525) - (274,970) (378,367) (170,158)
Change in assets and liabilities:
Accounts receivable 14,354 (26,715) (94,636) 959,970 (590,863)
Other assets 18,364 70,736 12,178 (77,419) (14,910)
Accounts payable (114,136) 46,862 259,045 (744,967) 680,684
Accrued liabilities 162,344 (45,532) (276,235) 16,776 95,611
----------- ----------- ------------ -------------- ------------
Net cash used in operations (1,226,922) (1,623,243) (2,730,191) (2,351,051) (1,002,842)
----------- ----------- ------------ -------------- ------------
Cash flows from investing activities:
Additions to oil and gas properties and
equipment (245,722) (484,186) (914,483) (1,942,474) (3,258,426)
Sale of marketable securities 277,032 751,511 183,137 2,621,823 2,079,452
Proceeds from the sale of properties 336,000 - - 5,751,180 -
----------- ----------- -------------- -------------- ------------
Net cash provided by (used in) investing activities 367,310 267,325 (731,346) 6,430,529 (1,178,974)
----------- ----------- -------------- -------------- ------------
Cash flows from financing activities:
Exercise of stock options - 35,000 298,433 - 1,601,375
----------- ---------- -------------- -------------- ----------
Net cash from financing activities - 35,000 298,433 - 1,601,375
----------- ----------- -------------- -------------- ----------
Increase (decrease) in cash
and cash equivalents (859,612) (1,320,918) (3,163,104) 4,079,478 (580,441)
Cash and cash equivalents at the
beginning of period 3,045,530 6,208,634 6,208,634 2,129,156 2,709,597
----------- ----------- -------------- ------------- ----------
Cash and cash equivalents at the
end of period (Note 2) $2,185,918 $4,887,716 $3,045,530 $6,208,634 $2,129,156
========== ========== ========== ========== ==========
See accompanying notes.
</TABLE>
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF LIMITED VOTING SHARES
AND CONTRIBUTED SURPLUS
(Expressed in Canadian dollars)
<TABLE>
Limited
Number Voting Shares Contributed
of shares $1 par value surplus Total
--------- ------------ ------- -----
<S> <C> <C> <C> <C>
Balance as at December 31, 1996 13,956,540 $13,956,540 $24,930,964 $38,887,504
Exercise of stock options 278,200 278,200 1,323,175 1,601,375
---------- ----------- ----------- -----------
Balance as at December 31, 1997 and 1998 14,234,740 14,234,740 26,254,139 40,488,879
Exercise of stock options and other sales 50,230 50,230 248,203 298,433
---------- ----------- ---------- ----------
Balance as at December 31, 1999 and
June 30, 2000 (unaudited) 14,284,970 $14,284,970 $26,502,342 $40,787,312
========== =========== =========== ===========
</TABLE>
See accompanying notes.
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Expressed in Canadian dollars)
December 31, 1999, 1998 and 1997
(Information at June 30, 2000 and 1999 and for the
six months then ended is unaudited)
1. Summary of significant accounting policies
Accounting principles
The Company prepares its accounts in accordance with accounting
principles generally accepted in Canada which conform in all material respects
with United States generally accepted accounting principles ("U.S. GAAP").
Consolidation
The consolidated financial statements include the accounts of Canada
Southern Petroleum Ltd. and its wholly-owned subsidiaries, Canpet Inc. and
C.S. Petroleum Limited.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the amounts reported in the financial statements and
accompanying notes. Specifically estimates were utilized in calculating
depletion, depreciation and amortization, site restoration costs, and
abandonments and write downs. Actual results could differ from those estimates.
Cash and cash equivalents
For the purposes of the statement of cash flows, the Company considers
all highly liquid investments with a maturity of three months or less at the
date of acquisition to be cash equivalents.
Oil and gas properties and equipment
The Company, which is engaged primarily in one industry, the
exploration for and the development of oil and gas properties, principally in
Canada, follows the full cost method of accounting for oil and gas properties,
whereby all costs associated with the exploration for and the development of oil
and gas reserves are capitalized. Such costs include land acquisition, drilling,
geological, geophysical and overhead expenses. The Company's cost centers are
Canada and the United States.
The Company periodically reviews the costs associated with undeveloped
properties and mineral rights to determine whether they are likely to be
recovered. When such costs are not likely to be recovered, such costs are
transferred to the depletable pool of oil and gas costs.
<PAGE>
1. Summary of significant accounting policies (Cont'd)
The net carrying cost of the Company's oil and gas properties in
producing cost centers is limited to an estimated recoverable amount. This
amount is the aggregate of future net revenues from proved reserves and the
costs of undeveloped properties, net of impairment allowances, less future
general and administrative costs, financing costs and income taxes. Future net
revenues are calculated using year end prices that are not escalated or
discounted. For Canadian GAAP future net revenues are undiscounted, whereas, for
U.S. GAAP future net revenues are discounted at 10%.
The costs of the Company's 30% carried interest in the Kotaneelee gas
field are included in oil and gas properties and in the cost center for the
purpose of computing depletion. In addition, the Company's share of estimated
net reserves after pay out are also included in the proved oil and gas reserves
base for the purpose of computing depletion. During November 1999, the field
achieved pay out status.
Gains or losses are not recognized upon disposition of oil and gas
properties unless crediting the proceeds against accumulated costs would result
in a change in the rate of depletion of 20% or more.
Depletion is provided on costs accumulated in producing cost centers
including production equipment using the unit of production method. For purposes
of the depletion calculation, gross proved oil and gas reserves as determined by
outside consultants are converted to a common unit of measure on the basis of
their approximate relative energy content.
Depreciation has been computed for equipment, other than production
equipment, on the straight-line method based on estimated useful lives of four
to ten years.
Substantially all of the Company's exploration and development
activities related to oil and gas are conducted jointly with others and
accordingly the consolidated financial statements reflect only the Company's
proportionate interest in such activities.
