U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 40-F
[_] REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE
SECURITIES EXCHANGE ACT OF 1934
[X] ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002.
WESTERN OIL SANDS INC.
(Exact name of Registrant as specified in its charter)
Province of Alberta, Canada 1311 Not applicable.
(PROVINCE OR OTHER JURISDICTION OF (PRIMARY STANDARD INDUSTRIAL (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) CLASSIFICATION CODE NUMBER) IDENTIFICATION NO.)
2400 ERNST & YOUNG TOWER
440 - 2ND AVENUE S.W.
CALGARY, ALBERTA, CANADA T2P 5E9
(403) 233-1700
(ADDRESS AND TELEPHONE NUMBER OF REGISTRANT'S PRINCIPAL EXECUTIVE OFFICES)
CT CORPORATION SYSTEM
111 EIGHTH AVENUE, NEW YORK, NEW YORK 10011
(212) 894-8400
(NAME, ADDRESS (INCLUDING ZIP CODE) AND
TELEPHONE NUMBER (INCLUDING AREA CODE) OF AGENT FOR
SERVICE IN THE UNITED STATES)
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:
None
Securities for which there is a reporting obligation pursuant
to Section 15(d) of the Act:
8 3/8% Senior Secured Notes due 2012
For annual reports, indicate by check mark the information
filed with this Form:
[X] Annual information form [X] Audited annual financial statements
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:
The Registrant had 47,742,471 Common Shares outstanding at December 31, 2002
Indicate by check mark whether the Registrant by filing the information
contained in this Form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934
(the "Exchange Act"). If "Yes" is marked, indicate the filing number assigned to
the Registrant in connection with such Rule.
Yes [_] No [X]
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Exchange Act 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 [_]
TABLE OF CONTENTS
DOCUMENT
1. Annual Information Form of the Registrant for the
fiscal year ended December 31, 2002.
2. Management's Discussion and Analysis of the
Registrant for the year ended December 31, 2002.
3. Consolidated Financial Statements of the Registrant
for the year ended December 31, 2002, including a
reconciliation to United States generally accepted
accounting principles.
4. Exhibits
CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS AND
MANAGEMENT'S DISCUSSION AND ANALYSIS
A. AUDITED ANNUAL FINANCIAL STATEMENTS
For consolidated audited financial statements, including the report of
independent chartered accountants with respect thereto, see pages 49 through 69
of the Registrant's 2002 Annual Report attached hereto and included herein. For
a reconciliation of important differences between Canadian and United States
generally accepted accounting principles, see Note 16 of the Notes to the
Consolidated Financial Statements on pages 65 through 69 of such 2002 Annual
Report.
B. MANAGEMENT'S DISCUSSION AND ANALYSIS
For management's discussion and analysis, see pages 31 through 48 of
the Registrant's 2002 Annual Report attached hereto and included herein.
For the purposes of this Annual Report on Form 40-F, only pages 31
through 69 of the Registrant's 2002 Annual Report referred to above shall be
deemed filed, and the balance of such 2002 Annual Report, except as it may be
otherwise specifically incorporated by reference in the Registrant's Annual
Information Form, shall be deemed not filed with the Securities and Exchange
Commission as part of this Annual Report on Form 40-F under the Exchange Act.
CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES. As of a date
within the 90-day period prior to the filing of this report, an evaluation of
the effectiveness of the Registrant's "disclosure controls and procedures" (as
such term is defined in Rules 13a-14(c) and 15d-14(c) of the United States
Securities Exchange Act of 1934 (the "Exchange Act")) was carried out by the
Registrant's Chief Executive Officer ("CEO") and Chief Financial Officer
("CFO"). Based on that evaluation, the CEO and CFO have concluded that as of
such date the Registrant's disclosure controls and procedures are effective to
ensure that information required to be disclosed by the Registrant in reports
that it files or submits under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in United States
Securities and Exchange Commission rules and forms.
(b) CHANGES IN INTERNAL CONTROLS. Subsequent to the completion of their
evaluation, there have been no significant changes in the Registrant's internal
controls or in other factors that could significantly affect the internal
controls, including any corrective actions with regard to significant
deficiencies and material weaknesses.
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. UNDERTAKING
The Registrant undertakes to make available, in person or by telephone,
representatives to respond to inquiries made by the Commission staff, and to
furnish promptly, when required to do so by the Commission staff, information
relating to: the securities registered pursuant to Form 40-F; the securities in
relation to which the obligation to file an annual report on Form 40-F arises;
or transactions in said securities.
B. CONSENT TO SERVICE OF PROCESS
A Form F-X signed by the Registrant and its agent for service of
process was filed with the Commission together with the Registrant's
Registration Statement on Form F-10, No. 333-90736.
SIGNATURE
Pursuant to the requirements of the Exchange Act, the Registrant
certifies that it meets all of the requirements for filing on Form 40-F and has
duly caused this annual report to be signed on its behalf by the undersigned,
thereto duly authorized.
WESTERN OIL SANDS INC.
May 9, 2003
By: /s/ David A. Dyck
---------------------------------
Name: David A. Dyck
Title: Vice President, Finance
and Chief Financial Officer
CERTIFICATIONS
I, Guy J. Turcotte, certify that:
1. I have reviewed this annual report on Form 40-F of Western Oil Sands Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 9, 2003
/s/ Guy J. Turcotte
- --------------------------------
Guy J. Turcotte
President and Chief Executive Officer
I, David A. Dyck, certify that:
1. I have reviewed this annual report on Form 40-F of Western Oil Sands Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 9, 2003
/s/ David A. Dyck
- ---------------------------------
David A. Dyck
Vice President, Finance and
Chief Financial Officer
EXHIBIT INDEX
EXHIBIT NO. DOCUMENT
- ----------- --------
99.1 Consent of PricewaterhouseCoopers LLP, independent
accountants.
99.2 Consent of Gilbert Laustsen Jung Associates Ltd., independent
engineers.
99.3 Consent of Norwest Corporation, independent mining
consultants.
99.4 Certificate of Principal Executive Officer Pursuant to 18
U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.5 Certificate of Principal Financial Officer Pursuant to 18
U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
DOCUMENT 1
----------
[GRAPHIC OMITTED]
[LOGO - Western Oil Sands]
ANNUAL INFORMATION FORM
May 9, 2003
TABLE OF CONTENTS
PAGE
CORPORATE STRUCTURE............................................................1
GENERAL DEVELOPMENT OF THE BUSINESS............................................1
NARRATIVE DESCRIPTION OF THE BUSINESS..........................................4
Project Overview......................................................4
Resource Base.........................................................5
Project Construction..................................................6
Mining and Extraction.................................................6
Upgrader..............................................................6
Third Party Facilities................................................6
Marketing and Sales...................................................7
Tailings Disposal and Reclamation.....................................7
Regulatory Approvals..................................................7
Insurance.............................................................7
Proposed Expansions and Pre-Feasibility Study Agreement...............8
Reserves..............................................................9
Land Tenure..........................................................11
Royalties............................................................11
Environmental Considerations.........................................11
Future Commitments...................................................13
Joint Venture Agreement..............................................13
SELECTED CONSOLIDATED FINANCIAL INFORMATION...................................17
DIVIDEND POLICY...............................................................17
MANAGEMENT DISCUSSION AND ANALYSIS............................................17
MARKET FOR SECURITIES.........................................................18
DIRECTORS AND OFFICERS........................................................18
RISKS AND UNCERTAINTIES.......................................................20
ADDITIONAL INFORMATION........................................................30
GLOSSARY .....................................................................31
-i-
WESTERN OIL SANDS INC.
ANNUAL INFORMATION FORM
CORPORATE STRUCTURE
Western Oil Sands Inc. ("Western" or the "Corporation") is incorporated under
the BUSINESS CORPORATIONS ACT (Alberta) on June 18, 1999. The Corporation
amended its articles on July 27, 1999, October 6, 1999, November 30, 1999,
December 22, 1999, December 8, 2000, March 14, 2001 and May 21, 2002 to change
its name to Western Oil Sands Inc., remove its private company restrictions, to
amend its share capital to create a class of Non-voting Convertible Equity
Shares, to designate a series of Class D Preferred Shares and to fix the rights,
privileges, restrictions and conditions attaching to such series and to increase
the maximum number of directors permitted.
Western has three wholly-owned subsidiaries; 852006 Alberta Ltd. (which together
with Western holds a 20% undivided interest in the Project), Western Oil Sands
Finance Inc. and Western Oil Sands USA Inc., as shown below:
[GRAPHIC OMITTED]
[ORGANIZATIONAL CHART]
-----------------
Western --------------\
/ (Alberta) \
/ ----------------- \ \
100% / | \ \
/ | \ \
/ | \ \
- --------------------- General | ----------------- -----------------
852006 Alberta Ltd. Partner | Western Oil Sands Western Oil Sands
(Alberta) | Finance Inc. USA Inc.
- --------------------- 1% Limited | (Alberta) (Delaware)
\ Partnership | ----------------- (inactive)
\ Units | -----------------
99% Limited \ |
Partnership Units \ -----------------------
\ Western Oil Sands L.P.
(Alberta)
-----------------------
|
|
20%
|
|
--^--
Project
---------
References in this Annual Information Form to Western or the Corporation
includes its wholly-owned subsidiaries, 852006 Alberta Ltd., Western Oil Sands
Finance Inc., Western Oil Sands USA Inc. and Western Oil Sands L.P., unless the
context otherwise requires. INITIALLY CAPITALIZED TERMS USED HEREIN AND NOT
OTHERWISE DEFINED HAVE THE MEANINGS ASCRIBED THERETO IN THE GLOSSARY.
GENERAL DEVELOPMENT OF THE BUSINESS
Western was formed to participate in a joint venture project to design,
construct and operate the principal facilities necessary to mine, extract and
upgrade the recoverable bitumen reserves found in certain oil sands deposits
located on the western portion of Lease 13 and to pursue other oil sands
opportunities. The Project is being undertaken by Shell, as to an undivided 60%
ownership interest, ChevronTexaco, as to an undivided 20% ownership interest,
and Western, pursuant to the Joint Venture formed for such purpose.
-2-
During 1999 the Corporation completed a series of private placements for
aggregate gross proceeds of approximately $123 million at prices ranging from
$2.50 per share to $8.50 per share. The Corporation also entered into a $535
million Senior Credit Facility with certain Canadian lending institutions to
assist in funding the expected capital expenditures of the Project.
On September 28, 2000, through a rights offering to the holders of existing
equity securities and a private placement, the Corporation issued 10,709,076
Non-voting Convertible Equity Shares for aggregate consideration of $130
million. Of these shares, 9,217,992 were issued at $12.00 per share, while
1,491,084 were issued on a flow-through basis at $13.00 per share.
On December 21, 2000, the Corporation completed its initial public offering of
4,000,000 Common Shares at a price of $15.00 per share, for gross proceeds of
$60 million. Concurrently therewith, the Common Shares were listed on the
Toronto Stock Exchange under the symbol "WTO".
On February 1, 2001, the Corporation filed two prospectuses qualifying the
issuance of an aggregate of 34,033,029 Common Shares, 494,224 Class A Warrants
and 465,188 Class B Warrants issuable upon the conversion or exercise, as the
case may be, of all the Non-voting Convertible Equity Shares, Class A Special
Warrants, Class B Special Warrants and Warrant Options previously issued by the
Corporation. Subsequently, in February and March 2001, the 465,188 Class B
Warrants were exercised into Common Shares for aggregate gross proceeds of $3.7
million.
On March 14, 2001, the Corporation completed a private placement for the
issuance of Class D Preferred Shares, Series A at a price of $18.00 per share
for gross proceeds of $12 million. Each Class D Preferred Share is convertible
into one Common Share prior to redemption, which is at the option of the
Corporation at any time, at a price equal to their issue price plus a cumulative
dividend of 12% per year compounded semi-annually until January 1, 2007,
increasing by 3% per quarter thereafter to a maximum of 24% per year. The
Corporation also entered into a $90 million bridge facility with a Canadian
chartered bank. The $90 million bridge facility was secured by an undertaking by
Western to raise funds from other sources including future bond offerings and/or
equity offerings. This facility was subsequently repaid and cancelled on October
25, 2001.
On April 27, 2001, the Corporation completed a private placement of 625,000
Common Shares at $16.00 per share issued on a flow-through basis, for gross
proceeds of $10 million.
In June 2001, the Corporation entered into an additional $30 million bridge
facility with a Canadian chartered bank, that was also secured by an undertaking
by Western to raise funds from other sources including future bond offerings
and/or equity offerings and was subsequently repaid and cancelled on October 25,
2001. Also in June 2001, the Corporation commenced drawdowns under the Senior
Credit Facility to meet its ongoing commitments to the construction of the
Project.
In July 2001, the Corporation completed a further private placement to certain
of its existing shareholders of 3,404,729 Non-voting Convertible Equity Shares
at $13.00 and $14.00 per share, together with 725,589 Non-voting Convertible
Equity Shares issued on a flow-through basis at $15.60 per share, for aggregate
gross proceeds of $57.9 million. At this time, certain shareholders also
undertook to subscribe for 725,590 Non-voting Convertible Equity Shares on a
flow-through basis at $15.60 per share, which were subsequently subscribed for
and issued in November 2001, for gross proceeds of $11.3 million. In conjunction
with these offerings 2,589,641 Call Obligations were issued to certain
subscribers, whereby each Call Obligation was exercisable into one Non-voting
Convertible Equity Share and one Warrant to purchase a Non-voting Convertible
Equity Share upon the payment of $13.00 per Call Obligation. These Call
Obligations expired March 31, 2003.
-3-
On October 25, 2001, the Corporation completed a rights offering to existing
shareholders, of 3,384,835 Common Shares at a price of $14.00 per share for
gross proceeds of $47.4 million. On October 25, 2001, Western established a new
$88 million two-year bridge note purchase facility ("Bridge Facility") with a
Canadian chartered bank. The notes (the "Convertible Notes") issuable pursuant
to draws under the Bridge Facility are convertible, at maturity at Western's
option and in the event of a default at the option of the bank, into Common
Shares at 95% of the then current market price.
In November 2001, the Corporation completed a private placement of 150,000
Non-voting Convertible Equity Shares issued on a flow-through basis at $17.30
per share for gross proceeds of $2.6 million. On November 27, 2001, the
Corporation filed a prospectus which qualified for issuance an aggregate of
5,005,908 Common Shares issuable upon conversion of all the Non-voting
Convertible Equity Shares issued in July and November 2001.
On April 23, 2002, the Corporation completed a private placement offering of
US$450 million senior secured Notes. The Notes bear interest at 8.375% per
annum, payable on May 1 and November 1 of each year, beginning on November 1,
2002 and mature on May 1, 2012. Of the net proceeds from this offering, $508
million was used to repay the Senior Credit Facility and all amounts owed to
Shell. The Senior Credit Facility was cancelled in conjunction with its
repayment.
Concurrent with the completion of the offering of Notes, the Corporation entered
into a senior credit facility with a syndicate of banks in the aggregate amount
of $100 million comprised of a revolving $75 million debt service/completion
facility to be used primarily to finance interest payable on the Notes with the
surplus to be available to fund Project construction costs and a revolving $25
million letter of credit facility to backstop certain overdraft arrangements
under the Joint Venture Agreement and the Corporation's land reclamation
requirements.
On August 16, 2002 Western made a claim for cost overruns in the amount of $430
million and on November 19, 2002 Western made an initial claim for start-up
delay coverage under its Project delay/cost overrun insurance policies. Further
claims for start-up delays have been and will be made pursuant to the terms of
the policy as required.
On November 19, 2002, the Corporation entered into a $50 million credit facility
(the "Working Capital Facility") with a syndicate of Canadian chartered banks to
fund the Corporation's working capital requirements. The Working Capital
Facility was amended on January 30, 2003 to increase the maximum amount of such
facility to $75 million and to add an additional Canadian chartered bank to the
syndicate of lenders.
The Project achieved a major milestone on December 29, 2002 with first bitumen
production at the Mine. Deliveries of diluted bitumen into the Corridor pipeline
system for delivery to the Upgrader located at Scotford, Alberta commenced
before the end of 2002. At the Upgrader, the primary distillation units were
successfully tested during the fourth quarter of 2002 and commissioning and
testing of the synthetic crude units was well underway at the end of 2002.
As at December 31, 2002, there were 47,742,471 Common Shares, 666,667 Class D
Preferred Shares Series A, 494,224 Class A Warrants and 1,329,000 stock options
issued and outstanding.
On February 7, 2003 the Corporation completed a public offering of 2,050,000
Common Shares at $24.50 per share for gross proceeds of $50.225 million.
The proceeds of each of the private placements, the initial public offering, the
rights offering, the subsequent public offering, the Bridge Facility, the Senior
Credit Facility (prior to repayment), the
-4-
offering of the Notes, the new senior credit facility and the Working Capital
Facility were used by the Corporation to fund the Corporation's 20% share of
capital costs of the Project and related expenses. Western's share of Project
construction costs to December 31, 2002 amounts to $1,080.8 million. The
original AFE obligated the Corporation to expend $709.4 million from 1999 to
2003. During the course of construction, additional costs were identified to
complete the Project and Western's share of the expected total capital costs for
the completed Project (excluding costs of repair due to the fire described
below) is $1.125 billion.
A fire occurred in the froth treatment area at the Mine, caused by a hydrocarbon
leak arising from the failure of a piping connection, on January 6, 2003. The
fire did not cause significant damage to major process equipment or piping
systems. Damage was mainly limited to electrical cables, instrumentation and
insulation in the solvent recovery area of the froth treatment plant and
subsequent damage to pipes as a result of freezing. Repairs to Train 1 of the
froth treatment plant were completed by the end of March 2003 and the production
of bitumen resumed in April 2003. Repairs to Train 2 of the froth treatment
plant at the Mine are almost complete and these facilities are expected to be
available for use in May 2003. The costs of repairs for the fire and freeze
damage have increased to an estimate of $150 million ($30 million net to
Western). Western has extensive insurance coverage in place and is seeking to
recover these costs from insurers. The first interim submission totaling $45
million ($9 million for Western's share) has been presented to insurers for
payment, with further submissions to follow. The insurance policies for the
Project cover property damage of up to $500 million per incident at the Project
level ($100 million for Western's share). In addition, subject to a 30-day
waiting period, potential start-up delay coverage is in place at the Project
level for up to $500 million per incident ($100 million net to Western).
NARRATIVE DESCRIPTION OF THE BUSINESS
Western holds a 20% undivided ownership interest in the Project. The Project is
a joint venture to design, construct and operate the principal facilities
necessary to mine, extract and upgrade the recoverable bitumen reserves
underlying certain oil sands deposits located on the western portion of Lease
13. Lease 13 is located in northern Alberta approximately 70 km north of Fort
McMurray, Alberta, abutting the Athabasca River and the integrated Upgrader is
situated near Shell's existing refinery near Fort Saskatchewan, Alberta. Western
is entitled to participate in the future development of Lease 13 and to
participate in other oil sands opportunities with Shell and ChevronTexaco in
respect of Shell's Other Athabasca Leases, and also within a defined area of
mutual interest. As at December 31, 2002, Western had 27 employees, of which 12
were seconded to Albian in connection with the Project.
PROJECT OVERVIEW
The Project is designed to produce high quality bitumen by surface mining
certain Athabasca oil sands deposits and upgrading the extracted bitumen into
custom blended petroleum products for eventual sale to conventional refineries
where it will be used to produce petroleum products. Approximately 275,000
tonnes per day of ore, in addition to approximately 155,000 tonnes per day of
overburden, low grade (waste) oil sand and extraction plant rejects will
initially be mined from the Mine. It is expected that 155,000 bbls per day of
bitumen will be extracted from this ore in the Extraction Plant and with the
addition of non-bitumen feedstocks approximately 190,000 bbls per day of
refinery feedstocks and synthetic crude oil blends will be produced by the
Upgrader.
The Project is an integrated oil sands development pursuant to which:
o Oil sands deposits will be mined using open pit techniques at the Mine
located on the western portion of Lease 13, which will be a truck and
shovel mine operation.
-5-
o Raw bitumen will be extracted from the oil sands through processes
powered by electrical and thermal energy at the Extraction Plant that
is located on the western portion of Lease 13. The extraction process
consists of primary extraction and froth treatment stages.
o Once extracted, the raw bitumen feedstock will be transported from the
Mine through a dual pipeline system to the Scotford Upgrader located
near Fort Saskatchewan, Alberta where it will be upgraded into refinery
feedstocks.
o Upgrading is the final stage of the production process. The bitumen
feedstock is distilled to recover diluent, then undergoes a
hydro-conversion process with integrated hydro-treating to generate
suitable product streams.
o After the bitumen has been upgraded, it will be sold as refinery
feedstock to North American refineries and to the Scotford Refinery,
which is adjacent to the Scotford Upgrader, for further processing. A
dual pipeline system connects the Scotford Upgrader to certain third
party pipelines in Edmonton, Alberta.
