FORM 20-F
[ ] Registration Statement pursuant to Section 12(b) or (g) of the Securities
Exchange Act of 1934
or
[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended August 31, 2000
or
[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ............ to .............
Commission file number: 0-30196
TRIMARK OIL & GAS LTD.
(Exact name of Registrant as specified in its charter)
TRIMARK OIL & GAS LTD.
(Translation of Registrant's name into English)
YUKON TERRITORY, CANADA
(Jurisdiction of incorporation or organization)
1305 - 1090 WEST GEORGIA STREET, VANCOUVER, BRITISH COLUMBIA, V6E 3V7
(Address of principal executive offices)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
NONE
Securities registered or to be registered pursuant to Section 12(g) of the Act.
COMMON STOCK, NO PAR VALUE
(Title of Class)
Securities for which there is a reporting obligation pursuant to Section 15(d)
of the Act.
NONE
(Title of Class)
Indicate the number of outstanding shares of each of the issuer's classes of
capital or common stock as of the close of the period covered by the annual
report.
16,005,446 COMMON SHARES AS OF AUGUST 31, 2000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
----- ------
Indicate by checkmark which financial statement item the registrant has elected
to follow.
Item 17 X Item 18 Page 1 of 104
------ ------
CURRENCY TRANSLATIONS
UNLESS OTHERWISE INDICATED, ALL DOLLAR AMOUNTS ARE EXPRESSED IN CANADIAN
DOLLARS. The following table sets forth the exchange rates for one Canadian
dollar expressed in terms of one U.S. dollar for the past five fiscal years.
YEAR AVERAGE LOW - HIGH PERIOD END
- ---- ------- ---------- ----------
September 1, 1995 - August 31, 1996 0.7335 0.7235 - 0.7527 0.7307
September 1, 1996 - August 31, 1997 0.7296 0.7145 - 0.7513 0.7199
September 1, 1997 - August 31, 1998 0.6901 0.6341 - 0.7292 0.6351
September 1, 1998 - August 31, 1999 0.6682 0.6423 - 0.6891 0.6682
September 1, 1999 - August 31, 2000 0.6805 0.6629 - 0.6969 0.6793
Exchange rates are based upon the noon buying rate in New York City for cable
transfers in foreign currencies as certified for customs purposes by the Federal
Reserve Bank of New York.
The noon rate of exchange on January 31, 2001, reported by the United States
Federal Reserve Bank of New York for the conversion of Canadian dollars into
United States dollars was CDN$1.4995 (US$0.6669 = CDN$1.00).
The Company has not paid any dividends during the past five fiscal years.
GLOSSARY
The following is a glossary of oil and gas terms used in this annual report:
ANTICLINES Underground mountain-shaped strata
covered with caprock or an impervious
layer.
BBL OR BARREL 34.972 Imperial gallons or 42 US gallons
BCF One billion cubic feet.
BO Barrels of oil.
BOE Barrels of oil equivalent.
BOPD Barrels of oil per day.
BW Barrels of water.
BWPD Barrels of water per day.
FARM-IN Acquisition of all or part of the
operating rights from the working
interest owner to an assignee, by the
assumption of all or some of the burden
of development to earn an interest in
the property. The vendor usually retains
an overriding royalty but may retain any
type of interest.
2
FARM-OUT Transfer of all or part of the operating
rights from the working interest owner
to an assignee, who assumes all or some
of the burden of development in return
for an interest in the property. The
assignor usually retains an overriding
royalty but may retain any type of
interest.
GROSS ACRES The total number of acres in which
the company holds a working interest or
the right to earn a working interest.
GROSS RESERVES The total reserves estimated to be
economically recoverable.
GROSS WELLS The total number of wells in which the
company has a working interest.
ISOPACH MAPS Maps showing variations in the thickness
of a particular sedimentary bed and the
interval or spacing between one
sedimentary bed and another.
LIQUIDS Crude oil and natural gas liquids.
MBO One thousand barrels of oil.
MCF One thousand cubic feet.
MD Millidarcies - a term used to measure
the relative ease with which oil and gas
can flow.
MMBOE One million barrels of oil equivalent.
MMCFD One million cubic feet per day.
NET ACRES The gross acres multiplied by the
percentage working interest therein
owned or to be owned by the company.
NET RESERVES The company's lessor royalty,
overriding royalty, and working interest
share of reserves from the properties,
after deduction of all freehold, and
overriding royalties payable to others.
NET REVENUE INTEREST The percentage interest in which the
lessor has the right to receive a
specified fractional share of the
minerals produced from the property or
value thereof.
NET WELLS The gross wells multiplied by the
percentage working interest therein
owned or to be owned by the company.
NGLS Natural gas liquids.
3
PROVED OIL AND GAS RESERVES Proved oil and gas reserves are the
estimated quantities of crude oil,
natural gas, and natural gas liquids
which geological and engineering data
demonstrate with reasonable certainty to
be recoverable in future years from
known reservoirs under existing economic
and operating conditions, i.e. prices
and costs as of the date the estimate is
made. Prices include consideration of
changes in existing prices provided only
by contractual arrangements, but not on
escalations based upon future
conditions.
(i) Reservoirs are considered
proved if economic
producibility is supported by
either actual production or
conclusive formation test. The
area of a reservoir considered
proved includes:
(A) that portion delineated by
drilling and defined by
gas- oil and/or oil-water
contacts, if any; and
(B) the immediately adjoining
portions not yet drilled,
but which can be
reasonably judged as
economically productive on
the basis of available
geological and engineering
data. In the absence of
information on fluid
contacts, the lowest known
structural occurrence of
hydrocarbons controls the
lower proved limit of the
reservoir.
(ii) Reserves which can be produced
economically through
application of improved
recovery techniques (such as
fluid injection) are included
in the "proved" classification
when successful testing by a
pilot project, or the operation
of an installed program in the
reservoir, provides support for
the engineering analysis on
which the project or program
was based.
4
(iii)Estimates of proved reserves do
not include the following:
(A) Oil that may become
available from known
reservoirs but is
classified separately as
"indicated additional
reserves",
(B) Crude oil, natural gas,
and natural gas liquids,
the recovery of which is
subject to reasonable
doubt because of
uncertainty as to geology,
reservoir characteristics,
or economic factors,
(C) Crude oil, natural gas,
and natural gas liquids,
that may occur in
undrilled prospects, and
(D) Crude oil, natural gas,
and natural gas liquids,
that may be recovered from
oil shales, coal,
gilsonite and other such
sources.
PROVED DEVELOPED OIL Reserves that can be expected to be
AND GAS RESERVES Recovered through existing wells with
existing equipment and operating
methods. Additional oil and gas expected
to be obtained through the application
of fluid injection or other improved
recovery techniques for supplementing
the natural forces and mechanisms of
primary recovery should be included as
"proved developed reserves" only after
testing by a pilot project or after the
operation of an installed program has
confirmed through production response
that increased recovery will be
achieved.
PROVED UNDEVELOPED RESERVES Reserves that are expected to be
recovered from new wells on undrilled
acreage, or from existing wells where a
relatively major expenditure is required
for recompletion. Reserves on undrilled
acreage shall be limited to those
drilling units offsetting productive
units that are reasonably certain of
production when drilled. Proved reserves
for other undrilled units can be claimed
only where it can be demonstrated with
certainty that there is continuity of
production from the existing productive
formation. Under no circumstances should
estimates for proved undeveloped
reserves be attributable to any acreage
for which an application of fluid
injection or other improved recovery
technique is contemplated, unless such
techniques have been proved effective by
actual tests in the area and in the same
reservoir.
PROVED PROPERTIES Properties with proved reserves.
UNPROVED PROPERTIES Properties with no proved reserves.
REVERSIONARY INTEREST A portion of an economic nterest that
will be returned to its former owner
after a predetermined amount of
production or income has been produced.
5
UNDEVELOPED ACREAGE Lands on which there are no current
reserves assigned.
WATERFLOODING The secondary recovery method in which
water is forced down injection wells
laid out in various patterns around the
producing wells. The water injected
displaces the oil and forces it to the
producing wells.
WORKING INTEREST The interest held by a company in an oil
or natural gas property, which interest
normally bears its proportionate share
of the costs of exploration,
development, and operation as well as
any royalties or other production
burdens.
WORKOVER A major remedial operation on a
completed well to restore, maintain, or
improve the well's production. Workovers
use workover rigs and can take many
forms such as acidizing or fracing the
well or removal of sand or paraffin
buildup. The term workover is also used
for deepening an existing well or
plugging back to produce from a
shallower formation.
6
PART I
ITEM 1. DESCRIPTION OF BUSINESS.
- --------------------------------------------------------------------------------
NAME AND INCORPORATION
The head office and principal address of the Company is located at #1305 - 1090
West Georgia Street, Vancouver, British Columbia, V6E 3V7.
The Company was incorporated under the laws of British Columbia, Canada, under
the name of Golden Chance Resources Inc. on June 16, 1983. On November 12, 1986,
a special resolution was passed authorizing an increase in the number of
authorized shares from 10,000,000 shares without par value to 30,000,000 shares.
The number of common shares outstanding increased in the same proportion. On
October 15, 1990, the Company's name was changed to Trimark Resources Ltd. and a
one new for nine old share consolidation was implemented. The Company also
increased its authorized capital to 30,000,000 common shares. On December 14,
1993, the Company was continued under the BUSINESS CORPORATIONS ACT (Yukon
Territory). On the continuance the Company changed its authorized capital into
"unlimited common shares without par value." On December 13, 1996, the Company's
name was changed to International Trimark Resources Ltd. On June 16, 1997, the
Company's name was changed to Trimark Oil & Gas Ltd. and a one new for two old
share consolidation was implemented.
The Company's common shares were listed on the Vancouver Stock Exchange (the
"VSE") through November 28, 1999. Effective November 29, 1999, the VSE and the
Alberta Stock Exchange (the "ASE") merged and began operations as the Canadian
Venture Exchange (the "CDNX"). The merger of the VSE and the ASE to form the
CDNX has not had a significant impact on the Company's operations. The CDNX
classifies listed companies into two different tiers based on standards, which
include historical financial performance, stage of development, and financial
resources of the listed company. Tier I is the CDNX's premier tier and is
reserved for the CDNX's most advanced issuers with the most significant
financial resources. As an oil and gas issuer, an issuer must meet the following
criteria to be classified as Tier I:
i) proven reserves with a present value of CDN $2.0 million based
on constant dollar pricing assumptions, discounted at 15%; and
ii) adequate working capital (at least CDN $500,000).
Tier I issuers benefit from decreased filing requirements and improved service
standards. The majority of the companies listed on the CDNX are Tier II
companies. The Company trades on the CDNX under the symbol "TMK" and is
classified as a Tier II company. The Company has made a submission to the CDNX
to be classified as a Tier I issuer and is awaiting completion of the CDNX's
review.
Effective August 7, 2000, the Company's common stock was listed for quotation on
the Over-the-Counter Bulletin Board operated by the National Association of
Securities Dealers under the symbol "TOGSF".
The Company has one wholly-owned subsidiary, Trimark Resources Inc. ("Trimark
Inc."), which was incorporated on June 4, 1993, under the laws of the state of
Colorado. Trimark Inc. has one wholly-owned subsidiary, Safari Petroleum LLC
("Safari"), a limited liability company formed on June 14, 1995, under the
7
laws of the state of Colorado. The Company, through Trimark Inc. and Safari,
engages in oil and gas activities in the United States.
CORPORATE STRUCTURE
The following chart sets forth the names of the subsidiaries of the Company,
their respective jurisdictions of incorporation or continuance and the Company's
current voting and equity interests therein. Unless otherwise indicated herein,
the term the "Company" means collectively the Company and its subsidiaries.
--------------------------
| TRIMARK OIL & GAS LTD. |
| (Yukon) |
--------------------------
|
|
-------------------------- --------------------------------
| | | PROPERTIES: |
| TRIMARK RESOURCES INC. | | East Lost Hills Joint Venture|
| (Colorado) |-------------| San Joaquin Joint Venture |
| 100% | | Regional California |
| | | East Blossom Prospect |
| | | West Simon Project |
--------------------------- --------------------------------
|
|
--------------------------- --------------------------------
| | | |
| | | PROPERTIES: |
| SAFARI PETROLEUM LLC |-------------| Big Springs Unit |
| (Colorado) | | South Haskell Field |
| 100% | | |
--------------------------- --------------------------------
DESCRIPTION OF BUSINESS OF TRIMARK
Since October 1990, the Company, through Trimark Inc. and Safari, has been
active in the business of acquiring, exploring and developing oil and gas
prospects in the United States. The Company's principal assets are its interests
in the East Lost Hills Joint Venture, the San Joaquin Joint Venture and
interests in Regional California. These assets are currently at the exploration
stage. The Company is concentrating its oil and gas exploration efforts on these
properties. The Company also holds interests in minor producing wells, in the
Big Springs Unit and South Haskell Field, and interests in the East Blossom
Prospect and the West Simon Project. These assets are described in detail in
"Item 1. Description of Business - Material Properties."
The Company sells its share of petroleum, natural gas and natural gas liquids to
a variety of purchasers at the wellhead in the United States. The Company makes
all of its sales on a spot basis. These purchasers provide a ready market for
all the Company's production and pay the local market price, which can fluctuate
from day-to-day based upon prevailing market conditions. Due to the number of
purchasers in each area, management does not feel that the loss of one or a
number of purchasers would pose a significant risk to the continuity of the
Company's operations. The Company does not maintain significant inventories of
petroleum or natural gas liquids and has no gas balancing arrangements in place.
8
Total revenues reported for fiscal 1998, 1999 and 2000 were as follows:
YEARS ENDED MAY 31,(IN $000)
---------------------------------------
2000 1999 1998
$ $ $
Oil and Gas Sales
- United States 203 136 229
---------- --------- ----------
Interest and Other
- United States 58 - -
- Canada 137 7 3
---------- --------- ----------
195 7 3
---------- --------- ----------
Total Revenues 398 143 232
========== ========= ==========
EXPLORATION EXPENDITURES
During fiscal 1998, 1999 and 2000, the Company incurred $1,712,635, $4,625,161
and $2,817,323, respectively, on the acquisition, exploration and development of
its petroleum interests.
As of the date of this report, the Company's significant exploration and
development projects are located in California, where the Company is
participating in three joint ventures, the East Lost Hills, the San Joaquin and
the Regional California joint ventures. The Company anticipates that it could
incur up to US$3.7 million in exploration and development expenditures on these
properties for the 2001 calendar year.
The US$3.7 million assumes that all wells currently in progress and wells which
may be proposed will, in fact, all be drilled and completed. These projections
and work schedules are contingent on many factors, many of which are beyond the
Company's control. Work schedules can and will change based on results in the
field. Actual costs may vary significantly from current estimates. The estimates
are management's estimates of the upper limits of possible expenditures to be
incurred.
The Company has not allocated funds for further development of its interests in
the Big Springs Unit and South Haskell Field.
MATERIAL PROPERTIES
EAST LOST HILLS JOINT VENTURE AND SAN JOAQUIN JOINT VENTURE, CALIFORNIA
In February 1999, Berkley Petroleum Corp. ("Berkley") agreed to purchase from
Armstrong Resources LLC ("Armstrong") an interest in various oil and gas
prospects in the San Joaquin Basin. Neither Berkley or Armstrong are affiliates
of the Company, and to the best of the Company's knowledge Berkley and Armstong
are not affiliated with each other. In order to reduce its financial
commitments, Berkley allowed other companies to participate with it in the
acquisition. Hilton Petroleum Inc. ("Hilton Inc."), a wholly- owned subsidiary
of Hilton Petroleum Ltd. ("Hilton"), acquired an 11% interest of which 4% was
reserved for the Company. On February 26, 1999, the Company entered into an
agreement to acquire, for a purchase price of approximately $2,151,000
(US$1,450,000), a 4% capital interest (3% working interest) in the San Joaquin
Joint Venture from Hilton Inc. The agreement with Berkley and Armstrong requires
that the
9
Company pay 4% of the costs on the first three wells ("capital interest"), and
3% of the costs on all subsequent wells. The Company's share of net revenues, if
any, will be approximately 2.5% in the San Joaquin Joint Venture ("net revenue
interest"). The Company's agreement with Hilton Inc. was on identical terms as
Hilton Inc.'s agreement with Berkley other than a promote fee of $74,170
(US$50,000) which has been capitalized as an acquisition cost. The Company is
obligated to fund its prorata share of the exploration costs. Hilton is a public
company which has certain directors and officers in common with the Company.
Berkley is the operator of the San Joaquin Joint Venture.
As a condition of Berkley's acquisition of the San Joaquin Joint Venture
properties, Berkley acquired, on a reversionary basis, Armstrong's 17.5%
interest in the East Lost Hills Joint Venture. After a specified level of oil
and gas revenue is generated the 17.5% interest will be returned to Armstrong.
As part of the Company's acquisition of the 4% interest in the San Joaquin Joint
Venture, the Company acquired a 0.7% (4% of 17.5%) reversionary working interest
in the East Lost Hills Joint Venture. Of the approximately $2,151,000
(US$1,450,000) purchase price of the San Joaquin Joint Venture Interest and the
0.7% reversionary working interest, $1,038,000 (US$700,000) was allocated to the
0.7% reversionary working interest.
On March 8, 1999, the Company entered into an agreement to acquire, from Hilton
Inc., a 1% working interest in the East Lost Hills Joint Venture for
approximately $2,972,000 (US$2,000,000) and sold to Hilton Inc. its 0.7%
reversionary interest in the East Lost Hills Joint Venture at its recorded cost
of $1,038,000 (US$700,000). The 0.7% interest was sold in order to fund the
payment for the acquisition of the 1% working interest from Hilton Inc. The 1%
working interest acquired by the Company from Hilton Inc. does not revert to
Armstrong. The $1,038,000 proceeds from the sale were credited against the
$2,972,000 payable to Hilton Inc. Of the remaining $1,934,000 (US$1,300,000)
payable, $890,000 (US$600,000) was paid in cash and $1,044,000 (US$700,000) was
paid by the issuance of 1,160,000 of the Company's common shares at a deemed
price of $0.90 per share. The Company is also obligated to pay its proportionate
share of all on-going exploration activities. The Company's share of net
revenues, if any, will be approximately 0.80% in the East Lost Hills Joint
Venture. Berkley is the operator of the East Lost Hills Joint Venture.
The Company closed the acquisition of the San Joaquin Joint Venture and the East
Lost Hills Joint Venture in July 1999.
The San Joaquin Joint Venture and the East Lost Hills Joint Venture are both
situated in the oil-rich San Joaquin Basin, approximately 45 miles northwest of
Bakersfield. See "Item 2. Description of Property."
As of August 31, 2000, the Company had recorded approximately $1.9 million in
leasehold acquisition costs and $960,000 in exploration and development
expenditures on the East Lost Hills Joint Venture and $2.2 million in leasehold
acquisition costs and $1.1 million in exploration and development expenditures
on the San Joaquin Joint Venture. See "Item 2. Description of Property -
Material Properties - East Lost Hills Joint Venture and San Joaquin Joint
Venture, California."
The Company has budgeted US$660,000 for exploration and development on the East
Lost Hills Joint Venture and San Joaquin Joint Venture during the 2001 calendar
year.
10
REGIONAL CALIFORNIA
The Company has agreed with Pohle Oil & Gas Inc. ("Pohle") to participate in the
generation, acquisition and exploration of oil and gas projects in the San
Joaquin Basin of California. Pohle is a private arm's length company located in
Bakersfield, California. The Company's initial capital interest was 23.333%
which was increased to 31.666% effective December 1, 2000 and effective January
1, 2001, increased to 43.66668%. As of February 26, 2001 an oil and gas
exploration agreement was signed with Pohle.
Under the agreement, the Company, effective January 1, 2001, will reimburse
Pohle for its 43.66668% share of all costs associated with the generation of oil
and gas prospects including, but not limited to, overhead costs, geologic and
geophysical costs and lease acquisition costs. In addition, the Company will pay
up to 43.66668% of drilling costs through completion and sales point for the
first well drilled on a specific prospect. All of Pohle's costs on the first
well drilled are paid by the other partners in the joint ventures. For any
subsequent well drilled on a prospect or operating costs when operations
commence, the Company will pay up to 32.749% of the costs.
From May 22, 2000 through August 31, 2000, the Company spent $547,000.
OTHER PROPERTIES
EAST BLOSSOM PROSPECT, SAN JOAQUIN COUNTY, CALIFORNIA
On May 17, 2000, the Company entered into an agreement with Sunset Exploration,
Inc., a private California corporation whereby the Company could earn a 25%
working interest (18.75% net revenue interest) in the first well, before payout,
and a 12.5% working interest (9.375% net revenue interest) after payout, and in
subsequent wells, in oil and gas leasehold interests and lands, encompassing 826
acres, located in San Joaquin County, California.
During fiscal 2000, the Company spent $200,000 pursuant to the terms of the
agreement and earned its 25% working interest. During fiscal 2000, the Company
drilled and completed the well. For fiscal 2001, the Company has budgeted
$30,000 to complete the hookup of the well.
WEST SIMON PROJECT, JEFFERSON DAVIS PARISH, LOUISIANA
On January 13, 2000, the Company entered into an agreement with Valley Oil &
Gas, LLC, a private corporation whereby the Company purchased a 24% working
interest (18% net revenue interest) in the West Simon Project, encompassing 320
acres, located in Jefferson Davis Parish, Louisiana, for US$241,750.