Revenue recognition
The Company recognizes revenue on its working interest properties from
the production of oil and gas in the period the oil and gas are sold.
<PAGE>
1. Summary of significant accounting policies (Cont'd)
Revenue under carried interest agreements is recorded in the period
when the proceeds become receivable and collection is reasonably assured. The
Company is entitled to participate in oil and gas net revenues after the
repayment of exploration, drilling and completion expenses to the party or
parties bearing these costs. Each carried interest account is subject to an
independent audit. In the past, these audits have resulted in both positive and
negative adjustments which are attributable to prior year periods. For these
reasons, the proceeds under carried interest agreements may fluctuate each year
depending on both capital expenditures and any audit adjustments.
The Company follows the industry practice of reporting its revenues
from carried interest agreements, whereby one month of revenues is charged in
advance for the next two months' operating and capital expenditures. In
addition, the production revenues from the last two months of each quarter are
reported during the following quarter because the data are not usually
available.
Earnings per share
Earnings per common share ("EPS") is based upon the weighted average
number of common and common equivalent shares outstanding during the period. The
Company's basic and diluted calculations of EPS are the same for both U.S. and
Canadian GAAP.
Future site restoration costs
Total future site restoration costs are estimated to be $ 146,000 at
June 30, ($228,000 at December 31, 1999) and are being provided on a unit of
production basis. The provision is based on current costs of complying with
existing legislation and industry practice for site restoration and abandonment.
At June 30, 2000, all of such costs had been accrued. At December 31, 1999,
approximately $53,000 of such costs had not been accrued. The estimated costs of
abandoning the two producing wells in the Kotaneelee field are not included in
future site restoration costs. These costs would be paid by the working interest
partners and charged to the carried interest account.
Future income taxes
In 1999, under new recommendations of the Canadian Institute of
Chartered Accountants, the Company retroactively adopted the liability method of
accounting for income taxes. Under this method, the Company records income taxes
to give effect to temporary differences between the carrying amount and the tax
basis of the Company's assets and liabilities. Temporary differences arise when
the realization of an asset or the settlement of a liability would give rise to
either an increase or decrease in the Company's income taxes payable for the
year or later period. Future income taxes are recorded at the enacted income tax
rates that are expected to apply when the future tax liability is settled or the
future tax asset is realized. Income tax expense is the tax payable for the
period and the change during the period in future income tax and liabilities.
<PAGE>
1. Summary of significant accounting policies (Cont'd)
Adoption of the liability method of accounting for income taxes
resulted in changes to previously reported net income, net income per share and
the balance sheet accounts, as follows:
<TABLE>
1998 1997
---- ----
<S> <C> <C>
Net loss previously reported $(2,706,537) $(1,757,664)
Adjustment for the effect of the change in accounting method 378,367 170,158
------------ ------------
Net loss as restated $(2,328,170) $(1,587,506)
============ ============
Net loss per share previously reported $(.19) $(.12)
Adjustment for the effect of the change in accounting method .03 .01
------ ------
Net loss per share as restated $(.16) $(.11)
====== ======
Future tax asset previously reported $ - $ -
Adjustment for the effect of the change in accounting method 1,308,505 930,138
--------- -------
Future tax asset as restated $1,308,505 $ 930,138
========== =========
Deficit previously reported $(23,849,001) $(21,142,464)
Adjustment for the effect of the change in accounting method 1,308,505 930,138
------------- -------------
Deficit as restated $(22,540,496) $(20,212,326)
============= =============
</TABLE>
If the tax allocation method of accounting for income taxes had been
retained, the Company would have reported a net loss of $(3,276,394) or $(.23)
per share for 1999.
Foreign currency translation
Transactions for settlement in U.S. dollars have been translated at
average monthly exchange rates. Monetary assets and liabilities in U.S. dollars
have been translated at the year end exchange rates. Exchange gains or losses
resulting from these adjustments are included in costs and expenses.
Financial instruments
The carrying value for cash and cash equivalents, accounts receivable
and accounts payable approximates fair value based on anticipated cash flows and
current market conditions.
Comprehensive income
The Company has no items of other comprehensive income for U.S. GAAP.
Comprehensive loss for all periods presented is equal to the net loss.
<PAGE>
2. Cash and cash equivalents
The Company considers all highly liquid short term investments with
maturities of three months or less at date of acquisition to be cash
equivalents. Cash equivalents are carried at cost which approximates market
value.