RESOURCE BASE
Lease 13 lies within the mineable oil sands area of the Athabasca deposits. The
49,872 acres of Lease 13 are estimated by Western to contain 4.9 billion bbls of
in-place mineable bitumen resources at an average grade of 11.6% bitumen and a
strip ratio of less than 1.5:1. NorWest has verified these estimates in the
NorWest Report.
The Mine covers a 121 square kilometre portion of the western portion of Lease
13. According to GLJ, the western portion of Lease 13 contains approximately 1.1
billion bbls of proven and 0.6 billion bbls of probable reserves and is
sufficient for approximately 30 years of non-declining bitumen production at
155,000 bbls/d. This has been verified by Norwest in the NorWest Report based on
consideration of the geology of the mine plan area, integrity of the exploration
data base, the model used to represent the geology of the mine plan area and the
model used to estimate ore characteristics. NorWest also considered specific
geology-related risks.
The current 30-year mine reserve is one of the five potentially mineable ore
deposits that have been identified on Lease 13 and Shell's Other Athabasca
Leases. Western is entitled to participate in future expansions on Lease 13 and
to participate in the other oil sands opportunities with Shell and ChevronTexaco
in respect of Shell's Other Athabasca Leases, and within a defined area of
mutual interest. The following table outlines the Joint Venture's proved and
probable reserves on the western portion of Lease 13, as estimated by GLJ, and
the resources available for future expansion opportunities on the remainder of
Lease 13 and Leases 88 and 89, as verified by NorWest:
WESTERN'S
TOTAL SHARE
(MMbbls) (MMbbls)
-------- --------
JOINT VENTURE
Reserves on western portion of Lease 13................ 1,681 336
===== ===
FUTURE OPPORTUNITIES
Resources on remainder of Lease 13..................... 3,200 640
Resources on Leases 88 and 89.......................... 3,900 780
----- ---
7,100 1,420
===== =====
-6-
PROJECT CONSTRUCTION
Construction was completed at the Mine and at the Scotford Upgrader in December
2002 and both facilities are now in the start-up process. At the end of 2002,
operations management assumed responsibility for all facilities and activities
at both sites and initiated start-up operations.
The Project achieved a major milestone on December 29, 2002 with first bitumen
production at the Mine. Initial indications were that bitumen recovery and
quality were achieving design targets and meeting required upgrading
specifications. Deliveries of diluted bitumen into the pipeline system for
delivery to the Scotford Upgrader commenced before the end of 2002. At the
Scotford Upgrader, the primary distillation units were successfully tested
during the fourth quarter of 2002 and commissioning and testing of the synthetic
crude units was well underway at the end of 2002.
In late March 2003, the Upgrader successfully started producing light synthetic
crude, utilizing purchased feedstocks. On April 19, 2003 the Project achieved
fully integrated operations when the Scotford Upgrader began processing bitumen
from the Mine to manufacture synthetic crude oil products. Western expects to
reach full-scale production at the Mine of 155,000 bbls per day of bitumen
(31,000 bbls per day for Western's share) which together with purchased
feedstocks, will result in synthetic crude oil production of approximately
190,000 bbls per day (38,000 bbls per day net to Western) at the Upgrader by the
end of the third quarter of 2003.
MINING AND EXTRACTION
Albian was formed for the sole purpose of constructing and operating the Mine
and the Extraction Plant and is owned by the Owners in proportion to their
respective ownership interests in the Project. Albian manages and has
responsibility for the construction and operation of the Mine and the Extraction
Plant. Western provides certain management services including the full and part
time services of certain of its employees to Albian.
UPGRADER
The HMU was constructed to provide hydrogen to the Upgrader. The owner of the
HMU is Scotford HMU Leasing Inc., a special purpose corporation owned by the
Owners and Shell Canada Products Limited. The Owners' interests are held in
proportion to their ownership in the Project. Shell managed construction of the
HMU. The cost of the HMU was financed through a secured bank loan in the
principal amount of up to $290 million made available by a syndicate of banks.
Dow will supply additional hydrogen to the Upgrader pursuant to a long-term
contract.
THIRD PARTY FACILITIES
The Owners have entered into various contracts with certain third parties to
construct, own and operate certain additional facilities required by the
Project. Terasen Pipelines (Corridor) Inc. ("Terasen"), a subsidiary of BC Gas
Inc., constructed and owns the dual pipeline systems that connect the Mine to
the Scotford Upgrader and the Scotford Upgrader to certain third party
pipelines. Terasen operates this system directly. The Owners are severally
responsible for the costs of transportation on the pipeline systems, which is on
a take or pay basis.
ATCO built, owns and operates the cogeneration facility located on Lease 13
which provides power and steam for the Mine and Extraction Plant. ATCO also owns
and operates the cogeneration facility constructed to provide electrical power
to the Upgrader. The Owners are obligated to purchase power from ATCO under
long-term contracts. ATCO has the ability to sell any excess power generated by
the cogeneration facilities to the commercial power market.
-7-
MARKETING AND SALES
Shell Canada Products Limited will take delivery of vacuum gas oil at the
Scotford Refinery, representing approximately one-third of the total Upgrader
production, pursuant to a long-term sales arrangement. Western expects to sell
approximately 12,000 bbls per day of vacuum gas oil to Shell Canada Products
Limited under this arrangement representing its 20% share of such total sales.
The remaining production from the Upgrader and any third party feedstocks will
initially form the basis of two streams of synthetic crude oil (one heavy and
one light), and later a single stream blend, totaling approximately 130,000 bbls
per day (26,000 bbls per day to Western). This production will be taken in kind
and marketed by each Owner to numerous refineries throughout North America. The
Scotford Upgrader is located at the hub of the western Canadian refining
industry near Edmonton, Alberta, providing the Owners with access to a number of
pipeline systems, to which the Corridor pipeline system is connected. Provisions
for pipeline deliveries are being established through Trans Mountain Pipe Line
Company Ltd. and Enbridge Inc.
TAILINGS DISPOSAL AND RECLAMATION
During the first five to seven years of operation, all of the tailings from the
extraction process will be transported to an external tailings settling pond by
pipeline to enable the solids to settle from the water. Subsequent to this five
to seven year period, fresh coarse dewatered tailings produced in the Extraction
Plant will be processed and deposited in dyked-off areas in the mine pit.
An objective of the tailings management plan will be to minimize the size of the
tailings settling pond. The Owners expect to accomplish this by arranging the
mine plan to provide available storage for the consolidated tailings in the mine
pit as soon as possible and subsequently by increasing the production of
consolidated tailings, as space in the mine pit becomes available. The major
benefit of this consolidated tailings method will be to enable the mined area to
be reclaimed as a solid landform as the tailings deposits progressively
consolidate towards a geotechnically stable mine backfill. This is designed to
minimize land disturbance and the subsequent impact on the environment.
At the end of the mine life, all remaining surface disposal sites will be
reclaimed. The remaining void from the last few years of mining will be used to
dispose of any fine tailings and water from the tailings settling pond, and will
be capped with fresh water to form a lake. Appropriate drainage systems will be
incorporated into the final landform to provide a self-sustaining ecosystem.
REGULATORY APPROVALS
The Project has obtained all of the material regulatory approvals and permits
that it requires for completion and operation of the Project.
INSURANCE
The Owners have obtained insurance to protect against certain risks of loss
during the construction of the Mine, Extraction Plant and the Upgrader. The
insurance is typical for a project of the nature of the Project.
In addition, Western has obtained, for its own account, a $200 million insurance
policy which, throughout the period March 2000 through April 2004, covers
certain costs, expenses and losses of revenue including: (i) costs and expenses
or loss of revenues arising from a delay in achieving the guaranteed production
levels as set out in the feasibility study; (ii) costs and expenses incurred in
connection with the modification, repair or replacement of equipment or
material, which are directly related to achieving the guaranteed production
levels; (iii) escalation in Project costs beyond the budgeted Project costs,
which are
-8-
directly related to achieving the guaranteed production levels; and (iv) debt
service costs related to obligations incurred to finance any of (i), (ii) or
(iii). The establishment and maintenance of this policy was a requirement of the
Senior Credit Facility.
During the period from June 24, 2002 through to April 17, 2003, Western has
filed interim claims for cost overruns in the amount of $430 million and for
start-up delay coverage in the amount of $100 million.
Western is in discussions with its insurers regarding its claims and is
attempting to resolve disagreements with them as to coverage under the policies.
Western remains confident in the extent of coverage available under the
insurance policies; however, Western cannot at this time estimate when any
payments under the policies may be forthcoming. Notwithstanding the amount of
Western's claims, the policy limit of these insurance policies is $200 million.
In connection with operations, Western intends to obtain insurance designed to
protect its ownership interest against losses or damage to the Mine, Extraction
Plant and Upgrader once commercial operations begin, to preserve its operating
income and to protect against its risk of loss to third parties and which is
reasonably obtainable.
PROPOSED EXPANSIONS AND PRE-FEASIBILITY STUDY AGREEMENT
The Owners announced in August 2001 that they intend to evaluate potential
long-term development opportunities relating to the resources contained within
Lease 13 and on Shell's Other Athabasca Leases. These opportunities include:
o optimization and expansion of the western portion of Lease 13
and Lease 90, which is one of Shell's Other Athabasca Leases,
to increase total bitumen production from the current design
of 155,000 bbls/d to 225,000 bbls/d. Based on satisfactory
results of a feasibility study, this development would likely
occur in the 2006 to 2007 time frame;
o development of a new mine and extraction facility, known as
the Jackpine Mine, Phase One, to be located on the eastern
portion of Lease 13 with a capacity of 200,000 bbls/d of
bitumen production. This development would follow expansion of
the western portion of Lease 13; and
o development of additional resources located on Leases 88 and
89, known as the Jackpine Mine, Phase Two, with a capacity of
approximately 100,000 bbls/d of bitumen production. This
development would follow the development of Jackpine Mine,
Phase One.
In conjunction with these developments, Western, Shell and ChevronTexaco have
entered into a pre-feasibility study agreement in respect of the development of
the Jackpine Mine, Phase One. The objective of the agreement is to obtain
primary regulatory approvals, licenses, permits and authorizations for the
construction of the Jackpine Mine, Phase One mine and extraction plant and may
also in certain circumstances incorporate the resources for Leases 88, 89 and/or
Lease 90. The interests of the parties to this agreement will be the same as in
the Joint Venture Agreement; however, the terms of the Joint Venture Agreement
will not govern this undertaking. The budgeted cost of these activities to the
Owners is approximately $18.7 million, of which Western's share is approximately
$3.7 million. This agreement is not an amendment to the Joint Venture Agreement
and is not considered a feasibility study or an expansion pursuant to the Joint
Venture Agreement, nor will it trigger any rights for notices for proposed
expansions under the Joint Venture Agreement. This agreement does not add to nor
detract from any of Western's rights under the Joint Venture Agreement. The
overall management has been delegated to the Executive Committee of the Joint
Venture, which will specifically delegate certain matters to the project
-9-
administrator. Western may withdraw from the agreement at any time, however,
Western may be reinstated by paying twice the costs it would have otherwise been
required to pay to preserve its rights to participate in a feasibility study and
expansion pursuant to the Joint Venture Agreement.
RESERVES
GLJ prepared the GLJ Report which evaluated the reserves attributable to Western
as of January 1, 2003. The tables below summarize the oil reserves and the
present value of the estimated future net cash flow attributable to Western's
ownership as evaluated in the GLJ Report. All evaluations of future net cash
flow are stated prior to any provisions for income tax, reclamation costs,
Project financing, general and corporate overhead, hedging activities and patent
fees. THE FUTURE NET CASH FLOWS ARE ESTIMATES ONLY AND SHOULD NOT BE CONSTRUED
AS REPRESENTING THE FAIR MARKET VALUE OF THE RESERVES.
SUMMARY OF RESERVES AND PRESENT VALUES OF ESTIMATED FUTURE NET CASH FLOW
AS AT JANUARY 1, 2003
ESCALATED PRICES AND COSTS
PRESENT VALUES OF ESTIMATED FUTURE
NET CASH FLOW BEFORE INCOME TAXES
----------------------------------
OWNERSHIP
GROSS PROJECT INTEREST NET AFTER
RESERVES RESERVES ROYALTY 0% 10% 15% 20%
-------- -------- ------- -- --- --- ---
(MMbbls) (MMbbls) (MMbbls) ($ million)
Proved 1,111 222 202 2,960 1,302 972 766
Probable 570 114 96 1,956 341 195 133
Risked probable (50%) 285 57 48 978 170 97 67
Proved plus 50% probable 1,396 279 250 3,938 1,472 1,069 833
Proved plus probable 1,681 336 298 4,915 1,642 1,167 900
CONSTANT PRICES AND COSTS
PRESENT VALUES OF ESTIMATED FUTURE
NET CASH FLOW BEFORE INCOME TAXES
----------------------------------
OWNERSHIP
GROSS PROJECT INTEREST NET AFTER
RESERVES RESERVES ROYALTY 0% 10% 15% 20%
-------- -------- ------- -- --- --- ---
(MMbbls) (MMbbls) (MMbbls) ($ million)
Proved 1,111 222 189 5,369 2,347 1,744 1,369
Probable 570 114 93 2,960 484 265 174
Risked probable (50%) 285 57 46 1,480 242 133 87
Proved plus 50% probable 1,396 279 236 6,849 2,589 1,876 1,456
Proved plus probable 1,681 336 282 8,329 2,830 2,009 1,543
-10-
NOTES:
(1) Columns may not add due to rounding.
(2) Reserve definitions consistent with National Policy Statement 2-B of
the Canadian Securities Administrators have been used in the GLJ
Report, where:
"Proved Reserves" are those quantities of reserves estimated as
recoverable with a high degree of certainty under current technology
and existing economic conditions, from that portion of a reservoir
which can be reasonably evaluated as economically productive on the
basis of analysis of drilling, geological, geophysical and engineering
data.
"Probable Reserves" are those reserves which analysis of drilling,
geological, geophysical and engineering data does not demonstrate to be
proved under current technology and existing economic conditions, but
where such analysis suggests the likelihood of their existence and
future recovery.
"Established" is a proved plus risked probable category that
incorporates 50 percent of the unrisked probable additional reserves,
production and cash flow.
(3) The Project reserves are undeveloped. No reserves have been attributed
to the bitumen deposits present in the eastern portion of Lease 13, or
Leases 88 and 89, because of the current uncertainty of their
development.
(4) Oil volumes correspond to upgraded bitumen on the basis of 1.03
bbls/bbl of undiluted bitumen. Production from the Upgrader will
include volumes that are attributable to off-lease feedstock purchases
that cannot be booked as Project reserves. In the escalated price case,
GLJ estimates the oil pricing to be Edmonton Par less $4.00/bbl in
2003, $3.00/bbl in 2004 and $2.00/bbl thereafter. In the constant price
case, GLJ estimates the oil pricing to be Edmonton Par less $4.00/bbl.
These pricing forecasts reflect total revenues associated with the
output from the Upgrader less the purchase costs associated with
feedstock.
(5) Bitumen production has been forecast by GLJ to start in 2003, and reach
155,000 bbls per day by 2005 in the proved plus risked probable
category. Production in the proved case is forecast to be 80,000 bbls
per day in 2003 and to average 150,000 bbls per day thereafter, with a
mine life of 20 years. The 150,000 bbls per day rate and 20 years of
operation is consistent with the regulatory applications. In the proved
plus probable case, production is forecast to grow from a rate of
96,000 bbls per day in 2003 to an average rate of 160,000 bbls per day
by 2007. The reserves recovered in the proved plus probable category
reflect a 10 year extension to the proved forecast consistent with the
Mine plan prepared for the feasibility study which was prepared in
connection with the Project.
(6) Remaining capital costs relating to post-AFE Project costs are forecast
in the proved plus risked probable reserves evaluation to be $125
million (in 2003 $). Operating costs over the Project life will
fluctuate, with an average of approximately $15.06/bbl (2003 $)
undiluted bitumen forecast in the proved plus risked probable category.
Sustaining capital of approximately $1.53/bbl (2003 $) bitumen is
forecast in the proved plus risked probable category. The evaluation
recognizes that a component of operating costs is tied to the price of
natural gas; $5.82/MMBTU was used in the above estimate. A range of
operating and capital costs are used by GLJ, with higher estimates
being used in the proved category and lower estimates used in the
proved plus probable category.
(7) While the production, operating and capital costs were prepared with an
understanding as to the feasibility study prepared in connection with
the Project and due diligence reports obtained by Western, these
forecasts reflect GLJ's judgment and interpretations and should not be
construed as corresponding to their expectation.
(8) Royalties are anticipated to be paid at the Mine boundary using a
deemed bitumen revenue. The basis for determining the bitumen price has
not been determined. For purposes of this evaluation, GLJ has deducted
$4.00/bbl from GLJ's price for 12 degree heavy oil at Hardisty to
reflect the lower quality and transportation. The royalties correspond
to the generic oil sand royalty regime recently enacted. An initial
royalty of 1% on gross revenue is paid until 100% of the Project
capital, including a return on capital, has been recovered. The royalty
subsequently becomes 25% of net deemed bitumen revenue. The return
allowance is set at the monthly federal long-term bond rate, which is
forecast to be 4% real.
(9) The constant price reflects December 31, 2002 prices of $49.29/bbl
Edmonton Par oil, $34.29/bbl 12 degree crude at Hardisty, $5.82/MMBTU
gas and zero inflation. In the escalated price assumptions, the
following GLJ price forecast effective April 1, 2003 was used:
LIGHT, SWEET HEAVY CRUDE OIL
PROJECT EXCHANGE WTI CRUDE OIL AT CRUDE OIL (12 API) AT AVERAGE
YEAR INFLATION RATE CUSHING OKLAHOMA (40 API, 0.3% S) HARDISTY ALBERTA GAS
% $US/$Cdn $US/bbl $Cdn/bbl $Cdn/bbl $/MMBTU
- --------------------------------------------------------------------------------------------------------
2003 1.5 0.68 29.25 42.00 28.00 6.00
2004 1.5 0.68 25.00 36.00 23.75 5.20
2005 1.5 0.68 23.00 33.00 22.00 4.85
2006 1.5 0.68 23.00 33.00 22.75 4.85
-11-
LIGHT, SWEET HEAVY CRUDE OIL
PROJECT EXCHANGE WTI CRUDE OIL AT CRUDE OIL (12 API) AT AVERAGE
YEAR INFLATION RATE CUSHING OKLAHOMA (40 API, 0.3% S) HARDISTY ALBERTA GAS
% $US/$Cdn $US/bbl $Cdn/bbl $Cdn/bbl $/MMBTU
- --------------------------------------------------------------------------------------------------------
2007 1.5 0.68 23.00 33.00 22.75 4.85
2008 1.5 0.68 23.00 33.00 22.75 4.90
2009 1.5 0.68 23.00 33.00 22.75 5.00
2010 1.5 0.68 23.25 33.50 23.25 5.10
2011 1.5 0.68 23.75 34.00 23.75 5.20
2012 1.5 0.68 24.00 34.50 24.25 5.30
2013 1.5 0.68 24.50 35.00 24.75 5.40
2014+ 1.5 0.68 +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr
It is noted that the accuracy of any reserve estimate, especially when based on
volumetric analysis, is a function of the quality of available data and of
engineering interpretation and judgment. While reserve estimates presented
herein are considered reasonable, performance subsequent to the date of the
estimate may justify their revision, either upward or downward. The GLJ Report
presents net revenue projections prepared for the reserves attributable to the
ownership interest of Western along with a discussion of the evaluation.
LAND TENURE
Oil produced from oil sands is produced under Crown Oil Sands Leases granted by
the Province of Alberta. Such Crown Oil Sands Leases have an initial term of 15
years, and may be continued thereafter under the OIL SANDS TENURE REGULATION
(Alberta) to the extent that the lessee has attained the required minimum level
of evaluation of the oil sands in the leases or the leases are producing. Lease
13 has been continued under such regulation. The real property related to the
pipelines, the Upgrader and the cogeneration facilities fall into two basic
categories of ownership: (i) a number of locations, including some
pumping/compressor stations, are owned in fee simple; and (ii) the majority of
locations are covered by leases, easements, rights-of-way, permits or licenses
from landowners or governmental authorities permitting the land to be used in
such a manner.