Including the acquisition cost of its interest in the West Simon Project, the
Company spent approximately $524,000 in lease acquisition and drilling costs on
the West Simon Project during fiscal 2000. For fiscal 2001, the Company has
budgeted and spent $30,000 to complete the well and bring the well on
production. There are no further capital costs.
11
BIG SPRINGS UNIT, DEUEL COUNTY, NEBRASKA
The Big Springs Unit is comprised of working interests in leases located in
Deuel County, Nebraska. On April 11, 1997, the Company and Mr. E. J. Helsley,
the son-in-law of Mr. Donald W. Busby, an officer, director and principal
shareholder of the Company, entered into an agreement whereby the Company
acquired from Mr. Helsley an initial 100% working interest (80% net revenue
interest) in the Big Springs Unit. The Company obtained shareholder and
regulatory approval of the acquisition in September 1997, and issued 1,300,000
common shares of the Company at a deemed price of $1.26 per share and paid the
sum of $916,500 (US$660,000) cash to Mr. Helsley and completed the transaction.
The Big Springs Unit is subject to overriding royalties aggregating 20% owned by
individuals who are not related to the Company. After the acquisition of the Big
Springs Unit, the Company proceeded to farm-out certain of its interests.
On September 10, 1997, the Company and Rainbow Oil & Gas, Inc. ("Rainbow"), a
non-affiliate, agreed that Rainbow could earn a 25% working interest (20% net
revenue interest) in all wells drilled on the Big Springs Unit by spending
approximately $810,000 (US$550,000) on drilling and completing wells and issuing
4,000 of its common shares to the Company. The Company closed the transaction
with Rainbow in December 1997. As of the date of this annual report, Rainbow has
earned its 25% interest.
On September 12, 1997, the Company and STB Energy Inc. ("STB") agreed that STB
could earn a 25% working interest (20% net revenue interest) in new wells
drilled in the Big Springs Unit by spending approximately $810,000 (US$550,000)
on drilling and completing wells on the Big Springs Unit. STB is an indirectly
wholly-owned subsidiary of Hilton. The Company closed the transaction with STB
in December 1997. STB has spent its $810,000 (US$550,000) and earned its
interests.
As a result of the farm-outs to Rainbow and STB, the Company maintains working
interests of between 50% and 75% in various wells in the Big Springs Unit.
Management has no further exploration and development plans for the Big Springs
Unit during the remainder of the fiscal year ending August 31, 2001. As of
August 31, 2000, the Company had recorded $235,000 as the net carrying value in
the Big Springs Unit.
SOUTH HASKELL FIELD, HASKELL COUNTY, TEXAS
Commencing November 1994, the Company participated in the identification of
prospective acreage, seismic work and drilling of twelve wells in the South
Haskell Field, Haskell County, Texas. By paying its 10% share of costs, the
Company owns a 10% working interest and a 8% net revenue interest in twelve
wells. Management has no further exploration and development plans for the South
Haskell Field during the remainder of the fiscal year ending August 31, 2001.
12
OTHER ASSETS
In addition to its petroleum interests, the Company holds the following assets
as at January 31, 2001:
(a) a US$400,000 unsecured convertible note (the "ALPNET Note") dated June
2, 2000, issued by ALPNET, Inc. ("ALPNET"), a public Utah company
trading on the facilities of the National Association of Securities
Dealers. The ALPNET Note has a variable interest rate of US prime plus
2%, payable on a quarterly basis. The principal is repayable in three
equal annual instalments commencing June 2, 2003. The Company has the
right to convert all or any portion of the outstanding principal into
common stock of ALPNET, on the basis of US$2.22 per share. ALPNET has
the right to pay the full amount, or any portion, of the ALPNET Note
prior to its maturity.
In connection with the ALPNET Note, ALPNET granted the Company a
warrant to purchase up to 90,090 common shares of ALPNET, at an
exercise price of US$3.33 per share, on or before June 2, 2002. The
closing price of ALPNET's common stock on January 31, 2001 was US$1.28.
(b) during the year ended August 31, 2000, the Company provided a
US$125,000 relocation loan to Donald W. Busby, the President, Chairman
and CEO of the Company. The loan bears interest at 5% per annum,
compounded monthly, and matures on March 27, 2002. As at January 31,
2001, the US$125,000 principal, plus accrued interest of US$5,429,
remained outstanding.
EMPLOYEES
As of January 31, 2001, the Company has no paid employees. The Company has,
however, retained DWB Management Ltd. ("DWB"), a company wholly-owned by Mr.
Donald W. Busby, the President, Chairman and Chief Executive Officer of the
Company, to provide marketing, financial management and consulting services. The
Company has also retained Chase Management Ltd. ("Chase") to provide accounting,
management and administrative services. Chase is a private company wholly-owned
by Mr. Nick DeMare, a director of the Company. In addition, the Company employs
a number of consultants to perform specific functions, on an as needed basis.
RISK FACTORS
Due to the nature of the Company's business and the present stage of exploration
on its oil and gas prospects, the following risk factors apply to the Company's
operations:
EXPLORATION AND PRODUCTION RISKS
The business of exploring for and producing oil and gas involves a substantial
risk of investment loss which even a combination of experience, knowledge and
careful evaluation may not be able to overcome. Drilling oil and gas wells
involves the risk that the wells will be unproductive or that, although
productive, the wells do not produce oil and/or gas in economic quantities.
Other hazards, such as unusual or unexpected geological formations, pressures,
fires, blowouts, loss of circulation of drilling fluids or other conditions may
substantially delay or prevent completion of any well. Specifically, the
operators of the East Lost Hills Joint Venture have experienced a fire and
blowout during their exploration. Adverse weather conditions can also hinder
drilling operations. A productive well may become uneconomic in the event water
or other deleterious substances are encountered, which impair or prevent the
production of oil and/or gas from the
13
well. In addition, production from any well may be unmarketable if it is
impregnated with water or other deleterious substances. As with any petroleum
property, there can be no assurance that oil and gas will be produced from the
properties in which the Company has interests. In addition, the marketability of
oil and gas which may be acquired or discovered, will be affected by numerous
factors beyond the control of the Company. These factors include the proximity
and capacity of oil and gas pipelines and processing equipment, market
fluctuations of prices, taxes, royalties, land tenure, allowable production and
environmental protection. The extent of these factors cannot be accurately
predicted, but the combination of these factors may result in the Company not
receiving an adequate return on invested capital. There is no assurance that
additional crude oil or natural gas in commercial quantities will be discovered
by the Company.
FINANCING RISKS
As of January 31, 2001, the Company had working capital of approximately
$575,000. The Company anticipates it could incur exploration and development
expenditures, completion costs and ongoing overhead for calendar 2001 totaling
approximately $6.2 million.
The Company has primarily relied on the sale of its equity capital to fund the
acquisition, exploration and development of its petroleum properties. There can
be no assurance that the Company will be able to obtain adequate financing in
the future or that the terms of such financing will be favorable. Failure to
obtain such additional financing could result in the delay or indefinite
postponement of further exploration and development of the Company's projects
with the possible loss of such properties.
NON-OPERATOR STATUS
At this stage of its business, the Company relies upon other project
participants to provide and complete all project operations and responsibilities
including operating, drilling, marketing and project administration. As a
result, the Company has only a limited ability to exercise control over a
significant portion of a project's operations or the associated costs of those
operations. The success of a project is dependent upon a number of factors that
are outside of the Company's area of expertise and project responsibilities.
These factors include: (1) the availability of favorable term leases and
required permitting for projects, (2) the availability of future capital
resources by the Company and the other participants for the purchasing of leases
and the drilling of wells, (3) the approval of other participants to the
purchasing of leases and the drilling of wells on the projects, and (4) the
economic conditions at the time of drilling, including the prevailing and
anticipated prices for oil and gas. The Company's reliance on other project
participants and its limited ability to directly control certain project costs
could have a material negative effect on the Company's receipt of expected rates
of return on the Company's investment in certain projects.
UNINSURABLE RISKS
Although management believes the operator of any properties in which the Company
and its subsidiaries may acquire interests, will acquire and maintain
appropriate insurance coverage in accordance with standard industry practice,
the Company and its subsidiaries may suffer losses from uninsurable hazards or
from hazards which the operator has chosen not to insure against because of high
premium costs or other reasons. The Company and its subsidiaries intend to
engage in participating in the drilling of both exploratory and development
wells. Exploratory wells have much greater dry hole risk than do wells which are
drilled offsetting established production. The Company and its subsidiaries may
become subject to liability for
14
pollution, fire, explosion, blow-outs, cratering and oil spills against which it
cannot insure or against which it may elect not to insure. Such events could
result in substantial damage to oil and gas wells, producing facilities and
other property and personal injury. The payment of any such liabilities may have
a material, adverse effect on the Company's financial position.
NO ASSURANCE OF TITLES
It is the practice of the Company in acquiring oil and gas leases or undivided
interests in oil and gas leases not to undergo the expense of retaining lawyers
to examine the title to the mineral interest to be placed under lease or already
placed under lease. Rather, the Company will rely upon the judgment of oil and
gas lease brokers or landsmen who perform the field work in examining records in
the appropriate governmental office before attempting to place under lease a
specific mineral interest. This practice is widely followed in the oil and gas
industry. Prior to the drilling of an oil and gas well, however, it is the
normal practice in the oil and gas industry for the person or company acting as
the operator of the well to obtain a preliminary title review of the spacing
unit within which the proposed oil and gas well is to be drilled to ensure there
are no obvious deficiencies in title to the well, however, neither the Company
nor the person or company acting as operator of the well will obtain counsel to
examine title to such spacing unit until the well is about to go into
production. It frequently happens, as a result of such examinations, that
certain curative work must be done to correct deficiencies in the marketability
of the title, and such curative work entails expense. The work might include
obtaining affidavits of heirship or causing an estate to be administered. IT
DOES HAPPEN, FROM TIME TO TIME, THAT THE EXAMINATION MADE BY THE TITLE LAWYERS
REVEALS THAT THE OIL AND GAS LEASE OR LEASES ARE WORTHLESS, HAVING BEEN
PURCHASED IN ERROR FROM A PERSON WHO IS NOT THE OWNER OF THE MINERAL INTEREST
DESIRED. IN SUCH INSTANCES, THE AMOUNT PAID FOR SUCH OIL AND GAS LEASE OR LEASES
IS GENERALLY LOST. To date the Company has not lost title to any of its oil and
gas leases, nor is it aware that any of its currently held properties is subject
to being lost as a result of faulty titles.
ENVIRONMENTAL REGULATIONS
In general, the exploration and production activities of the Company are subject
to certain federal, state and local laws and regulations relating to
environmental quality and pollution control. Such laws and regulations increase
the costs of these activities and may prevent or delay the commencement or
continuance of a given operation. Compliance with these laws and regulations has
not had a material effect on the Company's operations or financial condition to
date. Specifically, the Company is subject to legislation regarding emissions
into the environment, water discharges, and storage and disposition of hazardous
wastes. In addition, legislation has been enacted which requires well and
facility sites to be abandoned and reclaimed to the satisfaction of state
authorities. However, such laws and regulations are frequently changed and the
Company is unable to predict the ultimate cost of compliance. Generally,
environmental requirements do not appear to affect the Company any differently
or to any greater or lesser extent than other companies in the industry.
The Company believes that its operations comply, in all material respects, with
all applicable environmental regulations.
GOVERNMENTAL REGULATIONS
Oil and gas exploration, development and production are subject to various types
of regulation by local, state and federal agencies. Legislation affecting the
oil and gas industry is under constant review for amendment
15
and expansion. Also, numerous departments and agencies, both federal and state,
are authorized by statute to issue and have issued rules and regulations binding
on the oil and gas industry and its individual members, some of which carry
substantial penalties for failure to comply. The regulatory burden on the oil
and gas industry increases the Company's cost of doing business and,
consequently, affects its profitability. However, since these regulations
generally apply to all oil and gas producers, management of the Company believes
that these regulations should not put the Company at a material disadvantage to
other oil and gas producers.
Most states in which the Company and its subsidiaries own and operate properties
have statutes, rules and regulations governing conservation matters including
the unitization or pooling of oil and gas properties, establishment of maximum
rates of production from oil and gas wells and the spacing of such wells.
Oil and gas mineral rights may be held by individuals or corporations and, in
certain circumstances, by governments having jurisdiction over the area in which
such mineral rights are located. As a general rule, parties holding such mineral
rights grant licenses or leases to third parties to facilitate the exploration
and development of these mineral rights. The terms of the leases and licenses
are generally established to require timely development. Notwithstanding the
ownership of mineral rights, the government of the jurisdiction in which mineral
rights are located generally retains authority over the manner of development of
those rights.
In addition to royalties paid to freehold owners, each state generally imposes a
production or severance tax with respect to production and sale of crude oil,
natural gas and natural gas liquids within their respective jurisdictions. For
the most part, state production taxes are applied as a percentage of production
or sales.
NATURAL GAS AND OIL PRICES
In recent decades, there have been periods of both worldwide overproduction and
underproduction of hydrocarbons and periods of both increased and relaxed energy
conservation efforts. Such conditions have resulted in periods of excess supply
of, and reduced demand for, crude oil on a worldwide basis and for natural gas
on a domestic basis. These periods have been followed by periods of short supply
of and increased demand for crude oil. The excess or short supply of crude oil
has placed pressures on prices and has resulted in dramatic price fluctuations
even during relatively short periods of seasonal market demand. Recently, the
price of natural gas has exhibited significant market demand fluctuations. Most
of the natural gas consumed within the United States is produced within the
United States or Canada. The current demand for natural gas has resulted in
significant price increases and ever increasing volatility in the price of
natural gas.
COMPETITION
The oil and gas industry is intensely competitive and the Company competes with
other companies which have greater resources. Many of such companies not only
explore for and produce crude oil and natural gas but also carry on refining
operations and market petroleum and other products on a worldwide basis. There
is also competition between the oil and gas industry and other industries with
respect to the supply of energy and fuel to industrial, commercial and
individual customers.
16
RISKS ASSOCIATED WITH MANAGEMENT OF GROWTH
Because of its small size, the Company desires to grow rapidly in order to
achieve certain economies of scale. Although there is no assurance that this
rapid growth will occur, to the extent that it does occur, it will place a
significant strain on the Company's financial, technical, operational and
administrative resources. As the Company expands its activities and increases
the number of projects it is evaluating or in which it is participating, there
will be additional demands on the Company's financial, technical and
administrative resources. The failure to continue to upgrade the Company's
technical, administrative, operating and financial control systems or the
occurrence of unexpected expansion difficulties, including the recruitment and
retention of geoscientists and engineers, could have a material adverse effect
on the Company's business, financial condition and results of operations.
DEPENDENCE UPON KEY PERSONNEL
The success of the Company's operations and activities is dependent to a
significant extent on the efforts and abilities of its management. The loss of
services of any of its management could have a material adverse effect on the
Company. The Company has not obtained "key man" insurance for any of its
management.
The Company is almost entirely reliant on the management of Mr. Donald W. Busby.
The loss of the services of Mr. Busby may adversely affect the business and
prospects of the Company. Mr. Busby's services are provided through DWB
Management Ltd. ("DWB") on a month-to-month basis.
CONCENTRATION OF RISKS; LACK OF DIVERSE BUSINESS OPERATIONS
The Company currently is pursuing only the oil and gas exploration business.
Although the Company is pursuing other oil and gas projects, it is concentrating
its oil and gas exploration efforts in the San Joaquin Basin. Although the
Company is involved in separate and distinct projects in the San Joaquin Basin,
the Company's exploration efforts are concentrated in this same general area and
this lack of diverse business operations subjects the Company to a certain
degree of concentration of risks. The future success of the Company may be
dependent upon its success in discovering and developing oil and gas in
commercial quantities on its San Joaquin properties and upon the general
economic success of the oil and gas industry.
DIVIDEND RISKS
The Company has not paid any dividends on its common shares and does not intend
to pay dividends on its common shares in the immediate future. Any decision to
pay dividends on its common shares in the future will be made by the board of
directors on the Company on the basis of earnings, financial requirements and
other such conditions that may exist at that time.
PRICE FLUCTUATIONS: SHARE PRICE VOLATILITY
In recent years, the securities markets in Canada have experienced a high level
of price and volume volatility, and the market prices of securities of many
companies, particularly junior mineral exploration companies like the Company,
have experienced wide fluctuations which have not necessarily been related to
the operating performance, underlying asset values or prospects of such
companies. In particular, the per share price of the Company's common stock
fluctuated from a low of $0.37 to a high of $1.40 during the 12-month
17
period ending January 31, 2000. There can be no assurance that these price
fluctuations will not continue to occur.
CURRENCY FLUCTUATIONS
Presently, the Company's petroleum activities are conducted in the United States
and all petroleum revenues and expenditures are conducted in United States
dollars. To date, all equity financing conducted by the Company has been
conducted in Canadian dollars. The Company maintains its head office in
Vancouver, Canada, and may, from time-to-time, maintain cash holdings in
Canadian dollars. Recently the Canadian dollar has experienced a devaluation
against the United States dollar. Continued devaluation of the Canadian dollar
may have a material and adverse effect on the Company's operations.
CONFLICTS OF INTEREST
Certain of the directors also serve as directors of other companies or have
significant shareholdings in other companies and, to the extent that such other
companies may participate in ventures in which the Company may participate, the
directors of the Company may have a conflict of interest in negotiating and
concluding terms relating to the extent of such participation. In the event that
such a conflict of interest arises at a meeting of the board of directors, a
director who has such a conflict will disclose the nature and extent of his
interest to the board of directors and abstain from voting for or against the
approval of such a participation or such terms.
In accordance with the laws of the Yukon Territory, the directors of the Company
are required to act honestly and in good faith with a view to the best interests
of the Company. In determining whether or not the Company will participate in a
particular program and the interest therein to be acquired by it, the directors
will primarily consider the degree of risk to which the Company may be exposed
and its financial position at that time.
PENNY STOCK REGULATION
The SEC has adopted rules that regulate broker-dealer practices in connection
with transactions in "penny stocks". Generally, penny stocks are equity
securities with a price of less than US$5 (other than securities registered on
certain national securities exchanges or quoted on the NASDAQ system). If the
Company's shares are traded for less than US$5 per share, as they currently are,
the shares will be subject to the SEC's penny stock rules unless (1) the
Company's net tangible assets exceed US$5,000,000 during the Company's first
three years of continuous operations or US$2,000,000 after the Company's first
three years of continuous operations; or (2) the Company has had average revenue
of at least US$6,000,000 for the last three years. The penny stock rules require
a broker-dealer, prior to a transaction in a penny stock not otherwise exempt
from the rules, to deliver a standardized risk disclosure document prescribed by
the SEC that provides information about penny stocks and the nature and level of
risks in the penny stock market. The broker-dealer also must provide the
customer with current bid and offer quotations for the penny stock, the
compensation of the broker-dealer and its salesperson in the transaction and
monthly account statements showing the market value of each penny stock held in
the customer's account. In addition, the penny stock rules require that prior to
a transaction in a penny stock not otherwise exempt from those rules, the
broker-dealer must make a special written determination that the penny stock is
a suitable investment for the purchaser and receive the purchaser's written
agreement to the transaction. These requirements may have the effect of reducing
the level of trading activity in the secondary market for a stock
18
that becomes subject to the penny stock rules. As long as the Company's Common
Stock is subject to the penny stock rules, the holders of the Common Stock may
find it difficult to sell the Common Stock of the Company.
ENFORCEMENT OF LEGAL PROCESS
Service of process upon individuals or firms that are not resident in the United
States may be difficult to obtain within the United States. Some of the members
of the Board of Directors and senior management of the Company reside outside
the United States. Furthermore, since most of the Company's assets are located
outside the United States, any judgment obtained in the United States against
the Company or such persons may not be collectible within the United States. The
Company has appointed officials of certain states to act as the Company's agent
for service of process in relation to the offer and sale of securities in those
states, but has not appointed anyone to accept service of process in connection
with any other claim.
ITEM 2. DESCRIPTION OF PROPERTY.
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The Company's principal business is the acquisition of interests in petroleum
and natural gas rights, and the exploration for and development, production and
sale of petroleum and natural gas. All of the Company's properties are located
in the United States. The Company is not an operator of any of its oil and gas
projects.
The Company owns interests in petroleum and natural gas properties in three
distinct areas in the United States, identified as follows:
MATERIAL PROPERTIES
EAST LOST HILLS JOINT VENTURE AND SAN JOAQUIN JOINT VENTURE, CALIFORNIA
The San Joaquin Basin has proved to be one of the most productive hydrocarbon
producing basins in the continental United States, having produced in excess of
12.7 MMBOE. The basin contains six of the 25 largest oil fields in the U.S.A.
and produces more than 75% of California's oil and gas production. The San
Joaquin Basin production totals for 1997, reported by the California Department
of Oil and Gas, for all producers in the aggregate, indicate total production of
246.9 MMBOE. Of this figure, Kern County accounts for over 90% of the oil
production from the San Joaquin basin.