<TABLE>
Six months Year ended
ended June 30, December 31,
-------------- ---------------------------
2000 1999 1998
-------------- ---------------------------
<S> <C> <C> <C>
Cash $ 255,778 $ 398,884 $ 269,918
Canadian and U.S. bankers acceptances and mortgage notes
(Yield:2000-5.5%, 1999-5.0%, 1998-4.9%) 1,346,610 2,076,663 4,880,833
U.S. marketable securities (Yield: 2000-6%, 1999-5.4%,
1998-4.8%) 583,530 569,983 1,057,883
---------- ---------- ----------
$2,185,918 $3,045,530 $6,208,634
========== ========== ==========
</TABLE>
3. Marketable Securities
At June 30, 2000, December 31, 1999 and 1998, the Company held the
following marketable securities which were expected to be held until maturity:
<TABLE>
Security Par value Maturity Date Amortized Cost Fair value
-------- --------- ------------- -------------- ----------
2000
<S> <C> <C> <C> <C>
U.S. Federal Home Loan $295,900 Aug. 3, 2000 $291,342 $294,113
Bank Disc. Note -------- ======== ========
1999
U.S. Federal Home Loan
Bank Disc. Note $577,700 Jan. 18, 2000 $568,374 $576,300
======== ======== ========
1998
U.S. Federal National
Mortgage Assoc. $765,100 Apr. 7, 1999 $751,511 $751,700
======== ======== ========
</TABLE>
<PAGE>
<TABLE>
4. Oil and gas properties and equipment
Less Accumulated
Depreciation
Depletion and, Net Book
Cost Writedowns Value
Balance June 30, 2000 ----------------- ----------------- -------------
<S> <C> <C> <C>
Oil and gas properties - developed $18,864,542 $9,538,063 $9,326,479
Oil and gas properties (U.S.) - undeveloped 1,319,220 1,319,219 1
Seismic data 112,000 112,000 -
----------- ---------- ----------
Total oil and gas properties 20,295,762 10,969,282 9,326,480
Equipment 91,838 54,884 36,954
----------- ---------- ----------
Total oil and gas properties and equipment $20,387,600 $11,024,166 $9,363,434
=========== =========== ==========
Balance December 31, 1999
Oil and gas properties - developed $19,009,974 $9,422,066 $9,587,908
Oil and gas properties (U.S.) - undeveloped 1,266,334 684,635 581,699
Seismic data 112,000 112,000 -
----------- ----------- ----------
Total oil and gas properties 20,388,308 10,218,701 10,169,607
Equipment 89,567 51,880 37,687
----------- ----------- -----------
Total oil and gas properties and equipment $20,477,875 $10,270,581 $10,207,294
=========== =========== ===========
Balance December 31, 1998
Oil and gas properties-developed $18,524,670 $8,720,066 $9,804,605
Oil and gas properties (U.S.) - undeveloped 851,651 684,635 167,016
Seismic data 112,000 112,000 -
----------- ---------- ----------
Total oil and gas properties 19,488,321 9,516,701 9,971,621
Equipment 75,073 46,684 28,389
----------- ---------- ----------
Total oil and gas properties and equipment $19,563,394 $9,563,385 $10,000,010
=========== ========== ===========
</TABLE>
Substantially all gas sales were made to CanWest Gas Supply Inc. and oil
sales were made to Probe Exploration, Inc. ("Probe"). The gain on sale of
assets and the amount of abandonments and write downs are same under both
Canadian and U.S. GAAP. During 1999, a total of $73,000 ($95,000 in 1998 and
$91,000 in 1997) of general and administrative expenses were capitalized.
Included in the amount of accounts receivable at June 30, 2000 is
$233,000 and $269,000 at December 31, 1999 due from various industry partners
which include Berkley Petroleum Ltd., PetroCanada, Oil For America - Exploration
and Farries Engineering.
During 1999, the Company's primary Alberta asset and revenue producing
property was its heavy crude oil production and related facilities at Kitscoty.
The Company sold its 10 % working interest to the operator for $336,000
effective October 1, 1999. The transaction was completed during February 2000
and the proceeds of sale were credited to oil and gas properties in the first
quarter of fiscal 2000.
<PAGE>
5. Limited Voting Shares and stock options
The Memorandum of Association (Articles of Continuance) of the Company
provides that no person (as defined) shall vote more than 1,000 shares.
Under the terms of the Company's 1992 and 1998 stock option plans, the
Company is authorized to grant certain employees, directors and consultants
options to purchase Limited Voting Shares at prices based on the market price of
the shares as determined on the date of the grant. The options are normally
exercisable immediately and issued for a period of five years from the date of
grant.
During 1998, the Company adopted a stock option plan that permits the
granting of both stock options and stock appreciation rights. A total of 700,000
Limited Voting Shares are reserved for issuance under the plan.
Following is a summary of option transactions which reflects
adjustments of the stock option prices and the number of shares subject to stock
options as discussed above:
<TABLE>
Options Outstanding Expiration Dates Number of Shares Option Prices ($)
------------------- ---------------- ---------------- -----------------
<S> <C> <C> <C>
December 31, 1996 Oct. 1999 - Jun. 2001 445,700
Exercised (278,200) 3.70 - 8.75
Granted 35,000 13.50
------
December 31, 1997 Aug. 1999 - Oct. 2002 202,500 6.37 - 13.50
Granted 7,500 10.25
-----
December 31, 1998 Aug. 1999 - Apr. 2003 210,000 ($7.94 weighted average)
Granted 362,500 7.02
Exercised (49,000) 6.37-7.00
--------
December 31, 1999 Nov. 2000 - Jan. 2004 523,500 ($6.92 weighted average)
Granted 75,000 8.36
------
June 30, 2000 598,500 ($7.10 weighted average)
=======
Summary of Options Outstanding at June 30, 2000
Granted 1994 Nov. 2000 80,000 7.00
Granted 1996 Nov. 2000 62,500 6.37
Granted 1999 Jan. 2004 381,000 7.00
Granted 2000 Jan. 2005 75,000 8.36
------
Total - June 30, 2000 598,500
=======
Options reserved for future grants 432,134
---------------------------------- =======
</TABLE>
For U.S. GAAP, the Company has elected to follow Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB No. 25)
and related interpretations in accounting for its stock options. This method,
which is consistent with the Company's accounting under Canadian GAAP, has been
chosen because the alternative fair value accounting provided under FASB
Statement No. 123, "Accounting for Stock Based Compensation," requires use of
option valuation models that were not developed for use in valuing stock
options. Under APB No.
Limited Voting Shares and stock options (Cont'd)
25, because the exercise price of the Company's stock options equals the market
price of the underlying stock on the date of grant, no compensation expense is
recognized.
Pro forma information regarding net income and earnings per share is
required by FASB Statement No. 123, and has been determined as if the Company
had accounted for its stock options under the fair value method of that
Statement. The fair value for these options was estimated at the date of grant
using a Black-Scholes option pricing model. Option valuation models require that
input of highly subjective assumptions including the expected stock price
volatility. All of the valuations assumed no expected dividend. The assumptions
used in the 1997 valuation model were: risk free interest rate - 5.7%, expected
life - 5 years and expected volatility - .459. The assumptions used in the 1998
valuation model were: risk free interest rate - 4.45%, expected life - 5 years
and expected volatility - .328. The assumptions used in the 1999 valuation model
were: risk free interest rate - 4.65%, expected life - 5 years and expected
volatility - .503.