ROYALTIES
An initial royalty of 1% of the gross revenue on the bitumen produced is paid
until the Owners have recovered 100% of the capital costs associated with the
Mine and Extraction Plant, including a return on capital. Such return is based
on the monthly Canadian federal long-term bond rate. Subsequent thereto, the
royalty will be the greater of 1% of the gross revenue on the bitumen produced
and 25% of net bitumen revenue. Gross revenue is calculated based on the fair
market value of the bitumen prior to upgrading. Net revenue is determined by
deducting from gross revenue the aggregate of all allowable operating costs,
interest expense and amortization of capital costs and any loss carryforwards.
ENVIRONMENTAL CONSIDERATIONS
Oil sands operations are subject to environmental regulation pursuant to
provincial and federal legislation. In December 1997, Shell filed a consolidated
application with the provincial government for approvals pursuant to the ENERGY
RESOURCES CONSERVATION ACT (Alberta), the OIL SANDS CONSERVATION ACT (Alberta),
the ENVIRONMENTAL PROTECTION AND ENHANCEMENT ACT (Alberta) and the WATER
RESOURCES ACT (Alberta). Applications were filed with the federal government for
approvals pursuant to the NAVIGABLE WATERS PROTECTION ACT (Canada) and the
FISHERIES ACT (Canada). As at December 31, 2002 approvals have been received for
all of the major components of the Project.
-12-
Included in the application to the provincial government was an environmental
impact assessment that assessed the impacts associated with the development,
operation and reclamation of the Project within the context of existing regional
developments. The assessment identified several favorable environmental aspects
of the Project, including the following:
o the non-caustic extraction process which reduces water quality
concerns and allows for faster consolidation of tailings to
facilitate contemporaneous reclamation;
o the transportation of diluted bitumen to the Upgrader for
processing will reduce regional air emissions that would
otherwise occur in the Fort McMurray area;
o the absence of coke as a by-product of the upgrading process
which results in higher recoveries of bitumen;
o contemporaneous reclamation of the Mine site which decreases
surface disturbance; and
o low levels of carbon dioxide and sulphur dioxide emissions
resulting from the upgrading process.
The Owners have committed to an environmental management system approach to
operate the Project based on these and other advantages. This system aims to
support environmentally sound development through the integration of
environmental planning and accountability at all levels of operations and
management.
The key environmental issues and stakeholder concerns to be managed by the
Owners in the development of the Mine are similar to those currently being
managed by existing oil sands operators and communities and encompass the health
of local and regional residents and Project employees, surface disturbance on
the terrestrial ecosystem, effects on traditional land use and historical
resources, local and regional air quality, water quality, health of the aquatic
ecosystem in the Athabasca and Muskeg rivers and cumulative effects on wildlife
populations and aquatic resources. The Owners have committed to both
site-specific and regional monitoring programs that will track the effects of
the Project and the cumulative effects of regional development on environmental
components and ecosystems.
The Owners will operate the Project to achieve compliance with applicable
statutes, regulations, codes, permit conditions and, to the extent practicable,
government guidelines. Where the applicable laws are not clear or do not address
all environmental concerns, management will apply appropriate internal standards
and guidelines to address such concerns. In addition to complying with
legislation and regulations and exercising due diligence, the Owners will strive
to continuously improve the overall environmental performance of the operation
and products while aspiring for short term and long term commercial success for
the Project. Air quality is of particular importance to the project, and has
taken on greater significance with the federal government's ratification of the
Kyoto agreement. As part of a Voluntary Climate Change Action Plan, the Joint
Venture has substantially reduced emission targets for the Project. As it stands
today, the Project will be starting up with emission that are 27 per cent lower
than the original case that was approved by the Alberta Energy and Utilities
Board. This has been achieved through the addition of cogeneration units, the
use of waste hydrogen from a neighbouring facility and a variety of process
improvements. Our goal is to further reduce emissions by another 50 per cent by
2010 through a combination of energy efficiency projects. To achieve this goal,
the Owners are pursuing a multi-faceted plan, which will include energy
efficiency projects, investigation of cleaner technology, the purchase of
domestic and international offsets and tree-planting offset programs.
-13-
FUTURE COMMITMENTS
The Corporation has entered into various commodity pricing agreements designed
to mitigate the exposure to the volatility of crude oil prices. The agreements
are summarized as follows:
NOTIONAL VOLUME HEDGE PERIOD AVERAGE PRICE RECEIVED
---------------------- ---------------------------- -----------------------
WTI Swaps 4,500 bbls/d April 1, 2003 to March 31, Cdn.$39.72
2004
WTI Swaps 9,000 bbls/d April 1, 2004 to March 31, Cdn.$36.97
2005
JOINT VENTURE AGREEMENT
The following section describes the general terms of the Joint Venture Agreement
and other relevant agreements.
GENERAL
The Joint Venture, which commenced December 6, 1999, consists of the following:
(i) the mining of oil sands from the western portion of Lease 13; (ii)
extraction of bitumen from such oil sands at the Extraction Plant; (iii) the
upgrading of such diluted bitumen in the Upgrader into refinery feedstocks and
synthetic crude oil blends; (iv) certain rights of the Corporation and
ChevronTexaco to participate in mining operations on the east area of Lease 13
and in Shell's Other Athabasca Leases; (v) an area of mutual interest for
expansion of operations of the Joint Venture; (vi) the disposition of the
Upgrader products; and (vii) the construction operations relating to the
foregoing.
The Joint Venture has been established pursuant to a number of agreements among
the Owners and is the subject of other agreements between the Owners and third
parties.
JOINT VENTURE AND RELATED AGREEMENTS
The principal agreement, which established the Joint Venture and governs the
relationship of the Owners, is the Joint Venture Agreement. This agreement also
sets out the manner in which certain of the other Project agreements will be
dealt with.
The JVA provides for the formation of the Joint Venture, the manner in which the
Joint Venture is administered, the creation and manner in which the Executive
Committee, which is the decision making body in respect of most matters,
functions, the responsibilities of the project administrator, secondments of
Owners' personnel, budgets, costs, technology matters, dispositions, defaults,
environmental matters, expansions, Owner's rights vis-a-vis each other, as well
as financial, accounting, banking matters, basic design parameters of the
Project and other matters.
EXECUTIVE COMMITTEE AND PROJECT ADMINISTRATOR
The JVA establishes an Executive Committee that is responsible for most
decisions relative to the Joint Venture, other than those which are requirements
of the Owners. One of Shell's representatives has been appointed as the first
Chairman and each Owner has appointed two representatives to the Executive
Committee. Voting at the Executive Committee level is based upon Owners'
ownership interests. Matters are generally decided by an affirmative vote of two
or more non-defaulting Owners having an
-14-
aggregate ownership interest of more than 50%, other than in certain specified
instances where a greater majority or unanimity is required. Certain matters
relating to the Upgrader, facilities shared by the Upgrader and the Scotford
Refinery require an affirmative vote of one or more non-defaulting Owners
representing an aggregate 50% ownership interest. An affirmative vote of two or
more non-defaulting Owners representing an aggregate 85% ownership interest is
required for certain matters including, but not limited to curtailment or shut
down of the Project, removal of the project administrator appointed under the
JVA or an operator, custom processing, and amendments to certain Project
agreements. Unanimity is required among the Owners in respect of, among other
things, amendments to the Project agreements, to mortgage or encumber the
Project or the Project assets, and where the Project agreements expressly
require.
The Executive Committee will also oversee the operations of Albian and Shell as
operators of the Mine and Extraction Plant and the Upgrader and related
facilities and ensure that each Owner has an ongoing opportunity to provide
qualified secondees to the Project.
The project administrator, which initially is Shell, has an administrative
function and deals with day to day matters that include making payments under
third-party Project agreements and dealing with administrative matters relating
to non-performing Owners. The project administrator is responsible for carrying
out the directions of the Executive Committee and appointing an individual to
act as project integration manager.
WESTERN PERSONNEL
Albian operates the Mine and the Extraction Plant pursuant to an operating
agreement. The mining and extraction services agreement dated December 6, 1999
between Western and Albian (the "Mining and Extraction Services Agreement") sets
out that Western will provide certain mine and extraction management services
including the full and part-time services of certain of its employees and
consultants to Albian. Further, Western will identify additional personnel to be
employed by Albian beyond the Western personnel who are necessary for the
operation of the Mine and the Extraction Plant. Certain Western personnel will
be dedicated to the Project until three years after Extraction Plant Start-up
while others, whose functions relate solely to construction, are dedicated to
the Project through to six months after Extraction Plant Start-up. The Mining
and Extraction Services Agreement may be terminated three years after Extraction
Plant Start-up. All costs incurred by Western and approved by the Executive
Committee in respect of the provision of services by Western pursuant to the
Mining and Extraction Services Agreement are reimbursed by Albian.
SECURITY INTEREST AND NON-PERFORMING OWNERS
The JVA provides that each Owner is granted a security interest in the other
Owners' interests in the Project to secure each Owner's obligations under the
Joint Venture. In the event of non-payment or of defaults under the JVA,
performing Owners have various remedies available to them, including an option
granted to performing Owners to purchase the defaulting Owner's entire interest
in the Project and related assets for an amount which is equal to 80% of the
capital costs incurred, if prior to Project Start-up, or 80% of the fair market
value if the default occurs after Project Start-up. Further, purchasers of
Upgrader petroleum products from Owners may be directed by the project
administrator to pay to the project administrator any funds owing to an Owner
who has not met its obligations under the JVA.
EXPANSIONS
Should an Owner wish to undertake an expansion of a key component of the
Project, the mining of the remaining area of Lease 13 or the construction of a
new mine, it must first advise the other Owners and
-15-
provide a period of time for them to advise as to whether or not they will
participate in the feasibility study for the proposed expansion. If an Owner
does not originally participate in a feasibility study it may, upon completion
of the feasibility study, purchase the right to participate in the feasibility
study and the expansion by paying twice the cost of its proportionate share of
the feasibility study.
If an expansion is to take place, an Owner must satisfy certain conditions
relating to financial capability to undertake the proposed expansion. Expansion
on the eastern portion of Lease 13 or in respect of the Upgrader prior to five
years after Project Start-up may only be undertaken with the written approval of
Shell (provided Shell or an affiliate has an ownership interest in the Upgrader
and is an Owner and operator of the Scotford Refinery at the time in respect of
expansion to the Upgrader). In order to participate in an expansion in respect
of the east area of Lease 13, each Owner would be required to pay to Shell an
amount based on the share of the recoverable bitumen reserves to be acquired by
such Owner. Owners' interests will be adjusted to reflect expansions. Expansions
may only take place by Owners with total ownership interest of a minimum of 40%
in the key component of the Project, being expanded. If an Owner other than
Shell does not participate in an expansion on the east portion of Lease 13 or in
Shell's Other Athabasca Leases it shall have no further expansion rights.
UPGRADER, SHARED SERVICES AND FACILITIES
The Owners have entered into various agreements with respect to Upgrader
operations, including the major shared facilities agreement which appoints Shell
as operator and provides for the ownership and operation of those facilities
relating to both the Upgrader and the Scotford Refinery by the Owners and a
non-Owner affiliate company of Shell.
These shared facilities include:
o the sulphur recovery unit;
o the demineralization unit;
o the waste water treatment unit;
o the sour water processing unit; and
o the HMU and Dow's hydrogen facilities.
The Upgrader and Refinery Shared Services and Facilities Agreement sets out the
cost sharing agreement between the Upgrader owners, represented by Shell, and
the Scotford Refinery owner, an affiliate company of Shell, with respect to a
number of matters including security, maintenance, equipment, effluent
treatment, roads, cafeteria, laboratory, warehousing and other shared facilities
and services. The Owners have entered into site leases with the non-Owner Shell
affiliate in respect of the lands which underlie the Upgrader and certain other
facilities.
DISPOSITIONS
Owners may not assign or transfer ownership interests in the Project until three
years after Project Start-up unless such dispositions are: (i) a grant of
security and the secured party acknowledges it is subject to the Joint Venture
Agreement and is subordinate to all liens granted thereunder; (ii) dispositions
to affiliates; (iii) to a person meeting certain specified financial
requirements; and (iv) certain limited public or private placement offerings of
securities. Partial assignments are only permissible if all resulting
-16-
ownership interests are 10% or greater. The Owners have also granted each other
a right of first refusal in respect of proposed dispositions.
TERM
The Joint Venture continues until all abandonment and decommissioning
obligations of the Owners have been fulfilled in accordance with applicable laws
and all required regulatory approvals have been received, all third party
Project agreements have been terminated and all accounts among the Owners in
respect of the Project have been settled.
ENVIRONMENTAL
The Owners are severally responsible for payment of site reclamation and
restoration at the end of the Project. To ensure that this obligation will be
met, if an Owner does not have a certain minimum credit rating, such Owner shall
establish a reclamation trust fund, the terms of which may be amended from time
to time by the Executive Committee. Commencing five years after Project
Start-up, an Owner who does not have the required minimum credit rating or falls
below the required minimum credit rating will be required to pay into the
reclamation trust fund on a monthly basis.
Each Owner will be responsible for all liabilities associated with environmental
damage or accidental pollution in proportion to its ownership interest on a
several basis. An Owner lacking a minimum credit rating must maintain sudden and
accidental pollution insurance at a minimum level determined by an ordinary
resolution of the Executive Committee.
MOBILE EQUIPMENT LEASE
Trucks, shovels and certain other mobile equipment used for mining and
overburden removal are leased by the Owners pursuant to leases under a Master
Equipment Lease Agreement ("MEL Agreement"). The MEL Agreement enables the
Owners to lease the equipment from time to time as required for lease terms of
between two and seven years. The maximum aggregate acquisition cost of the
equipment to the lessor is not expected to exceed $260 million, and the Owners
will have the right to purchase the leased equipment (subject to certain
restrictions if not all equipment then leased is being purchased) at any time
until the end of the applicable lease term. If the Owners do not elect to
purchase the leased equipment by the end of its applicable lease term, all
equipment then under lease (regardless of the applicable lease terms) must be
returned to the lessor. In returning the equipment, the Owners must meet certain
return conditions, including requirements that the equipment be returned in a
certain condition. If after electing to return the equipment, the Owners are not
able to comply with the return conditions at the time of return, the Owners will
be required to purchase all equipment then under lease at a purchase price equal
to the original acquisition cost of the equipment. If the equipment is returned
to the lessor and the lessor is unable to recover through remarketing efforts
the acquisition cost of the returned equipment, together with remarketing costs,
the Owners will be obligated to pay to the lessor the shortfall amount up to a
maximum of 85% of the acquisition cost of the returned equipment.
-17-
SELECTED CONSOLIDATED FINANCIAL INFORMATION
YEAR ENDED DECEMBER 31
----------------------------------
2002 2001 2000
--------- ------- -------
($ thousands, except per share amounts)
Revenues -- -- --
Loss Attributable to Common 10,286 7,015 5,422
Shareholders
Loss Per Share (basic)(1) 0.21 0.17 0.21
Total Assets 1,359,638 854,394 428,088
Total Long Term Liabilities 827,133 368,306 65,477
Total Shareholders' Equity 487,497 434,866 297,904
Cash Dividends Nil Nil Nil
THREE MONTHS ENDED
------------------------------------------------------------------------------------------
MAR 31, JUNE 30, SEPT 30, DEC 31, MAR 31, JUNE 30, SEPT 30, DEC 31,
2002 2002 2002 2002 2001 2001 2001 2001
------ ------- ------- ------ ------ ------ ------ ------
($ in thousands,
except amounts
per share)
Revenues -- -- -- -- -- -- -- --
Net earnings (1,755) (24,681) (1,821) 17,971 (1,261) (1,354) (1,623) (2,777)
(loss)(2)
Earnings (Loss) (0.04) (0.51) (0.04) 0.38 (0.03) (0.03) (0.04) (0.07)
per share
(basic)(1)
Notes:
(1) The effect of options, if exercised, would not be dilutive.
(2) Represents Earnings (loss) Attributable to Common Shareholders.
DIVIDEND POLICY
No dividends have been paid on any shares of Western since the date of its
incorporation. The Corporation currently intends to retain its earnings to
finance the growth and development of its business and therefore it is not
expected that dividends will be paid on the Common Shares or Class D Preferred
Shares, Series A in the immediate or foreseeable future. In addition, the note
indenture governing the Notes contains restrictions on the Corporation's ability
to pay dividends or distributions of any kind.
MANAGEMENT DISCUSSION AND ANALYSIS
Reference is made to the section entitled "Management's Discussion and Analysis"
of the Corporation's 2002 Annual Report to Shareholders, which section is
incorporated herein by reference.
-18-
MARKET FOR SECURITIES
The Common Shares of the Corporation are listed for trading on the Toronto Stock
Exchange under the symbol "WTO".
DIRECTORS AND OFFICERS
The following table lists the names of the directors and officers of Western,
their municipalities of residence, positions and offices with Western and
principal occupations during the preceding five years:
NAME AND MUNICIPALITY PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST
OF RESIDENCE AND OFFICE FIVE YEARS DIRECTOR SINCE
- -------------------------- -------------------- ------------------------------------------ --------------
DIRECTORS
Glen F. Andrews(2)(4) Director Retired businessman. Previously October, 1999
Bainbridge Island, President of BHP Copper North America
Washington until June 1999. Prior thereto,
Executive Vice-President and General
Manager, BHP Copper of the
South America and Pacific
regions from 1996 to 1998 and
North American region in
1998.
Tullio Cedraschi(4) Director President and Chief Executive Officer of October, 2000
Montreal, Quebec CN Investment Division, the entity
responsible for investing the assets of
the Canadian National Railways Pension
Trust Funds.
Geoffrey A. Cumming(2)(3) Chairman and Director Vice-Chairman of Gardiner Group Capital October, 1999
Auckland, New Zealand Limited, a private Canadian investment
corporation, and prior to July 2002,
Chief Executive Officer of Gardiner Group
Capital Limited. Managing Director of
Zeus Capital Limited, a private New
Zealand investment corporation.
Walter W. Grist(4) Director Managing Director, Brown Brothers December, 1999
New York, New York Harriman & Co., a private investment
management and banking
partnership which is general
partner of The 1818 Fund III,
L.P.
Brian F. MacNeill(1)(3) Director Chairman of Petro-Canada since2000. October, 1999
Calgary, Alberta President and Chief Executive Officer of
Enbridge Inc., an energy transportation,
distribution and services corporation,
from 1991 to September 1, 2000.
-19-
NAME AND MUNICIPALITY PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST
OF RESIDENCE AND OFFICE FIVE YEARS DIRECTOR SINCE
- -------------------------- -------------------- ------------------------------------------ --------------
Robert G. Puchniak(1)(2) Director Executive Vice President and Chief October, 1999
Winnipeg, Manitoba Financial Officer of James Richardson &
Sons, Limited ("James Richardson") since
March 2001. Prior thereto, Vice-President,
Finance and Investment, James Richardson
since 1996.
Guy J. Turcotte President, Chief President of Western since January 2002 July, 1999
Calgary, Alberta Executive Officer and Chief Executive Officer of Western
and Director since July 1999; Chairman of Fort Chicago
Energy Partners, L.P. since September
1997 and Chief Executive Officer until
December 2002; Chief Executive Officer of
Stone Creek Properties since March 1998.
Mac H. Van Wielingen(1)(3) Director Chairman of ARC Financial Group December, 1999
Calgary, Alberta Ltd.("ARC"), a private investment
management company focused on the energy
sector, and previously, President of ARC
since 1989.
OFFICERS
Charles W. Berard Corporate Secretary Partner with Macleod Dixon LLP,
Calgary, Alberta Barristers & Solicitors.
David A. Dyck Vice-President, Vice-President, Finance and Chief
Calgary, Alberta Finance and Chief Financial Officer of Western since
Financial Officer April 2000; prior
thereto, Senior Vice
President Finance &
Administration and Chief
Financial Officer of Summit
Resources Limited ("Summit")
since September 1998; Vice
President Finance and Chief
Financial Officer of Summit
from October 1996 to
September 1998.
John Frangos Executive Executive Vice-President and Chief
Calgary, Alberta Vice-President and Operating Officer of Western since
Chief Operating January 2002; prior thereto Corporate
Officer Development, Western since May 1999;
previously Vice-President International
Business Development of BHP Minerals from
1997 to May 1999.
Gerry Luft Vice-President Vice-President Marketing of Western since
Calgary, Alberta Marketing January 2002; prior thereto President of
ProServ Energy Inc.
NOTES:
(1) Member of the Audit Committee.
(2) Member of the Compensation Committee.
(3) Member of the Governance Committee.
-20-
(4) Member of the Health, Safety and Environment Committee.
(5) The Corporation does not have an Executive Committee.