The Lost Hills Field is an anticlinal structure formed by what appears to be a
combination of compressional forces from the west, as well as right-lateral
motion associated with movement of the San Andreas fault system. The Monterey
and Temblor formations are broken by a high angle thrust fault on the west side
of the structure. The East Lost Hills Joint Venture lies in the footwall side of
this thrust fault, directly east of and structurally below the existing Lost
Hills field. To date, the Lost Hills Field has produced over 115 MBO and 120 BCF
of gas from Pleistocene, Pliocene and Miocene-age sands buried at depths of
between 2,000 to 6,000 feet.
The geological objectives at the East Lost Hills Joint Venture are stacked sands
(layers of sand stacked one over the other) within the Temblor Group which are
buried between 16,500 to 19,000 feet. The uppermost sand encountered by drilling
in the Temblor Group is called the Temblor Sand. Other sands which lie below
this interval have various local names, and vary in thickness and lateral
distribution from well to well. The
19
Temblor sands lie beneath the Miocene-age Monterey shale, which is a proven
source rock, as well as an excellent vertical reservoir seal. Two dimensional
("2-D") seismic data reveals the presence of a fault-bounded structural high at
Temblor level situated southeast of a well drilled by Shell and Arco (Shell-Arco
#1-23-22, T25S, R20, section 22). An interpretation made by Armstrong suggests
that this well did not penetrate the Temblor sands, but reached total depth
while still drilling in steeply dipping Monterey shales in the hanging wall of
the Lost Hills thrust block.
Seismic interpretation at the East Lost Hills Joint Venture indicates that a
minimum of 300 to 500 feet of structural elevation gain at the Temblor horizon
is likely at the drill site location, southeast from the Shell- Arco 1-23-22
well. With the application of a seismic velocity gradient, which is suspected to
exist in the area, the prospect can be interpreted to lie some 1,000 feet updip
from the Shell-Arco well at the Temblor horizon.
With the geological knowledge gained during drilling of the East Lost Hills
initial test well described below, Armstrong acquired a significant number of
additional oil and gas leases covering ground which appeared prospective for oil
and gas. In February 1999, Berkley concluded an agreement with Armstrong
acquiring an interest in these initial prospects and the right to all additional
prospects generated by Armstrong within the San Joaquin Basin.
EXPLORATION
EAST LOST HILLS JOINT VENTURE WORK PROGRAM
The initial test well, the Bellevue #1-17, commenced drilling in May 1998, and
was designed to test prospective Miocene sandstone reservoirs in the Temblor
formation of depths to an anticipated 18,500 feet. On November 23, 1998, while
drilling at 17,640 feet, the well blew out and ignited. An expert well control
team was engaged to contain the fire. The control team was able to contain the
well, with water, natural gas, natural gas liquids and oil being separated and
delivered to disposal and processing facilities.
As a result of the blow out, the development of the project was delayed by at
least ten months. A relief well, the Bellevue #1R-ST-3, was commenced on
December 18, 1998, in order to "kill" the flow of water and hydrocarbons flowing
out of the Bellevue #1-17 well. On May 29, 1999, the kill operation was
successfully completed. After the successful kill operation, the Bellevue
#1R-ST-3 relief well continued with drilling towards a bottom hole location
approximately 800 feet away from the bottom hole location of the Bellevue #1-17
well. On August 24, 1999, the operator announced that the well would be
completed having reached a total depth of 17,428 feet, approximately 180 feet
into the Temblor formation. In addition, Berkley, as operator, in August 1999
commenced drilling a second well, on the East Lost Hills Joint Venture. The
second well, the Berkley East Lost Hills #1 Well, is located 2.23 miles
north-west of the Bellevue #1R-ST-3 relief well.
The East Lost Hills Joint Venture holds an interest in a significant number of
leases. In order to maintain these leases the East Lost Hills Joint Venture has
committed to drill certain lands. If drilling does not occur, and the operator
is not able to negotiate amendments to the drilling schedule then the leases
will expire. At the present time a drilling schedule has been developed which
will ensure that no leases expire.
Between October 1, 1999, and October 22, 1999, the Bellevue #1R-ST-3 well was
prepared for a completion test. On Saturday, October 23, 1999, the completion
test was implemented by perforating the casing and
20
establishing communication with the pay zones so that gas could flow from the
pay zones into the casing. Initial results were positive and the well flowed
gas, albeit at restricted rates. The gas flowed, but only for a short period of
time as the flow was cut off when the perforations were plugged off. In an
attempt to re- establish communication, larger perforations were made but this
too was unsuccessful and the well bore was plugged with formation sand, shale,
and perforating debris. The well bore was cleaned up and in December 1999, was
production tested and flowed gas at rates ranging between 1.3 and 5.0 MMCFPD.
Condensate and water was obtained during the test. Pressure build-up analysis
indicated that only the uppermost sand unit encountered in the Bellevue #1R-ST-3
well was contributing to the flow. The operator had considered either a re-drill
or re-entry of this well bore. Given the ongoing drill programs, the East Lost
Hills joint venture partners have determined to either re-drill the well bore or
tie-in the well to the facility without further drilling. A decision will be
made during the second half of calendar 2001. Management believes minimal
maintenance costs will be incurred during this period.
On April 11, 2000, the Berkley East Lost Hills #1 well was drilled to a total
depth of 19,724 feet. A production line was run to total depth and the open hole
section, extending from 18,280 feet to total depth, was wireline logged. A total
of 2,474 feet of the Temblor formation was penetrated with a net sand interval
of 1,410 feet. The Berkley East Lost Hills #1 well was perforated on May 28,
2000. The flow test portion of the production test commenced on May 31, 2000 and
was completed on June 5, 2000. The initial perforated interval of 272 feet in
the well was flow tested at an extended, restricted flow rate of 13.1 MMCFPD of
natural gas. The pressure build-up portion of the production test has now been
interpreted. The data obtained from this build up is very encouraging and
supports the plan to connect the well in and proceed with the expanded
development drilling plan. Flowing bottom hole pressure during the test was
14,438 psi and liquids were easily transported by the gas. The gas rate, the
water gas ratio, and condensate gas ratios were stable for the final 48 hours of
the flow test.
Up to 10 additional locations, including the Berkley East Lost Hills # 2, #3 and
#4 wells, have been identified along the structural trend tested by Berkley East
Lost Hills #1, and the Bellevue #1-17 and #1R-ST-3 wells. An expanded drilling
program will test certain of these locations in the next twelve months.
Management expects that four additional wells will commence drilling in the next
twelve months.
Management believes, the location of the Berkley East Lost Hills #1 well and the
associated deep Temblor target is ideal with respect to both accessible natural
gas gathering systems and water disposal facilities. There is significant local
demand for natural gas. The well will be tied into an existing local gathering
system via an eight inch pipeline. Wellsite facilities will include three phase
separation and gas and liquid cooling equipment. Total capital cost for the
wellsite facilities and pipeline is estimated at US$3.5 million. Natural gas
will be sold to a major operator on an interim basis, pending results from
further drilling. Total cost for gas gathering and processing, condensate
handling, and water disposal is estimated at CDN$0.88/MCF. The royalty rate on
the Berkley East Lost Hills #1 well is 23.625%. Wellsite facility construction
and pipeline construction were completed in early February 2001, with production
startup commencing on February 6, 2001 at an initial restricted rate of 9.6
MMCFD.
As of September 1, 2000, the Company's share of estimated future net revenues in
the Berkley East Lost Hills #1 well, classified as proved developed
non-producing, was approximately $5.7 million (US$3.8 million).
The Berkley East Lost Hills #2 well, located approximately 1.5 miles northwest
of the Berkley East Lost Hills #1 well, commenced drilling on July 10, 2000. On
December 11, 2000, the Berkley East Lost Hills #2
21
well reached a final total depth of 18,011 feet. A decision has been made to
complete the Berkley East Lost Hills #2 well, with perforation of the casing
expected to commence in late February or early March of 2001. Production rates
will be determined from formal production testing. Management believes the
Berkley East Lost Hills #2 well can be quickly and cost effectively tied in to
the pipeline system constructed for the Berkley East Lost Hills #1 well.
The Berkley East Lost Hills #3 well commenced drilling on the west flank at East
Lost Hills on May 28, 2000. The total target depth for this well is 20,000 feet.
The west flank is a new structure which has not been drill tested. As at January
31, 2001, the well was at a depth of 19,410 feet.
The Berkley East Lost Hills #4 well commenced drilling on November 26, 2000. The
Berkley East Lost Hills #4 well is a stepout located two miles southeast from
the original Bellevue 1-17-R gas well along a structural strike.
The target depth for this well is 20,000 feet. The Berkley East Lost Hills #4
well was at a depth of 13,006 feet as at January 31, 2001.
Management has budgeted $990,000 for exploration and development on the East
Lost Hills Joint Venture during fiscal 2001.
SAN JOAQUIN JOINT VENTURE WORK PROGRAM
With respect to the San Joaquin Joint Venture Berkley commenced drilling the
initial exploratory well on the first of the three initial prospects, Cal Canal,
in July 1999. The Cal Canal well penetrated 1,230 feet of the Temblor formation
with 775 feet of net sand and was drilled to a total depth of 18,100 feet. The
well completion commenced on January 20, 2000. Non-commercial hydrocarbon flow
rates were obtained from the initial perforated 10 foot zone. Several additional
zones remain to be tested. The partners in the San Joaquin Joint Venture have
decided to defer further completion or deepening of the existing well bore until
information regarding reservoir quality and performance is obtained from
on-going drilling efforts in the San Joaquin Basin. All costs related to this
well have been billed and paid.
The next prospect scheduled to be drilled by the San Joaquin Joint Venture is
Pyramid Power. It is currently anticipated that the drilling commencement date
for this prospect will not be until late second quarter of the 2001 calendar
year. The total projected costs to drill and complete this well are
approximately US$15 million, with the Company's share being $900,000
(US$600,000). A firm date to drill the Lucky Dog prospect, the third of the
three initial prospects, has not been determined.
These first three prospects are not the only possible prospects in the San
Joaquin Joint Venture lands. Work is ongoing to identify more prospects. As of
January 31, 2001 no additional prospects had been identified.
Management has budgeted $900,000 for exploration and development on the San
Joaquin Joint Venture during fiscal 2001.
REGIONAL CALIFORNIA
With the initial exposure to the San Joaquin Basin of California, through the
participation in the East Lost Hills and Greater San Joaquin Basin Joint
Ventures, management decided to participate in an exploration
22
program, the focus of which was to identify prospects in the San Joaquin and
Sacramento Basins of California. Unlike the East Lost Hills and Greater San
Joaquin Basin Joint Venture lands, these prospects have much shallower target
horizons. The prospect acquisition costs and the costs to drill and complete
these prospects are substantially lower. As a result of these lower costs, the
Company was able to acquire a more substantial working interest in these
prospects.
To date, a number of prospects have been identified and leased and are in the
process of being permitted for drilling. A review of the major prospects in this
program is as follows:
MICA PROSPECT (43.66668% WI): The Mica Prospect is located on the west side
of the prolific southern San Joaquin Basin. This project is believed to be
a stratigraphic trap based on seismic and well control. The estimated drill
depth is 7,700 feet. The Mica Prospect consists of 320 gross acres (139.7
net acres) which are under lease. Total anticipated dry hole costs are
estimated at US$460,500. The Company's share of the dry hole costs is
US$201,085. A permit to drill the well has been filed and the expected date
when drilling will commence is in mid to late March 2001.
SEQUOIA PROSPECT (43.66668% WI): The Sequoia Prospect is located on the
east side of the southern San Joaquin Basin. This project is believed to be
a stratigraphic trap documented with seismic and well data. The estimated
drill depth is 7,000 feet. The Sequoia Prospect consists of 1,500 gross
acres (655.0 net acres) which are under lease. Total anticipated dry hole
costs are estimated at US$314,000. The Company's share of the dry hole
costs is US$137,113. A permit to drill the well has been filed and the
expected date when drilling will commence is in late March 2001.
PARSLEY PROSPECT (43.66668% WI): The Parsley Prospect is located in the
prolific gas producing area of the Sacramento Basin in Northern California.
This project is believed to be a structural fault trap with a direct
hydrocarbon indicator identified on seismic surveys. Estimated drill depth
is 9,000 feet. The Parsley Prospect consists of 400 gross acres (174.7 net
acres) which are under lease and is waiting on the final approval of an
additional 200 acres. Total anticipated dry hole costs are estimated at
US$665,000 because a direction well is required. The Company's share of the
dry hole costs is US$290,383. A permit to drill the well has been filed and
the expected date when drilling will commence is in late April to early May
2001.
BASIL PROSPECT (36.388831% WI): The Basil Prospect is located in the
southern portion of the Sacramento Basin. This project is believed to be a
structural fault trap documented with seismic and well data. This well must
be drilled directional under a body of water from a land based position.
The targets are believed to be at 4,500 feet but the well must be drilled
6,000 feet laterally to the target. The Basil Prospect consists of 3,540
gross acres (1,288.2 net acres) which are under lease. Total anticipated
dry hole costs are US$1,200,000 for a directional well. The Company's share
of the dry hole costs is US$436,666. This well is currently being
permitted. Initial drilling is expected to begin July 15, 2001.
MERCED PROJECT AREA (43.66668% WI): The Merced Project Area is located in
the northern part of the San Joaquin Basin and comprises four prospects.
Each prospect is believed to be a stratigraphic trap documented with
seismic and well data. It is anticipated that two prospects will be drilled
in 2001. Estimated drill depths range between 5,100 and 5,700 feet. The
Merced Project Area consists of over 2,000 gross acres (873.4 net acres)
whicha are under lease. Total anticipated dry hole costs for the two wells
are US$618,000. The Company's share of these costs is US$269,860.
Additional leases are being
23
acquired along this prospective trend and the Company expects to begin
initial drilling on the first well in the trend in May 2001.
YO-YO PROSPECT (43.66668% WI): The Yo-Yo Prospect is located in the
south-central Sacramento Basin. This project is a stratigraphic trap, as
defined by well data and a seismic anomaly. The estimated drill depth is
3,500 feet. The Yo-Yo Prospect consists of 160 gross acres (69.9 net acres)
which are under lease and the joint venture is working on acquiring a
seismic option over 1,600 acres. Total anticipated dry hole cost are
estimated at US$260,000. The Company's share of the dry hole costs is
US$113,533.
In addition to the major prospects in this program, work is ongoing to
identify additional prospects in the San Joaquin Basin. The Company's
ability to commit to additional development of these prospects will be
dependant upon the results of the program and the Company's ability to
develop sufficient operating cash flows and raise additional equity
financing.
OTHER PROPERTIES
EAST BLOSSOM PROSPECT CALIFORNIA
The East Blossom Prospect consists of 826 gross acres (118 net acres) located in
San Joaquin County, California.
The Company can earn a 25% working interest (18.75% net revenue interest) in the
first well, before payout, and a 12.5% working interest (9.375% net revenue
interest) after payout, and a 12.5% working interst (9.375% net revenue
interest) in subsequent wells. During July 2000, an initial well, the Blossom #1
well was drilled to a total depth of 7,784 feet. A flow test was conducted over
a four day period and flowed 5,233 MCF per day. The well is not on production
and is awaiting connection to gas pipeline.
As of September 1, 2000, the Company's share of estimated future net revenues in
the Blossom #1 well was approximately $580,000 (US$387,000).
WEST SIMON PROJECT, LOUISIANA
The West Simon Project consists of 320 gross acres (77 net acres) located in
Jefferson Davis Parish, Louisiana.
The East Roanoke field contains two producing wells, the Simon #1 in Section 8
and the Brieske #1 in Section 9, both located in Township 9 South, Range 3 West.
These wells are both completed in the Simon "A" sand. The Hackberry sands are
Oligocene in age and were deposited as channelized sand sequences related to
turbidite fan systems.
The Company acquired a 24% working interest (18% net revenue interest) in the
West Simon Project under a farmout agreement (the "Farmout") dated January 13,
2000, from Valley. After payout of the well, Valley has to right to backin for
an undivided 35% working interest in the property. In the event Valley elects to
backin after payout of the well, the Company's working interest in the well will
be 15.60%.
24
The Gus Landry reached total depth on July 1, 2000. The electric logging program
was commenced immediately and the logs indicated three potentially productive
zones. The Simon "A" sand (the primary target zone) was determined to be tight
and not capable of commercial production and an intermediate zone was thought to
be too thin to merit a completion attempt. The upper zone showed good electric
log results and the completion process began in mid July to evaluate this zone.
The upper zone was perforated September 23, 2000, and production from the well
commenced on September 25, 2000. Production commenced at 2.6 MMCFD, but rapidly
declined and had to be put on compression in February 2001. The well is
currently producing at a stabilized rate of 230 MCFPD, 4 BOPD and 28 BWPD
(barrels of water per day). The well's gross proceeds from production through
January 2001 amounted to US$460,000 (net of US$110,400 to the Company).
As of September 1, 2000, the Company's share of estimated future net revenues in
the Gus Landry #1 well was approximately $546,000 (US$364,000).
BIG SPRINGS UNIT, DEUEL COUNTY, NEBRASKA
The Company holds a 50% working interest (40% net revenue interest) in the Big
Springs Unit. The Big Springs Unit is subject to overriding royalties
aggregating 20% which have been reserved in favor of individuals at arm's length
to the Company and to Trimark Inc. The Big Springs field is located ten miles
north into Deuel County, Nebraska from the extreme northeast corner of the State
of Colorado. The base leasehold in the Big Springs Unit is 46,080 gross acres.
As of September 1, 2000, Company's share of estimated future net revenues in the
Big Springs Unit was approximately $132,000 (US$88,000).
No work program has been proposed for fiscal 2001.
SOUTH HASKELL FIELD, HASKELL COUNTY, TEXAS
The Company owns a 10% working interest and an 8% net revenue interest in 11
wells located in South Haskell Field, Haskell County, Texas. Centaur Petroleum
of Ft. Worth, Texas is the operator of the field. Eleven of the wells are
producing. The wells produce from the Canyon, Crosscut, and Palo Pinto sands at
a depth of 2,500 feet to 3,500 feet. The wells produce oil and water, but no
gas. The water is disposed of into several water disposal wells. As at September
1, 2000, the Company's share of estimated future net revenues in the South
Haskell Field was approximately $301,000 (US$201,000).
No work program has been proposed for fiscal 2001.
25
PRODUCTION INFORMATION
OIL AND GAS WELLS
The following table sets forth the proven developed wells, gross and net, in
which the Company owned a working interest as of January 31, 2001:
STATE GROSS WELLS NET WELLS
California 2 0.26
Louisiana 1 0.24
Nebraska 12 6.00
Texas 11 1.10
-- ----
Total 26 7.60
== ====
OIL AND NATURAL GAS RESERVES
(a) September 1, 2000
The following table sets forth information regarding the Company's
share of estimated proven oil and gas reserve quantities, reserve value
and discounted future net revenues as at September 1, 2000. The reserve
value related information as at September 1, 2000, was determined
through independent engineering evaluations completed by Lee Keeling
and Associates, Inc. ("Lee Keeling"), a firm of independent petroleum
consultants. The Company does not have any long-term supply or similar
agreements with foreign governments or authorities in which the Company
acts as producer.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and projecting future rates of production and timing of
development expenditures. The following reserve information represents
estimates only and should not be construed as being exact:
26
OIL AND NATURAL GAS RESERVES
UNESCALATED PRICES AND COSTS
AS OF SEPTEMBER 1, 2000
ESTIMATED FUTURE NET
GROSS RESERVES NET RESERVES PRODUCTION REVENUES(1)<F1>
-------------- ------------ --------------------
(US$000)
Discounted at
Oil Natural Gas Oil Natural Gas
(MBBLS) (MMCF) (MBBLS) (MMCF) 0% 10%
------- -------- ------- -------- -- ---
Proved Developed Producing(2)<F2> 131.4 194.2 10.5 77.6 288.4 221.3
Proved Developed Non-Producing(3)<F3> 908.4 111,475.0 8.0 1,104.6 4,533.2 1,922.1
------- --------- ----- ------- ------- -------
1,039.8 111,669.2 18.5 1,182.2 4,821.6 2,143.4
======= ========= ===== ======= ======= =======
<FN>
<F1>
(1) Future net revenue is the amount, exclusive of state and
federal income taxes, which will accrue to the appraised
interests from continued operation of the properties to
depletion. It should not be construed as a fair market value.
No provision has been made for the cost of plugging and
abandoning the properties or for the value of salvageable
equipment.
<F2>
(2) Proved developed producing reserves are those reserves
expected to be recovered from currently producing zones under
continuation of present operating methods.
<F3>
(3) Proved developed non-producing reserves are those reserves
expected to be recovered from zones which are currently
shut-in awaiting connection to a pipeline outlet.
</FN>
(b) September 1, 1999
The following table sets forth information regarding the Company's
share of estimated proven oil and gas reserve quantities, reserve value
and discounted future net revenues as of September 1, 1999. The reserve
value related information as at September 1, 1999, was determined
through independent engineering evaluations completed by Lee Keeling.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and projecting future rates of production and timing of
development expenditures. The following reserve information represents
estimates only and should not be construed as being exact:
OIL AND NATURAL GAS RESERVES
UNESCALATED PRICES AND COSTS
AS OF SEPTEMBER 1, 1999
PRESENT VALUE OF ESTIMATED
FUTURE NET REVENUES BEFORE
ESTIMATED INCOME TAXES - DISCOUNTED
FUTURE NET AT 10%
OIL GAS REVENUES ($000)
(MBBLS) (MMCF) ($000)
Proved developed
producing reserves 24.1 345.6 413.2 273
==== ===== ===== ===
27
(c) August 31, 1998
Management of the Company has prepared reserve evaluations of the
Company's interests on the proved developed properties in the Big
Springs Unit and South Haskell Field, as of August 31, 1998, using gas
and oil prices and operating costs, on an unescalated basis, effective
on that date. The Company does not have any long-term supply or similar
agreements with foreign governments or authorities in which the Company
acts as producer.