Because the Company's stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its stock options.
For the purpose of pro forma disclosures, the estimated fair value of
the stock options is expensed in the year of grant since the options are
immediately exercisable. The Company's pro forma information is as follows:
<TABLE>
Amount Per Share
----------------
<S> <C> <C> <C>
Net loss as reported December 31, 1997 $(1,587,506) $(.11)
Stock option expense 225,400 (.02)
------------ ------
Pro forma net loss December 31, 1997 $(1,812,906) $(.13)
============ ======
Net loss as reported December 31, 1998 $(2,328,170) $(.16)
Stock option expense 29,600 -
------------ -----
Pro forma net loss December 31, 1998 $(2,357,770) $(.16)
============ ======
Net loss as reported December 31, 1999 $(3,001,424) $(.21)
Stock option expense 1,247,000 (.09)
------------ -----
Pro forma net loss December 31, 1999 $(4,248,424) $(.30)
============ ======
</TABLE>
<PAGE>
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>
June 30
2000 1999 1999 1998 1997
------ ------ ------ ------ -----
<S> <C> <C> <C> <C> <C>
44.84% 44.84% 44.84% 44.84% 44.84%
====== ====== ====== ====== ======
Recovery for income taxes based
on combined basic Canadian federal $(911,448) $(832,586) $(1,469,135) $(1,213,611) $(788,137)
and provincial income tax
Nondeductible crown charges 821 5,908 11,249 104,663 154,463
Resource allowance 159,376 189,828 383,663 403,270 232,922
Other (205,038) 12,617 (47,601) 24,919 21,106
Nontaxable portion of capital gain - - - (20,049) (20,743)
Unrealized tax loss 713,764 551,037 846,854 322,441 170,158
------- ------- ----------- ----------- ----------
Actual income tax recovery $(242,525) $(73,196) $ (274,970) $ (378,367) $ (230,231)
========== ========= =========== =========== ===========
</TABLE>
At June 30, 2000 and December 31, 1999, the Company had net operating
losses for income tax purposes of approximately $5,981,000 and $5,027,000,
respectively which are available to be carried forward to future periods. These
losses expire in the following years: 2000 - $294,000, 2001 - $545,000, 2002 -
$569,000, 2003 - $1,077,000, 2004 - $545,000, 2005 - $1,407,000 , 2006 -
$590,000 and 2007 - $954,000.
At June 30, 2000 and December 31, 2000, the Company has the following
oil and gas tax deductions available to reduce future taxable income, subject to
a final determination by taxation authorities.
<TABLE>
June 30, 2000 December 31, 1999
Canada
<S> <C> <C>
Drilling, exploration and lease acquisition costs $10,852,000 $ 10,570,000
Drilling and exploration costs-successored 1,926,000 1,926,000
Earned depletion 1,975,000 1,975,000
Earned depletion-successored 208,000 208,000
Undepreciated capital costs 2,262,000 2,336,000
Cumulative eligible capital losses 407,000 407,000
Share issue costs 38,000 99,000
United States
Exploration and lease acquisition costs $1,234,000 $1,234,000
</TABLE>
As a result of these deductions, the Company has a future tax asset
which primarily represents the excess of available resource deductions for
income tax purposes over the recorded value of oil and gas properties together
with operating and capital income tax loss carryforwards. These amounts are
expected to be recovered from the production of current oil and gas reserves. As
certain of the resource deductions are restricted and the operating loss
carryforwards are
6. Income taxes (Cont'd)
subject to expiration, there is considerable risk that certain of these
deductions will not be utilized. Accordingly, the Company has established a
valuation allowance to recognize this uncertainty.
<TABLE>
June 30,
2000 1999 1998 1997
---------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Future tax asset $6,304,941 $6,749,358 $5,728,699 $ 4,642,765
Valuation reserve (4,478,941) (5,165,883) (4,420,194) (3,712,627)
---------- ----------- ----------- -----------
Net future tax asset $1,826,000 $1,583,475 $1,308,505 $ 930,138
========== ========== ========== =========
Future tax recovery $242,525 $ 274,970 $ 378,367 $ 170,158
======== ========= ========= =========
</TABLE>
7. Line of credit
The Company has an operating line of credit with a Canadian chartered
bank which provides for a loan of $500,000. The interest rate on borrowing is at
3/4% above the bank's prime lending rate. The line of credit is subject to
annual review and is secured by a general assignment of accounts receivable and
an undertaking to provide security in the form of assignment of future working
interest proceeds. No drawings were made under this line during 1999 or 1998.
8. Litigation
The Company, which has a 30% interest in the Kotaneelee gas field,
believes that the working interest owners in the field have not adequately
pursued the attainment of contracts for the sale of Kotaneelee gas. In October
1989 and in March 1990, the Company filed statements of claim in the Court of
Queen's Bench of Alberta, Judicial District of Calgary, Canada, against the
working interest partners in the Kotaneelee gas field. The named defendants
were Amoco Canada Petroleum Corporation, Ltd., Dome Petroleum
Limited (now Amoco Canada Resources Ltd.), and Amoco Production Company
(collectively the "Amoco Dome Group"), Columbia Gas Development of Canada Ltd.
("Columbia"), Mobil Oil Canada Ltd. ("Mobil") and Esso Resource of Canada Ltd.
("Esso") (collectively the "Defendants"). In 1991, Anderson Exploration Ltd.
acquired all of the shares in Columbia and changed its name to Anderson Oil &
Gas Inc. ("Anderson"). Anderson is now the sole operator (the "Operator") of
the field and is a direct defendant in the Canadian lawsuit. Columbia's
previous parent, The Columbia Gas System, Inc., which was reorganized in a
bankruptcy proceeding in the United States, is contractually liable to Anderson
in the legal proceedings currently at trial.