Each director holds office until the next annual meeting of shareholders of the
Corporation or until their successors are duly elected or appointed.
As at March 1, 2003, the directors and officers of the Corporation, together
with their respective spouses, children or corporations controlled by them own
or control, directly or indirectly, an aggregate of 6,411,043 Common Shares and
no Class D Preferred Shares, Series A or approximately 12.9 % of the issued and
outstanding voting securities of the Corporation.
RISKS AND UNCERTAINTIES
The Corporation is exposed to a number of risks and uncertainties relating to
its operations.
WESTERN MAY NOT BE ABLE TO FUND COST OVERRUNS.
The total costs to construct the Project have not been and will not be fully
determined until commissioning of the Project is completed.
In the event of cost overruns, Western may not have enough capital to complete
its share of costs. There can be no assurance that Western's $200 million policy
of project delay/cost overrun insurance will cover all such overruns, that
Western will be able to satisfy the conditions to making a claim under such
insurance, that Western will be successful in asserting any claim under such
insurance or any insurance claim to be made with respect to the fire at the Mine
or that any claims under any insurance will be paid in a timely fashion. If
these funds are unavailable, there can be no assurance that alternative
financing would be available.
As well, there can be no assurances that the current operations schedules will
continue to proceed as planned without any delays or on budget. Any such delays
will likely increase the costs of the Project and may require additional
financing, and there can be no assurances that such financing will be available.
THE MINE, EXTRACTION PLANT AND UPGRADER MAY NOT PERFORM AS PLANNED.
The Project may encounter delays or increased costs due to many factors,
including:
o breakdown or failure of equipment or processes;
o design errors;
o operator errors;
o violation of permit requirements;
o disruption in the supply of energy; and
o catastrophic events such as fire, earthquake, storms or
explosions.
The Project consists of multiple facilities, all of which must be successfully
integrated and co-ordinated. There can be no assurance that each component will
operate as designed or expected or that the necessary levels of integration and
co-ordination will be achieved. Some of the mining and extraction processes
employed in the Project represent new applications of established processes,
processes that are larger in
-21-
scale than other commercial operations, or new processes that are scaled-up from
the pilot plant processes used to test the feasibility of the Mine and
Extraction Plant. There can be no assurance that all components of the mining
and extraction facility will perform as expected or that the costs to operate
this facility will not be significantly higher than expected.
The Extraction Plant will utilize a three-stage countercurrent decantation
process and configurations that have not previously been used commercially in
oil sands extraction and that have only been tested on a reduced scale in the
pilot plant at Lease 13. There can be no assurance that the Extraction Plant,
once commissioned, will achieve the same performance results as the pilot plant
and that the Extraction Plant will be able to economically produce the quality
and quantity of bitumen required by the Upgrader.
There can be no assurance that the Upgrader, once commissioned, will achieve the
same performance results as the Upgrader pilot plant or that the Upgrader will
have the same level of success in upgrading bitumen and purchased feedstocks
into products with the desired specifications. Costs to operate the Upgrader may
be significantly higher than expected.
THIRD-PARTY FACILITIES MAY NOT OPERATE AS PLANNED.
The Project depends upon successful operation of facilities owned and operated
by third parties. The Owners are party to certain agreements with third parties
to provide for, among other things, the following services and utilities:
o pipeline transportation to be provided through the Corridor
pipeline system;
o electricity and steam to be provided to the Mine and the
Extraction Plant from the Muskeg River cogeneration facility;
o transportation of natural gas to the Muskeg River cogeneration
facility by the ATCO pipeline;
o hydrogen to be provided to the upgrader from the hydrogen
manufacturing unit and Dow; and
o electricity and steam to be provided to the Upgrader from the
Upgrader cogeneration facility.
For the Mine and Extraction Plant, electricity and steam will be provided by the
Muskeg River cogeneration facility. If the Muskeg River cogeneration facility
fails to operate in the manner designed, there can be no assurance that the
Owners will be able to obtain alternative sources of electricity on a timely
basis, at prices acceptable to Western, or at all. If the cogeneration facility
does not provide the required steam, it is unlikely that other sources of steam
could be acquired on a timely basis, at prices acceptable to Western, or at all.
For the Upgrader, the electricity and steam will be provided by the Upgrader
cogeneration facility. There can be no assurance that in the event the Upgrader
cogeneration facility fails to operate in the manner designed, the Owners will
be able to secure alternative sources of electricity and steam on a timely
basis, at prices acceptable to Western, or at all.
The HMU is designed to produce approximately 75% of the Upgrader's hydrogen
requirements, with the remainder to be provided by Dow. If the HMU unit fails to
perform as designed or Dow fails to deliver pursuant to its contract,
respectively, there can be no assurance that the Project will be able to obtain
its hydrogen requirements on a timely basis, at prices acceptable to Western, or
at all.
-22-
The Project relies on transportation of bitumen and upgrader output from a
pipeline system to be owned and operated by Terasen. If the Corridor pipeline
system is unavailable for any reason, Western will have to find alternatives to
the Corridor pipeline system which may not be available on a timely basis, at
prices acceptable to Western, or at all.
Under the terms of certain third-party agreements, the Owners are committed to
pay for utilities and services on a long-term "take-or-pay" basis, regardless of
the extent that such utilities and services are actually used. In addition,
under the terms of the agreement with Terasen, Western must make scheduled
payments to them even if the Corridor pipeline system has diminished capacity or
is unavailable. If, due to Project delays, suspensions, shut-downs or other
reasons, the Owners fail to meet their commitments under these long-term
agreements, the Owners may incur substantial costs and may, in some
circumstances, be obligated to purchase the facilities constructed by the third
parties to provide the services and utilities for a purchase price in excess of
the fair market value of the facilities. There can be no assurance that Western
will have sufficient funds to satisfy these obligations.
Most of the contracts with third-party operators do not contain provisions for
the payment of liquidated damages. Accordingly, if certain of the third-party
facilities do not operate as planned, Western will not have a direct financial
claim against the third-party operators.
PRODUCTION FOLLOWING START-UP MAY NOT MEET THE PLANNED SCHEDULE OR BUDGET.
There is a risk that production from the Project may not increase as quickly as
planned, or at the costs anticipated. Many factors in addition to the risks
described above under "Risk Factors - The Mine, Extraction Plant and Upgrader
may not perform as planned" could impact the pace of Project Start-Up and
economic efficiency of production including:
o the operation of any part of the Project (Mine, Extraction
Plant, Upgrader or third-party facilities) falling below
expected levels of performance, output or efficiency; and
o unanticipated or unplanned shutdowns or curtailments of any
component of the Project.
THE PROJECT MAY EXPERIENCE EQUIPMENT FAILURES FOR WHICH WESTERN DOES NOT HAVE
SUFFICIENT INSURANCE.
The Upgrader will process large volumes of hydrocarbons at high pressure and
temperatures in equipment with fine tolerances. Equipment failures could result
in damage to the Extraction Plant and the Upgrader and liability to third
parties against which Western may not be able to fully insure or may elect not
to insure for various reasons, including high premium costs. Even if adequate
insurance is obtained, delays in realizing on claims and replacing damaged
equipment could adversely affect Western's operations and revenues.
FEEDSTOCK SUPPLY FOR THE UPGRADER MAY NOT ALWAYS BE AVAILABLE.
The Upgrader will require certain additional feedstocks to produce its output.
Western has entered into contracts for required feedstocks for terms of between
one and five years. There can be no assurance that feedstocks of the desired
quality will be available on a timely basis after these contracts expire, at
prices acceptable to Western, or at all. Unavailability of required feedstocks
could have an adverse effect on the rate and quality of Upgrader output.
-23-
THE PROJECT MAY NOT BE ABLE TO HIRE AND RETAIN THE SKILLED EMPLOYEES IT
REQUIRES.
The Project requires experienced employees with particular areas of expertise.
There are other oil sands and other industrial projects and expansions in
Alberta that compete with the Project for skilled employees, and such
competition may result in increases to the compensation paid to such employees.
The Project has already incurred increased costs as a result of such competition
and decreases in productivity. There can be no assurances that all of the
required employees with the necessary expertise will be available.
THE PROJECTIONS AND ASSUMPTIONS ABOUT OUR FUTURE PERFORMANCE MAY PROVE TO BE
INACCURATE.
The Project is not yet fully operational and Western has limited historical
operating results. Western's financing plan is based upon certain assumptions
and financial projections regarding its share of revenues and of operating,
maintenance and capital costs of the Project.
DEBT LEVELS COULD LIMIT FUTURE FLEXIBILITY IN OBTAINING ADDITIONAL DEBT
FINANCING AND IN PURSUING BUSINESS OPPORTUNITIES.
As at December 31, 2002, Western had approximately $915 million of debt
(including our obligations under the HMU lease and the Convertible Notes).
Western may also incur significant additional indebtedness for various purposes,
including expansions. Western's debt level and restrictive covenants will have
important effects on its future operations.
In addition, Western's ability to make scheduled payments or to refinance its
debt obligations will depend upon its financial and operating performance,
which, in turn, will depend upon prevailing industry and general economic
conditions beyond Western's control.
There can be no assurance that Western's operating performance, cash flow and
capital resources will be sufficient to repay its debt in the future.
FINANCING ARRANGEMENTS CONTAIN COVENANTS LIMITING OUR DISCRETION TO OPERATE OUR
BUSINESS.
Western's financing arrangements contain provisions that limit its discretion to
operate its business. If Western fails to comply with the restrictions set forth
in its current or future financing agreements, Western will be in default and
the principal and accrued interest may become due and payable.
INDEPENDENT REVIEWS MAY BE INACCURATE.
Although third parties have prepared reviews, reports and projections relating
to the viability and expected performance of the Project, there can be no
assurance that these reports, reviews and projections and the assumptions on
which they are based will, over time, prove to be accurate.
RESERVE AND RESOURCE ESTIMATES ARE UNCERTAIN.
There are numerous uncertainties inherent in estimating quantities of reserves
and resources, including many factors beyond Western's control. Western's
reserve and resource data represent estimates only. The usefulness of such
estimates is highly dependent upon the accuracy of the assumptions on which they
are based, the quality of the information available and the ability to compare
such information against industry standards.
-24-
Fluctuations of oil prices may render the mining of oil sands reserves
uneconomical. Other factors relating to the oil sands reserves, such as the need
for orderly development of ore bodies or the processing of new or different
grades of ore, may impair Western's profitability.
In general, estimates of economically recoverable bitumen reserves and the
related future net pretax cash flows of the Project are based upon a number of
variable factors and assumptions, such as:
o historical production from similar properties which are owned
by other operators;
o the assumed effects of regulation by governmental agencies;
o estimated future operating costs; and
o the availability of enhanced recovery techniques,
all of which may vary considerably from actual results of the Project.
There is no history of production from Western's properties. All such estimates
are to some degree speculative, and classifications of reserves are only
attempts to define the degree of speculation involved. Western's reserve figures
have been determined based upon assumed oil prices and operating costs. For
those reasons, estimates of the economically recoverable bitumen reserves
attributable to any particular group of properties, classification of such
reserves based on risk of recovery and estimates of future net revenues expected
therefrom, prepared by different engineers or by the same engineers at different
times, may vary substantially. Western's actual production, revenues, taxes and
development and operating expenditures with respect to Western's reserves will
vary from such estimates, and such variances could be material. Reserve
estimates may require revision based on actual production experience.
SHELL AND CHEVRONTEXACO MAY NOT AGREE WITH WESTERN ON MATTERS RELATED TO THE
PROJECT.
The Project is a joint venture among Shell, ChevronTexaco and Western. Future
plans of the Project, including decisions related to levels of production, will
depend on agreement among the Owners and will depend on the financial strength
and views of Shell and ChevronTexaco. There can be no assurance that the Owners
will agree on all matters relating to the Project.
Under the Joint Venture Agreement, ordinary resolutions of the Executive
Committee may be passed without Western's consent and there can be no assurance
that such resolutions may not adversely affect Western.
In addition, if Western's voting interest in any functional units falls below
15%, Western's consent will not be required for an extraordinary resolution of
the Executive Committee relating to that functional unit and such resolutions
may adversely effect Western.
SHELL AND CHEVRONTEXACO MAY NOT MEET THEIR OBLIGATIONS TO THE PROJECT.
Western is subject to the risk of non-payment by Shell or ChevronTexaco in
meeting their payment obligations to the Project. To the extent any Owner does
not meet its obligations to fund its costs in respect of the Joint Venture
Agreement and related agreements, Western, together with any other performing
Owners, would be required to fund those obligations.
-25-
IF WESTERN DEFAULTS ON ITS OBLIGATIONS UNDER THE JOINT VENTURE AGREEMENT, SHELL
AND CHEVRONTEXACO WILL HAVE THE RIGHT TO PURCHASE WESTERN'S INTEREST IN THE
JOINT VENTURE AT A DISCOUNT.
If Western fails to meet all or part of our obligations under the Joint Venture
Agreement, including by failing to participate in any expansion of an existing
mine which does not require an expansion of the Extraction Plant, Upgrader,
major shared facilities or third party facilities (which expansions can be
carried out pursuant to an ordinary resolution of the Executive Committee), the
other Owners will have an option to purchase Western's entire ownership interest
in the Joint Venture and related assets at a discount. The amount at which they
could purchase Western's ownership interest would be equal to 80% of the capital
costs incurred if default occurs prior to final completion, or 80% of fair
market value if default occurs after final completion.
IF WESTERN DOES NOT PARTICIPATE IN CERTAIN EXPANSIONS, WESTERN WILL LOSE VOTING
OR SIGNIFICANT EXPANSION RIGHTS.
If Western does not participate in expansions on the western portion of Lease
13, in certain circumstances Western's voting interest will be diluted and
Western's consent will no longer be required for extraordinary resolutions of
the Executive Committee. In addition, if Western does not participate in an
expansion on the remainder of Lease 13 or Shell's Other Athabasca Leases, or if
Western no longer has an ownership interest in each functional unit comprising
the Project, Western will lose its right to participate in any further
expansions, lose any rights to share in the resources contained on Leases 88 and
89 and Shell's Other Athabasca Leases and lose any rights to participate in an
area of mutual interest with the other Owners. Shell and ChevronTexaco, have
significantly greater capital resources than Western has. If the other Owners
decide to undertake expansions, including expansions on the eastern portion of
Lease 13 and on Leases 88 and 89, there can be no assurance that Western will be
able to fund its share of the expansion. Western's participation would be
subject to several conditions, including Western's satisfaction with feasibility
studies and Western's access to the necessary capital resources.
IF WESTERN PARTICIPATES IN CERTAIN EXPANSIONS, THOSE EXPANSIONS WILL BE SUBJECT
TO MANY OF THE SAME RISKS AS THE PROJECT.
Western may participate in expansions on the western portion of Lease 13, on the
remainder of Lease 13 or on Shell's Other Athabasca Leases. The Owners have
announced plans to evaluate potential long-term development opportunities
relating to resources contained within Lease 13 and on Shell's Other Athabasca
Leases. If Western were to participate in any expansion, Western will require
additional financing in order to fund its share of costs associated with an
expansion. Additionally, Western's participation in expansions will be subject
to many of the same risks as the Project.
WESTERN MAY NOT BE ABLE TO EFFECTIVELY MANAGE OUR GROWTH.
The Joint Venture Agreement permits our participation in certain expansion
opportunities. Participation in any expansion opportunities would significantly
increase the demands on Western's management resources. We may not be able to
effectively manage these expansions, and any failure to do so could have a
material adverse effect on Western's business, financial condition or results of
operations.
SHELL MAY NOT FULFIL ITS OBLIGATIONS TO WESTERN UNDER OUR LONG-TERM SALES
CONTRACT.
Western expects to sell its share of vacuum gas oil produced by the Project to
an affiliate of Shell on a long-term basis. Since a large portion of our
revenues will be received from an affiliate of Shell, Western
-26
will have a concentration of credit risk. Furthermore, if the Shell affiliate
does not have the capacity at the Scotford Refinery to physically process
Western's share of vacuum gas oil produced by the Project after using its
commercially reasonable efforts to maintain such capacity, it will not be
required to purchase Western's share of vacuum gas oil until the refinery
regains such capacity. Certain modifications to the Scotford Refinery are being
undertaken to permit it to take the expected vacuum gas oil output. If such
modifications are not completed on a timely or satisfactory basis, the Scotford
Refinery may not be able to process the vacuum gas oil output from the Upgrader.
If the affiliate of Shell were to default on, or not be required to fulfill its
obligations to us, or if the Scotford Refinery is not capable of processing the
vacuum gas oil, there can be no assurance that Western could sell its share of
vacuum gas oil to other purchasers at a price equal to or greater than that
provided for in its contract with the Shell affiliate, or at all.
Additionally, the price Western receives for products sold to the affiliate of
Shell may vary depending on the characteristics of the products sold. To the
extent the characteristics of the products fail to meet agreed upon
specifications, the purchase price for such products will be adjusted downward.
If the characteristics of the products are significantly below specifications
the affiliate of Shell is entitled to reject such products. Downward adjustment
of the purchase price or rejection of the products could have an adverse effect
on Western's operations and revenues, and there can be no assurance that we
could sell any rejected products elsewhere.
THE PRICE OF CRUDE OIL AND NATURAL GAS MAY FLUCTUATE AND NEGATIVELY IMPACT
FINANCIAL RESULTS.
Western's financial results will be dependent upon the prevailing price of crude
oil and natural gas. Oil and natural gas prices fluctuate significantly in
response to supply and demand factors beyond our control. Political
developments, especially in the Middle East, can affect world oil supply and oil
prices. As a result of the relatively higher operating costs of the Project
compared to some conventional crude oil production operations, Western's
operating margin is more sensitive to oil prices than that of some conventional
crude oil producers.
Any prolonged period of low oil prices could result in a decision by the Owners
to suspend or reduce production. Any such suspension or reduction of production
would result in a corresponding substantial decrease in Western's revenues and
earnings and could expose us to significant additional expense as a result of
certain long-term contracts. If the Owners did not decide to suspend or reduce
production, the sale of our product at reduced prices would lower our revenues.
In addition, because natural gas comprises a substantial part of our operating
costs, any prolonged period of high natural gas prices will negatively impact
Western's financial results.
HEDGING ACTIVITIES COULD RESULT IN LOSSES OR LIMIT THE BENEFIT OF CERTAIN
COMMODITY PRICE INCREASES.
The nature of Western's operations results in exposure to fluctuations in
commodity prices. Western has initiated a hedging program to use financial
instruments and physical delivery contracts to hedge its exposure to these
risks. When engaging in hedging Western will be exposed to credit-related losses
in the event of non-performance by counterparties to the financial instruments.
From time to time Western may enter into additional hedging activities in an
effort to mitigate the potential impact of declining oil prices. These
activities may consist of, but may not be limited to:
o buying a price floor under which Western will receive a
minimum price for its oil production;
o buying a collar under which Western will receive a price
within a specified range for its oil production;
-27-
o entering into fixed contracts for oil production; and
o entering into a contract to fix the differential between the
price for Western's outputs and either the West Texas
Intermediate or the Edmonton Par crude oil pricing benchmarks.
If product prices increase above those levels specified in any future hedging
agreements, Western could lose the cost of floors or ceilings or a fixed price
could limit Western from receiving the full benefit of commodity price
increases. In addition, by entering into these hedging activities, Western may
suffer financial loss if we are unable to produce sufficient quantities of oil
to fulfil our obligations.
Western may hedge its exposure to the costs of various inputs to the Project,
such as natural gas or feedstocks. If the prices of these inputs falls below the
levels specified in any future hedging agreements, Western could lose the cost
of ceilings or a fixed price could limit Western from receiving the full benefit
of commodity price decreases.
WESTERN MAY EXPERIENCE PRICING PRESSURE ON ITS SHARE OF THE PROJECT'S SYNTHETIC
CRUDE OIL PRODUCTION DUE TO OVERSUPPLY AND COMPETITION.
Western intends to sell its share of synthetic crude oil production to
refineries in North America. These sales will compete with the sales of both
synthetic and conventional crude oil. There exist other suppliers of synthetic
crude oil and there are several additional projects being contemplated. If
undertaken and completed, these projects will result in a significant increase
in the supply of synthetic crude oil to the market. In addition, not all
refineries are able to process or refine synthetic crude oil. There can be no
assurance that sufficient market demand will exist at all times to absorb
Western's share of the Project's synthetic crude oil production.
WESTERN MAY NOT BE ABLE TO PRODUCE A HIGH VALUE SINGLE STREAM BLEND.