OIL AND NATURAL GAS RESERVES
UNESCALATED PRICES AND COSTS
AS OF AUGUST 31, 1998
PRESENT VALUE OF ESTIMATED
FUTURE NET REVENUES BEFORE
ESTIMATED INCOME TAXES - DISCOUNTED
FUTURE NET AT 10%
OIL GAS REVENUES ($000)
(MBBLS) (MMCF) ($000)
Proved developed
producing reserves 37.1 851.2 1,007.0 578.8
==== ===== ======= =====
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production
volumes, average prices received and average production costs associated with
the Company's sale of oil and gas for the periods shown:
YEAR YEAR YEAR
ENDED ENDED ENDED
AUGUST 31, 2000 AUGUST 31, 1999 AUGUST 31, 1998
Net production:
Oil (Barrels) 3,069 3,424 4,476
Gas (MCF) 24,399 28,364 46,476
Average sales price:
Oil (per Barrel) $36.98 $19.97 $23.08
Gas (per MCF) $3.66 $2.38 $2.70
Average production cost (per BOE) $21.80 $16.22 $8.74
PRINCIPAL OFFICE
The Company's business is administrated principally from its head office in
Vancouver, Suite #1305 - 1090 West Georgia Street in Vancouver, British
Columbia, Canada.
The Company has retained DWB Management Ltd. ("DWB"), a company wholly-owned by
Mr. Donald W. Busby, Chief Executive Officer of the Company, to provide
marketing, financial management and consulting services. The Company has also
retained Chase Management Ltd. ("Chase") to provide accounting, management and
administrative services. Chase is a private company wholly-owned by Nick DeMare,
a director of the Company. In addition, the Company employs a number of
consultants to perform specific functions, on an as needed basis. Except for the
Company's agreement with DWB, the Company does not have employment agreements
with any of its management, directors or their respective companies.
28
ITEM 3. LEGAL PROCEEDINGS.
- --------------------------------------------------------------------------------
There are no legal proceedings to which the Company is a party, nor to the best
of the knowledge of management are any legal proceedings contemplated.
ITEM 4. CONTROL OF REGISTRANT
- --------------------------------------------------------------------------------
PRINCIPAL HOLDERS OF VOTING SECURITIES
To the best of the Company's knowledge, it is not directly or indirectly owned
or controlled by another corporation or by any foreign government. Hilton
Petroleum Ltd., a principal shareholder, is a Canadian public company. Mr.
Donald Busby, an officer and director of the Company, is a director of Hilton.
Mr. Nick DeMare, a director of the Company, is a director of Hilton. The
following table sets forth certain information regarding ownership by the
Company's officers and directors as a group, as well as all persons who own
greater than 10% of the Company's outstanding shares, as of January 31, 2001:
- -------------------------------------------------------------------------------------------------------------------------
Title of Class Name and Address of Owner Shares Beneficially Owned Percent of Class(1)<F1>
- -------------------------------------------------------------------------------------------------------------------------
Common Stock Hilton Petroleum Ltd. 3,860,000(2)<F2> 19.28%
Vancouver, British Columbia
Common Stock Donald W. Busby 3,939,520(3)<F3>(4)<F4> 19.55%
Conifer, Colorado
Common Stock Officers & Directors, as a group 5,468,743(3)<F3>(4)<F4> 25.72%
(5 persons) (5)<F5>(6)<F6>
<FN>
<F1>
(1) Where persons listed on this table have the right to obtain additional
shares of Common Stock through the exercise of outstanding options or
warrants within 60 days from January 31, 2001, these additional shares
are deemed to be outstanding for the purpose of computing the
percentage of Common Stock owned by such persons, but are not deemed to
be outstanding for the purpose of computing the percentage owned by any
other person. Based on 16,624,016 shares of common stock outstanding as
of January 31, 2001 plus the 1,700,000 units to be issued to Hilton on
the completion of a private placement. See "Item 12. Options to
Purchase Securities from Registrant or Subsidiaries".
<F2>
(2) Includes 460,000 shares of common stock held by Hilton Petroleum Ltd.
("Hilton") and 1,700,000 units to be issued to Hilton on completion of
a private placement. See "Item 12. Options to Purchase Securities from
Registrant or Subsidiaries".
<F3>
(3) Includes 1,340,080 shares of common stock held by Boone Petroleum Inc.
("Boone"), a private company wholly-owned by Mr. Busby and 774,800
shares held by the Donald W. Busby 1999 Irrevocable Trust, an
irrevocable trust as to which Mr. Busby was grantor but is not trustee.
Mr. Busby has the right to replace the trustee. Mr. Busby disclaims
beneficial ownership of all shares held by the Trust.
<F4>
(4) Includes warrants held by Boone to acquire an additional 1,144,640
common shares, warrants held by the Donald W. Busby 1999 Irrevocable
Trust to acquire 540,650 common shares, and options held by Mr. Busby
to acquire 680,000 common shares.
<F5>
(5) Includes 173,310 common shares and 226,498 common shares held by DNG
Capital Corp. ("DNG") and 888 Capital Corp. ("888"), respectively. DNG
is a private company wholly-owned by Mr. DeMare, 888 is a private
company 50% owned by Mr. DeMare.
29
<F6>
(6) Includes warrants held by Mr. DeMare, DNG and 888 to acquire an
additional 1,059 common shares, 75,000 common shares, and 470,856
common shares, respectively. Also includes options held by Chase to
acquire an additional 250,000 common shares. Chase is a private company
wholly-owned by Mr. DeMare.
</FN>
CHANGE OF CONTROL
As of the date of this annual report, there are no arrangements known to the
Company which may at a subsequent date result in a change of control of the
Company.
ITEM 5. NATURE OF TRADING MARKET.
- --------------------------------------------------------------------------------
The Company's common shares were listed on the Vancouver Stock Exchange through
November 28, 1999. Effective November 29, 1999, the Vancouver Stock Exchange and
the Alberta Stock Exchange merged and began operations as the Canadian Venture
Exchange. The merger of the Vancouver Stock Exchange and the Alberta Stock
Exchange to form the Canadian Venture Exchange has not had a significant impact
on the Company's operations. The Canadian Venture Exchange classifies listed
companies into two different tiers based on standards, which include historical
financial performance, stage of development, and financial resources of the
listed company. Tier I is the Canadian Venture Exchange's premier tier and is
reserved for the Canadian Venture Exchange's most advanced issuers with the most
significant financial resources. As an oil and gas issuer, an issuer must meet
the following criteria to be classified as Tier I:
i) proven reserves with a present value of CDN $2.0 million based
on constant dollar pricing assumptions, discounted at 15%; and
ii) adequate working capital (at least CDN $500,000).
Tier I issuers benefit from decreased filing requirements and improved service
standards. The majority of the companies listed on the Canadian Venture Exchange
are Tier II companies. The Company trades on the Canadian Venture Exchange under
the symbol "TMK" and is classified as a Tier II company. The Company has made a
submission to the CDNX to be classified as a Tier 1 issuer and is awaiting
completion of the CDNX's review.
The following table sets forth the market price ranges and the aggregate volume
of trading of the common shares of the Company on the Vancouver Stock Exchange
and, subsequently the Canadian Venture Exchange, for the fiscal quarters
beginning September 1, 1998, through January 31, 2001:
PERIOD HIGH($) LOW($) VOLUME
FISCAL 1999
Sep.1/98 - Nov.30/98 0.42 0.21 167,725
Dec.1/98 - Feb.28/99 0.70 0.38 718,910
Mar.1/99 - May31/99 1.10 0.70 4,878,997
Jun.1/99 - Aug.31/99 1.75 0.83 7,988,251
30
PERIOD HIGH($) LOW($) VOLUME
FISCAL 2000
Sep.1/99 - Nov.30/99 2.91 1.30 13,180,706
Dec.1/99 - Feb.29/00 1.56 0.37 6,417,641
Mar.1/00 - May31/00 1.40 0.40 9,608,639
Jun.1/00 - Aug.31/00 1.30 0.42 7,598,854
FISCAL 2001
Sep.1/00 - Nov.30/00 0.85 0.37 1,799,577
The Company's Common Stock began trading on the Over-the-Counter Bulletin Board
(the "OTC Bulletin Board") on August 7, 2000 under the symbol "TOGSF". The range
of high and low bid prices and the volume for fiscal quarters beginning June 1,
2000, through November 30, 2000, as reported by the OTC Bulletin Board, are as
follows:
PERIOD HIGH BID(US$) LOW BID(US$) VOLUME
FISCAL 2000
Jun.1/00 - Aug.31/00 0.39 0.38 69,700
FISCAL 2001
Sep.1/00 - Nov.30/00 0.56 0.40 217,900
The above quotations reflect inter-dealer prices, without retail mark-up,
mark-down, or commission and may not necessarily represent actual transactions.
There were approximately 18 registered holders of the Company's shares in the
United States, with combined holdings of 3,207,509 shares, on January 31, 2001.
ITEM 6. EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY
HOLDERS.
- --------------------------------------------------------------------------------
There are no governmental laws, decrees, or regulations in Canada relating to
restrictions on the export or import of capital, or affecting the remittance of
interest, dividends, or other payments to non-resident holders on the Company's
Common Stock. Any remittances of dividends to United States residents are,
however, subject to a 15% withholding tax (10% if the shareholder is a
corporation owning at least 10% of the outstanding Common Stock of the Company)
pursuant to Article X of the reciprocal tax treaty between Canada and the United
States. See "Item 7 Taxation."
Except as provided in the Investment Canada Act (the "Act"), there are no
limitations specific to the rights of non-Canadians to hold or vote the common
stock of the Company under the laws of Canada or in the charter documents of the
Company.
31
Management of the Company considers that the following general summary fairly
describes those provisions of the Act pertinent to an investment by an American
investor in the Company.
The Act requires a non-Canadian making an investment which would result in the
acquisition of control of a Canadian business, the gross value of the assets of
which exceeds certain threshold levels or the business activity of which is
related to Canada's cultural heritage or national identity, to either notify, or
file an application for review with, Investment Canada, the federal agency
created by the Investment Canada Act.
The notification procedure involves a brief statement of information about the
investment of a prescribed form which is required to be filed with Investment
Canada by the investor at any time up to 30 days following implementation of the
investment. It is intended that investments requiring only notification will
proceed without government intervention unless the investment is in a specific
type of business activity related to Canada's cultural heritage and national
identity.
If an investment is reviewable under the Act, an application for review in the
form prescribed is normally required to be filed with Investment Canada prior to
the investment taking place and the investment may not be implemented until the
review has been completed and the Minister responsible for Investment Canada is
satisfied that the investment is likely to be of net benefit to Canada. If the
Minister is not satisfied that the investment is likely to be of net benefit to
Canada, the non-Canadian must not implement the investment or, if the investment
has been implemented, may be required to divest himself of control of the
business that is the subject of the investment.
The following investments by non-Canadians are subject to notification under the
Act:
(1) an investment to establish a new Canadian business; and
(2) an investment to acquire control of a Canadian business that is not
reviewable pursuant to the Act.
The following investments by a non-Canadian are subject to review under the Act:
(1) direct acquisitions of control of Canadian businesses with assets of $5
million or more unless the acquisition is being made by an American
investor;
(2) direct acquisitions of control of Canadian businesses with assets of
$152,000,000 or more by an American investor;
(3) indirect acquisitions of control of Canadian businesses with assets of
$5 million or more if such assets represent more than 50% of the total
value of the assets of the entities, the control of which is being
acquired, unless the acquisition is being made by an American investor;
(4) indirect acquisitions of control of Canadian businesses with assets of
$152,000,000 or more by an American investor if such assets represent
more than 50% of the total value of the assets of the entities, the
control of which is being acquired;
(5) indirect acquisitions of control of Canadian businesses with assets of
$50 million or more even if such assets represent less than 50% of the
total value of the assets of the entities, the control of
32
which is being acquired, unless the acquisition is being made by an
American investor in which case there is no review; and
(6) an investment subject to notification that would not otherwise be
reviewable if the Canadian business engages in the activity of
publication, distribution or sale of books, magazines, periodicals,
newspapers, audio or video music recordings, or music in print or
machine-readable form.
Generally speaking, an acquisition is direct if it involves the acquisition of
control of the Canadian business or of its Canadian parent or grandparent and an
acquisition is indirect if it involves the acquisition of control of a
non-Canadian parent or grandparent of an entity carrying on the Canadian
business. Control may be acquired through the acquisition of actual or de jure
voting control of a Canadian corporation or through the acquisition of
substantially all of the assets of the Canadian business. No change of voting
control will be deemed to have occurred if less than one-third of the voting
control of a Canadian corporation is acquired by an investor.
An American, as defined in the Act includes an individual who is an American
national or a lawful, permanent resident of the United States, a government or
government agency of the United States, an American-controlled corporation,
limited partnership, trust or joint venture and a corporation, limited
partnership, trust or joint venture that is neither American-controlled or
Canadian-controlled of which two- thirds of its board of directors, general
partners or trustees, as the case may be, are any combination of Canadians and
Americans.
The higher thresholds for Americans do not apply if the Canadian business
engages in activities in certain sectors such as oil, natural gas, uranium,
financial services (except insurance), transportation services or media
activities.
The Act specifically exempts certain transactions from either notification or
review. Included among the category of transactions is the acquisition of voting
shares or other voting interests by any person in the ordinary course of that
person's business as a trader or dealer in securities. Given the nature of the
Company's business and the size of its operations, management does believe the
Investment Canada Act would apply to an investment in the Company's shares by a
U.S. investor.
ITEM 7. TAXATION.
- --------------------------------------------------------------------------------
MATERIAL CANADIAN FEDERAL INCOME TAX CONSEQUENCES
Management of the Company considers that the following discussion fairly
describes the material Canadian federal income tax consequences applicable to a
holder of Common Stock of the Company who is a resident of the United States and
who is not a resident of Canada and who does not use or hold, and is not deemed
to use or hold, his shares of Common Stock of the Company in connection with
carrying on a business in Canada (a "non-resident shareholder").
This summary is based upon the current provisions of the Income Tax Act (Canada)
(the "ITA"), the regulations thereunder (the "Regulations"), the current
publicly announced administrative and assessing policies of Revenue Canada,
Taxation and all specific proposals (the "Tax Proposals") to amend the ITA and
Regulations announced by the Minister of Finance (Canada) prior to the date
hereof. This description is not
33
exhaustive of all possible Canadian federal income tax consequences and, except
for the Tax Proposals, does not take into account or anticipate any changes in
law, whether by legislative, governmental or judicial action.
DIVIDENDS
Dividends paid on the common stock of the Company to a non-resident will be
subject to withholding tax. The Canada-U.S. Income Tax Convention (1980)
provides that the normal 25% withholding tax rate is reduced to 15% on dividends
paid on shares of a corporation resident in Canada (such as the Company) to
residents of the United States, and also provides for a further reduction of
this rate to 5% where the beneficial owner of the dividends is a corporation
which is a resident of the United States which owns at least 10% of the voting
shares of the corporation paying the dividend.
CAPITAL GAINS
In general, a non-resident of Canada is not subject to tax under the ITA with
respect to a capital gain realized upon the disposition of a share of a
corporation resident in Canada that is listed on a prescribed stock exchange.
For purposes of the ITA, the Company is listed on a prescribed stock exchange.
Non-residents of Canada who dispose of shares of the Company will be subject to
income tax in Canada with respect to capital gains if:
(a) the non-resident holder;
(b) persons with whom the non-resident holder did not deal at
arm's length; or
(c) the non-resident holder and persons with whom the non-resident
holder did not deal with at arm's length,
owned not less than 25% of the issued shares of any class or series of the
Company at any time during the five-year period preceding the disposition. In
the case of a non-resident holder to whom shares of the Company represent
taxable Canadian property and who is resident in the United States, no Canadian
taxes will be payable on a capital gain realized on such shares by reason of the
Canada-U.S. Income Tax Convention (1980) (the "Treaty") unless the value of such
shares is derived principally from real property situated in Canada. However, in
such a case, certain transitional relief under the Treaty may be available.
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
The following discussion summarizes the material United States federal income
tax consequences, under current law, applicable to a U.S. Holder (as defined
below) of the Company's common stock. This discussion does not address
consequences peculiar to persons subject to special provisions of federal income
tax law, such as tax-exempt organizations, qualified retirement plans, financial
institutions, insurance companies, real estate investment trusts, regulated
investment companies, broker-dealers, nonresident alien individuals or foreign
corporations or shareholders owning common stock representing 10% of the vote
and value of the Company. In addition, this discussion does not cover any state,
local or foreign tax consequences.
The following discussion is based upon the sections of the Internal Revenue Code
of 1986, as amended (the "Code"), Treasury Regulations, published Internal
Revenue Service ("IRS") rulings, published administrative positions of the IRS
and court decisions that are currently applicable, any or all of which could be
materially and adversely changed, possibly on a retroactive basis, at any time.
In addition, this discussion does not
34
consider the potential effects, both adverse and beneficial of recently proposed
legislation which, if enacted, could be applied, possibly on a retroactive
basis, at any time. Holders and prospective holders of the Company's Common
Stock should consult their own tax advisors about the federal, state, local and
foreign tax consequences of purchasing, owning and disposing of shares of Common
Stock of the Company.
U.S. HOLDERS
As used herein, a "U.S. Holder" is defined as (i) citizens or residents of the
U.S., or any state thereof, (ii) a corporation or other entity created or
organized under the laws of the U.S., or any political subdivision thereof,
(iii) an estate the income of which is subject to U.S. federal income tax
regardless of source or that is otherwise subject to U.S. federal income tax on
a net income basis in respect of the common stock, or (iv) a trust whose
administration is subject to the primary supervision of a U.S. court and which
has one or more U.S. fiduciaries who have the authority to control all
substantial decisions of the trust, whose ownership of common stock is not
effectively connected with the conduct of a trade or business in the United
States and shareholders who acquired their stock through the exercise of
employee stock options or otherwise as compensation.
DISTRIBUTIONS ON SHARES OF COMMON STOCK
U.S. Holders receiving dividend distributions (including constructive dividends)
with respect to the Company's common stock are required to include in gross
income for United States federal income tax purposes the gross amount of such
distributions to the extent that the Company has current or accumulated earnings
and profits, without reduction for any Canadian income tax withheld from such
distributions. Such Canadian tax withheld may be credited, subject to certain
limitations, against the U.S. Holder's United States federal income tax
liability or, alternatively, may be deducted in computing the U.S. Holder's
United States federal taxable income by those who itemize deductions. (See more
detailed discussion at "Foreign Tax Credit" below.) To the extent that
distributions exceed current or accumulated earnings and profits of the Company,
they will be treated first as a return of capital up to the U.S. Holder's
adjusted basis in the common stock and thereafter as gain from the sale or
exchange of such shares. Preferential tax rates for long- term capital gains are
applicable to a U.S. Holder which is an individual, estate or trust. There are
currently no preferential tax rates for long-term capital gains for a U.S.
Holder which is a corporation. Dividends paid on the Company's common stock will
not generally be eligible for the dividends received deduction provided to
corporations receiving dividends from certain United States corporations.
FOREIGN TAX CREDIT
A U.S. Holder who pays (or has withheld from distributions) Canadian income tax
with respect to the ownership of the Company's common stock may be entitled, at
the option of the U.S. Holder, to either a deduction or a tax credit for such
foreign tax paid or withheld. Generally, it will be more advantageous to claim a
credit because a credit reduces United States federal income taxes on a
dollar-for-dollar basis, while a deduction merely reduces the taxpayer's income
subject to tax. This election is made on a year-by-year basis and applies to all
foreign taxes paid by (or withheld from) the U.S. Holder during that year.
Subject to certain limitations, Canadian taxes withheld will be eligible for
credit against the U.S. Holder's United States federal income taxes. Under the
Code, the limitation on foreign taxes eligible for credit is calculated
separately with respect to specific classes of income. Dividends paid by the
Company generally will be either "passive" income or "financial services"
income, depending on the particular U.S. Holder's circumstances. Foreign tax
credits allowable with respect to each class of income cannot exceed the U.S.
federal income tax
35
otherwise payable with respect to such class of income. The consequences of the
separate limitations will depend on the nature and sources of each U.S. Holder's
income and the deductions appropriately allocated or apportioned thereto. The
availability of the foreign tax credit and the application of the limitations on
the credit are fact specific and holders and prospective holders of common stock
should consult their own tax advisors regarding their individual circumstances.