The Company claims that the Defendants breached a contract obligation
and/or a fiduciary duty owed to the Company to market gas from the Kotaneelee
gas field when it was possible to so do. The Company asserts that marketing the
Kotaneelee gas was possible in 1984 and that the Defendants deliberately failed
to do so. The Company seeks money damages and
8. Litigation (Cont'd)
the forfeiture of the Kotaneelee gas field. The Company presented evidence at
trial that the money damages sustained by the Company were approximately $100
million.
In addition, the Company has claimed that the Company's carried
interest account should be reduced because of improper charges to the carried
interest account by the Defendants. The Company claims that when the Defendants
in 1980 suspended production from the field's gas wells, they failed to take
precautionary measures necessary to protect and maintain the wells in good
operating condition. The wells thereafter deteriorated, which caused unnecessary
expenditures to be incurred, including expenditures to redrill one well. In
addition, the Company claims that expenditures made to repair and rebuild the
field's dehydration plant should not have been necessary had the facilities been
properly constructed and maintained by the Defendants. The expenditures, the
Company claims, were inappropriately charged to the field's carried interest
account. The effect of an increased carried interest account is to extend the
period before pay out begins to the carried interest account owners.
The Company claims that production from the field should have commenced
in 1984. At that time the field's carried interest account was approximately $63
million. The Company claims that by 1993 at least $34 million of unnecessary
expenses had been wrongfully charged to the carried interest account. The
Company's 30% share of these expenses would be approximately $10.2 million. The
Company further claims that if production had commenced in 1984, the carried
interest account would have been paid out in approximately two years and the
Company would have begun to receive revenues from the field in 1986. The
operator reported that as of November 30, 1999 development costs totaling $96.7
million had been incurred and repaid.
The amount of recoverable costs is one of the issues being contested in
the Kotaneelee litigation. The Company claims, and the Defendants deny, that the
Defendants have made improper charges to the carried interest account and one
defendant (Amoco Canada) maintains that the carried interest account should be
charged additional amounts for gas processing fees. Amoco Canada claims that the
remaining costs to be recovered at December 31, 1999 were either $58,711,000 or
$19,325,000 depending on inclusion of interest. It is not possible to determine
whether Amoco Canada will be successful in its claim that gas processing fees
should be charged to the carried interest account.
Although, according to the Operator's reports, the Kotaneelee gas field
reached pay out status on November 10, 1999, the Operator has notified the
Company that it will not make any payments to the carried interest owners,
including the Company, until the issue of the amount of recoverable costs under
the carried interest account has been resolved by the Court of Queen's Bench of
Alberta, Canada. The Operator has stated that it will deposit the Company's
share of net production proceeds in an interest bearing account with an escrow
agent. A motion was filed in December 1999 by the plaintiffs in Canada to direct
all of the Defendants to make timely payments
8. Litigation (Cont'd)
of all current and future amounts due from the Company's share of field
revenues. The motion was subsequently amended to include all of the Defendants.
On April 10, 2000, the trial court dismissed the Company's motion pending the
Court's ultimate determination of the issues surrounding the Kotaneelee field
carried-interest account. The Company has filed a notice of appeal of the
dismissal with the Alberta Court of Appeal. Net production proceeds are unlikely
to be paid to the Company until final resolution by the Courts of the Kotaneelee
litigation.
Since March 2000, the Operator of the Kotaneelee field has been
reporting the amount of the Company's share of net revenues being deposited in
escrow. The July 2000 report provided information for production during the
month of April 2000. Based on the reported data, the Company believes the total
amount due the Company is $2,702,470 of which $896,038 has been deposited in
escrow.
Columbia has filed a counterclaim against the Company seeking, if the
Company is successful in its claim for the forfeiture of the field, repayment
from the Company of all unrecovered sums Columbia has expended on the Kotaneelee
lands before the Company is entitled to its interest.
Based upon newly discovered evidence, the Company filed a new claim
during May 1998 that the Defendants failed to develop the field in a timely
manner. The Company is unable to estimate the time necessary to conclude this
litigation.
Matters Ancillary to Kotaneelee Litigation
In its 1989 statement of claim, the Company sought a declaratory
judgment regarding two issues:
(1) whether interest accrued on the carried interest account; and
(2) whether expenditures for gathering lines and dehydration
equipment are expenditures chargeable to the carried interest
account or whether the Company will be assessed a processing
fee on gas throughput.
With respect to the first issue, the Company maintains that no interest
should accrue on the account and the Defendants have not contested this
position. With regard to the second issue, the Company maintains that the
expenditures are chargeable to the carried interest account. Mobil, Esso and
Columbia have essentially agreed to the Company's position in the original
pleadings to the Court 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 Queen's Bench of Alberta, Canada, which related to a
suit brought against
8. Litigation (Cont'd)
AlliedSignal Inc. ("AlliedSignal") in Florida which was dismissed on the basis
that Canada was the appropriate forum for the litigation. AlliedSignal had
sought additional relief against the Company in Canada to preclude other types
of suits by the Company and to recover the costs of the defense of the initial
action. The settlement bars AlliedSignal from making a claim against the Company
for any costs in connection with the Kotaneelee Litigation. The Company agreed
not to bring any action against AlliedSignal in connection with the Kotaneelee
gas field. Neither party made any monetary payment to the other party.
Under Canadian law, certain costs (known as "taxable costs") of the
litigation may be assessed against the non-prevailing party. Effective September
1, 1998, the Alberta Rules of Court were amended to provide for a material
increase in the costs which may be awarded to the prevailing party in matters
before the Court.
The trial has been lengthy, complicated and costly to all parties and
the Company believes that the prevailing party or parties in the litigation will
argue for a substantial assessment of costs against the non-prevailing party or
parties. The Court has very broad discretion as to whether to award costs and
disbursements and as to the calculation of any amounts to be awarded.