Western expects that within one year of Project Start-Up it will be in a
position to market a single stream blend of synthetic crude oil which has a
greater value than the heavy and light streams to be marketed initially. There
is a risk that Western will be unable to create a single stream with a higher
value than the heavy and light streams. There is also a risk that the price per
barrel from selling two synthetic crude oil streams and vacuum gas oil could be
significantly less than the price per barrel from selling a single synthetic
crude oil stream and vacuum gas oil.
WESTERN WILL COMPETE WITH LARGER COMPANIES AND ALTERNATIVE FUELS WHEN IT SEEKS
TO SELL ITS SHARE OF THE PROJECT'S PRODUCTION.
The Canadian and international petroleum industry is highly competitive in all
aspects, including the distribution and marketing of petroleum products. Western
will compete with established oil sands operators which have established
operating histories and greater financial and other resources than Western. In
addition, Western will compete with other producers of synthetic crude oil
blends and producers of conventional crude oil, including Shell and
ChevronTexaco, some of whom have lower operating costs and many of whom have
extensive marketing networks. The crude oil industry also competes with other
industries and alternative energy sources in supplying energy, fuel and related
products to consumers.
THE ABANDONMENT AND RECLAMATION COSTS RELATING TO THE PROJECT MAY BE HIGHER THAN
ANTICIPATED.
Western will be responsible for compliance with terms and conditions set forth
in the environmental and regulatory approvals for the Project and all present
and future laws and regulations regarding the
-28-
decommissioning and abandonment of the Project and the reclamation of its lands.
The costs related to these activities may be substantially higher than
anticipated. It is not possible to accurately predict these costs since they
will be a function of regulatory requirements at the time and the value of the
equipment salvaged. In addition, to the extent Western does not meet the minimum
credit rating required under the Joint Venture Agreement, Western must establish
and fund a reclamation trust fund. Western currently does not hold the minimum
credit rating. Even if Western does hold the minimum credit rating, in the
future Western may determine that it is prudent or that Western is required by
applicable laws or regulations to establish and fund one or more additional
funds to provide for payment of future decommissioning, abandonment and
reclamation costs. Even if Western concludes that the establishment of such a
fund is prudent or required, Western may lack the financial resources to do so.
Western may also be required by future regulatory requirements to establish a
fund or place funds in trust with regulators for the decommissioning and
abandonment of the Project and the reclamation of its lands.
THE PROJECT MAY FAIL TO COMPLY WITH VARIOUS ENVIRONMENTAL APPROVALS WHICH MAY
EITHER CAUSE THE WITHDRAWAL OF THESE APPROVALS OR IMPOSE OTHER COSTS.
The construction, operation and decommissioning of the Project and reclamation
of the Project's lands are conditional upon various environmental and regulatory
approvals issued by governmental authorities. Further, the construction,
operation and decommissioning of the Project and reclamation of the Project's
lands will be subject to approvals and present and future laws and regulations
relating to environmental protection and operational safety. Risks of
substantial costs and liabilities are inherent in oil sands operations, and
there can be no assurance that substantial costs and liabilities will not be
incurred or that the Project will be permitted by regulators to carry on its
operations. Other developments, such as increasingly strict environmental and
safety laws, regulations and enforcement policies thereunder, and claims for
damages to property or persons resulting from the Project's operations, could
also result in substantial costs and liabilities to Western, delays in
operations or abandonment of the Project.
Canada is a signatory to the United Nations Framework Convention on Climate
Change and has ratified the Kyoto Protocol established thereunder to set legally
binding targets to reduce nation-wide emissions of carbon dioxide, methane,
nitrous oxide and other so-called "greenhouse gases". The Project will be a
significant producer of some greenhouse gases covered by the treaty. The
Government of Canada has put forward a Climate Change Plan for Canada which
suggests further legislation will set greenhouse gases emission reduction
requirements for various industrial activities, including oil and gas
production. Future federal legislation, together with provincial emission
reduction requirements, such as those proposed in Alberta's Bill 32: Climate
Change and Emissions Management Act, may require the reduction of emissions
and/or emissions intensity from the Project. The direct or indirect costs of
these regulations may adversely affect the Project. There can be no assurance
that future environmental approvals, laws or regulations will not adversely
impact the Owners' ability to operate the Project or increase or maintain
production or will not increase unit costs of production. Equipment from
suppliers that can meet future emission standards or other environmental
requirements may not be available on an economic basis, or at all, and other
methods of reducing emissions to required levels may significantly increase
operating costs or reduce output.
CHANGES IN GOVERNMENT REGULATION OF WESTERN'S OPERATIONS MAY HARM WESTERN.
Western's mining, extraction and upgrading operations and the operations of
third-party contractors are subject to extensive Canadian federal, provincial
and local laws and regulations governing exploration, development,
transportation, production, exports, labor standards, occupational health, waste
disposal, protection and remediation of the environment, mine safety, hazardous
materials, toxic substances and other matters. Amendments to current laws and
regulations and the introduction of new laws and
-29-
regulations governing operations and activities of mining corporations and more
stringent application of such laws and regulations are actively considered from
time to time and could harm the Project.
There can be no assurance that the various government licenses and approvals
sought will be granted to the Project or, if granted, will not be cancelled or
will be renewed upon expiry or that income tax laws and government incentive
programs relating to the Project, and the mining, oil sands and oil and gas
industries generally, will not be changed in a manner which may adversely affect
Western.
Currently, Western benefits from a favorable royalty regime; however, there can
be no assurance that this royalty regime will not change in a manner that would
adversely affect Western.
Lease 13 is subject to the OIL SANDS TENURE REGULATION (Alberta) which was
introduced in 2000. This legislation deems Lease 13 to continue beyond its
primary term to the extent that the lessee has attained the minimum level of
evaluation of the oil sands in Lease 13 or Lease 13 is producing. There can be
no assurance that the Owners will be able to comply with the requirements of the
OIL SANDS TENURE REGULATION (Alberta). In addition, the Minister, in certain
circumstances, may change the designation of any lease subject to the
legislation and provide notice requiring the Owners to commence production or
recovery of, or to increase existing production or recovery of bitumen within
the time specified in such notice. There can be no assurance that if such a
notice is given, the Owners will be able to comply with its terms to maintain
Lease 13. Additionally, the OIL SANDS TENURE REGULATION (Alberta) expires on
December 1, 2004 and, if such legislation is not renewed in its present or
similarly favorable form, the status of Lease 13 may be in question.
ABORIGINAL PEOPLES MAY MAKE CLAIMS AGAINST WESTERN OR THE PROJECT REGARDING THE
LANDS ON WHICH THE PROJECT IS LOCATED.
Aboriginal peoples have claimed aboriginal title and rights to a substantial
portion of western Canada. Certain aboriginal peoples have filed a claim against
the Government of Canada, certain governmental entities and the City of Fort
McMurray, Alberta claiming, among other things, that the plaintiffs have
aboriginal title to large areas of lands surrounding Fort McMurray, including
the lands on which the Project and most of the other oil sands operations in
Alberta are located. Such claims, if successful, could have an adverse effect on
the Project.
VARIOUS HAZARDS INHERENT IN WESTERN'S OPERATIONS COULD RESULT IN LOSS OF
EQUIPMENT OR LIFE.
The operation of the Project will be subject to the customary hazards of mining,
extracting, transporting and processing hydrocarbons, including the risk of
catastrophic events such as fire, earthquake, storms or explosions. A casualty
occurrence might result in the loss of equipment or life, as well as injury or
property damage. Western will not carry insurance with respect to all casualty
occurrences and disruptions. Western cannot assure you that is insurance will be
sufficient to cover any such casualty occurrences or disruptions, including with
respect to the damage caused by the fire at the Mine. Losses and liabilities
arising from uninsured or under-insured events could have a material adverse
effect on the Project and on Western's business, financial condition and results
of operations.
FLUCTUATIONS IN THE US AND CANADIAN DOLLAR EXCHANGE RATE MAY CAUSE WESTERN'S
OPERATING COSTS TO RISE.
Crude oil prices are generally based on a US dollar market price, while
Western's operating costs are primarily denominated in Canadian dollars. Adverse
fluctuations in the US and Canadian dollar exchange rate may cause Western's
operating costs to rise in relation to Western's revenues. Western
-30-
does not currently hedge against currency fluctuations and there can be no
assurance that any hedging policy Western may adopt would be successful.
ADDITIONAL INFORMATION
The Corporation, upon request to the Chief Financial Officer of the Corporation,
will provide to any person or company:
(a) when the securities of the Corporation are in the course of a
distribution under a preliminary short form prospectus or a
short form prospectus,
(i) one copy of the Annual Information Form of the
Corporation, together with one copy of any document,
or the pertinent pages of any document, incorporated
by reference in the Annual Information Form,
(ii) one copy of the comparative financial statements of
the Corporation for its most recently completed
financial year for which financial statements have
been filed together with the accompanying report of
the auditor and one copy of the most recent interim
financial statements of the Corporation that have
been filed, if any, for any period after the end of
its most recently completed financial year,
(iii) one copy of the information circular of the
Corporation in respect of its most recent annual
meeting of shareholders that involved the election of
directors,
(iv) one copy of any other documents that are incorporated
by reference into the preliminary short form
prospectus or the short form prospectus and are not
required to be provided under clauses (i), (ii) or
(iii); or
(b) at any other time, one copy of any documents referred to in
clauses (a)(i), (ii) and (iii), provided that the Corporation
may require the payment of a reasonable charge if the request
is made by a person or company who is not a security holder of
the Corporation.
Additional information including directors' and officers' remuneration and
indebtedness, principal holders of the Corporation's securities, options to
purchase securities and interests of insiders in material transactions, if
applicable, is contained in the Corporation's information circular for its most
recent annual meeting of shareholders that involved the election of directors,
and additional financial information is provided in the Corporation's
comparative financial statements for its most recently completed financial year.
-31-
GLOSSARY
IN THIS ANNUAL INFORMATION FORM, THE FOLLOWING TERMS SHALL HAVE THE MEANINGS SET
FORTH BELOW, UNLESS OTHERWISE INDICATED:
"AFE" Authorization for expenditure;
"ALBIAN" Albian Sands Energy Inc., a corporation owned by the Owners in
proportion to their ownership interest, which was incorporated for the purposes
of acting as the operator of the Mine and the Extraction Plant;
"ATCO" ATCO Power Canada Limited;
"BBLS" Barrels. One barrel equals 0.15891 cubic metres at 15(0)Celsius;
"CHEVRONTEXACO" Chevron Canada Limited;
"COMMON SHARES" The Class A shares of Western;
"DOW" Dow Chemicals Canada Inc.;
"EXECUTIVE COMMITTEE" The executive committee appointed under the Joint Venture
Agreement which has the responsibility for managing the Project and which is
comprised of two representatives of each of the Owners;
"EXTRACTION PLANT" The extraction facilities to be constructed on the western
portion of Lease 13 which are designed to separate crude bitumen from the oil
sands and process such crude bitumen so that it may be transported by pipeline
to the Scotford Upgrader;
"EXTRACTION PLANT START-UP" That time when the Extraction Plant has operated at
not less than 85% of its design capacity for a period of 30 consecutive days and
any construction deficiencies and defects have been rectified to the
satisfaction of the Owners;
"GLJ" Gilbert Laustsen Jung Associates Ltd., independent petroleum consultants;
"GLJ REPORT" The report prepared by GLJ dated April 3, 2003 evaluating the
reserves attributable to Western as of January 1, 2003;
"HMU" The hydrogen manufacturing unit which will supply hydrogen to the
Upgrader;
"JOINT VENTURE" The unincorporated joint venture created by the Owners pursuant
to the Joint Venture Agreement to undertake the Project;
"JOINT VENTURE AGREEMENT" or "JVA" The Joint Venture Agreement dated December 6,
1999, among the Owners, as amended;
"LEASE 13" Bituminous Sands Lease No. 7277080T13 and all renewals, extensions,
replacements and amendments thereto, granted to Shell by the Government of
Alberta, and transferred to Albian Sands Energy Inc., the western portion of
which is the site for the mining and extraction operations of the Project;
"MMBBLS" Millions of barrels;
-32-
"MINE" The open pit mine to be constructed on the western portion of Lease 13
and all equipment, machinery, vehicles and facilities used in connection
therewith;
"NON-VOTING CONVERTIBLE EQUITY SHARES" The non-voting convertible Class B equity
shares of Western each convertible into one Common Share in certain
circumstances subject to adjustment, at no additional cost;
"NORWEST" NorWest Mine Services Inc., independent mining consultants;
"NORWEST REPORT" The report prepared by NorWest dated January 18, 2000 and
confirmed by a further report dated March 6, 2001 that considered additional
exploration data and geological information acquired after August 1, 1999;
"NOTES" Senior secured notes of Western bearing interest at a rate of 8.375% per
annum and maturing on May 1, 2012;
"OWNERS" The owners of undivided ownership interests in the Project which
include Shell, as to a 60% undivided ownership interest, ChevronTexaco, as to a
20% undivided ownership interest, and Western, as to a 20% undivided ownership
interest;
"PROJECT" The design and construction of facilities and implementation of
operations of the Mine, the Extraction Plant, the Upgrader and all other
facilities necessary to mine, extract, transport and upgrade crude bitumen from
the oil sands deposits on the western portion of Lease 13;
"PROJECT START-UP" That time when the main Project facilities have operated at
not less than 85% of their design capacity for a period of 30 consecutive days
and any construction deficiencies and defects have been rectified to the
satisfaction of the Owners;
"SCOTFORD REFINERY" The oil refinery owned by Shell Products Canada Limited
which is located near Fort Saskatchewan, Alberta and which is adjacent to the
location of the Scotford Upgrader;
"SCOTFORD UPGRADER" or "UPGRADER" The oil sands bitumen upgrader which will
process diluted bitumen product from the Extraction Plant to produce refinery
feed stocks for sale to Shell Products Canada Limited at the Scotford Refinery
and synthetic crude oil for shipment to other North American refineries;
"SENIOR CREDIT FACILITY" The credit facility between the Corporation and certain
lending institutions which, prior to repayment, provided a portion of the
capital costs of the Project and which facility also included debt service and
cost overrun facilities;
"SHELL" Shell Canada Limited; and
"SHELL'S OTHER ATHABASCA LEASES" Alberta Crown Oil Sands Lease Nos. 7288080T88,
7288080T89, 7288080T90, 7280050T26, 7281010T93, 7281030T53, 7281030T45,
7280080T28 and all renewals, extensions, replacements and amendments in respect
of same, granted to Shell by the Government of Alberta.
DOCUMENT 2
----------
MANAGEMENT'S DISCUSSION & ANALYSIS
The following discussion of financial condition and results of operations should
be read in conjunction with the Consolidated Financial Statements and Notes. It
offers Management's analysis of our financial and operating results and provides
estimates, where possible, of our future financial and operating performance
based on information currently available. Actual results may vary from estimates
and the variances may be significant.
OVERVIEW
Western Oil Sands Inc. is a Canadian oil sands corporation which holds a 20 per
cent undivided ownership interest in a multibillion dollar Joint Venture to
exploit the recoverable bitumen reserves and resources found in certain oil
sands deposits in the Athabasca region of Alberta (the "Project") and to pursue
other oil sands opportunities. Shell Canada Limited ("Shell") and Chevron Canada
Limited ("ChevronTexaco") hold the remaining 60 per cent and 20 per cent
undivided ownership interests in the Joint Venture, respectively. The Project,
which includes facilities owned by the Joint Venture and third parties, will use
established processes to mine oil sands deposits, extract, and upgrade the
bitumen into synthetic crude oil and vacuum gas oil, or VGO.
The Joint Venture will develop the western portion of Lease 13, a large oil
sands lease in the Athabasca region of northeastern Alberta, Canada, held by the
owners and granted by the Government of Alberta. The western portion of Lease 13
contains approximately 1.7 billion barrels of proved and probable reserves and
is sufficient for 30 years of non-declining bitumen production at a rate of
155,000 barrels per day. Western is entitled to participate in future expansion
opportunities, including in respect of Lease 13 and on three other nearby oil
sands leases owned by Shell, referred to as leases 88, 89 and 90.
Our main role is to provide construction and operating expertise for
the Mine and extraction plant. Our personnel includes 14 mining professionals
who have accumulated over 350 man years of experience derived from a variety of
global mining and resource extraction projects, who provide the management of
the Mine and extraction facilities and who have the expertise to develop growth
opportunities on the remaining leases. We have employed the same proven
technologies and processes in the Athabasca Oil Sands Project that have been
used successfully in other resource extraction projects around the world.
Shell has extensive refining experience and its organization is
primarily responsible for the construction and operation of the Scotford
Upgrader, as well as providing the overall Project administration and accounting
functions.
ChevronTexaco provides a key management support role at both the Mine
and the Upgrader sites. ChevronTexaco is a recognized world-leader in catalyst
and hydro-treatment technologies, which are key elements in the successful
upgrading of the mined bitumen.
HIGHLIGHTS
o We incurred $527.5 million of capital expenditures during 2002, $519.9
million of which were direct Project costs with the balance comprised of
corporate assets.
o During the year we issued US$450 million of corporate bonds and established
new bank credit facilities totalling $150 million.
o We raised $50.2 million in additional equity capital in February 2003, as a
direct result of not having received any of the insurance proceeds from our
$200 million cost overrun insurance policy.
o Construction of the Project was completed in 2002 and both the Muskeg River
Mine and the Scotford Upgrader were commissioned for start-up.
o Mining operations commenced prior to year-end 2002 following which diluted
bitumen was delivered into the Corridor Pipeline system en route to the
Scotford Upgrader.
OPERATIONS
Project Update
Construction of the Project was completed in 2002 and all the major milestones
have been met, despite the challenges of the lack of skilled labour and the
management of related productivity issues that were experienced throughout the
year.
Northern Alberta experienced an unprecedented demand for labour in the
second half of 2001, largely as a result of other industry projects experiencing
delays in completion and continuing to utilize craft labour that was expected to
be available earlier for our Project. The restricted availability of skilled
craftsmen had an adverse impact on productivity at our project beginning in
2001. Labour productivity continued to be lower than expected throughout 2002
and this applied significant cost pressure to the Project throughout the year. A
combination of these and other factors led to a 59 per cent increase in the
forecasted cost of the Project from the original budget of $3.5 billion (our
share $709 million), to $5.6 billion (our share $1.12 billion).
All units at both the Muskeg River Mine and the Scotford Upgrader have
been turned over to operations for commissioning and start-up. The first
production of synthetic crude out of the Upgrader was achieved by the end of the
first quarter of 2003.
Key Project milestones achieved in the year include:
o The ATCO Gas Pipeline supplying gas to the upstream cogeneration plant was
completed during the year. Line fill with natural gas occurred in January
2002.
o The Corridor Pipeline was completed and first diluent line fill was
injected in April 2002.
o In August 2002, first ore was mined and processed through the primary
extraction facilities producing bitumen froth at the Muskeg River Mine.
o In August 2002, the Project took delivery of the first mining truck and
electric shovel that will be used in the mining operations. The Project
will ultimately have a mining fleet consisting of twenty-three 400-ton
mining trucks and five electric shovels.
o Construction, testing and commissioning of the ATCO Cogeneration Facilities
at both the Muskeg River Mine and the Scotford Upgrader were completed by
the fourth quarter of 2002.
o By November 30, 2002, mechanical completion was achieved for all aspects of
the Project, both at the extraction plant and the Scotford Upgrader.
o First bitumen production at the Muskeg River Mine started on December 29,
2002, followed immediately with the shipment of diluted bitumen into the
Corridor Pipeline system for delivery to the Scotford Upgrader.
On January 6, 2003, a fire occurred in the froth treatment area at the
Muskeg River Mine, caused by a hydrocarbon leak arising from the failure of a
piping connection. The fire did not cause significant damage to major process
equipment or piping systems. Damage was mainly limited to electrical cables,
instrumentation and insulation in the solvent recovery area of the froth
treatment plant and subsequent damage to pipes as a result of freezing. The
original estimate of repair costs for the fire was in the order of $75 million
($15 million our share). Although not yet determined, the final costs will be
higher than the original estimate and will include additional costs to repair
the freeze damage. We expect that repairs will be completed and production of
bitumen will resume with first synthetic crude oil production from the Scotford
Upgrader scheduled by the end of the first quarter of 2003. We expect to draw on
extensive project insurance coverage to recover repair costs.
Capital Expenditures
Construction activities have been conducted under a Joint Venture agreement
whereby we participate in the operations of the Project to our 20 per cent
working interest and are responsible for 20 per cent of the costs. During 2002,
our share of Project capital expenditures totalled $519.9 million compared to
$432.8 million for 2001. These expenditures included construction costs of the
Project at the Muskeg River Mine and the Scotford Upgrader as well as direct
capitalized finance and other costs of $55.3 million in 2002, up from $10.7
million capitalized in 2001. The capitalized costs consist primarily of bond and
bank interest and stand-by fees that are being capitalized during the
construction period as is consistent with industry practice and our policy.