DISPOSITION OF SHARES OF COMMON STOCK
A U.S. Holder will recognize gain or loss upon the sale of shares of common
stock equal to the difference, if any, between (i) the amount of cash plus the
fair market value of any property received; and (ii) the shareholder's tax basis
in the common stock. This gain or loss will be capital gain or loss if the
shares are a capital asset in the hands of the U.S. Holder, and such gain or
loss will be long-term capital gain or loss if the U.S. Holder has held the
common stock for more than one year. Gains and losses are netted and combined
according to special rules in arriving at the overall capital gain or loss for a
particular tax year. Deductions for net capital losses are subject to
significant limitations. For U.S. Holders who are individuals, any unused
portion of such net capital loss may be carried over to be used in later tax
years until such net capital loss is thereby exhausted. For U.S. Holders which
are corporations (other than corporations subject to Subchapter S of the Code),
an unused net capital loss may be carried back three years from the loss year
and carried forward five years from the loss year to be offset against capital
gains until such net capital loss is thereby exhausted.
OTHER CONSIDERATIONS
The Company has not determined whether it meets the definition of a "passive
foreign investment company" (a "PFIC"). It is unlikely that the Company meets
the definition of a "foreign personal holding company" (a "FPHC") or a
"controlled foreign corporation" (a "CFC") under current U.S. law.
If more than 50% of the voting power or value of the Company were owned
(actually or constructively) by U.S. Holders who each owned (actually or
constructively) 10% or more of the voting power of the Company's common shares
("10% Shareholders"), then the Company would become a CFC and each 10%
Shareholder would be required to include in its taxable income as a constructive
dividend an amount equal to its share of certain undistributed income of the
Company. If (1) more than 50% of the voting power or value of the Company's
common shares were owned (actually or constructively) by five or fewer
individuals who are citizens or residents of the United States and (2) 60% or
more of the Company's income consisted of certain interest, dividend or other
enumerated types of income, then the Company would be a FPHC. If the Company
were a FPHC, then each U.S. Holder (regardless of the amount of the Company's
Common Shares owned by such U.S. Holder) would be required to include in its
taxable income as a constructive dividend its share of the Company's
undistributed income of specific types.
If 75% or more of the Company's annual gross income has ever consisted of, or
ever consists of, "passive" income or if 50% or more of the average value of the
Company's assets in any year has ever consisted of, or ever consists of, assets
that produce, or are held for the production of, such "passive" income, then the
Company would be or would become a PFIC. The Company has not provided assurances
that it has not been and does not expect to become a PFIC.
If the Company were to be a PFIC, then a U.S. Holder would be required to pay an
interest charge together with tax calculated at maximum tax rates on certain
"excess distributions" (defined to include gain on the
36
sale of stock) unless such U.S. Holder made an election either to (1) include in
his or her taxable income certain undistributed amounts of the Company's income
or (2) mark to market his or her Company common shares at the end of each
taxable year as set forth in Section 1296 of the Code.
INFORMATION REPORTING AND BACKUP WITHHOLDING
U.S. information reporting requirements may apply with respect to the payment of
dividends to U.S. Holders of the Company's shares. Under Treasury regulations
currently in effect, non-corporate holders may be subject to backup withholding
at a 31% rate with respect to dividends when such holder (1) fails to furnish or
certify a correct taxpayer identification number to the payor in the required
manner, (2) is notified by the IRS that it has failed to report payments of
interest or dividends properly or (3) fails, under certain circumstances, to
certify that it has been notified by the IRS that it is subject to backup
withholding for failure to report interest and dividend payments.
ITEM 8. SELECTED FINANCIAL DATA.
- --------------------------------------------------------------------------------
DURING THE YEAR ENDED AUGUST 31, 2000, THE COMPANY CHANGED ITS METHOD OF
ACCOUNTING FOR ITS PETROLEUM INTERESTS FROM THE SUCCESSFUL EFFORTS METHOD TO THE
FULL COST METHOD. MANAGEMENT BELIEVES THAT THE NEW ACCOUNTING POLICY IS MORE
APPROPRIATE FOR OIL AND GAS COMPANIES SUCH AS THE COMPANY. THIS CHANGE IN
ACCOUNTING POLICY HAS BEEN APPLIED RETROACTIVELY.
The selected financial data of the Company for the years ended August 31, 2000,
1999 and 1998, was derived from the financial statements of the Company which
have been audited by Dyke & Howard, independent Chartered Accountants, as
indicated in their report which is included elsewhere in this annual report. The
selected financial data set forth for the years ended August 31, 1997 and 1996
are derived from the Company's audited financial statements, not included
herein.
The information in the following table was extracted from the more detailed
consolidated financial statements and related notes included herein and should
be read in conjunction with such financial statements and with the information
appearing under the heading "Item 9 - Management's Discussion and Analysis of
Financial Condition and Results of Operations."
Reference is made to Note 9 of the Company's consolidated financial statements
included herein for a discussion of the material differences between Canadian
GAAP and U.S. GAAP, and their effect on the Company's financial statements.
($ IN 000, EXCEPT PER SHARE DATA)
---------------------------------------------------------------
YEAR ENDED AUGUST 31,
---------------------------------------------------------------
2000 1999 1998 1997 1996
Revenues $398 $143 $232 $156 $150
Production $155 $132 $107 $81 $63
Depreciation, depletion and impairment $78 $1,703 $1,983 $49 $281
General and administrative $462 $350 $217 $193 $216
Loss on sale of petroleum interests - - - - $262
Net income (loss) $(297) $(2,042) $(2,076) $(167) $(672)
37
($ IN 000, EXCEPT PER SHARE DATA)
---------------------------------------------------------------
YEAR ENDED AUGUST 31,
---------------------------------------------------------------
2000 1999 1998 1997 1996
Income (loss) per share $(0.02) $(0.40) $(0.84) $(0.16) $(0.78)
Weighted average number of shares 14,781 5,068 2,468 1,069 863
Dividends per share $0.00 $0.00 $0.00 $0.00 $0.00
Working capital (deficiency) $1,262 $1,338 $(471) $282 $99
Resource assets $7,795 $5,096 $2,169 $801 $532
Other assets $773 - - - -
Shareholders' equity $9,830 $6,434 $1,698 $1,083 $631
Total assets $10,137 $6,698 $2,225 $1,289 $741
ADJUSTMENT TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
(a) The consolidated financial statements of the Company have been prepared
in accordance to Canadian GAAP which differ in certain material
respects from US GAAP. Material differences between Canadian and US
GAAP and their effect on the Company's consolidated financial
statements are summarized in the tables below.
Consolidated Statement of Loss
2000 1999 1998
$ $ $
Net loss as reported under Canadian GAAP (296,849) (2,042,191) (2,075,741)
Adjustments for related party
transactions (ii) - 450,084 574,292
Stock-based compensation (iv) (98,126) (735,393) (137,324)
Other compensation expense (vii) (134,742) (31,600) (91,180)
-------------- -------------- --------------
Net loss under US GAAP (529,717) (2,359,100) (1,729,953)
============== ============== ==============
Weighted average number of
common shares outstanding (i) 15,012,218 5,296,479 3,954,706
============== ============== ==============
Loss per share under US GAAP (0.04) (0.45) (0.44)
============== ============== ==============
38
Consolidated Balance Sheet
2000 1999
$ $
Total assets under Canadian GAAP 10,136,627 6,697,995
Adjustments for related party transactions (ii) (2,744,022) (2,744,022)
Deferred tax asset (v) 1,651,821 1,573,000
Less: Valuation allowance (v) (1,651,821) (1,573,000)
-------------- --------------
Total assets under US GAAP 7,392,605 3,953,973
============== ==============
Total liabilities under Canadian GAAP 306,565 264,115
-------------- --------------
Total liabilities under US GAAP 306,565 264,115
============== ==============
Total shareholders' equity under Canadian GAAP 9,830,062 6,433,880
Adjustments for related party transactions (ii) (2,744,022) (2,744,022)
-------------- --------------
Total shareholders' equity under US GAAP 7,086,040 3,689,858
============== ==============
(i) Escrowed Shares
Under US GAAP escrowed shares are not included in the
computation of loss per share and the common shares which
underlie the special warrants are included in the calculation
of loss per share.
(ii) Capital Contributions with Respect to Related Party
Transactions
The Company has acquired and disposed of certain petroleum
interests with Hilton Inc. for a combination of monetary and
non-monetary consideration.
US GAAP requires that certain transfers of non-monetary assets
to a company by its promoters or shareholders, in exchange for
stock, should generally be recorded at the transferor's
historical cost basis, whereas under Canadian GAAP, transfers
of non-monetary assets may be recorded based on the fair value
of either the stock issued or the assets acquired under
certain circumstances. Under Canadian GAAP these transactions
were recorded at their fair values. The transactions have been
adjusted to reflect the transactions based on the historical
cost basis.
The net loss under US GAAP has also been adjusted for the
subsequent amortization and impairment charges of a portion of
these petroleum interest acquisitions costs.
(iii) Ceiling test on petroleum interests
US GAAP requires that the net book value of proved petroleum
interests not exceed the sum of the present value of estimated
future net revenues (determined using current prices of
petroleum production less estimated future expenditures to be
incurred in developing and producing the proved reserves,
discounted at ten percent). This ceiling test was performed
39
effective August 31, 2000 and it was determined that no
write-down of proved petroleum interests was necessary.
(iv) The Company grants stock options which reserves common shares
for issuance to employees and directors. Under Canadian GAAP,
the issuance of stock options is not recognized for accounting
purposes. Under US GAAP, the issuance of stock options
requires an assessment to determine stock based compensation.
Accordingly, the Company has applied the provisions of
Financial Account Standards ("SFAS") 123 Accounting for
Stock-Based Compensation to calculate stock-based compensation
under US GAAP using the fair value method.
The fair value of each option grant is estimated on the date
of grant using the Black-Scholes option pricing model with the
following assumptions used for grants in 2000, 1999 and 1998:
2000 1999 1998
------------------ ----------------- ------------------
Risk-free interest rate 5.63% - 5.79% 6.25% - 7.5% 4.75% - 6.50%
Expected volatility 87% 89% 112%
Expected lives 2 - 3 years 3 years 2 - 3 years
(v) Income Tax
Under Canadian GAAP, deferred tax assets relating to the
potential benefit of income tax loss carryforwards are not
recognized unless there is virtual certainty of realization of
the benefit. US GAAP provides similar treatment, but requires
the benefit be recognized and a valuation allowance be
recognized to fully offset the deferred tax asset.
As at August 31, 2000, the Company has fully reserved the
$1,651,821 tax benefit of operating loss carryforwards, by a
valuation allowance of the same amount, because the likelihood
of realization of the tax benefit cannot be determined. Of the
total tax benefit, $78,821 is attributable to the year ended
August 31, 2000.
(vi) Private Placements of Common Stock and Special Warrants with
Related Parties
US GAAP requires disclosure of private placements conducted by
the Company where directors and officers of the Company are
participants. During the year ended August 31, 2000,
directors, officers and companies controlled by the directors
or officers acquired 1,387,794 shares or special warrants
(1999 - 1,580,000; 1998 - 340,000) of the Company, pursuant to
private placements conducted by the Company, for cash proceeds
of $1,116,952 (1999 - $1,264,000; 1998 - $374,000).
(vii) Private Placements of Common Stock
The Company conducts the majority of its equity financings
pursuant to private placements. Under the policies of the
Canadian Venture Exchange, on which the Company's common stock
is listed, the Company may provide a discount off the market
price of the Company's
40
common stock. US GAAP does not permit a discount from the
market price. US GAAP requires the recognition of the market
value of the Company's common stock as a credit to share
capital, with a charge to operations for the portion of the
discount relating to equity financings conducted with officers
and directors of the Company and a charge to shareholders'
equity, as a capital distribution, for the discount relating
to the remaining portion of the equity financings.
Under US GAAP, loss and capital distributions for the year
ended August 31, 2000 would increase by $134,742 (1999 -
$31,600; 1998 - $91,180) and $184,919 (1999 - $37,805; 1998 -
$167,736), respectively, and share capital, as at August 31,
2000 would increase by $647,982 (1999 - $328,321). There is no
net change to shareholders' equity.
(b) The Company's consolidated statements of cash flow comply with US GAAP.
(c) New Technical Pronouncements
In June 1998 SFAS No. 133 "Accounting for Derivative Instruments and
Hedging Activities", as amended by SFAS No. 137 and No. 138, were
issued for fiscal years beginning after June 15, 2000. The impact of
the adoption of the new standard is currently being reviewed by the
Company.
In March 2000 FIN No. 44 "Accounting for Certain Transactions Involving
Stock Compensation, An Interpretation of APB Opinion No. 25" was issued
for fiscal years beginning after July 1, 2000. Adoption of FIN No. 44
is not expected to have an impact on the Company's consolidated
financial statements.
ITEM 9. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.
- --------------------------------------------------------------------------------
The following discussion of the results of operations of the Company for the
fiscal years ended August 31, 2000, 1999 and 1998 should be read in conjunction
with the consolidated financial statements of the Company and related notes
included therein.
The Company's consolidated financial statements are in Canadian dollars and are
prepared in accordance with Canadian GAAP, the application of which, in the case
of the Company, conforms in all material respects for the period presented with
U.S. GAAP except for the differences referred to in Note 9 of the consolidated
financial statements of the Company included herein. The noon rate of exchange
on January 31, 2001, reported by the United States Federal Reserve Bank of New
York for the conversion of Canadian dollars into United States dollars was
Cdn.$1.4995 (US$0.6669 = Cdn.$1.00). The effects of inflation and price changes
have not had a material impact on the Company's income or net sales revenues
during the past three years.
The Company's consolidated financial statements were prepared on a going concern
basis which assumes that the Company will be able to realize assets and
discharge liabilities in the normal course of business.
41
OVERVIEW
The Company, through its subsidiaries, Trimark Inc. and Safari, is engaged in
the business of exploring for and development of oil and gas prospects in the
United States. Substantially all of the Company's oil and gas exploration
activities are conducted jointly with others. Because the Company owns an
undivided interest in each asset and is proportionately liable for its share of
each liability, the consolidated financial information reflects the Company's
proportionate interest in such activities. The Company sells all of its oil and
gas production on a spot basis and does not utilize forward sales contracts.
During the year ended August 31, 2000, the Company changed its method of
accounting for its petroleum interests from the successful efforts method to the
full cost method. Management believes that the new accounting policy is more
appropriate for oil and gas companies such as the Company. This change in
accounting policy has been applied retroactively.
Under the full cost method, all costs related to the exploration for and
development of petroleum and natural gas reserves are capitalized on a
country-by-country basis. Costs include lease acquisition costs, geological and
geophysical expenses, overhead directly related to exploration and development
activities and costs of drilling both productive and non-productive wells.
Proceeds from the sale of properties are applied against capitalized costs,
without any gain or loss being recognized, unless such a sale would
significantly alter the rate of depletion and depreciation.
Depletion of exploration and development costs and depreciation of production
equipment is provided using the unit-of-production method based upon estimated
proven petroleum and natural gas reserves. The costs of significant unevaluated
properties are excluded from costs subject to depletion. For depletion and
depreciation purposes, relative volumes of petroleum and natural gas production
and reserves are converted at the energy equivalent conversion rate of six
thousand cubic feet of natural gas to one barrel of crude oil.
In applying the full cost method, the Company performs a ceiling test whereby
the carrying value of petroleum and natural gas properties and production
equipment, net of recorded deferred income taxes and the accumulated provision
for site restoration and abandonment costs, is compared annually to an estimate
of future net cash flow from the production of proven reserves. Net cash flow is
estimated using year end prices, less estimated future general and
administrative expenses, financing costs and income taxes. Should this
comparison indicate an excess carrying value, the excess is charged against
earnings.
Substantially all of the Company's exploration, development and production
activities are conducted jointly with others, and accordingly, these
consolidated financial statements reflect only the Company's proportionate
interest in such activities.
YEAR ENDED AUGUST 31, 2000 COMPARED TO YEAR ENDED AUGUST 31, 1999
During the year ended August 31, 2000, the Company reported a net loss of
$296,849 ($0.02 per share), a decrease of $1,745,342, from the loss of
$2,042,191 ($0.40 per share) reported in 1999.
Revenue from oil and gas sales increased 49% during 2000, from $135,865 in 1999
to $202,714 in 2000. Revenue from oil sales increased 66% due to the increased
average selling price for oil during 2000. Oil production fell 10%, from 3,424
bbls in 1999 to 3,069 bbls in 2000, and average selling prices increased by
42
85%, from $19.97/bbl in 1999 to $36.98/bbl in 2000. Revenue from natural gas
sales increased by 32%, from $67,476 in 1999 to $89,232 in 2000. Natural gas
production decreased by 14%, from 28,364 mcf in 1999 to 24,399 mcf in 2000. The
average selling price of natural gas increased by 54%, from $2.38/mcf in 1999 to
$3.66 mcf in 2000.
The Company's production expenses increased 18%, from $132,176 in 1999 to
$154,529 in 2000. On a per unit basis, production expenses were $16.22/BOE in
1999 compared to $21.80/BOE in 2000.
No impairment provisions were required in 2000 as a result of the ceiling test
performed effective August 31, 2000. During 1999, the Company wrote-down the
carrying value of its petroleum interests by $1,649,518. Excluding the ceiling
test write-down made in 1999, depreciation and depletion expenses increased to
$78,340 in 2000 from $53,982 in 1999. On a per unit basis, the rate was
$10.98/BOE in 2000 compared to $6.62/BOE in 1999.
Interest and other income increased substantially in 2000 to $195,735, compared
to $7,464 in 1999. The significant increase in interest income in 2000 arose due
to the impact of the high levels of cash and term deposits held during 2000 as a
result of the financings conducted by the Company at the end of fiscal 1999 and
early fiscal 2000.
YEAR ENDED AUGUST 31, 1999 COMPARED TO YEAR ENDED AUGUST 31, 1998
During the year ended August 31, 1999, the Company reported a net loss of
$2,042,191 ($0.40 per share) compared to a loss of $2,075,741 ($0.84 per share)
incurred for the comparable 1998 period.
Revenue from oil and gas sales decreased 41% during 1999, to $135,865, compared
to $228,983 for 1998. Revenue from oil sales decreased 34% to $68,391 in 1999
from $103,305 in 1998. The decrease is attributed to a combination of reduced
production and the severe decrease in the average selling price for oil in 1999.
Oil production fell 24%, from 4,476 bbls in 1998 to 3,424 bbls in 1999 and
average selling prices received decreased 13%, from $23.08/bbl in 1998 to
$19.97/bbl in 1999. Revenue from natural gas sales decreased 46%, from $125,678
in 1998 to $67,476 in 1999. Natural gas production decreased by 39%, from 46,479
mcf in 1998 to 28,364 mcf in 1999. The average selling price of natural gas
decreased 12%, from $2.70/mcf in 1998 to $2.38/mcf in 1999.
The Company's production expenses increased 24% to $132,176 in 1999 from
$106,843 in 1998. On a per unit basis, production expenses increased to
$16.22/BOE in 1999 from $8.74/BOE in 1998. Additional operating expenses were
incurred in 1999 due to the additional pumping units on six wells on the Big
Springs Unit.
As a result of ceiling tests performed effective August 31, 1999 and 1998, the
Company wrote down the carry values of its petroleum interests by $1,649,518 in
1999 and $1,755,234 in 1998.
Excluding the ceiling test write-downs, the Company's depreciation and depletion
expenses decreased to $53,982 in 1999 from $228,068 in 1998. On a per unit
basis, the rate was $6.62/BOE in 1999 compared to $9.47/BOE in 1998.
43
YEAR ENDED AUGUST 31, 1998 COMPARED TO YEAR ENDED AUGUST 31, 1997
During the fiscal year ended August 31, 1998, the Company reported a net loss of
$2,075,741 ($0.84 per share), an increase of $1,908,367 from the net loss of
$167,374 ($0.16 per share) incurred in 1997. The Company's revenue from oil and
gas sales increased 55% in 1998 to $228,983 from $147,518 in 1997. Revenue from
oil sales decreased 28% in 1998 to $103,305 from $143,862 in 1997. The decrease
is attributable to oil volume decreasing by 9%, from 4,923 bbls in 1997 to 4,476
bbls in 1998. In addition, the average selling price for oil was $23.08/bbl,
down 21% from the 1997 average of $29.22/bbl. Revenue from natural gas sales
increased to $125,678 in 1998 from $3,286 in 1997. This increase is attributable
primarily to an increase in natural gas production in 1998 to 46,479 mcf from
1,491 mcf in 1997, arising from the installation of pumping units on six wells
on the Big Springs Unit in 1998. The average selling price for natural gas also
increased from $2.20/mcf in 1997 to $2.70/mcf in 1998.
The Company's production expenses increased 32% to $106,843 in 1998 compared to
$81,071 in 1997, due to increased production. On a per unit basis, production
expenses decreased to $8.74/BOE in 1998 from $15.68/BOE in 1997. The decrease in
production costs is attributed to the higher gas production in 1998 as compared
to mostly oil production in 1997.
The increased net loss in 1998 was attributed primarily to a total of $1,983,302
recorded for depreciation, depletion and impairment in petroleum interests.
Excluding the ceiling test write-downs, the Company's depreciation and depletion
expenses increased to $228,068 in 1998 from $32,332 in 1997, due to higher gas
volumes produced in 1998. On a per unit basis, the rate was $9.47/BOE in 1998
compared to $6.25/BOE in 1997. The increase is due to the impact of the
acquisition of the Big Springs Unit in September 1997.
During fiscal 1998, the Company completed the acquisition of the East Morgantown
Prospect, at a cost of $211,657. The Company also completed the acquisition of
the Big Springs Unit and issued 1,300,000 common shares, at a deemed price of
$1.26 per share, and paid the remaining balance of $644,000 (a $272,500 deposit
due on the purchase was paid in fiscal 1997).