Accordingly, the Company is unable to determine whether, in the event that it
does not prevail on its claims in the litigation, costs will be assessed against
it or in what amounts. However, since the costs incurred by the Defendants have
been substantial, and since the Court has broad discretion in the awarding of
costs, an award to the Defendants potentially could be material. A cost award
against the Company could be of sufficient magnitude to necessitate a sale of
Company assets or a debt or equity financing to fund such an award. There are no
assurances that any such sale or financing would be consummated.
There is no assurance whatsoever 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
In 1991, the Company granted interests to certain of its officers,
employees, directors, counsel and consultants amounting to an aggregate of 7.8%
of any and all benefits to the Company after expenses from the litigation in
Canada relating to the Kotaneelee gas field. The Company has reserved a 2.2%
interest in such net benefits for possible future grants to persons who may
include officers and directors of the Company.
Mr. Heath, a director of the Company, has royalty interests in certain
of the Company's oil and gas properties, (present and past) which were received
directly or indirectly through the Company. The Company and third-party
operators and/or owners of properties made payments pursuant to these royalties
for the benefit of Mr. Heath totaling U.S. $15,435, $8,324 and $11,158 in 1999,
1998 and 1997, respectively. During the six month period ended June 30, 2000,
Mr. Heath was paid $8,435.
10. Other financial information
<TABLE>
June 30, December 31,
Accrued liabilities
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Accrued accounting and legal expenses $ 142,535 $ 18,256 $ 69,890
Accrued royalties - - 141,575
Other 38,065 - 83,026
--------- -------- --------
$ 180,600 $ 18,256 $294,491
========= ======== ========
</TABLE>
<TABLE>
Six months ended
June 30, Year ended December 31,
---------------------- -------------------------------------
2000 1999 1999 1998 1997
------ ------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Royalty payments (1) $1,877 $12,992 $ 71,838 $146,161 $366,661
====== ======= ======== ======== ========
Interest payments (2) $212 $53 $ 2,600 $ 1,625 $ 1,775
====== ======== ======== ======= =======
Large corporation tax payments $5,772 $9,336 $ 15,108 $ 22,837 $ 27,388
====== ====== ======== ======== ========
--------------------
(1) Oil and gas sales are reported net of royalties paid.
(2) Bank line of credit charges.
</TABLE>
11. Leases
At June 30, 2000, the future minimum rental payments and estimated
operating costs applicable to the Company's noncancelable five year operating
(office) lease which was effective June 1, 2000 are as follows:
Fiscal Year Amount
----------- ------
2000 $23,061
2001 39,534
2002 40,943
2003 41,949
2004 41,949
2005 17,478
------
Total $204,914
========
<PAGE>
CANADA SOUTHERN PETROLEUM LTD.
(Expressed in Canadian dollars)
December 31, 1999
SUPPLEMENTARY INFORMATION ON OIL
AND GAS ACTIVITIES
(unaudited)
The following information includes estimates which are subject to rapid
and unanticipated change. Therefore, these estimates may not accurately reflect
future net income to the Company.
All amounts below except for costs, acreage, wells drilled and present
activities relate to Canada. Oil and gas reserve data and the information
relating to cash flows were provided by Paddock Lindstrom & Associates Ltd.,
independent consultants.
Estimated net quantities of proved oil and gas reserves:
<TABLE>
Oil Gas
(bbls) (bcf)
------ -----
Proved reserves:
<S> <C> <C>
December 31, 1996 425,800 29.031
Revisions of previous estimates 179,333 (3.802)
Production* (71,333) (.838)
-------- ------
December 31, 1997 533,800 24.391
Sale of properties (350,800) (2.632)
Revisions of previous estimates (73,419) (2.088)
Production* (73,381) (1.263)
-------- -------
December 31, 1998 36,200 18.408
Revisions of previous estimates 5,050 6.786
Production* (11,650) (1.710)
-------- -------
December 31,1999 29,600 23.484
====== ======
Proved developed reserves:
December 31, 1996 358,400 28.265
======= ======
December 31, 1997 508,200 24.391
======= ======
December 31, 1998 36,200 18.408
====== ======
December 31, 1999 29,600 23.484
====== ======
-----------------
* Production data includes oil and gas sales and the proceeds from the
carried interest properties.
</TABLE>
<PAGE>
Results of oil and gas operations:
<TABLE>
1999 1998 1997
(Restated) (Restated)
Income:
<S> <C> <C> <C>
Oil and gas sales $189,461 $1,603,155 $1,644,222
Proceeds from carried interests 587,073 206,503 475,697
Gain on sale of assets - 1,378,180 -
-------- --------- ---------
776,534 3,187,838 2,119,919
-------- --------- ---------
Costs and expenses:
Production costs 147,332 975,899 799,372
Depletion depreciation, and amortization 707,200 869,600 623,600
Provision for future site restoration costs 600 29,500 21,500
Abandonments and write downs - 684,635 -
Income tax expense (recovery) (35,243) 281,687 302,870
-------- --------- ---------
819,889 2,841,321 1,747,342
------- --------- ---------
Net income (loss) from operations $ (43,355) $346,517 $372,577
========== ======== ========
</TABLE>
Capitalized costs of oil and gas activities:
<TABLE>
1999 1998 1997
-------- -------- ---------
<S> <C> <C> <C>
Acquisition costs $241,000 $ 11,000 $ 399,000
Exploration 514,000 174,000 546,000
Development 145,000 1,758,000 2,313,000
</TABLE>
Standardized measure of discounted future net cash flows relating to proved oil
and gas reserve quantities during the following period (in thousands of
dollars):
<TABLE>
1999 1998 1997
<S> <C> <C> <C>
Future cash inflows $70,491 $28,052 $46,435
Future development and production costs (24,364) (14,030) (22,517)
-------- -------- --------
46,127 14,022 23,918
Future income tax expense* (6,331) - (1,573)
------- -------- -------
Future net cash flows 39,796 14,022 22,345
10% annual discount (8,758) (4,781) (7,836)
------- -------- -------
Standardized measure of discounted
future net cash flows $31,038 $9,241 $14,509
======= ====== ========
</TABLE>
------
* Reflects tax benefit for the years 1999, 1998 and 1997, from carry forward of
exploration, development and lease acquisition costs, undepreciated capital
costs and book earned depletion of $18,940,000, $16,381,000 and $18,065,000.