In 2002 we also spent $7.6 million on corporate assets and certain
other capitalized costs not related to the Project.
We capitalized a further $15.7 million in 2002 related to our share of
the costs for construction of the Hydrogen Manufacturing Unit (HMU) at the
Scotford Upgrader, up from $17.8 million in 2001. The HMU costs are being
financed by a capital lease. An amount of $2.0 million related to other accrued
finance costs was also capitalized.
CAPITAL ASSETS
Since
($millions) 2002 2001 2000 1999 inception
- -------------------------------------------------------------------------------------------------------------
Expenditures
Muskeg River Mine 219.0 212.1 66.7 3.9 501.7
Scotford Upgrader 245.6 210.0 118.0 5.5 579.1
Capitalized finance costs 53.0 9.5 6.4 - 68.9
Entry fee (0.4) 1.2 - 34.2 35.0
Shell interest (1) 2.7 - - - 2.7
- -------------------------------------------------------------------------------------------------------------
Project expenditures 519.9 432.8 191.1 43.6 1,187.4
Corporate assets 7.6 0.8 1.0 3.1 12.5
- -------------------------------------------------------------------------------------------------------------
Cash expenditures 527.5 433.6 192.1 46.7 1,199.9
Non cash capitalized costs
Shell Fees and interest (1) - 6.4 7.3 40.0 53.7
HMU 15.7 17.8 17.3 - 50.8
Capitalized finance costs 2.0 - - - 2.0
Corporate assets - - - 1.1 1.1
--------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
Total 545.2 457.8 216.7 87.8 1,307.5
- -------------------------------------------------------------------------------------------------------------
(1) Shell fees and accrued interest liability were repaid in full in April 2002
out of proceeds of the Senior Secured Notes offering.
The forecast cost of the Project is $5.6 billion (our share $1.12
billion), up from $4.8 billion ($957 million our share) that was forecast at
December 31, 2001. The impact of this cost increase is to increase our proved
plus probable reserve development cost from $2.85 to $3.35 per barrel. On the
basis of this level of expenditures, we have funding arrangements that are
sufficient to cover our share of commitments. In addition we believe that a
portion of these increased Project costs fall within the scope and coverage of
our Cost Overrun Insurance policy. (See discussion in Financial Risks.)
Capital expenditures are expected to be lower in 2003 as construction
of the Project was completed in 2002 and we are in the commissioning and
start-up phase of the Project. Capital expenditures for 2003 are estimated at
$65 million and represent deferred operating expenses during commissioning and
start-up, as well as maintenance capital expenditures throughout the year.
Reserves
Gilbert Laustsen Jung Associates Ltd. (GLJ), an independent engineering firm
located in Calgary, evaluates our reserves. The following table summarizes the
Project reserves and our share of those reserves as at January 1, 2003, based on
GLJ's forecast of escalating prices and costs:
Gross Ownership
- -------------------------------------------------------------------------------------------------------------
Project Interest Net After Present Values of Estimated Future
Reserves Reserves Royalty Net Cash Flow Before Income Taxes
(MMbbls) (MMbbls) (MMbbls) 0% 10% 15% 20%
- -------------------------------------------------------------------------------------------------------------
($ million)
Proved 1,111 222 202 2,960 1,302 972 766
Probable 570 114 96 1,956 340 195 134
Risked probable (50%) 285 57 48 978 170 97 67
Proved plus 50% probable 1,396 279 250 3,938 1,472 1,069 833
Proved plus probable 1,681 336 298 4,916 1,642 1,167 900
- -------------------------------------------------------------------------------------------------------------
This analysis by GLJ includes only those reserves from the western
portion of Lease 13, which is the initial area being mined by the Joint Venture.
These reserves will provide a reserve life of approximately 30 years based on
anticipated bitumen production rates of 155,000 barrels per day (our share
31,000 barrels per day).
In addition, we are entitled to participate in expansion opportunities
with the Owners, on the remainder of Lease 13 and on three nearby oil sands
leases owned by Shell, namely Leases 88, 89 and 90. The following table outlines
the potential resources available under these expansion opportunities:
Total Resources Western's Share
Area (MMbbls) (MMbbls)
- --------------------------------------------------------------------------------
Remainder of Lease 13 and Lease 90 3,200 640
Leases 88 and 89 3,900 780
- --------------------------------------------------------------------------------
7,100 1,420
- --------------------------------------------------------------------------------
FINANCIAL RESULTS
Apart from our interest in the Athabasca Oil Sands Project, we have no other
assets nor do we have any other on-going operations. Our operating activities
commenced with Project start-up, which occurred at the Muskeg River Mine in
December 2002. We expect to be moving into commercial production in the second
quarter of 2003 following production of synthetic
crude oil which occurred in the first quarter of 2003 and will be reporting
operating results for the balance of 2003 in our quarterly interim reports.
General and Administrative Expenses
General and administrative expenses for 2002 totalled $5.7 million (2001 - $5.3
million). The increase is primarily due to the addition of marketing and
administrative personnel as we prepare to enter our operating phase. General and
administrative expenses are expected to increase modestly in 2003 commensurate
with additional staff or consultants that may be required throughout the year.
Royalties
The current royalty system for oil sands consists of an initial royalty of one
per cent of the gross revenue on the bitumen produced (based on its value prior
to upgrading) until we have recovered our share of all the capital costs
associated with the Muskeg River Mine and Extraction plant, together with a
return on capital equal to the Canadian federal long-term bond rate. After full
capital cost recovery, the royalty shall be the greater of one per cent of the
gross revenue on the bitumen produced and 25 per cent of net revenue on the
bitumen produced. We will be paying royalties at the one per cent rate once we
start producing. We estimate that payout will not be achieved for several years,
after which we will be paying royalties at the higher rates. The timing of this
will depend in part on the prices we receive for our production as well any
additional capital costs incurred through expansion activities.
Interest Expense
During 2002 we incurred $48.1 million in interest expense on our debt
obligations (2001 - $11.0 million). These included the long-term bonds, the
bridge facility, our other bank facilities and the Shell fees loan. This debt
has been used to finance construction costs and, accordingly, all interest is
being capitalized until the Project reaches commercial production, which we
expect by the second quarter of 2003. (See Capital Assets.) Capitalized interest
will be written off over the term of the Project. Once commercial production is
attained, interest costs will be expensed in the period to which it relates.
GRAPH: SHARE TRADING HISTORY
Date Share Price ($) Volume (thousands)
Jan-01 14.25 320.7
Feb-01 15.00 635.7
Mar-01 14.60 627.5
Apr-01 13.75 374.0
May-01 14.00 240.1
Jun-01 14.00 134.0
Jul-01 15.25 1005.8
Aug-01 14.80 3015.5
Sep-01 15.20 572.3
Oct-01 17.00 2007.8
Nov-01 15.60 644.8
Dec-01 19.09 756.8
Jan-02 22.00 5302.9
Feb-02 25.35 2699.8
GRAPH: SHARE TRADING HISTORY
Date Share Price ($) Volume (thousands)
Mar-02 28.15 4010.5
Apr-02 26.15 2496.4
May-02 27.55 2223.2
Jun-02 27.80 971.5
Jul-02 24.00 1532.9
Aug-02 25.61 987.4
Sep-02 24.40 901.1
Oct-02 20.20 1443.1
Nov-02 21.00 1742.0
Dec-02 24.25 1172.8
Income Taxes
Large Corporations Tax increased to $2.9 million from $1.5 million last year as
a direct result of the expansion of our capital base.
As we have not had any operating revenues to date, we have not yet
earned taxable net income. At December 31, 2002, we had approximately $1.2
billion of loss carry forwards and tax pools. In addition, we had $8.7 million
of financing issue costs, which can be used to offset future taxable income. The
potential future benefit relating to the loss carry forwards and share issue
costs has been recorded in the financial statements, resulting in a future
income tax recovery of $22.5 million. This asset is offset by a future income
tax liability of $23.0 million arising from the renunciation of deductions for
flow-through shares, resulting in a net future tax liability of $0.5 million,
with share capital being reduced by the $23.0 million tax effect of the
renunciations.
TAX POOLS
December 31
($ thousands) 2002
- --------------------------------------------------------------------------------
Canadian Exploration Expense $ 45,214
Canadian Development Expense 15,993
Canadian Exploration and Development Overhead Expense 2,704
Cumulative Eligible Capital 4,039
Capital Cost Allowance 25,632
Accelerated Capital Cost Allowance 1,031,616
------------
Total $ 1,125,198
- --------------------------------------------------------------------------------
Net Loss
Corporate expenses totalled $28.6 million for 2002 and included an amount of
$22.8 million representing the one-time write-off of deferred financing costs
related to credit facilities that were replaced by the US$450 million Senior
Secured Notes offering in April 2002. Excluding the write-off, we incurred
expenses of $5.9 million, compared to $5.5 million in 2001, an increase that
reflects the expected growth in corporate activities as we move towards
start-up. As we do not yet have revenues from on-going operations to offset
these costs, our net loss was comprised primarily of the corporate expenses net
of a future income tax recovery arising from the recognition of the tax benefit
relating to loss carry forwards. The net loss attributable to Common
Shareholders for 2002 was $10.3 million ($0.21 per share) compared to $7.0
million ($0.17 per share) for the year ended December 31, 2001.
QUARTERLY INFORMATION
2002
- -------------------------------------------------------------------------------------------------------------
Q1 Q2 Q3 Q4 Total
- -------------------------------------------------------------------------------------------------------------
($millions, except per share amounts)
Capital Expenditures $ 110.0 $ 133.2 $ 145.3 $ 139.0 527.5
Long-term Debt 418.5 683.4 713.6 775.8 775.8
Cash Flow from Operations (1.7) (1.9) (1.8) (3.2) (8.6)
Cash Flow per Share (0.03) (0.04) (0.04) (0.07) (0.18)
Loss Attributable to Common Shareholders (1.8) (24.7) (1.8) 18.0 (10.3)
Loss per Share $ (0.04) $ (0.51) $ (0.04) $ 0.38 (0.21)
--------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
2001
- -------------------------------------------------------------------------------------------------------------
Q1 Q2 Q3 Q4 Total
- -------------------------------------------------------------------------------------------------------------
($millions, except per share amounts)
Capital Expenditures $ 77.9 $ 117.4 $ 117.4 $ 120.9 433.6
Long-term Debt - 110.8 197.8 279.5 279.5
Cash Flow from Operations (1.2) (1.3) (1.6) (2.7) (6.8)
Cash Flow per Share (0.03) (0.03) (0.04) (0.06) (0.16)
Loss Attributable to Common Shareholders (1.3) (1.3) (1.6) (2.8) (7.0)
Loss per Share $ (0.03) $ (0.03) $ (0.04) $(0.07) (0.17)
- -------------------------------------------------------------------------------------------------------------
FINANCIAL POSITION
It was our stated intention at the start of the year to replace our senior
credit facility with long-term debt financing. In the second quarter of 2002 we
met this objective with the issuance of US$450 million of Senior Secured Notes,
bearing interest at 8.375%, and maturing on May 1, 2012. The net proceeds of
this offering were used to repay all amounts outstanding under our existing $535
million Senior Credit Facility, repay all amounts due to Shell and to fund our
share of remaining construction costs for the Project. The $535 million Senior
Credit Facility was cancelled upon repayment.
In conjunction with the offering, we established a new $100 million
senior credit facility with a syndicate of chartered banks; $75 million of which
will primarily be used to fund the first year's debt service under the offering
as well as construction completion costs; the remaining $25 million is for
working capital and letter of credit requirements. At December 31, 2002, $45.0
million had been drawn under this facility, with letters of credit issued in the
amount of $15.4 million.
We maintain our $88 million bridge note purchase facility, due October
2003, with a Canadian chartered bank. At December 31, 2002 the full $88 million
was drawn and outstanding on this facility (2001 - $NIL). The amounts drawn
under this facility are deemed to consist of both an equity and a liability
component, recognized as convertible notes in the financial statements. The
initial carrying amount of the equity component is adjusted for accretion to
bring it up to the stated principal amount of the facility at maturity. This
accretion is charged to the deficit.
In November 2002, we established a new $50 million working capital
facility with a syndicate of Canadian chartered banks, primarily to fund our
working capital requirements during start-up of the Project. At December 31,
2002, $20 million had been drawn under this facility. This working capital
facility was increased to $75 million in January 2003 with the addition of
another bank to the syndicate.
GRAPH: EVOLVING FINANCING STRUCTURE
Jun 99 $21.0 million equity
Jul 99 $41.7 million equity
Aug 99 $20.6 million equity
Nov 99 $40.0 million equity
Jul 00 $100 million debt
Sep 00 $130.0 million equity
Dec 00 $60.0 million equity
Feb 01 $3.7 million equity
Mar 01 $12 million debt
Apr 01 $10.0 million equity
Jun 01 $90 million debt
Jun 01 $30 million debt
Jun 01 $535 million debt
Jul 01 $57.9 million equity
Oct 01 $88 million debt
Oct 01 $47.4 million equity
Nov 01 $13.9 million equity
Apr 02 US$450 million debt
Apr 02 $100 million debt
Nov 02 $50 million debt
Feb 03 $50.2 million equity
Equity Financing
In February 2003, we issued 2,050,000 Common Shares at a price of $24.50 per
share for gross proceeds of approximately $50.2 million. The Common Shares were
offered to the public on a bought-deal basis through a syndicate of underwriters
led by TD Securities Inc. Net proceeds from the issue were used to fund
remaining costs for the Project and related expenses, for general corporate
purposes and to reduce some of our short-term borrowings.
Over the past three years one of our primary objectives has been to
fund our share of construction costs and to ensure that the timing of proceeds
from financings coincides with the funding requirements for the Project. We have
consciously structured our financing activities to maximize the value for our
shareholders by minimizing the amount of equity issued and to issue equity at
successively higher prices. These activities have resulted in 22 separate
financing transactions over the past three years totalling $2.2 billion of gross
proceeds and $1.5 billion net of re-financings. The chart above and accompanying
notes provide a snapshot of the debt and equity transactions that have allowed
us to participate in this exciting Project.
a. In June 1999, we issued 11 common shares at nominal value to
incorporate the Company and arranged a private placement of 6,096,343
Non-voting Convertible Equity Shares, 279,950 Class A Warrants and
823,707 Class B Special Warrants for aggregate gross proceeds of $21.0
million.
b. In July 1999, we arranged a private placement of 8,330,000 Units, each
Unit consisting of one Non-voting Convertible Equity Share and three
call obligations, for gross proceeds of $41.7 million. In conjunction
with this offering, the agent for the placement received a commission
of 138,071 Non-voting Convertible Equity Shares valued at $1.6 million
and a fee for services in connection with the acquisition of our
ownership interest in the Project was paid to the agent through the
issuance of a further 200,000 Non-voting Convertible Equity Shares.
c. In August 1999, we arranged a private placement of 2,750,000 Units,
each Unit consisting of one Non-voting Convertible Equity Share and 4.5
call obligations, for gross proceeds of $20.6 million.
d. In November 1999, we arranged a private placement of 4,705,882
Non-voting Convertible Equity Shares at a price of $8.50 per share for
proceeds of $40.0 million.
These first four equity transactions were completed in December 1999.
e. In July 2000, we established a $100 million bridge facility with a
Canadian Chartered Bank. This bridge facility was in place until
September 28, 2000, when we completed an equity offering of 10,709,076
Non-voting Convertible Equity Shares, of which 1,491,084 were issued on
a flow-through basis, for aggregate gross proceeds of $130.0 million.
At this time the bridge facility was cancelled.
f. In December 2000, we completed our Initial Public Offering on to the
Toronto Stock Exchange, which involved the issuance of 4,000,000 Common
Shares for gross proceeds of $60.0 million.
g. On February 1, 2001, we filed two prospectuses qualifying the issuance
of an aggregate of 34,033,029 Common Shares, 494,224 Class A Warrants
and 465,188 Class B Warrants issuable upon the conversion or exercise,
as the case may be, of the Non-voting Convertible Equity Shares, Class
A Special Warrants, Class B Special Warrants and Warrant Options issued
in prior years by the Corporation. Subsequently, in February and March
2001, the 465,188 Class B Warrants were exercised into Common Shares
for aggregate gross proceeds of $3.7 million.
h. On March 14, 2001, we completed a private placement of 666,667 Class D
Preferred Shares, Series A, for gross proceeds of $12 million. Each
Class D Preferred Share is convertible into one Common Share prior to
redemption, which is at our option at any time at a price equal to
their issue price plus a cumulative dividend of 12 per cent per year
compounded semi-annually until January 1, 2007, increasing by 3 per
cent per quarter thereafter to a maximum of 24 per cent per year.
i. On April 27, 2001, we completed a private placement of 625,000 Common
Shares at $16.00 per share issued on a flow-through basis, for gross
proceeds of $10.0 million.
j. We entered into a bridge financing arrangement in March 2001 for up to
$90 million, and a second bridge financing arrangement in June 2001 for
$30 million, both of which were considered as equity for purposes of
the Senior Credit Facility. These two bridge facilities totalling $120
million were required to be repaid by October 31, 2001.
k. We satisfied the conditions precedent on our $535 million Senior Credit
Facility in June 2001 and commenced drawdowns under this facility to
meet our ongoing commitments to the construction of the Project. The
conditions precedent that were required were customary for facilities
of this nature, and included a requirement that an aggregate of $400
million of our equity capital be expended on the Athabasca Oil Sands
Project. The Senior Credit Facility was available for funding the
budgeted construction costs of the
Project of up to $485 million. Additionally, the Senior Credit Facility
was available for pre-completion debt servicing, which included
interest costs and fees under the Senior Credit Facility, of up to $50
million. Under the terms of the Senior Credit Facility, we were
obligated to obtain, and continue to maintain, $200 million of cost
overrun insurance. The Senior Credit Facility was repaid in full and
cancelled upon completion of the US$450 million Senior Secured Notes
offering in April 2002.
l. On July 25, 2001, we completed an equity private placement to certain
of our existing shareholders of 3,404,729 Non-voting Convertible Equity
Shares at $13.00 and $14.00 per share, together with 725,589 Non-voting
Convertible Equity Shares issued on a flow-through basis at $15.60 per
share, for aggregate gross proceeds of $57.9 million. In conjunction
with this offering, 2,589,641 Call Obligations were issued to certain
subscribers, whereby each Call Obligation is exercisable into one
Non-voting Convertible Equity Share and one Warrant to purchase
Non-voting Convertible Equity Share upon the payment of $13.00 per Call
Obligation. These call obligations are exercisable until March 31, 2003
at our discretion and the underlying warrant is exercisable, at the
market price on the day we exercise our rights under the call
obligations, for a period of four years after the call obligation
exercise. There is a requirement imposed by the TSE to undertake a
rights offering prior to exercising any of these Call Obligations. At
this time, certain shareholders also undertook to subscribe for 725,590
Non-voting Convertible Equity Shares on a flow-through basis at $15.60
per share, which were subscribed for and issued in November 2001.
m. On October 25, 2001, we established a new $88 million two-year bridge
note purchase facility ("Bridge Facility") with a Canadian Chartered
Bank. The notes issuable pursuant to draws on the Bridge Facility are
convertible, at maturity at our option, and in the event of a default
at the option of the bank into Common Shares. This Bridge Facility
replaced the existing $90 million and $30 million bridge facilities and
was required in order to satisfy the sufficiency of funding criteria of
the Senior Credit Facility, in order to demonstrate that we can meet
our funding obligations to the Project. This Bridge Facility was fully
drawn upon as at December 31, 2002.
n. On October 25, 2001, we completed a rights offering to existing
shareholders of 3,384,835 Common Shares at a price of $14.00 per share
for gross proceeds of $47.4 million.
o. In November 2001, we completed a private placement of 150,000
Non-voting Convertible Equity Shares issued on a flow-through basis at
$17.30 per share for gross proceeds of $2.6 million. At this time, the
undertakings for 725,590 Non-voting Convertible Equity Shares on a
flow-through basis from July were also subscribed to, for gross
proceeds of $11.3 million. In addition to the new equity raised,
another prospectus was filed on November 27, 2001, which qualified for
issuance an aggregate of 5,005,908 Common Shares issuable upon
conversion of all the Non-voting Convertible Equity Shares that were
issued in 2001.
p. In April 2002, we completed the issuance of US$450 million of Senior
Secured Notes, bearing interest fixed at 8.375%, and maturing on May 1,
2012 The net proceeds of the offering were used to repay all amounts
outstanding under the existing Senior Credit Facility and repay all
amounts due to Shell Canada Limited, with the balance of the proceeds
placed in a trust account, which were used for funding the Company's
share of remaining construction costs for the oil sands project. The
Senior Credit Facility was cancelled upon repayment.