LIQUIDITY AND CAPITAL RESOURCES
The Company's total assets increased from $6,697,995 at August 31, 1999 to
$10,136,627 at August 31, 2000. The increase is primarily attributable to the
additional equity financings conducted by the Company during 2000, when the
Company issued 4,380,086 common shares for net proceeds of $4,726,601. The
proceeds from the financings were utilized to meet the Company's funding
requirements on the East Lost Hills and San Joaquin Joint Venture programs and
the acquisition and exploration of its working interests in the East Blossom
Prospect and West Simon Project.
At August 31, 2000, the Company had working capital of $1,261,777, a slight
decrease from a working capital of $1,337,755 at August 31, 1999. The Company
has commitments of approximately $5.2 million for its share of planned
expenditures on the East Lost Hills Joint Venture, the San Joaquin Joint Venture
and the Regional California program during the 2001 calendar year. In order to
meet its commitments, the Company continues to seek additional equity financing.
Subsequent to August 31, 2000, the Company completed a private placement
financing of 118,570 units, at $0.70 per unit, for $83,000. Each unit consists
of one share and one warrant to purchase a further share, at $0.84 per share, on
or before June 19, 2002. The Company has completed the first tranche of 500,000
units of an additional financing of 2.2 million units, at
44
$0.52 per unit, to raise a total of $1,144,000. Each unit will consist of one
share and one warrant to entitle the holder to purchase a further share, at
$0.52 per share, for a period of two years.
The Company's management may elect to acquire new projects, at which time the
Company may require additional equity financing to fund overhead and maintain
its interests in current projects, or may decide to relinquish certain of its
properties or allow its interest to be diluted pursuant to the terms of the
respective joint venture agreements. These decisions will be based on the
results of ongoing exploration programs and the response of equity markets to
the Company's projects and business plan.
The Company does not know of any trends, demands, commitments, events or
uncertainties that will result in, or that are reasonably likely to result in,
the Company's liquidity either materially increasing or decreasing at present or
in the foreseeable future. Material increases or decreases in the Company's
liquidity are substantially determined by the success or failure of the
Company's exploration programs, the acquisition of projects, and the
availability of financings.
The Company does not now, and does not expect to engage in currency hedging to
offset any risk of currency fluctuations.
ITEM 9A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
- --------------------------------------------------------------------------------
Not Applicable.
ITEM 10. DIRECTORS AND OFFICERS OF REGISTRANT.
- --------------------------------------------------------------------------------
The name and municipality of residence and positions held with the Company
during the five years prior to the date of this annual report of each director,
officer, promoter and other member of management of the Company as of January
31, 2001, is as follows:
NAME AND MUNICIPALITY OF RESIDENCE POSITION WITH THE COMPANY TERM OF OFFICE (FOR EACH OFFICE HELD)
- ---------------------------------- ------------------------- -------------------------------------
DONALD W. BUSBY(1)<F1> Chairman From April 1999 - present
Conifer, Colorado, U.S.A. President From September 1999 - present; and
February 1997 - April 1999
Chief Executive Officer From February 1997 - present
Director From December 1988 - present
Promoter From December 1988 - present
PHILIP ZACCARIA(2)<F2> Director From April 1999 - present
San Antonio, Texas, U.S.A. President From April 1999 - September 1999
Chief Operating Officer From April 1999 - September 1999
NICK DEMARE(1)<F1> Director January 1996 - present
Burnaby, British Columbia, Canada President From January 1996 - February 1997
GEORGE MUSCROFT(1)<F1> Director From February 1997 - present
Tsawassen, British Columbia, Canada
HARVEY LIM Corporate Secretary From December 1988 - present
Vancouver, British Columbia, Canada Director From October 1990 - May 1994
45
<FN>
<F1>
(1) Member of the Audit Committee.
<F2>
(2) Mr. Zaccaria did not stand for re-election at the Company's annual
general meeting held on February 22, 2001.
</FN>
The Company does not currently have an Executive Committee.
DONALD W. BUSBY (AGE 63), CHAIRMAN, PRESIDENT, CHIEF EXECUTIVE OFFICER, PROMOTER
AND DIRECTOR
Since June 1988, Mr. Busby has been the president and owner of DWB Management
Ltd. Mr. Busby, through DWB, provides marketing, financial management and
consulting services to various mineral exploration companies, including the
Company. Since August 1990, Mr. Busby has been the owner and president of Boone
Petroleum Inc., a private company owned by Mr. Busby. Mr. Busby currently serves
as an officer and director of other public reporting companies.
PHILIP ZACCARIA (AGE 41), DIRECTOR
Mr. Zaccaria has a Bachelor of Science (1983) in Petroleum Engineering from the
University of Texas. Since June 1984, Mr. Zaccaria has been the President of PNP
Petroleum, Inc. (San Antonio, Texas) PNP provides consulting services to oil and
gas companies. Since June 1995, Mr. Zaccaria has been the President of Sonterin
Energy Inc. Mr. Zaccaria is responsible for managing Sonterin's day-to-day
operations. From August 1991 to December 1997, Mr. Zaccaria was the President of
Mescalero Energy Inc. (San Antonio, Texas). Mescalero filed bankruptcy in
December 1997. As President of Mescalero, Mr. Zaccaria was responsible for
managing Mescalero's day-to-day operations.
Mr. Zaccaria did not stand for re-election at the Company's annual general
meeting held on February 22, 2001.
NICK DEMARE (AGE 46), DIRECTOR
Mr. DeMare holds a Bachelor of Commerce degree from the University of British
Columbia and is a member in good standing of the Institute of Chartered
Accountants of British Columbia. Since May, 1991, Mr. DeMare has been the
President of Chase Management Ltd. (Vancouver, British Columbia), a private
company which provides a broad range of administrative, management and financial
services to private and public companies engaged in mineral exploration and
development, gold and silver production, oil and gas exploration and production
and venture capital. Mr. DeMare indirectly owns 100% of Chase. Mr. DeMare
currently serves as an officer and director of other public reporting companies.
GEORGE MUSCROFT (AGE 71), DIRECTOR
Mr. Muscroft holds a Bachelor of Science degree from the University of Toronto
(1953) and has been a professional engineer since 1954. Since 1984, Mr. Muscroft
has been the President of Modnar Enterprises, an independent consulting
engineering firm.
HARVEY LIM (AGE 42), CORPORATE SECRETARY
Mr. Lim holds a Bachelor of Commerce degree from the University of British
Columbia and is a member in good standing of the Institute of Chartered
Accountants of British Columbia. Mr. Lim was employed by Coopers & Lybrand (now
PricewaterhouseCoopers LLC) from 1981 to 1988. Since 1988, Mr. Lim has been
46
employed by Chase Management Ltd. Mr. Lim currently serves as an officer and
director of other public reporting companies.
On February 22, 2001, Mr. Dick Darrow (age 80) was elected as a director of the
Company. Mr. Darrow holds a Master of Geology degree from the University of
California at Berkley. Mr. Darrow is a petroleum geologist resident in
Bakersfield, California and has extensive experience in the oil and gas
industry. From 1953 through March 1984, Mr. Darrow was employed with Standard
Oil Company of California. Since his early retirement, as a senior staff
geologist, Mr. Darrow has been a self-employed consulting geologist. Mr. Darrow
has an extensive geological knowledge of the San Joaquin and Sacramento oil and
gas basins of California.
ITEM 11. COMPENSATION OF DIRECTORS AND OFFICERS.
- --------------------------------------------------------------------------------
During the fiscal year ended August 31, 2000, the directors and officers of the
Company, as a group, had received or charged the Company a total of $120,264 for
services rendered by the directors and officers or companies owned by the
individuals.
The Company is required, under applicable securities legislation in Canada, to
disclose to its shareholders details of compensation paid to its directors and
officers. The following fairly reflects all material information regarding
compensation paid by the Company to its directors and officers, which
information has been disclosed to the Company's shareholders in accordance with
applicable Canadian law.
EXECUTIVE COMPENSATION
"Named Executive Officers" means the Chief Executive Officer ("CEO") of the
Company, regardless of the amount of compensation of that individual, and each
of the Company's four most highly compensated executive officers, other than the
CEO, who were serving as executive officers at the end of the most recent fiscal
year and whose total salary and bonus amounted to $100,000 or more. In addition,
disclosure is also required for any individuals whose total salary and bonus
during the most recent fiscal year was $100,000 whether or not they are an
executive officer at the end of the fiscal year.
The Company currently has one Named Executive Officer, Donald W. Busby (the
"Named Executive Officer"). The following table sets forth the compensation
awarded, paid to or earned by the Named Executive Officer during the financial
years ended August 31, 1998, 1999 and 2000:
47
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG TERM COMPENSATION
-----------------------------------------------------------------------
AWARDS PAYOUTS
-----------------------------------
SECURITIES RESTRICTED
UNDER SHARES OR ALL
OTHER OPTIONS/ RESTRICTED OTHER
NAME AND ANNUAL SARS SHARE LTIP COMPEN-
PRINCIPAL SALARY BONUS COMPENSATION GRANTED UNITS PAYOUTS SATION
POSITION YEAR ($) ($) ($) (#)(2)<F2> ($) ($) ($)
(A) (B)(1)<F1> (C) (D) (E) (F) (G) (H) (I)
- --------------------------------------------------------------------------------------------------------------------------
Donald W. Busby 2000 Nil Nil Nil Nil/Nil N/A N/A 60,000(3)<F3>
Chairman, President, 1999 Nil Nil Nil 605,100/Nil N/A N/A 69,987(3)<F3>
CEO and Director 1998 Nil Nil Nil 108,300/Nil N/A N/A 68,726(3)<F3>
- --------------------------------------------------------------------------------------------------------------------------
NOTES:
<FN>
<F1>
(1) Financial years ended August 31, 1998, 1999 and 2000.
<F2>
(2) Figures represent options granted during a particular year; see
"Aggregate Option" table for the aggregate number of options
outstanding at year end.
<F3>
(3) Amounts paid to private companies wholly owned by Mr. Busby.
</FN>
LONG TERM INCENTIVE PLAN AWARDS
Long term incentive plan awards ("LTIP") means "any plan providing compensation
intended to serve as an incentive for performance to occur over a period longer
than one financial year whether performance is measured by reference to
financial performance of the Company or an affiliate, or the price of the
Company's shares but does not include option or stock appreciation rights plans
or plans for compensation through restricted shares or units". The Company has
not granted any LTIP's during the financial year ended August 31, 2000.
STOCK APPRECIATION RIGHTS
Stock appreciation rights ("SAR's") means a right, granted by an issuer or any
of its subsidiaries as compensation for services rendered or in connection with
office or employment, to receive a payment of cash or an issue or transfer of
securities based wholly or in part on changes in the trading price of the
Company's shares. No SAR's were granted to or exercised by the Named Executive
Officer or directors during the financial year ended August 31, 2000.
OPTION GRANTS IN LAST FISCAL YEAR
The Company did not grant any stock options to the Named Executive Officer
during the financial year ended August 31, 2000.
48
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION
VALUES
The following table sets forth details of all exercises of stock options during
the financial year ended August 31, 2000 by the Named Executive Officer and the
fiscal year-end value of unexercised options on an aggregated basis:
VALUE OF UNEXERCISED
UNEXERCISED OPTIONS AT IN-THE-MONEY OPTIONS
FISCAL YEAR-END AT FISCAL YEAR-END
SECURITIES AGGREGATE (#)(3)<F3> ($)(3)<F3>(4)<F4>
ACQUIRED ON VALUE
EXERCISE REALIZED EXERCISABLE/ EXERCISABLE/
NAME (#)(1)<F1> ($)(2)<F2> UNEXERCISABLE UNEXERCISABLE
(A) (B) (C) (D) (E)
- ------------------------------------------------------------------------------------------------------------------------
Donald W. Busby 200,000 92,000 287,000/Nil Nil/Nil
- ------------------------------------------------------------------------------------------------------------------------
NOTES:
<FN>
<F1>
(1) Number of common shares of the Company acquired on the exercise of
stock options.
<F2>
(2) Calculated using the closing price of common shares of the Company on
the Canadian Venture Exchange.
<F3>
(3) As freestanding SARs have not been granted, the number of shares relate
solely to stock options.
<F4>
(4) Value of unexercised in-the-money options calculated using the closing
price of common shares of the Company on the Canadian Venture Exchange
on August 31, 2000 of $0.53 per share, less the exercise price of
in-the-money stock options.
</FN>
PENSION PLANS
The Company does not provide retirement benefits for directors or executive
officers.
TERMINATION OF EMPLOYMENT, CHANGE IN RESPONSIBILITIES AND EMPLOYMENT CONTRACTS
The Company has no plans or arrangements in respect of remuneration received or
that may be received by the Named Executive Officer in the Company's most
recently completed financial year or current financial year in respect of
compensating such officers in the event of termination of employment (as a
result of resignation, retirement, change of control, etc.) or a change in
responsibilities following a change of control, where the value of such
compensation exceeds $100,000 per executive officer.
COMPENSATION OF DIRECTORS
The following table sets forth stock options granted by the Company during the
financial year ended August 31, 2000 to directors who are not Named Executive
Officers of the Company:
49
MARKET VALUE OF
% OF TOTAL SECURITIES UNDERLYING
SECURITIES UNDER OPTIONS EXERCISE OR OPTIONS ON
OPTIONS GRANTED GRANTED IN BASE PRICE DATE OF GRANT EXPIRATION
NAME (#)(1)<F1> FINANCIAL YEAR(2)<F2> ($/SECURITY)(3)<F3> ($/SECURITY) DATE
(A) (B) (C) (D) (E) (F)
- ---------------------------------------------------------------------------------------------------------------------------
Nick DeMare 100,000(4)<F4> 66.7% 1.90 1.90 Oct.1/02
- ---------------------------------------------------------------------------------------------------------------------------
George Muscroft 25,000 1.7% 1.90 1.90 Oct.1/02
- ---------------------------------------------------------------------------------------------------------------------------
NOTES:
<FN>
<F1>
(1) The options have no special vesting provisions. The market value of the
common shares of the Company on the date of grant is the price at which
the Company's shares closed for trading on the Canadian Venture
Exchange on that day. Freestanding SARs have not been granted.
<F2>
(2) Percentage of all options granted during the fiscal year.
<F3>
(3) The exercise price of stock options was set according to the rules of
the Canadian Venture Exchange. The exercise price of stock options may
only be adjusted in the event that specified events cause dilution of
the Company's share capital.
<F4>
(4) Granted to Chase Management Ltd., a private company wholly owned by Mr. DeMare.
</FN>
The following table sets forth details of all exercises of stock options/SARs
during the financial year ended August 31, 2000 by directors who are not Named
Executive Officers of the Company and the financial year- end value of
unexercised options/SARs:
VALUE OF UNEXERCISED
UNEXERCISED IN-THE-MONEY OPTIONS/
OPTIONS/SARS AT FISCAL SARS AT FISCAL YEAR-END
SECURITIES AGGREGATE YEAR-END ($)(3)<F3>(4)<F4>
ACQUIRED ON VALUE (#)(3)<F3>
EXERCISE REALIZED EXERCISABLE/ EXERCISABLE/
NAME (#)(1)<F1> ($)(2)<F2> UNEXERCISABLE UNEXERCISABLE
(A) (B) (C) (D) (E)
- --------------------------------------------------------------------------------------------------------------------------
Nick DeMare Nil Nil 250,000(5)<F5>/Nil Nil/Nil
- --------------------------------------------------------------------------------------------------------------------------
Phlip Zaccaria Nil Nil 100,000/Nil Nil/Nil
- --------------------------------------------------------------------------------------------------------------------------
George Muscroft Nil Nil 25,000/Nil Nil/Nil
- --------------------------------------------------------------------------------------------------------------------------
NOTES:
<FN>
<F1>
(1) Number of common shares of the Company acquired on the exercise of
stock options.
<F2>
(2) Calculated using the closing price of common shares of the Company on
the Canadian Venture Exchange on the date of the exercise, less the
exercise price per share.
<F3>
(3) As freestanding SARs have not been granted, the numbers relate solely
to stock options.
<F4>
(4) Value of unexercised in-the-money options calculated using the closing
price of common shares of the Company on the Canadian Venture Exchange
on August 31, 2000, less the exercise price of in-the-money stock
options.
<F5>
(5) Granted to Chase Management Ltd., a private company wholly owned by Mr.
DeMare.
</FN>
50
During the most recently completed financial year, directors received
compensation for services provided to the Company in their capacities as
directors and/or consultants and/or experts as follows:
COMPENSATION TABLE
ANNUAL ALL OTHER
COMPENSATION COMPENSATION
NAME OF DIRECTOR YEAR(1)<F1> - DIRECTORS FEES - CONSULTING FEES
- ------------------------------------------------------------------------------------------------------------------------
Nick DeMare 2000 $Nil $45,550(2)<F2>
- ------------------------------------------------------------------------------------------------------------------------
Philip Zaccaria 2000 $Nil $14,714
- ------------------------------------------------------------------------------------------------------------------------
George Muscroft 2000 $Nil $Nil
- ------------------------------------------------------------------------------------------------------------------------
NOTES:
<FN>
<F1>
(1) Financial year ended August 31, 2000.
<F2>
(2) Paid to Chase Management Ltd. ("Chase"), a private company wholly owned
by Mr. DeMare, for accounting and professional services rendered by
Chase personnel.
</FN>
ITEM 12. OPTIONS TO PURCHASE SECURITIES FROM REGISTRANT OR
SUBSIDIARIES
- --------------------------------------------------------------------------------
OPTIONS AND OTHER RIGHTS TO PURCHASE SECURITIES
Stock Options to purchase securities from the Company are granted to directors
and employees of the Company on terms and conditions acceptable to the
regulatory authorities in Canada, notably the CDNX. Stock options must be
approved by the Company's shareholders at an Annual General Meeting. The Company
has no formal written stock option plan.
Under the stock option program, stock options for up to 10% of the number of
issued and outstanding shares of common stock may be granted from time to time,
provided that stock options in favor of any one individual may not exceed 5% of
the issued and outstanding shares of common stock. No stock option granted under
the stock option program is transferable by the optionee other than by will or
the laws of descent and distribution, and each stock option is exercisable
during the lifetime of the optionee only by such optionee.
The exercise price of all stock options granted under the stock option program
must be at least equal to the fair market value of such shares of common stock
on the date of grant, and the maximum term of each stock option may not exceed
five years.
The exercise prices for stock options were determined in accordance with CDNX
guidelines and reflect the average closing price of the Company's common stock
for the ten trading days on the CDNX immediately preceding the date on which the
directors granted and publicly announced the stock options.
51
As of January 31, 2001, the Company had granted an aggregate of 1,587,000
non-transferable incentive stock options to purchase shares of the Company's
common stock to the following persons:
NATURE NO. OF EXERCISE
OPTIONEE OF OPTION OPTIONS PRICE EXPIRY DATE
- -------- --------- ------- -------- -----------
Donald W. Busby Director 287,000 $1.14 Jul. 23/02
Chase Management Ltd.(1)<F1> Employee 150,000 $1.14 Jul. 23/02
Philip Zaccaria Employee 100,000 $1.14 Jul. 23/02
Earl Helsley Employee 50,000 $1.14 Jul. 23/02
Betty L. Moody Employee 25,000 $1.14 Jul. 23/02
Chase Management Ltd.(1)<F1> Employee 100,000 $1.90 Oct. 1/02
George Muscroft Director 25,000 $1.90 Oct. 1/02
Ian Padden Employee 50,000 $0.77 Jun. 13/03
Donald W. Busby(2)<F2> Director 393,000 $0.60 Jan. 25/04
George Muscroft(2)<F2> Director 60,000 $0.60 Jan. 25/04
Nick DeMare(2)<F2> Director 100,000 $0.60 Jan. 25/04
Ian Padden(2)<F2> Employee 50,000 $0.60 Jan. 25/04
Dick Darrow(2)<F2> Employee 100,000 $0.60 Jan. 25/04
Betty L. Moody(2)<F2> Employee 15,000 $0.60 Jan. 25/04
Harvey Lim(2)<F2> Employee 30,000 $0.60 Jan. 25/04
Arabella Smith(2)<F2> Employee 15,000 $0.60 Jan. 25/04
Rosanna Wong(2)<F2> Employee 15,000 $0.60 Jan. 25/04
Linda Liu(2)<F2> Employee 15,000 $0.60 Jan. 25/04
Jacqueline Hibbs(2)<F2> Employee 7,000 $0.60 Jan. 25/04
---------
Total 1,587,000
=========
<FN>
<F1>
(1) A private company indirectly wholly-owned by Mr. DeMare.
<F2>
(2) These options were granted on January 25, 2001 and approved by the CDNX
on February 5, 2001.
</FN>
All of the stock options terminate on the earlier of the expiration date or the
30th day following the day on which the director, officer or employee, as the
case may be, ceases to be a director, officer or employee of the Company.
As of January 31, 2001, the directors and officers and companies controlled or
under significant influence of officers and directors of the Company, as a
group, held stock options to purchase up to 1,245,000 of the Company's common
shares.