Current prices used in the above estimates were based upon selling
prices at the wellhead at December of each year. The actual price ($2.83) of
Kotaneelee gas at December 31, 1999, was used in these estimates. Current costs
were based upon estimates made by consulting engineers at the end of each year.
<PAGE>
Changes in the standardized measure during the following periods (in thousands
of dollars):
<TABLE>
Year ended December 31,
-----------------------------------------------------
1999 1998 1997
Changes due to: -------------- ------------ -------
<S> <C> <C> <C>
Sale of properties $ - $(4,374) $ -
Prices and production costs 17,776 (402) (579)
Future development costs (116) (1,204) (2,350)
Sales net of production costs (619) (906) (1,562)
Development costs incurred
during the year 145 1,758 2,313
Net change due to extensions,
discoveries and improved recovery - - 1,692
Revisions of quantity estimates 7,256 (872) (3,642)
Accretion of discount 924 1,045 1,723
Net change in income taxes (3,569) (313) 939
------- -------- --------
Net change $21,797 $(5,268) $(1,466)
======== ======== ========
</TABLE>
<PAGE>
--------------------------------------------------------------------------------
You should rely only on the information contained or incorporated by reference
in this prospectus. We have not authorized anyone (including any broker or
salesman) to provide you with different or inconsistent information. If anyone
provides you with different or inconsistent information, you should not rely on
it. This document may be used only where it is legal to sell these securities.
You should assume that the information contained in this prospectus is accurate
only as of _______, 2000. You should not assume that this prospectus is accurate
as of any other date.
--------------------------------------------------------------------------------
Canada Southern Petroleum Ltd.
__________ LIMITED
VOTING SHARES
___________ RIGHTS TO
PURCHASE LIMITED
VOTING SHARES
------------------
PROSPECTUS
------------------
__________, 2000
<PAGE>
II-5
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 13. Other Expenses of Issuance and Distribution.
The following table sets forth our estimates of the expenses incurred
in connection with the sale of common stock being registered, all of which will
be paid by us.
SEC registration fee $[______]
Stock exchange listing fees $[______]
Printing expenses $[______]
Transfer agent's and registrar's fees $[______]
Legal fees and expenses $[______]
Accounting fees and expenses $[______]
Blue sky qualification fees and expenses $[______]
Miscellaneous fees and expenses $[______]
TOTAL:
Item 14. Indemnification of Directors and Officers.
Paragraph 177 of the Company's Articles of Association (By-Laws)
provides as follows:
177. (a) Each of the Directors and officers for the time being of the
Company and his heirs, executors and administrators, in the absence of
any dishonesty on his part, shall be indemnified and secured harmless
by the Company from and against all claims, actions, costs, charges,
losses, damages and expenses incurred or sustained by reason of any
action or thing done, concurred in or omitted in or about the execution
of his duty or supposed duty as a result of the breach of his fiduciary
duty.
(b) No Director or officer for the time being of the Company and his
heirs, executors and administrators, in the absence of any dishonesty
on his part, shall be liable for: the acts, receipts, neglects or
defaults of any other person; or for joining in any receipt or act for
conformity; or for any loss, damage or expense happening to the Company
through the insufficiency or deficiency of title to any property
acquired by, for or on behalf of the Company; or for the insufficiency
or deficiency of any security in or upon which any moneys of the
Company are invested; or for any loss or damages arising from the
bankruptcy, insolvency or tortious act of any person with whom any
moneys, securities or other property of the Company are lodged or
deposited; or for any other loss, damage or misfortune whatever which
may arise out of the execution of his duty or supposed duty or as a
result of the breach of his fiduciary duty or in relation thereto.
(c) The Company shall indemnify a director or officer of the Company, a
former director or officer of the Company or a person who acts or acted
at the Company's request as a director or officer of a body corporate
of which the Company is or was a shareholder or creditor, and his heirs
and legal representatives, against all claims, costs, charges and
expenses, including an amount paid to settle an action or satisfy a
judgment, penalty or fine, reasonably incurred by him in respect of any
civil, criminal or administrative action or proceeding to which he is
made a party by reason of being or having been a director or officer of
such corporation or body corporate if:
(1) He acted honestly and in good faith with a view to the
best interests of the Company; or
(2) In the case of a criminal or administrative action or
proceeding that is enforced by a monetary penalty, he
had reasonable grounds for believing that his conduct
was lawful; or
(3) He was substantially successful on the merits in this
defense of the action or proceeding.
(d) The foregoing provisions of this article shall be in amplification
of and in addition to and not by way of limitation of or substitution
for any rights, immunities or protection conferred upon any director or
officer by any statute, law, matter or thing whatsoever.
The Company has entered into expense agreements with its executive
officers and each of its directors. These agreements provide that the Company
shall advance such persons the costs, including reasonable attorneys' fees, of
defending any litigation brought against them by reason of such person being or
having been a director or executive officer of the Company. The agreements also
obligate the directors and executive officer to repay any such amounts advanced
should a final decision by a court having jurisdiction in the matter determine
that the director or executive officer in question is not entitled to be
indemnified.
In 1987, we purchased U.S. $150,000 of directors' and officers'
liability insurance coverage from an unaffiliated Bermuda company at a cost of
U.S. $150,000 plus an annual U.S. $7,500 service fee during the period of the
policy. We are credited with investment income from the policy premium during
the term of the policy and all or a portion of such premium will be refunded at
the end of the policy term to the extent that no claims are made. We had been
unable to obtain any other liability coverage for the Company's directors and
officers.