In conjunction with the offering, we established a new $100 million
credit facility with a syndicate of chartered banks; $75 million of
which will primarily be used to fund the first year's debt service
under the offering as well as construction completion costs; the
remaining $25 million is for working capital and letter of credit
requirements. At December 31, 2002, $45.0 million had been drawn under
this facility, with letters of credit also issued for $15.4 million.
q. In November 2002, we established a new $50 million Working Capital
Facility with a syndicate of Canadian chartered banks, primarily to
fund our working capital requirements during start-up of the Project.
This facility was increased to $75 million in January 2003 with the
addition of another bank to the syndicate.
r. Subsequent to year-end, we completed the issuance of 2,050,000 Common
Shares at a price of $24.50 per share for gross proceeds of
approximately $50.2 million. The Common Shares were offered to the
public on a bought-deal basis through a syndicate of underwriters led
by TD Securities Inc. Net proceeds from the issue will be used to fund
remaining costs for the Project and related expenses, for general
corporate purposes and may be used to reduce some of our short-term
borrowings.
GRAPH: 2002 CASH MOVEMENTS ($ MILLIONS)
Cash, Beginning of Year 53.0
Net Equity Issued 2.0
Capital Expenditures -527.5
Debt Raised 494.3
Working Capital - 13.9
Deferred Charges - 17.9
G&A - 8.6
Convertible Notes 86.7
Shell Loan Repaid - 53.7
Cash, End of Year 14.4
At December 31, 2002, our equity capital consisted of:
ISSUED AND OUTSTANDING:
Common Shares 47,742,471
Class D Preferred Shares, Series A 666,667
------------
- --------------------------------------------------------------------------------
48,409,138
OUTSTANDING:
Class A Warrants 494,224
Stock Options 1,329,000
------------
- --------------------------------------------------------------------------------
Fully diluted number of shares 50,232,362
- --------------------------------------------------------------------------------
Analysis of Cash Resources
We have been financing Project costs out of equity and debt proceeds throughout
2002. Our cash balances decreased by $38.6 million during 2002 from $53.0
million at December 31, 2001 to $14.4 million at December 31, 2002. Cash inflows
were comprised of $494.3 million of long-term debt issued during the year (net
of repayments), $86.7 million of convertible debt issued in the year (net of
interest paid) and $2.0 million of equity capital (net of issue costs) raised
throughout the year. Cash outflows included capital expenditures of $527.5
million, debt issue costs and deferred charges of $17.9 million, a $13.9 million
increase in working capital throughout the year and cash corporate expenses of
$8.6 million. In addition, we repaid a liability owed to Shell Canada Limited of
$53.7 million.
RISK AND SUCCESS FACTORS RELATING TO OIL SANDS
We face a number of risks that we need to manage in conducting our business
affairs. The following discussion identifies some of the key areas of exposure
for us and, where applicable, sets forth measures undertaken to reduce or
mitigate these exposures. A complete discussion of risk factors that may impact
our business is provided in our Annual Information Form.
Business Risks
We are currently a single purpose company, our only asset being our investment
in oil sands through the Project. As such, all capital expenditures are directly
or indirectly related to oil sands construction and development and 100 per cent
of revenues will be derived from oil sands operations.
At this stage, the main risks to the Project execution include the
potential for reduced productivity and increased costs that can be associated
with weather or unforeseen disruptions in the supply of labour. While the design
of the Project facilities mainly utilizes established technologies, the
commissioning and start-up of the new facilities could result in delays in
achieving the targeted production capacity of 155,000 barrels per day by the
third quarter of 2003.
We may be faced with competition from other industry participants in
the oil sands business. This could take the form of competition for skilled
people, increased demands on the Fort McMurray infrastructure (housing, roads,
schools, etc.), or higher prices for the products and services required to
operate and maintain the plant.
Our relationship with our employees and provincial building trade
unions is important to our future success because poor productivity and work
disruptions have the potential to adversely affect the Project, whether in
construction or in operations. New labour agreements with the building trades
were ratified in August 2001. While we are not a direct party to these
agreements, they impact us as these trades have supplied the labour during the
construction phase of the Project. Although we are now entering an operating
phase we have significant plans for expansion and the strong working
relationship the Project's management has developed with the trade unions will
be an important factor in our future activities.
The Project depends upon successful operation of facilities owned and
operated by third parties. The Joint Venture partners are party to certain
agreements with third parties to provide for, among other things, the following
services and utilities:
o pipeline transportation to be provided through the Corridor Pipeline;
o electricity and steam to be provided to the Mine and the extraction plant
from the Muskeg River cogeneration facility;
o transportation of natural gas to the Muskeg River cogeneration facility by
the ATCO pipeline;
o hydrogen to be provided to the Upgrader from the HMU and Dow Chemicals
Canada Inc., or Dow; and
o electricity and steam to be provided to the Upgrader from the Upgrader
cogeneration facility.
All of these third party arrangements are critical for the successful
start-up and operation of the Project. Disruptions in respect of these
facilities could have an adverse impact on future financial results.
Once the Project is operational, we will be subject to the operational
risks inherent in the oil sands business. We intend to sell our share of
synthetic crude oil production to refineries in North America. These sales will
compete with the sales of both synthetic and conventional crude oil. There exist
other suppliers of synthetic crude oil and there are several additional projects
being contemplated. If undertaken and completed, these projects will result in a
significant increase in the
supply of synthetic crude oil to the market. In addition, not all refineries are
able to process or refine synthetic crude oil. There can be no assurance that
sufficient market demand will exist at all times to absorb our share of the
Project's light synthetic crude oil production.
As a partner in the Athabasca Oil Sands Joint Venture, we actively
participate in operational risk management programs implemented by the Joint
Venture to mitigate the above risks. Our exposure to operational risks is also
managed by maintaining appropriate levels of insurance.
Financial Risks
We must finance our share of the construction costs of the Project in the face
of uncertain debt and equity capital markets and in a volatile commodity-pricing
environment. Should the costs of the Project exceed the available financial
resources and we are unable to establish sufficient funding to complete the
Project under the current debt arrangements, additional financing may be
required.
On the basis of the current estimate of costs for construction of the
Project, we have funding arrangements that are sufficient to cover our share of
costs. An increase in the costs for completion of the Project beyond the current
estimate may result in us raising additional equity or debt in order to meet our
share of cost commitments.
As part of our financing plan, we established a cost overrun/project
delay insurance policy in the amount of $200 million. This insurance policy
covers certain costs, expenses and losses of revenue through the construction
period arising from causes beyond our control and including: (i) costs and
expenses or loss of revenues arising from a delay in achieving a guaranteed
production level; (ii) costs and expenses incurred in connection with the
modification, repair or replacement of equipment or material, which are directly
related to achieving guaranteed production levels; and (iii) escalation in
Project costs beyond the budgeted Project costs, which are directly related to
achieving guaranteed production levels. In effect, the program provides coverage
for increased costs for the project of up to $200 million to the extent the
increased costs are incurred to meet bitumen production levels of 155,000
barrels per day as contemplated in the initial design of the project.
This insurance policy will mitigate a portion of the cost increases for
the project beyond the initial project budget of $709 million (our share). We
engaged claims consultants in the first quarter of 2002, and by year-end we had
filed interim claims for cost overruns totalling $435 million and interim claims
for loss of revenues arising from delays in production totalling $9.3 million.
The forecasted total claim for loss of revenues, to be submitted prior to
achieving commercial production in the second quarter of 2003, is expected to be
in excess of $100 million. To date, we have not received any proceeds from the
insurance policy and no amounts have been reflected in the Consolidated
Financial Statements. We have been frustrated by the lack of response on the
part of the insurers and in January 2003 we were forced to raise $50.2 million
of additional equity financing as a direct result of these delays. While we hope
that insurance proceeds will be forthcoming, further delays may put additional
pressure on our financial condition.
In addition to the cost overrun insurance obtained by us, the Joint
Venture partners have obtained insurance to protect against certain risks of
loss during the construction of the Owners' facilities, which includes the Mine,
extraction plant and the Upgrader. The insurance is typical for a project of
this nature.
Upon commencement of operations, we intend to obtain insurance designed
to protect our ownership interest against losses or damage to the Owners'
facilities, to preserve our operating income and to protect against our risk of
loss to third parties and which is reasonably obtainable.
Once in production, our financial results will be dependent upon the
prevailing price of crude oil. Oil prices fluctuate significantly in response to
supply and demand factors beyond our control, which could have an impact on
future financial results.
As at December 31, 2002 we have entered into various commodity pricing
agreements designed to mitigate exposure to the volatility of crude oil prices
in Canadian dollars. The agreements are summarized as follows:
Notional Hedge Price Unrealized
Volume Period Received Gain/(Loss)
- -------------------------------------------------------------------------------------------------------
WTI Swaps 4,500 bbls/d April 1, 2003 to March 31, 2004 Cdn$39.72 ($1.1 million)
WTI Swaps 8,500 bbls/d April 1, 2004 to March 31, 2005 Cdn$36.95 ($1.5 million)
- -------------------------------------------------------------------------------------------------------
We do not expect that the adoption of the new CICA Accounting Guideline
13 "Hedging Relationships", effective for fiscal years beginning on or after
July 1, 2003, will have an impact on our consolidated financial statements.
Any prolonged period of low oil prices could result in a decision by
the Joint Venture partners to suspend or reduce production. Any such suspension
or reduction of production would result in a corresponding substantial decrease
in our future revenues and earnings and could expose us to significant
additional expense as a result of certain long-term contracts. In addition,
because natural gas comprises a substantial part of operating costs, any
prolonged period of high natural gas prices could negatively impact our future
financial results.
We will also be exposed to fluctuations in changes in currency and
interest rates, which may impact our financial results and our ability to
service our debt financing.
To mitigate our exposure to these financial risks, we will be
establishing a financial risk management program in consultation with our Board
of Directors prior to commencement of operations.
Environmental Risks
Canada is a signatory to the December 1997 Kyoto Treaty with respect to
instituting reductions to greenhouse gases. The Project will be a significant
producer of some greenhouse gases covered by the treaty. While specific measures
for meeting Canada's commitments have not been developed and the Kyoto treaty
may be modified or nullified, actions taken under the treaty may adversely
impact the Project. It cannot be assured that future environmental approvals,
laws or regulations will not adversely impact the Joint Venture partners'
ability to operate the Project or increase or maintain production or will not
increase unit costs of production. Equipment from suppliers that can meet future
emission standards may not be available on an economic basis, or at all, and
other methods of reducing emissions to required levels may significantly
increase operating costs or reduce output. There is a risk that the Canadian
federal and/or provincial governments could pass legislation that would tax such
emissions or require, directly or indirectly, reductions in such emissions
produced by energy industry participants, including the Project.
We will be responsible for compliance with terms and conditions set
forth in the Project's environmental and regulatory approvals and all laws and
regulations regarding the decommissioning and abandonment of the Project and
reclamation of its lands. The costs related to these activities may be
substantially higher than anticipated. It is not possible to accurately predict
these costs since they will be a function of regulatory requirements at the time
and the value of the equipment salvaged. In addition, to the extent we do not
meet the minimum credit rating required under the Joint Venture agreement, we
must establish and fund a reclamation trust fund. We currently do not hold the
minimum credit rating. Even if we do hold the minimum credit rating, in the
future it may be determined that it is prudent or be required by applicable laws
or regulations to establish and fund one or more additional funds to provide for
payment of future decommissioning, abandonment and reclamation costs. Even if we
conclude that the establishment of such a fund is prudent or required, we may
lack the financial resources to do so.
The Joint Venture partners have established programs to monitor and
report on environmental performance including reportable incidents, spills and
compliance issues. In addition, comprehensive quarterly reports are prepared
covering all aspects of health, safety and sustainable development on Lease 13
and the Upgrader to ensure that the Project is in compliance with all laws and
regulations and that management are accountable for performance set by the Joint
Venture partners.
OUTLOOK
Key milestones for 2003 include revenues from production of synthetic crude
expected to commence in the first quarter of 2003 when the Upgrader facilities
will be brought on stream and production will ramp-up through the second half of
2003. Full bitumen production of 155,000 barrels per day (31,000 barrels per day
net to us) is scheduled to occur by the third quarter of 2003.
Non-bitumen feedstocks supplied to the Upgrader to aid in the upgrading
process will add an additional 35,000 barrels per day to the Project's output.
Our share of total output will be 38,000 barrels per day. We are committed to
sell 12,000 barrels per day of Vacuum Gas Oil (VGO) to Shell at a fixed
differential to market. We will be marketing the balance of our production
volumes for our own account to various refineries in North America.
The following table details the sensitivities of cash flow and net
earnings per share to certain relevant operating factors during 2004, which will
be our first year of full production. The base case upon which the sensitivities
are reflected assumes bitumen production for us of 31,000 barrels per day,
constant WTI at US$22.00 per barrel, a foreign exchange rate of US$0.65 per
Cdn$, a constant Alberta gas cost of Cdn$4.51 per thousand cubic feet and
reflects the additional shares issued in the February 2003 equity offering.
Basic Basic
Cash Flow Cash Flow Earnings Earnings
Variable Variation ($millions) Per Share ($millions) Per Share
- ----------------------------------------------------------------------------------------------------------
Production 1,000 bbls/day $ 12.17 $ 0.24 $ 7.60 $ 0.15
Oil Prices USD $1.00 $ 17.23 $ 0.34 $ 11.03 $ 0.22
Gas Prices $0.10/Mcf $ 0.71 $ 0.01 $ 0.46 $ 0.01
Foreign Exchange (1) USD/CDN .01 $ 5.62 $ 0.11 $ 3.60 $ 0.07
- ----------------------------------------------------------------------------------------------------------
(1) Excludes unrealized foreign exchange gains or losses on long-term monetary
items. The impact of the Canadian dollar strengthening by US $0.01 would be
an increase of $10.5 million in net earnings based on December 31, 2002 US
dollar donominated debt levels.
Our vision is to complete this Project and then expand our production
base through development of the remaining oil sands leases we have access to
under the Joint Venture agreement with our partners. The initial Project will
develop a total of 1.7 billion barrels (336 million barrels is our share) out of
a total resource base on Leases 13, 88, 89 and 90
estimated at 8.8 billion barrels (1.8 billion barrels is our share). Our
partners or we have not yet begun development of the remaining resources on our
leases, but we have begun evaluating long-term development plans. Any such
development plans would be subject to approval by the board of directors of each
Joint Venture partner, various regulatory agencies and other stakeholders, and
would require significant funding obligations.
The potential development plans include two areas of expansion.
Firstly, an optimization and expansion of the Muskeg River Mine and Lease 90 has
the potential to increase bitumen production to 225,000 barrels per day (45,000
barrels per day net to us) and would likely take place in the 2006 to 2007 time
frame. Secondly, there is an opportunity for a new stand-alone mine on the
eastern portion of Lease 13 and Leases 88 and 89, known as the Jackpine Mine,
which would add a potential 300,000 barrels per day (60,000 barrels per day net
to us) of bitumen production. The Jackpine Mine development would follow the
expansion of the Muskeg River Mine. The Joint Venture Owners filed a Public
Disclosure Document in respect of these development opportunities on August 8,
2001. The graph below outlines the potential effect on bitumen production per
day assuming the development plans are undertaken successfully.
GRAPH: DEVELOPMENT POTENTIAL (BARRELS PER DAY)
DOCUMENT 3
----------
AUDITORS' REPORT
TO THE SHAREHOLDERS OF WESTERN OIL SANDS INC.
We have audited the consolidated balance sheets of Western Oil Sands Inc. as at
December 31, 2002 and 2001 and the consolidated statements of operations and
deficit, and cash flows for the years then ended. These financial statements are
the responsibility of the Corporation'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 Western Oil Sands Inc. as at
December 31, 2002 and 2001 and the results of its operations and its cash flows
for the years then ended in accordance with Canadian generally accepted
accounting principles.
/s/ "PRICEWATERHOUSECOOPERS LLP"
Chartered Accountants
Calgary, Canada
February 14, 2003
1
WESTERN OIL SANDS INC.
CONSOLIDATED BALANCE SHEETS
December 31 2002 2001
================================================================================
($ THOUSANDS)
ASSETS
Current Assets
Cash $ 14,428 $ 52,973
Accounts receivable 6,624 7,228
Inventory 4,175 --
- --------------------------------------------------------------------------------
25,227 60,201
- --------------------------------------------------------------------------------
Capital Assets (Note 3) 1,306,989 761,939
Deferred Charges (Note 4) 27,422 32,254
- --------------------------------------------------------------------------------
1,334,411 794,193
- --------------------------------------------------------------------------------
$ 1,359,638 $ 854,394
================================================================================
LIABILITIES
Current Liabilities
Accounts payable and accrued liabilities $ 40,953 $ 51,222
Convertible Notes (Note 5) 4,055 --
- --------------------------------------------------------------------------------
45,008 51,222
Long-term Liabilities
Long-term Debt (Note 6) 775,820 279,481
Other (Note 8) 50,859 88,825
Future Income Taxes (Note 7) 454 --
- --------------------------------------------------------------------------------
827,133 368,306
- --------------------------------------------------------------------------------
872,141 419,528
- --------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share Capital (Note 9) 426,275 447,303
Convertible Notes (Note 5) 83,945 --
Deficit (22,723) (12,437)
- --------------------------------------------------------------------------------
487,497 434,866
- --------------------------------------------------------------------------------
$ 1,359,638 $ 854,394
================================================================================
SEE ACCOMPANYING NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Approved by the Board of Directors:
/s/ "ROBERT G. PUCHNIAK" /s/ "BRIAN F. MACNEILL"
- ------------------------------------ --------------------------------------
Robert G. Puchniak Brian F. MacNeill
Director Director
2
WESTERN OIL SANDS INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
Year ended December 31 2002 2001
================================================================================
($ THOUSANDS, EXCEPT AMOUNTS PER SHARE)
CORPORATE EXPENSES
General and administrative $ 5,698 $ 5,310
Depreciation 192 170
Write-off of deferred financing costs 22,759 --
- --------------------------------------------------------------------------------
LOSS BEFORE INCOME TAXES 28,649 5,480
Income Taxes (Note 7) (19,646) 1,535
- --------------------------------------------------------------------------------
NET LOSS $ 9,003 $ 7,015
Charge for Convertible Notes (Note 5) 1,283 --
- --------------------------------------------------------------------------------
LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS 10,286 7,015
================================================================================
Deficit at Beginning of Year 12,437 5,422
- --------------------------------------------------------------------------------
Deficit at End of Year $ 22,723 $ 12,437
================================================================================
Loss per share (Note 9) - Basic and diluted $ 0.21 $ 0.17
- --------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
3
WESTERN OIL SANDS INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31 2002 2001
================================================================================
($ THOUSANDS)
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
Net loss $ (9,003) $ (7,015)
Non-cash items:
Write-off of deferred financing costs 22,759 --
Future Income Tax recovery (22,551) --
Depreciation 192 170
- --------------------------------------------------------------------------------
CASH FROM OPERATIONS (8,603) (6,845)
Increase in non-cash working capital (Note 14) (7,965) --
- --------------------------------------------------------------------------------
(16,568) (6,845)
- --------------------------------------------------------------------------------
FINANCING ACTIVITIES
Issue of share capital 1,977 143,978
Issue of long-term debt 773,840 279,481
Repayment of long-term debt (279,481) --
Deferred financing costs (17,927) (16,366)
Issue of convertible notes 88,000 --
Charge for convertible notes (1,283) --
Repayment of long-term liabilities (53,687) (2,152)
- --------------------------------------------------------------------------------
CASH GENERATED 511,439 404,941
- --------------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (527,541) (433,604)
Restricted cash -- 12,601
Increase in non-cash working capital (Note 14) (5,875) (18,231)
- --------------------------------------------------------------------------------
CASH INVESTED (533,416) (439,234)
- --------------------------------------------------------------------------------
Decrease in Cash (38,545) (41,138)
Cash at Beginning of Year 52,973 94,111
- --------------------------------------------------------------------------------
CASH AT END OF YEAR $ 14,428 $ 52,973
================================================================================
SEE ACCOMPANYING NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
4
WESTERN OIL SANDS INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(TABULAR DOLLAR AMOUNTS IN $ THOUSANDS)
1. BUSINESS OF THE CORPORATION
Western Oil Sands Inc. (the "Corporation") was incorporated on June 18,
1999 under the laws of the Province of Alberta. The Corporation was created
to acquire a 20 per cent working interest in an oil sands project in the
Athabasca region of northeast Alberta ("the Oil Sands Project"). The oil
sands project will consist of direct or indirect participation in the
design, construction and operation of mining, extracting, transporting and
upgrading of oil sands deposits.