WARRANTS AND OTHER COMMITMENTS
As of January 31, 2001, there were transferable common share purchase warrants
exercisable for the purchase of 5,851,301 common shares which expire at various
times until January 16, 2003, and may be exercised at various prices ranging
from $0.52 per share to $1.73 per share as follows:
52
COMMON SHARES ISSUABLE
UPON EXERCISE OF WARRANTS EXERCISE PRICE PER SHARE EXPIRATION DATE
2,790,234 $0.97 Jul. 14/01
1,256,782 $1.73 Sept. 24/01
1,185,715 $0.84 Jun. 05/02
118,570 $0.84 Jun. 19/02
500,000 $0.52 Jan. 16/03
----------
5,851,301
==========
The Company has also arranged a private placement with Hilton to purchase
1,700,000 units at a price of $0.52 per unit, with each unit consisting of one
common share and one share purchase warrant. Each warrant will enable Hilton to
purchase an additional common share at a price of $0.52 per share for a two year
period. As of January 31, 2000, the private placement was not completed.
As of January 31, 2001, the Company's officers and directors and companies
controlled or under significant influence of officers and directors of the
Company, as a group, held warrants to purchase up to 1,692,055 of the Company's
common shares.
ITEM 13. INTEREST OF MANAGEMENT IN CERTAIN TRANSACTIONS.
- --------------------------------------------------------------------------------
RELATED PARTY TRANSACTIONS
Other than as disclosed below, none of the present directors, officers or
principal shareholders of the Company, nor any associate or affiliate of the
foregoing, nor, to the best of the information and belief of the present
management of the Company, any of the former directors, senior officers or
principal shareholders of the Company, nor any associate or affiliate of such
former directors, officers or principal shareholders, have or have had any
interest, director or indirect, in any transaction, within the last year prior
to the date of this annual report, or in any proposed transaction which has
materially affected or will materially affect the Company except that:
1. Pursuant to the terms of a management contract (the "DWB Contract")
with DWB Management Ltd. ("DWB"), a private company wholly-owned by
Donald Busby, Trimark Inc. retained DWB to provide marketing,
consulting and management services. In consideration therefor, DWB is
paid a monthly fee of $7,000 and out-of-pocket disbursements incurred
by DWB on behalf of the Company. In the past, the Company has also paid
fees to Rockies, a private company wholly-owned by Donald W. Busby, for
professional consulting services performed for Trimark Inc. by Rockies.
No amounts were outstanding to DWB on August 31, 2000 and January 31,
2001.
2. The Company has retained Chase, a company indirectly wholly-owned by
Nick DeMare, to provide administrative, accounting and management
services. In consideration therefor, Chase is paid a monthly fee of
$3,000 and out-of-pocket disbursements incurred by Chase on behalf of
the Company. No amount was outstanding to Chase on August 31, 2000. As
at January 31, 2001, $4,832 was outstanding and owed to Chase.
53
3. The Company has completed previous private placements, the subscribers
of which include companies wholly-owned by Donald Busby and Nick
DeMare, directors and officers of the Company. The securities issued
pursuant to such private placements were issued in accordance with the
pricing policies of the CDNX.
4. During the fiscal year ended August 31, 2000, the Company provided a
US$125,000 relocation loan to Donald W. Busby. The loan bears interest
at 5% per annum, compounded monthly, and matures on March 27, 2002.
During the year ended August 31, 2000, interest income of $4,018 was
recorded by the Company. At August 31, 2000, the US$125,000 principal,
plus accrued interest of US$4,018, remained outstanding. As at January
31, 2001, the US$125,000 principal, plus accrued interest of US$5,429,
remained outstanding.
See also "Item 11. Compensation of Directors and Officers."
INDEBTEDNESS OF DIRECTORS, OFFICERS, PROMOTERS AND OTHER MANAGEMENT
During the fiscal year ended August 31, 2000, the Company provided a US$125,000
relocation loan to Donald W. Busby. The loan bears interest at 5% per annum,
compounded monthly, and matures on March 27, 2002. The loan is due at maturity.
At August 31, 2000, the US$125,000 principal, plus accrued interest of US$4,018,
remained outstanding. As at January 31, 2001, the US$125,000 principal, plus
accrued interest of US$5,429, remained outstanding.
CONFLICTS OF INTEREST
The table below shows that certain directors of the Company are also directors
or officers of other companies which are engaged in the business of acquiring,
developing and exploiting natural resource properties. Such associations may
give rise to conflicts of interest from time- to-time. The directors of the
Company are required by law to act honestly and in good faith with a view to the
best interest of the Company and to disclose any interest which they many have
in any project or opportunity of the Company. However, each director has a
similar obligation to other companies for which such director serves as an
officer or director. The Company has no specific internal policy governing
conflicts of interest. During the fiscal year ended August 31, 2000, no
conflicts of interest arose, except as described below and in "Item 13. Interest
of Management in Certain Transactions - Related Party Transactions." Where
conflicts of interests arose, the directors of the Company disclosed their
interests and abstained from voting on the transaction.
The following table identifies the name of each director of the Company and any
company, which is a reporting issuer in Canada, and for which such director
currently serves as an officer or director:
PRINCIPAL REPORTING COMPANY CAPACITY PERIOD
- --------- ----------------- -------- ------
Donald W. Busby Hilton Petroleum Ltd. Director Sept/95 to present
Chairman Apr/99 to present
President Sept/95 to Mar./99
QDM Ventures Ltd. President, CEO, May/00 to present
Director
Silverarrow Explorations Ltd. President, Director Jan/01 to present
54
PRINCIPAL REPORTING COMPANY CAPACITY PERIOD
- --------- ----------------- -------- ------
Nick DeMare Andean American Mining Corp. Secretary Dec/95 to present
Dial Thru International Inc. Director Jan/91 to present
GGL Diamond Corp. Director May/89 to present
Golden Peaks Resources Ltd. Director Jan/92 to present
Hilton Petroleum Ltd. Director Oct/89 to present
IMA Exploration Inc. Director Mar/96 to present
International Big Sky Resources Corp. Director, Secretary Nov/96 to present
Kookaburra Resources Ltd. Director Jun/88 to present
Peruvian Gold Limited Director Feb/93 to present
Planex Ventures Ld. Director Jan/00 to present
QDM Ventures Ltd. Director May/00 to present
Silverarrow Explorations Ltd. Director Jan/01 to present
Dick Darrow None -- --
George Muscroft Fenway Resources Ltd. Director Sept/91 to present
Primo Resources International Inc. Director Dec/91 to present
Harvey Lim Consolidated Epix Technologies Limited Director Dec/97 to present
Hilton Petroleum Ltd. Secretary Jun/97 to present
Peruvian Gold Limited Secretary May/95 to present
Planex Ventures Ltd. Director Jan/01 to present
Primo Resources International Inc. Secretary Feb/93 to present
QDM Ventures Ltd. Secretary May/00 to present
Silverarrow Explorations Ltd. Secretary Jan/01 to present
There are no known existing or potential conflicts of interest among the
Company, promoters, directors, officers, principal holders of securities and
persons providing professional services to the Company which could reasonably be
expected to affect an investor's investment decision except as set forth below:
Mr. Donald Busby, the Chairman, President, Chief Executive Officer and a
director of the Company, is also a director and officer of Hilton, which has
acquired an interest in the San Joaquin Joint Venture and the East Lost Hills
Joint Venture and has agreed to purchase units from the Company. See "Item 1.
Description of Business" and "Item 12. Options to Purchase Securities From
Registrant or Subsidiaries." The Company has acquired its interest in the East
Lost Hills Joint Venture and San Joaquin Joint Venture from Hilton. STB, a
wholly-owned subsidiary of Hilton, has earned from the Company a 25% working
interest in certain of the wells in the Big Springs Unit. Mr. Nick DeMare, a
director of the Company, is also a director of Hilton. Mr. Harvey Lim, the
Corporate Secretary of the Company, is also an officer of Hilton. See "Item 1.
Description of Business."
The Company does not have any agreements with its officers or directors,
including any officers or directors with a conflict of interest, with respect to
the amount of time they must spend on the Company's business.
55
PART II
ITEM 14. DESCRIPTION OF SECURITIES TO BE REGISTERED.
- --------------------------------------------------------------------------------
Not applicable.
PART III
ITEM 15. DEFAULTS UPON SENIOR SECURITIES.
- --------------------------------------------------------------------------------
None.
ITEM 16. CHANGES IN SECURITIES AND CHANGES IN SECURITY FOR REGISTERED
SECURITIES.
- --------------------------------------------------------------------------------
Not applicable.
PART IV
ITEM 17. FINANCIAL STATEMENTS.
- --------------------------------------------------------------------------------
See pages beginning with F-1.
ITEM 19. FINANCIAL STATEMENTS AND EXHIBITS.
- --------------------------------------------------------------------------------
FINANCIAL STATEMENTS
DESCRIPTION PAGE
Audited Consolidated Financial Statements for the Years Ended F-1
August 31, 2000, 1999 and 1998
56
EXHIBITS
EXHIBIT
NUMBER DESCRIPTION PAGE
------ ----------- ----
1.1 Roll Over Articles of Golden Chance Resources Inc. and amendments N/A
thereto.(1)<F1>
1.2 Certificate of Continuance and Articles of Continuance for Trimark Resources N/A
Ltd. and amendments thereto.(1)<F1>
1.3 Bylaws of Trimark Resources Ltd.(1)<F1> N/A
3.1 Letter of Intent dated February 25, 1999, between Hilton Petroleum, Inc., STB N/A
Energy Inc. and Berkley Petroleum Corp.(1)<F1>
3.2 Letter of Intent dated February 26, 1999, between Trimark Resources, Inc., N/A
Hilton Petroleum, Inc. and STB Energy, Inc.(1)<F1>
3.3 Letter Agreement dated March 8, 1999, between Trimark Resources, Inc., N/A
Hilton Petroleum, Inc. and STB Energy, Inc.(1)<F1>
3.4 Purchase and Sale Agreement dated June 15, 1999, between Hilton Petroleum, N/A
Inc. and Trimark Resources, Inc.(1)<F1>
3.5 Letter of Intent dated April 12, 1999, between Trimark Oil & Gas Ltd. and N/A
Philip Zaccaria and amendment dated May 14, 1999.(1)<F1>
3.6 Agreement dated April 11, 1997, between E.J. Helsley, Trimark Resources, Inc. N/A
and International Trimark Resources Ltd.(1)<F1>
3.7 Agreement dated September 10, 1997, between Trimark Resources, Inc., N/A
Trimark Oil & Gas Ltd. and Rainbow Oil & Gas, Inc.(1)<F1>
3.8 Agreement dated September 12, 1997, between Trimark Resources, Inc., N/A
Trimark Oil & Gas Ltd. and STB Energy Inc.(1)<F1>
3.9 Agreement dated September 1, 1993, between Trimark Resources Inc. and N/A
DWB Management Ltd.(1)<F1>
3.10 Participation Agreement dated October 8, 1997, between Trimark Resources, N/A
Inc. and Texstar Petroleum, Inc. (2)<F2>
3.11 Mutual Settlement and Release Agreement dated December 15, 1999 (3)<F3> N/A
3.12 Form of Loan Agreement Between Donald W. Busby and Trimark Oil & Gas Ltd. dated 81
November 19, 1999
3.13 Oil and Gas Prospect Exploration and Development Agreement dated February 92
26, 2000
<FN>
<F1>
(1) Previously filed as an exhibit to the Company's Registration Statement on
Form 20-F, filed with the Commission on July 29, 1999. File number 0-30196.
57
<F2>
(2) Previously filed as an exhibit to the Company's Amended Registration
Statement on Form 20-F/A Amendment No. 1, filed with the Commission on October
29, 1999. File number 0-30196.
<F3>
(3) Previously filed as an exhibit to the Company's Amended Registration
Statement on Form 20-F/A Amendment No. 3, filed with the Commission on January
18, 2000. File number 0-30196.
</FN>
58
================================================================================
TRIMARK OIL & GAS LTD.
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED
AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
- --------------------------------------------------------------------------------
F-1 59
[D & H GROUP LETTERHEAD]
AUDITORS' REPORT
To the Shareholders of
Trimark Oil and Gas Ltd.
We have audited the consolidated balance sheets of Trimark Oil and Gas Ltd. as
at August 31, 2000 and 1999 and the consolidated statements of loss and deficit
and cash flow for the years ended August 31, 2000, 1999 and 1998. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at August 31, 2000
and 1999 and the results of its operations and its cash flow for the years ended
August 31, 2000, 1999 and 1998 in accordance with Canadian generally accepted
accounting principles.
Canadian generally accepted accounting principles vary in certain significant
respects from accounting principles generally accepted in the United States.
Application of accounting principles generally accepted in the United States
would have affected assets and shareholders' equity as at August 31, 2000 and
1999 and results of operations for the year ended May 31, 2000, 1999 and 1998 to
the extent summarized in Note 9 to the consolidated financial statements.
As explained in Note 2 to the consolidated financial statements, during the year
ended August 31, 2000 the Company changed its method of accounting for petroleum
interests from the successful efforts method to the full cost method.
/s/ D&H GROUP
Vancouver, B.C.
December 20, 2000 CHARTERED ACCOUNTANTS
(D&H Group was formerly known as Dyke & Howard)
D&H Group
A PARTNERSHIP OF CORPORATIONS
A Member of BHD Association with affiliated offices across Canada and
Internationally
500-1441 Creekside Drive, Vancouver, B.C. V6J 4S7 [] www.dhgroup.ca
[] F (604) 731-9923 [] T (604) 731-5881
F-2 60
TRIMARK OIL & GAS LTD.
CONSOLIDATED BALANCE SHEETS
AS AT AUGUST 31, 2000 AND 1999
(EXPRESSED IN CANADIAN DOLLARS)
2000 1999
$ $
A S S E T S
CURRENT ASSETS
Cash 1,306,708 1,573,481
Amounts receivable 261,634 28,389
---------------- -----------------
1,568,342 1,601,870
PETROLEUM INTERESTS (Note 3) 7,795,380 5,096,125
OTHER ASSETS (Note 4) 772,905 -
---------------- -----------------
10,136,627 6,697,995
================ =================
L I A B I L I T I E S
CURRENT LIABILITIES
Accounts payable and accrued liabilities 306,565 264,115
---------------- -----------------
S H A R E H O L D E R S ' E Q U I T Y
SHARE CAPITAL (Note 5) 17,141,542 12,414,941
SHARE SUBSCRIPTIONS RECEIVED (Notes 12 and 5(a)) 83,000 1,116,570
DEFICIT (7,394,480) (7,097,631)
---------------- -----------------
9,830,062 6,433,880
---------------- -----------------
10,136,627 6,697,995
================ =================
APPROVED BY THE BOARD
/s/ Donald W. Busby , Director
- --------------------------------------------
/s/ Nick DeMare , Director
- --------------------------------------------
F-3 61
TRIMARK OIL & GAS LTD.
CONSOLIDATED STATEMENTS OF LOSS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
2000 1999 1998
$ $ $
(NOTE 1) (NOTE 1)
REVENUES
Oil and gas sales 202,714 135,865 228,983
Interest and other 195,735 7,464 2,727
--------------- ---------------- ---------------
398,449 143,329 231,710
--------------- ---------------- ---------------
EXPENSES
Production 154,529 132,176 106,843
General and administrative 462,429 349,844 217,306
Depreciation, depletion and impairment 78,340 1,703,500 1,983,302
--------------- ---------------- ---------------
695,298 2,185,520 2,307,451
--------------- ---------------- ---------------
NET LOSS FOR THE YEAR (296,849) (2,042,191) (2,075,741)
=============== ================ ===============
LOSS PER COMMON SHARE $(0.02) ($0.40) ($0.84)
=============== ================ ===============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 14,781,362 5,068,204 2,468,043
=============== ================ ===============
F-4 62
TRIMARK OIL & GAS LTD.
CONSOLIDATED STATEMENTS OF DEFICIT
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
2000 1999 1998
$ $ $
DEFICIT - BEGINNING OF YEAR
As originally stated (7,097,631) (5,055,440) (3,091,962)
Change in accounting policy (Note 2) - - 112,263
--------------- ---------------- ---------------
As restated (7,097,631) (5,055,440) (2,979,699)
NET LOSS FOR THE YEAR (296,849) (2,042,191) (2,075,741)
--------------- ---------------- ---------------
DEFICIT - END OF YEAR (7,394,480) (7,097,631) (5,055,440)
=============== ================ ===============
F-5 63
TRIMARK OIL & GAS LTD.
CONSOLIDATED STATEMENTS OF CASH FLOW
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
2000 1999 1998
$ $ $
CASH PROVIDED FROM (USED FOR)
OPERATING ACTIVITIES
Net loss for the year (296,849) (2,042,191) (2,075,741)
Items not involving cash
Depreciation, depletion and impairment 78,340 1,703,500 1,983,302
--------------- --------------- ---------------
(218,509) (338,691) (92,439)
Decrease (increase) in amounts receivable (233,245) 3,337 (17,777)
Increase (decrease) in accounts payable
and accrued liabilities 42,450 (197,772) 290,012
--------------- --------------- ---------------
(409,304) (533,126) 179,796
--------------- --------------- ---------------
FINANCING ACTIVITIES
Issuance of common shares 3,933,801 493,990 153,000
Issuance of special warrants - 4,400,200 984,900
Special warrants issuance costs - (276,404) (86,039)
Share issue costs (323,770) - -
Share subscriptions received 83,000 1,116,570 -
Advances (repayment of) - (65,220) 31,000
--------------- --------------- ---------------
3,693,031 5,669,136 1,082,861
--------------- --------------- ---------------
INVESTING ACTIVITIES
Additions to petroleum interests (2,817,323) (4,625,161) (1,712,635)
Proceeds from sale of petroleum interests 39,728 1,038,380 -
Additions to other assets (772,905) - -
--------------- --------------- ---------------
(3,550,500) (3,586,781) (1,712,635)
--------------- --------------- ---------------
INCREASE (DECREASE) IN CASH
FOR THE YEAR (266,773) 1,549,229 (449,978)
CASH - BEGINNING OF YEAR 1,573,481 24,252 474,230
--------------- --------------- ---------------
CASH - END OF YEAR 1,306,708 1,573,481 24,252
=============== =============== ===============
See Note 11.
F-6 64
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
1. ACCOUNTING POLICIES
FINANCIAL STATEMENT PRESENTATION
These consolidated financial statements have been prepared in
accordance with Canadian generally accepted accounting principles
("Canadian GAAP"). The significant differences between these principles
and those that would be accepted under United States generally accepted
accounting principles ("US GAAP") are disclosed in Note 9.
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 reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ
from those estimates.
BASIS OF CONSOLIDATION
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries, Trimark Resources Inc. and
Safari Petroleum, LLC.
REVENUE RECOGNITION
The Company recognizes oil and gas revenues from its interests in
producing wells as oil and gas is produced and sold from these wells.
The Company has no gas balancing arrangements in place. Oil and gas
sold is not significantly different from the Company's product
entitlement.
PETROLEUM PROPERTIES
CAPITALIZED COSTS
The Company follows the full cost method of accounting for petroleum
and natural gas operations. Under this method all costs related to the
exploration for and development of petroleum and natural gas reserves
are capitalized on a country-by-country basis. Costs include lease
acquisition costs, geological and geophysical expenses, overhead
directly related to exploration and development activities and costs of
drilling both productive and non-productive wells. Proceeds from the
sale of properties are applied against capitalized costs, without any
gain or loss being recognized, unless such a sale would significantly
alter the rate of depletion and depreciation.
F-7 65
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
1. ACCOUNTING POLICIES (continued)
DEPLETION AND DEPRECIATION
Depletion of exploration and development costs and depreciation of
production equipment is provided using the unit-of-production method
based upon estimated proven petroleum and natural gas reserves. The
costs of significant unevaluated properties are excluded from costs
subject to depletion. For depletion and depreciation purposes, relative
volumes of petroleum and natural gas production and reserves are
converted at the energy equivalent conversion rate of six thousand
cubic feet of natural gas to one barrel of crude oil.
CEILING TEST
In applying the full cost method, the Company performs a ceiling test
whereby the carrying value of petroleum and natural gas properties and
production equipment, net of recorded deferred income taxes and the
accumulated provision for site restoration and abandonment costs, is
compared annually to an estimate of future net cash flow from the
production of proven reserves. Net cash flow is estimated using year
end prices, less estimated future general and administrative expenses,
financing costs and income taxes. Should this comparison indicate an
excess carrying value, the excess is charged against earnings.
See also Note 2.
JOINT OPERATIONS
Substantially all of the Company's oil and gas exploration, development
and production activities are conducted jointly with others and,
accordingly, these consolidated financial statements reflect the
Company's proportionate interest in such activities.
FOREIGN CURRENCY TRANSLATION
The Company's foreign subsidiaries comprise a direct and integral
extension of the Company's operations. These subsidiaries are entirely
reliant on the Company to provide financing in order for them to
continue their activities. Consequently, the functional currency of
these subsidiaries is considered by management to be the Canadian
dollar and accordingly, exchange gains and losses are included in
income.
Monetary assets and liabilities are translated into Canadian dollars at
the balance sheet date rate of exchange and non-monetary assets and
liabilities at historical rates. Revenues and expenses are translated
at appropriate transaction date rates except for amortization,
depreciation and depletion, which are translated at historical rates.
Gains and losses on translation are included in income.