In recent years, we have been able to purchase directors' and officers'
insurance coverage. The current amount of D&O coverage is Can. $15 million
(including the above policy) at an annual cost of Can. $122,000.
Item 15. Recent Sales of Unregistered Securities
None.
Item 16. Exhibits and Financial Statement Schedules.
(a) Exhibits
Exhibit No. Exhibit
----------- -------
3.1 Memorandum of Association as amended on June 30, 1982, May
14, 1985 and April 7, 1988 filed as Exhibit 4B to Form S-8
as filed on November 25, 1998 is incorporated by reference.
3.2 By-laws, as amended, filed as Exhibit 4C to Form S-8 as
filed on November 25, 1998 are
5 Form of Opinion of Counsel - Patterson Palmer Hunt Murphy
(filed herewith).
10.1 Agreement dated May 28, 1959 between the Company et al. and
Home Oil Company Limited et
10.2 Copies of Supplementary Documents to May 28, 1959 Agreement
(see Exhibit 10.1 above),
10.3 Copy of Modification to Agreement dated May 28, 1959
(see Exhibit 10.1 above), made as of
10.4 Copy of Agreement dated April 1, 1966 among the Company et
al. and Dome Petroleum Limited
10.5 Copy of Letter Agreement dated February 1, 1977 between the
Company and Columbia Gas
10.6 Copy of Agreement dated January 28, 1972 between the Company
and Panarctic Oils Ltd. for
10.7 Stock Option Plan adopted December 9, 1992 filed as Exhibit
10(c) to Annual Report on Form
10.8 Stock Option Plan effective July 1, 1998 filed as Exhibit A
to Schedule 14A Information
23.1 Consent of Ernst & Young LLP (filed herewith).
23.2 Consent of Patterson Palmer Hunt Murphy (filed herewith).
23.3 Consent of Murtha Cullina LLP (filed herewith).
23.4 Consent of Blake, Cassels & Graydon LLP (filed herewith).
23.5 Consent of Paddock Lindstrom & Associates, Ltd.
(filed herewith).
24 Powers of Attorney of Ben A. Anderson, M. Anthony Ashton,
Timothy L. Largay, Arthur B.
27 Financial Data Schedule.
99.1 Form of rights certificate/subscription card (filed
herewith).
99.2 Instructions for Purchasing Stock (filed herewith).
99.3 Offering cover letter to stockholders (filed herewith).
Item 17. Undertakings
The undersigned registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being made,
a post-effective amendment to this registration statement:
(i) To include any prospectus required by section 10(a)(3) of the
Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events arising after the
effective date of the registration statement (or the most recent post-effective
amendment thereof) which, individually or in the aggregate, represent a
fundamental change in the information set forth in the registration statement;
(iii) To include any material information with respect to the plan of
distribution not previously disclosed in the registration statement or any
material change to such information in the registration statement;
Provided, however, that paragraphs (1)(i) and (1)(ii) do not apply if
the registration statement is on Form S-3 or Form S-8, and the information
required to be included in a post-effective amendment by those paragraphs is
contained in periodic reports filed by either registrant pursuant to section 13
or section 15(d) of the Securities Exchange Act of 1934 that are incorporated by
reference in the registration statement.
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed to be
a new registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona
fide offering thereof.
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the termination of
the offering.
(4) To file a post-effective amendment to the registration statement to
include any financial statements required by Rule 3-19 of Regulation S-X at the
start of any delayed offering or throughout a continuous offering.
<PAGE>
Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the registrants pursuant to the foregoing provisions, or otherwise, the
registrants have been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the
Securities Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
registrants of expenses incurred or paid by a director, officer or controlling
person of the registrants in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the registrants will, unless in
the opinion of its counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question whether such
indemnification is against public policy as expressed in the Securities Act and
will be governed by the final adjudication of such issue.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
registrant has duly caused this amendment to this registration statement to be
signed on its behalf by the undersigned, thereunto duly authorized in the city
of Calgary, Alberta, Canada, on the 22nd day of September, 2000.
CANADA SOUTHERN PETROLEUM LTD.
(Registrant)
By: /s/ Ben A. Anderson
Ben A. Anderson, President
Pursuant to the requirements of the Securities Act of 1933, this
amendment to this registration statement has been signed below by the following
persons in the capacities and o the date indicated.
<TABLE>
Signature Title Date
--------- ----- ----
Principal executive officer:
<S> <C> <C>
/s/Ben A. Anderson President September 22, 2000
------------------
Ben A. Anderson
Principal financial officer:
/s/David Blain Secretary/Treasurer and Chief September 22, 2000
-------------- Financial Officer
David Blain
A majority of the Board of
Directors:
/s/ James R. Joyce September 22, 2000
------------------
James R. Joyce
Attorney-in-Fact for:
Ben A. Anderson Director
M. Anthony Ashton Director
Benjamin W. Heath Director
Timothy L. Largay Director
Arthur B. O'Donnell Director
</TABLE>
Pursuant to the requirements of the Securities Act of 1933, the
undersigned has signed this registration statement on September 22, 2000.
/s/James R. Joyce
James R. Joyce
Authorized Representative
in the United States
<PAGE>
INDEX OF EXHIBITS
Item Number Description
5 Form of Opinion of Counsel - Patterson Palmer
Hunt Murphy
23.1 Consent of Ernst & Young LLP
23.2 Consent of Patterson Palmer Hunt Murphy
23.3 Consent of Murtha Cullina LLP
23.4 Consent of Blake, Cassels & Graydon LLP
23.5 Consent of Paddock Lindstrom & Associates, Ltd.
24 Powers of Attorney of Ben A. Anderson,
M. Anthony Ashton, Benjamin W. Heath,
27 Financial Data Schedule
99.1 Form of rights certificate/subscription card
99.2 Instructions for Purchasing Stock
99.3 Offering cover letter to stockholders
<PAGE>