F-8 66
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
1. ACCOUNTING POLICIES (continued)
INCOME TAXES
The Company follows the liability method of accounting for income taxes
in accordance with the Canadian Institute of Chartered Accountants new
income tax standard. Under this method, income tax liabilities and
assets are recognized for the estimated tax consequences attributable
to differences between the amounts reported in the consolidated
financial statements and their respective tax bases, using enacted
income tax rates. The effect of a change in income tax rates on future
income tax liabilities and assets is recognized in income in the period
that the change occurs. The adoption of this new standard has not had
any impact on the Company's consolidated financial statements.
SHARE OPTION PLAN
The Company grants share options in accordance with the policies of the
Canadian Venture Exchange (the "CDNX") as described in Note 5(c). No
compensation expense is recognized for this plan when shares or share
options are issued pursuant to the plan. Consideration paid for the
shares on exercise of the share option is credited to share capital.
LOSS PER COMMON SHARE
Loss per common share is calculated using the weighted average number
of shares outstanding during the year. Fully diluted loss per share are
not presented as the exercise of the options and warrants would be
anti-dilutive.
COMPARATIVE FIGURES
Certain of the 1999 and 1998 figures have been reclassified to conform
with the presentation used in 2000.
2. CHANGE IN ACCOUNTING POLICY
During the year ended August 31, 2000, the Company changed its method
of accounting for its petroleum interests from the successful efforts
method to the full cost method, as described in Note 1. Management
believes that the new accounting policy is more appropriate for oil and
gas companies such as the Company.
This change in accounting policy has been applied retroactively. Based
on the Company's petroleum resource activities conducted to date, the
deficit, as at August 31, 1998, was reduced by $112,263 and the loss
for the year ended August 31, 1997 was increased by $112,263. No change
to the reported net loss for the year ended August 31, 1999 was
required as a result of the change in accounting policy.
F-9 67
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
3. PETROLEUM INTERESTS
2000 1999
$ $
Proved properties
Proved acquisitions and leasehold costs 3,102,658 2,578,542
Tangible lease and well costs 58,326 53,984
Exploration costs 692,712 260,008
---------------- -----------------
3,853,696 2,892,534
---------------- -----------------
Unproved properties
Unproved acquisitions and leasehold costs 6,057,733 4,413,046
Exploration costs 1,579,181 1,407,435
---------------- -----------------
7,636,914 5,820,481
---------------- -----------------
11,490,610 8,713,015
Less: accumulated depreciation, depletion and impairment (3,695,230) (3,616,890)
---------------- -----------------
7,795,380 5,096,125
================ =================
Property acquisition costs include costs incurred to purchase, lease,
or otherwise acquire a property. Exploration costs include the costs of
geological and geophysical activity, dry holes and drilling and
equipping exploratory wells. Development costs include costs incurred
to gain access to prepare development well locations for drilling and
to drill and equip development wells.
No write-down was required during the year ended August 31, 2000 from
the ceiling test performed effective August 31, 2000. During the years
ended August 31, 1999 and 1998, the Company wrote-down the carrying
values of its petroleum interests by $1,649,518 and $1,755,234,
respectively, from the ceiling tests performed effective August 31,
1999 and 1998. The ceiling test is a cost-recovery test and is not
intended to result in an estimate of fair market value.
See also Note 7(c).
F-10 68
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
4. OTHER ASSETS
2000 1999
$ $
Convertible note (a) 588,880 -
Loan to officer (b) 184,025 -
-------------- --------------
772,905 -
============== ==============
(a) The Company holds a US$400,000 unsecured convertible note (the
"ALPNET Note") issued by ALPNET, Inc. ("ALPNET"), a public
Utah company trading on the facilities of the National
Association of Securities Dealers. The ALPNET Note has a
variable interest rate of US prime plus 2%, payable on a
quarterly basis. The principal is repayable in three equal
annual instalments commencing June 2, 2003. The Company has
the right to convert all or any portion of the outstanding
principal into common stock of ALPNET, on the basis of US$2.22
per share. ALPNET has the right to pay the full amount, or any
portion, of the ALPNET Note prior to its maturity.
In connection with the ALPNET Note, ALPNET granted the Company
a warrant to purchase up to 90,090 common shares of ALPNET, at
an exercise price of US$3.33 per share, on or before June 2,
2002.
(b) During the year ended August 31, 2000, the Company provided a
US$125,000 relocation loan to the President of the Company.
The loan bears interest at 5% per annum, compounded monthly,
and matures on March 27, 2002. During the year ended August
31, 2000, interest income of $4,018 was recorded and is
included in amounts receivable.
F-11 69
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
5. SHARE CAPITAL
Authorized - unlimited common shares without par value
Issued and outstanding -
2000 1999 1998
------------------------- ------------------------ ------------------------
NUMBER $ NUMBER $ NUMBER $
Balance, beginning of year 11,625,360 12,414,941 3,306,710 5,854,294 1,132,310 3,558,978
----------- ------------ ----------- ----------- ----------- ----------
Issued during the year
Private placement 3,699,279 4,399,261 - - - -
Exercise of options 200,000 228,000 620,300 493,990 100,000 153,000
Exercise of special
warrants - - 6,538,350 5,385,100 774,400 504,316
Exercise of warrants 325,000 286,000 - - - -
Exercise of agents warrants 155,807 137,110 - - - -
Acquisition of petroleum
interest - - 1,160,000 1,044,000 1,300,000 1,638,000
----------- ------------ ------------ ------------ ------------ ----------
4,380,086 5,050,371 8,318,650 6,923,090 2,174,400 2,295,316
Issuance costs - (323,770) - (362,443) - -
----------- ------------- ------------ ------------ ------------ ----------
4,380,086 4,726,601 8,318,650 6,560,647 2,174,400 2,295,316
----------- ------------- ------------ ------------ ------------ ----------
Balance, end of year 16,005,446 17,141,542 11,625,360 12,414,941 3,306,710 5,854,294
=========== ============= ============ ============ ============ ==========
(a) During the year ended August 31, 2000, the Company completed a
number of private placement financings, as follows:
(i) 2,513,564 units, at $1.42 per unit, for proceeds of
$3,245,491 net of finders fees and issue costs of
$323,770. Each unit consisted of one common share and
one share purchase warrant. Two warrants entitles the
holder to purchase an additional common share for a
period of two years, at a price of $1.56 per share on
or before September 24, 2000 and thereafter, at $1.73
per share on or before September 24, 2001. Directors,
officers and a company controlled by the Chairman of
the Company purchased 202,079 units. As of August 31,
2000, the warrants remained unexercised.
As at August 31, 1999, the Company had received
$1,116,570 and had recorded the amounts as share
subscriptions received; and
(ii) 1,185,715 units at $0.70 per unit, for proceeds of
$830,000. Each unit consisted of one common share and
one share purchase warrant. Each warrant entitles the
holder to purchase an additional common share for a
period of two years, at a price of $0.84 per share on
or before June 5, 2002. The Chairman, private
corporations controlled by the Chairman and a
director of the Company purchased all of the units.
As of August 31, 2000, the warrants remained
unexercised.
F-12 70
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
5. SHARE CAPITAL (continued)
(b) During the year ended August 31, 1999, the Company completed a
special warrant financing of 5,500,250 special warrants at a
price of $0.80 per special warrant to raise gross proceeds of
$4,400,200. The special warrants were then exercised, for no
additional consideration, into 5,500,250 common shares and
non-transferable share purchase warrants to purchase an
additional 2,750,125 common shares for a period of two years,
at a price of $0.88 per share on or before July 14, 2000 and
thereafter at a price of $0.97 per share on or before July 14,
2001. Private corporations controlled by the Chairman and a
director of the Company subscribed for 1,580,000 special
warrants.
In connection with this offering, the Company paid the agents
a fee of $180,584 and incurred $95,819 of issue costs. In
addition, the Company granted the agents warrants (the "Agents
Warrants") to purchase 520,916 common shares on the same basis
as the warrants.
During the year ended August 31, 2000, the Company issued
480,807 common shares on the exercise of 325,000 warrants and
155,807 Agents Warrants, for proceeds of $423,110. As at
August 31, 2000, 2,425,125 warrants and 365,109 Agents
Warrants remained outstanding.
(c) The Company grants share options in accordance with the
policies of the CDNX. Under the general guidelines of the CDNX
the Company may reserve up to 10% of its issued and
outstanding shares to its employees, directors or consultants
to purchase shares of the Company. The exercise price of any
option is not less than the greater of: i) closing price on
the CDNX on the last day of trading preceding the grant date
less a specified discount; and ii) $0.10.
Stock options to directors and employees of the Company and
consultants to acquire 837,000 shares were granted and
outstanding as at August 31, 2000. These options are
exercisable on varying dates expiring from fiscal 2000 to
fiscal 2003 at prices ranging from $1.14 to $1.90 per share.
Details of options outstanding are as follows:
2000 1999
NUMBER NUMBER
OF OPTIONS OF OPTIONS
Balance, beginning of year 902,000 208,300
Granted 150,000 1,314,000
Exercised (200,000) (620,300)
Cancelled/expired (15,000) -
------------- -------------
Balance, end of year 837,000 902,000
============= =============
F-13 71
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
5. SHARE CAPITAL (continued)
(d) As at August 31, 2000, 31,250 common shares are held in
escrow, the release of which is subject to the determination
and direction of the regulatory authorities.
(e) See also Note 12.
6. INCOME TAXES
As at August 31, 2000, the Company had accumulated non-capital losses
for Canadian income tax purposes of approximately $961,000 which expire
from 2001 to 2007 and a capital loss of approximately $164,000 which
may be carried forward indefinitely. In addition, the Company's United
States subsidiaries have tax basis net operating losses of
approximately US$2,008,000. The potential income tax benefits of these
losses have not been recognized in the accounts.
7. RELATED PARTY TRANSACTIONS
(a) Certain of the Company's petroleum properties are operated by
a private corporation controlled by the President of the
Company.
(b) During the year ended August 31, 2000, the Company was charged
$120,264 (1999 - $144,232; 1998 - $100,060) for management,
professional, accounting and administrative fees and rent
provided by companies controlled by directors of the Company
and a former president of the Company.
(c) During the year ended August 31, 1999, the Company and Hilton
Petroleum Inc. ("Hilton Inc.") entered into a number of
agreements whereby the Company purchased, from Hilton Inc.,
certain leasehold interests in unproved petroleum properties
for US$3,450,000 and sold, to Hilton Inc., certain leasehold
interests for US$700,000. The net consideration of
US$2,750,000 consisted of US$2,050,000 cash and US$700,000
paid by the issuance of 1,160,000 common shares of the
Company. Hilton Inc. is a wholly-owned subsidiary of Hilton
Petroleum Ltd. ("Hilton"), a public company with common
directors and management.
(d) See also Note 4.
F-14 72
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
8. SEGMENTED INFORMATION
As at August 31, 2000, the Company and its subsidiaries operated in one
industry segment, the exploration for, and the development and
production of crude oil and natural gas. The Company's current
petroleum interests are located in the United States and its corporate
assets are located in Canada. Identifiable assets, revenues and net
loss in each of these geographic areas are as follows:
2000
---------------------------------------------------
IDENTIFIABLE NET
ASSETS REVENUES INCOME (LOSS)
$ $ $
United States 8,223,111 260,952 (54,324)
Canada 1,913,516 137,497 (242,525)
-------------- -------------- ---------------
10,136,627 398,449 (296,849)
============== ============== ===============
1999
---------------------------------------------------
IDENTIFIABLE NET
ASSETS REVENUES INCOME (LOSS)
$ $ $
United States 5,410,650 135,865 (1,645,195)
Canada 1,287,345 7,464 (396,996)
-------------- -------------- ---------------
6,697,995 143,329 (2,042,191)
============== ============== ===============
1998
---------------------------------------------------
IDENTIFIABLE NET
ASSETS REVENUES INCOME (LOSS)
$ $ $
United States 2,207,750 228,983 (2,551,638)
Canada 17,072 2,727 475,897
-------------- -------------- ---------------
2,224,822 231,710 (2,075,741)
============== ============== ===============
F-15 73
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
9. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES
(a) The consolidated financial statements of the Company have been
prepared in accordance to Canadian GAAP which differ in
certain material respects from US GAAP. Material differences
between Canadian and US GAAP and their effect on the Company's
consolidated financial statements are summarized in the tables
below.
Consolidated Statement of Loss
2000 1999 1998
$ $ $
Net loss as reported under Canadian GAAP (296,849) (2,042,191) (2,075,741)
Adjustments for related party
transactions (ii) - 450,084 574,292
Stock-based compensation (iv) (98,126) (735,393) (137,324)
Other compensation expense (vii) (134,742) (31,600) (91,180)
-------------- -------------- --------------
Net loss under US GAAP (529,717) (2,359,100) (1,729,953)
============== ============== ==============
Weighted average number of
common shares outstanding (i) 15,012,218 5,296,479 3,954,706
============== ============== ==============
Loss per share under US GAAP (0.04) (0.45) (0.44)
============== ============== ==============
Consolidated Balance Sheet
2000 1999
$ $
Total assets under Canadian GAAP 10,136,627 6,697,995
Adjustments for related party transactions (ii) (2,744,022) (2,744,022)
Deferred tax asset (v) 1,651,821 1,573,000
Less: Valuation allowance (v) (1,651,821) (1,573,000)
-------------- --------------
Total assets under US GAAP 7,392,605 3,953,973
============== ==============
Total liabilities under Canadian GAAP 306,565 264,115
-------------- --------------
Total liabilities under US GAAP 306,565 264,115
============== ==============
Total shareholders' equity under Canadian GAAP 9,830,062 6,433,880
Adjustments for related party transactions (ii) (2,744,022) (2,744,022)
-------------- --------------
Total shareholders' equity under US GAAP 7,086,040 3,689,858
============== ==============
F-16 74
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
9. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (continued)
(i) Escrowed Shares
Under US GAAP escrowed shares are not included in the
computation of loss per share and the common shares
which underlie the special warrants are included in
the calculation of loss per share.
(ii) Capital Contributions with Respect to Related Party
Transactions
As described in Note 7(c), the Company has acquired
and disposed of certain petroleum interests with
Hilton Inc. for a combination of monetary and non-
monetary consideration.
US GAAP requires that certain transfers of
non-monetary assets to a company by its promoters or
shareholders, in exchange for stock, should generally
be recorded at the transferor's historical cost
basis, whereas under Canadian GAAP, transfers of
non-monetary assets may be recorded based on the fair
value of either the stock issued or the assets
acquired under certain circumstances. Under Canadian
GAAP these transactions were recorded at their fair
values. The transactions have been adjusted to
reflect the transactions based on the historical cost
basis.
The net loss under US GAAP has also been adjusted for
the subsequent amortization and impairment charges of
a portion of these petroleum interest acquisitions
costs.
(iii) Ceiling test on petroleum interests
US GAAP requires that the net book value of proved
petroleum interests not exceed the sum of the present
value of estimated future net revenues (determined
using current prices of petroleum production less
estimated future expenditures to be incurred in
developing and producing the proved reserves,
discounted at ten percent). This ceiling test was
performed effective August 31, 2000 and it was
determined that no write-down of proved petroleum
interests was necessary.
(iv) The Company grants stock options which reserves
common shares for issuance to employees and
directors. Under Canadian GAAP, the issuance of stock
options is not recognized for accounting purposes.
Under US GAAP, the issuance of stock options requires
an assessment to determine stock based compensation.
Accordingly, the Company has applied the provisions
of Financial Account Standards ("SFAS") 123
Accounting for Stock-Based Compensation to calculate
stock-based compensation under US GAAP using the fair
value method.
F-17 75
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
9. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (continued)
The fair value of each option grant is estimated on
the date of grant using the Black-Scholes option
pricing model with the following assumptions used for
grants in 2000, 1999 and 1998:
2000 1999 1998
---------------- ----------------- ----------------
Risk-free interest rate 5.63% - 5.79% 6.25% - 7.5% 4.75% - 6.50%
Expected volatility 87% 89% 112%
Expected lives 2 - 3 years 3 years 2 - 3 years
(v) Income Tax
Under Canadian GAAP, deferred tax assets relating to
the potential benefit of income tax loss
carryforwards are not recognized unless there is
virtual certainty of realization of the benefit. US
GAAP provides similar treatment, but requires the
benefit be recognized and a valuation allowance be
recognized to fully offset the deferred tax asset.
As at August 31, 2000, the Company has fully reserved
the $1,651,821 tax benefit of operating loss
carryforwards, by a valuation allowance of the same
amount, because the likelihood of realization of the
tax benefit cannot be determined. Of the total tax
benefit, $78,821 is attributable to the year ended
August 31, 2000.
(vi) Private Placements of Common Stock and Special
Warrants with Related Parties
US GAAP requires disclosure of private placements
conducted by the Company where directors and officers
of the Company are participants. During the year
ended August 31, 2000, directors, officers and
companies controlled by the directors or officers
acquired 1,387,794 shares or special warrants (1999 -
1,580,000; 1998 - 340,000) of the Company, pursuant
to private placements conducted by the Company, for
cash proceeds of $1,116,952 (1999 - $1,264,000; 1998
- $374,000).
F-18 76
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
9. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES (continued)
(vii) Private Placements of Common Stock
The Company conducts the majority of its equity
financings pursuant to private placements. Under the
policies of the Canadian Venture Exchange, on which
the Company's common stock is listed, the Company may
provide a discount off the market price of the
Company's common stock. US GAAP does not permit a
discount from the market price. US GAAP requires the
recognition of the market value of the Company's
common stock as a credit to share capital, with a
charge to operations for the portion of the discount
relating to equity financings conducted with officers
and directors of the Company and a charge to
shareholders' equity, as a capital distribution, for
the discount relating to the remaining portion of the
equity financings.
Under US GAAP, loss and capital distributions for the
year ended August 31, 2000 would increase by $134,742
(1999 - $31,600; 1998 - $91,180) and $184,919 (1999 -
$37,805; 1998 - $167,736), respectively, and share
capital, as at August 31, 2000 would increase by
$647,982 (1999 - $328,321). There is no net change to
shareholders' equity.
(b) The Company's consolidated statements of cash flow comply with
US GAAP.
(c) New Technical Pronouncements
In June 1998 SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities", as amended by SFAS No.
137 and No. 138, were issued for fiscal years beginning after
June 15, 2000. The impact of the adoption of the new standard
is currently being reviewed by the Company.
In March 2000 FIN No. 44 "Accounting for Certain Transactions
Involving Stock Compensation, An Interpretation of APB Opinion
No. 25" was issued for fiscal years beginning after July 1,
2000. Adoption of FIN No. 44 is not expected to have an impact
on the Company's consolidated financial statements.
F-19 77
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
10. FINANCIAL INSTRUMENTS
The fair values of financial instruments at August 31, 2000 and 1999,
were estimated based on relevant market information and the nature and
terms of financial instruments. Management is not aware of any factors
which would significantly affect the estimated fair market amounts,
however, such amounts have not been comprehensively revalued for
purposes of these financial statements. Disclosure subsequent to the
balance sheet dates and estimates of fair value at dates subsequent to
August 31, 2000 and 1999 may differ significantly from that presented.
Fair value approximates the amounts reflected in the financial
statements for cash, accounts receivable, other assets and accounts
payable and accrued liabilities.
The accounts receivable are from various companies operating in the oil
and gas industry in the United States and are subject to normal
industry credit risks.
11. SUPPLEMENTARY CASH FLOW INFORMATION
Non-cash investing and financing activities were conducted by the
Company as follows:
2000 1999 1998
$ $ $
Investing activities
Acquisition of petroleum interests
with issuance of shares - (1,044,000) (1,638,000)
============== ============== ==============
Financing activities
Issuance of shares for petroleum interests - 1,044,000 1,638,000
Issuance of shares for special warrants exercised - 5,385,100 504,316
Special warrants exercised - (5,385,100) (504,316)
-------------- -------------- --------------
- 1,044,000 1,638,000
============== ============== ==============
Other supplementary cash flow information:
2000 1999 1998
$ $ $
Interest paid in cash 12,649 - -
============ ============= ==============
Income taxes paid in cash - - -
============ ============= ==============
F-20 78
TRIMARK OIL & GAS LTD.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED AUGUST 31, 2000, 1999 AND 1998
(EXPRESSED IN CANADIAN DOLLARS)
12. SUBSEQUENT EVENTS
Subsequent to August 31, 2000, the Company:
i) completed a private placement financing of 118,570 units at
$0.70 per unit. Each unit consists of one common share and one
share purchase warrant. Each share purchase warrant entitles
the holder to purchase one common share at $0.84 per share on
or before June 19, 2002. As at August 31, 2000, the Company
had received $83,000 and recorded as share subscriptions
received; and
ii) agreed to conduct a private placement financing of 2,200,000
units at $0.52 per unit. Each unit will consist of one common
share and one share purchase warrant. Each share purchase
warrant will entitle the holder to purchase one common share
at a price of $0.52 per share for a period of two years. The
proposed purchasers of the private placement are a company
owned by the President of the Company and Hilton.
F-21 79
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act of
1934, the registrant certifies that it meets all of the requirements for filing
on Form 20-F and has duly caused this annual report to be signed on its behalf
by the undersigned, thereunto duty authorized.
TRIMARK OIL & GAS LTD.
/s/ Nick DeMare
Dated: FEBRUARY 28, 2001 ----------------------------------------
Nick DeMare, Director
80