2. SUMMARY OF ACCOUNTING POLICIES
(a) PRINCIPLES OF CONSOLIDATION The consolidated financial statements include
the accounts of the Corporation and its wholly-owned subsidiary
corporations and limited partnership, 852006 Alberta Limited, Western Oil
Sands, L.P., Western Oil Sands Finance Inc. (inactive) and Western Oil
Sands (USA) Inc. (inactive). The Corporation's oil sands activities are
conducted jointly with others. These financial statements reflect only the
Corporation's proportionate interest in such activities.
(b) MEASUREMENT UNCERTAINTY 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 at the date of the financial statements,
and the reported amounts of revenues and expenses during the reporting
period.
(c) CAPITAL ASSETS Capital assets are recorded at cost less accumulated
provisions for depreciation, depletion and amortization. Capitalized costs
include costs specifically related to the acquisition, exploration,
development and construction of the oil sands project. Capital assets are
reviewed for impairment whenever events or conditions indicate that their
net carrying amount may not be recoverable from estimated future cash
flows.
Depletion over the life of proved and probable reserves is on a unit of
production basis, commencing when the facilities are substantially complete
and after commercial production has begun. Capital assets are depreciated
on a straight-line basis over their useful lives, except for lease
acquisition costs and certain mine assets, which are amortized and
depreciated over the life of proved and probable reserves. The estimated
useful lives of depreciable capital assets are as follows:
Leasehold improvements 5 years
Furniture and fixtures 5 years
Computers 3 years
(d) FUTURE SITE RESTORATION Estimated future site restoration and reclamation
costs are provided on a unit of production method based on estimated proved
and probable reserves. Actual costs are charged against the provision when
incurred.
5
(e) FOREIGN CURRENCY TRANSLATION Transactions in foreign currencies are
translated into Canadian dollars at exchange rates prevailing at the
transaction dates. Monetary assets and liabilities denominated in a foreign
currency are translated into Canadian dollars at rates of exchange in
effect at the end of the period while non-monetary assets and liabilities
are translated at historical rates of exchange.
(f) STOCK-BASED COMPENSATION PLAN The Corporation has a stock-based
compensation plan which is described in Note 10. Effective January 1, 2002,
the Corporation adopted CICA 3870 "Stock-based Compensation and Other
Stock-based Payments". The new standard is applied prospectively to all
stock-based payments to non-employees and to employee awards that are
direct awards of stock, stock appreciation rights and similar awards to be
settled in cash. The new standard is applied to all grants of stock options
on or after January 1, 2002. No compensation expense is recognized for the
plan when the stock options are issued. Any consideration received on
exercise of stock options is credited to share capital.
(g) CONVERTIBLE NOTES Amounts drawn under the Note Purchase Facility are deemed
to consist of both an equity and a liability component in accordance with
Canadian GAAP. The initial carrying amount of the equity component is
adjusted for accretion to bring it up to the stated principal amount of the
Note Purchase Facility at maturity. This accretion is charged to the
Deficit.
(h) DERIVATIVE FINANCIAL INSTRUMENTS Financial instruments are used by the
Corporation to hedge its exposure to market risks relating to commodity
prices and foreign currency exchange rates. The Corporation's policy is not
to utilize financial instruments for speculative purposes.
The Corporation formally documents all relationships between hedging
instruments and hedged items as well as its risk management objectives and
strategies for undertaking various hedge transactions. This process
includes linking all derivatives to specific assets and liabilities on the
balance sheet or to specific firm commitments or forecasted transactions.
The Corporation also assesses, both at the hedges' inception and on an
ongoing basis, whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in fair values or
cash flows of hedged items.
The Corporation enters into hedges with respect to a portion of its oil
production to achieve a more predictable cash flow by reducing its exposure
to price and currency fluctuations. These transactions are entered into
with major Canadian financial institutions. Gains and losses from these
financial instruments are recognized in oil revenues as the hedge sale
transactions occur.
(i) INVENTORY Inventory is stated at the lower of average cost and net
realizable value.
(j) LOSS PER SHARE The Corporation uses the treasury stock method to determine
the dilutive effects of stock options and other dilutive instruments. Due
to losses for the years presented, all incremental shares have been
excluded from the diluted earnings per share calculation as the effect
would be anti-dilutive.
(k) CASH Cash presented in the consolidated financial statements is comprised
of cash and cash equivalents and includes short-term investments with a
maturity of three months or less when purchased.
6
(l) PENSION PLAN The Corporation has a defined contribution pension plan.
Expense is recognized as payments are made or entitlements are earned.
Expense for the year ended December 31, 2002 was $0.09 million (December
31, 2001 - $0.2 million).
(m) COMPARATIVE AMOUNTS Certain comparative amounts have been reclassified to
conform to the current year's presentation.
3. CAPITAL ASSETS
2002 2001
================================================================================
Oil Sands Project $ 1,243,061 $ 721,043
Oil Sands Project assets under capital lease 50,859 35,138
Corporate Assets 13,601 6,098
- --------------------------------------------------------------------------------
1,307,521 762,279
Less: accumulated depreciation (532) (340)
- --------------------------------------------------------------------------------
$ 1,306,989 $ 761,939
================================================================================
It is the Corporation's policy to capitalize carrying costs including interest
expense for capital assets acquired, constructed or developed over time. As at
December 31, 2002, $63.6 million of net interest expense (December 31, 2001 -
$15.5 million) has been capitalized as part of the cost of the oil sands
project. Cash interest paid for the year ended December 31, 2002 was $40.6
million (December 31, 2001 - $6.7 million). Cash interest received for the year
ended December 31, 2002 was $2.3 million (December 31, 2001 - $2.9 million).
4. DEFERRED CHARGES
2002 2001
- --------------------------------------------------------------------------------
Deferred charges $ 27,422 $ 32,254
================================================================================
Deferred charges include primarily debt financing costs that have been incurred
in establishing the Corporation's various debt facilities. These amounts will be
amortized over the term of the related debt facilities following start-up of the
oil sands project.
5. CONVERTIBLE NOTES
On October 25, 2001 the Corporation established an $88 million two-year Note
Purchase Facility (the "Note Purchase Facility") with a Canadian chartered bank.
The notes issuable pursuant to draws on the Note Purchase Facility are
convertible, at maturity at the option of the Corporation and in the event of a
default at the option of the bank, into Common Shares of the Corporation. If
converted, the conversion would be transacted at 95 per cent of the weighted
average trading price on the TSX for the twenty days prior to conversion. The
maturity date is October 25, 2003. Borrowings under the Note Purchase Facility
bear interest at the bank's prime lending, the bankers' acceptance or the LIBOR
rates plus applicable margins ranging from 125 to 225 basis points. The Note
Purchase Facility is unsecured and was fully drawn at December 31, 2002.
7
6. LONG-TERM DEBT
2002 2001
================================================================================
US$450 million Senior Secured Notes $710,820 --
Bank Debt $ 65,000 $ 279,481
- --------------------------------------------------------------------------------
$775,820 $ 279,481
================================================================================
(a) On April 23, 2002, the Corporation issued Senior Secured Notes in the
amount of US$450 million, bearing interest at 8.375%, with a maturity of
May 1, 2012 (the "Offering"). The net proceeds of the Offering were used to
repay all amounts outstanding under the Corporation's $535 million bank
facility (which was cancelled upon repayment) and repay all amounts due to
Shell Canada Limited, with the balance of the proceeds used to fund the
Corporation's share of remaining construction costs for the oil sands
project. The Senior Secured Notes provide the holders with security over
all the assets of the Corporation, subordinated to the Senior Credit
Facility, until the Corporation achieves an investment grade corporate
credit rating, at which time the Senior Secured Notes become unsecured.
(b) In conjunction with the Offering, the Corporation established a new $100
million Senior Credit Facility (the "Senior Credit Facility") with a
syndicate of Canadian chartered banks, up to $75 million of which will be
used to fund the first year's debt service under the Offering and
construction completion costs; the remaining $25 million will be used for
working capital and letter of credit requirements. Borrowings under the
facility bear interest at the lenders' prime lending, the bankers'
acceptance or the LIBOR rates plus applicable margins ranging from 100 to
200 basis points. $75 million of the Senior Credit Facility matures and is
repayable by April 23, 2005. The Senior Credit Facility contains certain
covenants and other provisions, which restrict the Corporation's ability to
incur additional indebtedness, pay dividends or make distributions of any
kind, undertake an expansion of the oil sands project, dispose of its
interest in the oil sands project, or change the nature of its business.
The Senior Credit Facility provides the banks with security over all of the
assets of the Corporation, with the exception of certain intercompany notes
and note guarantees issued in connection with the Offering detailed in Note
6(a). At December 31, 2002, an amount of $45 million had been drawn under
this Senior Credit Facility and letters of credit for $15.4 million had
been issued.
(c) On November 19, 2002, the Corporation established a $50 million 364-day
Extendible Revolving Credit Facility (the "Revolving Facility") with a
syndicate of Canadian chartered banks. Borrowings under the Revolving
Facility bear interest at the lenders' prime lending, the bankers'
acceptance or the LIBOR rates plus applicable margins ranging from 100 to
200 basis points. The Revolving Facility provides the banks with security
over all of the assets of the Corporation, with the exception of certain
intercompany notes and note guarantees in connection with the Offering
detailed in Note 6(a). The Revolving Facility contains a two-year term-out
provision should the facility not be renewed. At December 31, 2002, an
amount of $20 million had been drawn under this facility.
(d) The Corporation defers all issue costs and charges relating to the
Corporation's existing debt facilities prior to commencement of commercial
operations, and will amortize the charges thereafter. Upon completion of
the Offering, $22.8 million of such costs (representing amounts not related
to continuing debt facilities) were written off.
8
7. INCOME TAXES
2002 2001
- --------------------------------------------------------------------------------
Large Corporations Tax $ 2,905 $ 1,535
Future Income Tax (22,551) --
- --------------------------------------------------------------------------------
INCOME TAX (RECOVERY) EXPENSE $(19,646) $ 1,535
================================================================================
Cash taxes paid during the year ended December 31, 2002 were $2.4 million
(December 31, 2001 - $1 million) and related solely to Large Corporations Tax.
At December 31, 2002, the future income tax liability consists of:
2002 2001
- --------------------------------------------------------------------------------
Future Income Tax assets
Net losses carried forward $ 19,069 $ 11,584
Share issue costs 2,096 3,191
Debt issue costs 1,386 --
Future Income Tax liabilities
Renunciation of deductions for flow-through shares (23,005) --
Debt issue costs -- (4,132)
Less: valuation allowance -- (10,643)
- --------------------------------------------------------------------------------
NET FUTURE INCOME TAX LIABILITY $ (454) $ --
================================================================================
The following table reconciles income taxes calculated at the Canadian statutory
rate of 42.12% (2001 - 42.62%) with actual income taxes:
2002 2001
- --------------------------------------------------------------------------------
Loss before income taxes $(28,649) $ (5,480)
Income tax recovery at statutory rate (12,067) (2,336)
Unrecognized benefit of losses -- 2,336
Recognition of losses brought forward (10,484) --
Large Corporations Tax 2,905 1,535
- --------------------------------------------------------------------------------
INCOME TAX (RECOVERY) EXPENSE $(19,646) $ 1,535
================================================================================
The tax loss carry forward balances as evaluated at December 31, 2002 and the
expiry dates are as follows:
YEAR CREATED AMOUNT EXPIRY
======================================================
1999 $ 1.2 million 2006
2000 $ 11.7 million 2007
2001 $ 8.8 million 2008
2002 $ 23.6 million 2009
======================================================
In addition, at December 31, 2002, the Corporation had approximately $1.1
billion of tax pools available.
9
8. OTHER LONG-TERM LIABILITIES
2002 2001
================================================================================
Capital lease obligation $50,859 $35,138
Payable to Shell Canada Limited -- 53,687
- --------------------------------------------------------------------------------
$50,859 $88,825
================================================================================
The capital lease obligation relates to the Corporation's share of capital costs
for the hydrogen-manufacturing unit within the oil sands project. Repayment of
the principal obligation is scheduled to be $0.7 million in 2003 and $1.3
million per annum thereafter until fully repaid.
The Corporation was obligated to pay $40 million to acquire an interest in the
lease and to compensate the vendor of the interest for the benefit of existing
infrastructure at the Upgrader site. The Corporation elected to defer payment of
the $40 million by paying an annual deferral charge which includes interest plus
an adjustment for income taxes, until the Corporation issued the Senior Secured
Notes, part of the proceeds of which were used to repay all amounts due to Shell
Canada Limited.
9. SHARE CAPITAL
(a) AUTHORIZED The Corporation is authorized to issue an unlimited number of
Class A shares ("Common Shares"), an unlimited number of non-voting
Convertible Class B Equity Shares ("Class B Shares"), an unlimited number
of non-voting Class C Preferred Shares and an unlimited number of Class D
Preferred Shares, issuable in series.
The Common Shares are without nominal or par value. The Class B Shares are
convertible into Common Shares upon successful completion of a public
offering or certain other events, but with no additional consideration
owing to the Corporation. There have been no Class C Preferred Shares
issued. The Class D Preferred Shares, Series A, which have been issued, are
convertible into Common Shares prior to redemption on a one for one basis.
(b) ISSUED AND OUTSTANDING
NUMBER
COMMON SHARES OF SHARES AMOUNT
============================================================================================
Balance at December 31, 2000 4,000,011 $ 56,460
Issued on conversion of:
Class B Shares 37,935,280 315,656
Class A Special Warrants 279,950 912
Class B Special Warrants 823,707 2,059
Issued on exercise of Class B Warrants 465,188 3,721
Issued for cash (1) 625,000 10,000
Issued upon rights offering 3,384,835 47,388
Share issue Costs (856)
- --------------------------------------------------------------------------------------------
Balance at December 31, 2001 47,513,971 $ 435,340
- --------------------------------------------------------------------------------------------
Issued for cash 228,500 1,977
Renunciation of flow-through shares (4) -- (23,005)
- --------------------------------------------------------------------------------------------
Balance at December 31, 2002 47,742,471 414,312
============================================================================================
10
NUMBER
CLASS B SHARES OF SHARES AMOUNT
============================================================================================
Balance at December 31, 2000 (2) 32,929,372 $ 243,895
Issued for cash (3) 5,005,908 71,761
Converted to Common Shares (37,935,280) (315,656)
- --------------------------------------------------------------------------------------------
Balance at December 31, 2001 and December 31, 2002 -- $ --
- --------------------------------------------------------------------------------------------
CLASS A SPECIAL WARRANTS
============================================================================================
Balance at December 31, 2000 279,950 $ 912
Converted to Common Shares (279,950) (912)
- --------------------------------------------------------------------------------------------
Balance at December 31, 2001 and December 31, 2002 -- $ --
- --------------------------------------------------------------------------------------------
CLASS B SPECIAL WARRANTS
============================================================================================
Balance at December 31, 2000 823,707 $ 2,059
Converted to Common Shares (823,707) (2,059)
- --------------------------------------------------------------------------------------------
Balance at December 31, 2001 and December 31, 2002 -- $ --
- --------------------------------------------------------------------------------------------
CLASS D PREFERRED SHARES
============================================================================================
Balance at December 31, 2000 -- $ --
Issued for cash 666,667 12,000
Share issue costs (37)
- --------------------------------------------------------------------------------------------
Balance at December 31, 2001 and December 31, 2002 666,667 $ 11,963
- --------------------------------------------------------------------------------------------
============================================================================================
TOTAL SHARE CAPITAL 48,409,138 $ 426,275
============================================================================================
(1) Includes 625,000 shares issued by the Corporation on a flow-through
basis.
(2) Includes 1,491,084 shares issued by the Corporation on a flow-through
basis.
(3) Includes 1,601,179 shares issued by the Corporation on a flow-through
basis.
(4) In accordance with certain provisions of the Income Tax Act, Canadian
exploration expenses or Canadian development expenses related to
expenditures of the subscribed funds for shares issued on a
flow-through basis are transferred to the shareholders. Effective
December 31, 2002, all the expenditures related to these shares had
been renounced and the tax deductions were transferred to the
shareholders. Accordingly, a future income tax liability is created and
share capital is reduced by the tax effect of the renounced
expenditures.
(c) LOSS PER SHARE In calculating the weighted average number of Common Shares
outstanding, the Corporation includes Common Shares, Class B Shares, Class
A Special Warrants, and Class B Special Warrants. The Class B Shares have
been included as they are entitled to dividends in parity with the Common
Shares. On February 1, 2001 the Corporation qualified for distribution the
Common Shares issuable on conversion or exercise of the Class B Shares and
the Class A and B Special Warrants. Weighted average number of Common
Shares outstanding for December 31, 2002 is 48,330,320 (December 31, 2001-
41,404,904).
(d) CLASS D PREFERRED SHARES On March 14, 2001, the Corporation completed a
private placement for the issuance of 666,667 Class D Preferred Shares,
Series A, for proceeds of $12 million. The Class D Preferred Shares, Series
A, can be converted into Common Shares
11
prior to redemption on a one for one basis. If not previously converted,
they are redeemable at the option of the Corporation at any time at a price
equal to their issue price, plus a cumulative dividend of 12% per year
compounded semi-annually until January 1, 2007, from which date the
dividend increases by 3% per quarter to a maximum of 24% per year. Cash
dividends are not paid on the Class D Preferred Shares.
(e) CALL OBLIGATIONS The Corporation has entered into call obligation
agreements with certain shareholders, which obligate the holders of the
obligations to purchase up to 3,040,000 Class B Shares for $5.00 per share.
The Corporation is entitled to require the subscriber to exercise their
call obligations at its discretion upon the satisfaction of certain
conditions. These call obligations were to expire on December 31, 2001, but
were extended until March 31, 2003. An additional 2,589,641 call
obligations were entered into in July 2001, whereby each call obligation is
exercisable into one Class B Share and one warrant to purchase a Class B
Share upon the payment of $13.00 per call obligation. These call
obligations are exercisable until March 31, 2003 at the Corporation's
discretion and the underlying warrant is exercisable at the then market
price for a period of four years after the call obligation exercise. There
is a requirement imposed by the TSX to undertake a rights offering prior to
exercising any of the call obligations entered into in July 2001.
(f) WARRANTS Effective February 1, 2001 the Corporation qualified for
distribution 34,033,029 Common Shares, 494,224 Class A Warrants and 465,188
Class B Warrants resulting from the conversion of 32,929,372 Class B
Shares; 279,950 Class A Special Warrants; and 823,707 Class B Special
Warrants. In the first quarter of 2001, all Warrant Options and the 465,188
Class B Warrants were exercised. Consequently, the Corporation issued
465,188 Common Shares and received proceeds of $3.7 million. Each Class A
Warrant entitles the holder to purchase one Common Share at $2.50 per share
until five years after start-up of the oil sands project.
(g) ISSUANCES On July 25, 2001, the Corporation completed a private placement
to certain of its existing shareholders for the issuance of 4,130,318 Class
B Shares, of which 725,589 were issued on a flow-through basis, for
aggregate proceeds of $57.9 million. Certain shareholders also undertook to
subscribe for 725,590 Class B Shares on a flow-through basis that were
issued on November 1, 2001 for proceeds of $11.3 million. In addition, the
Corporation issued a further 150,000 Class B shares on a flow-through basis
on November 1, 2001 at a price of $17.30 per share, for gross proceeds of
$2.6 million. All 5,005,908 Class B Shares issued during 2001 were
converted into Common Shares on November 27, 2001 upon qualification by
prospectus, for no additional proceeds.
On October 25, 2001 the Corporation completed a Rights Offering, whereby
rights to subscribe for 3,384,835 Common Shares at a price of $14.00 per
share were offered to the holders of Common Shares and Class B Shares, for
aggregate proceeds of $47.4 million.
10. STOCK OPTIONS
(a) STOCK OPTION PLAN The Corporation has established a Stock Option Plan for
the issuance of options to purchase Common Shares to directors, officers
and employees of the Corporation and its subsidiaries and persons providing
ongoing services to the Corporation and its subsidiaries. Options granted
under the Stock Option Plan generally vest on an annual basis over four
years. The stock options expire five years from each vesting date.
12
2002 2001
=================================================================================================
WEIGHTED WEIGHTED
NUMBER OF AVERAGE NUMBER OF AVERAGE
OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE
- -------------------------------------------------------------------------------------------------
(thousands) (thousands)
Outstanding at beginning of year 1,238 $ 9.52 1,077 $ 8.53
Granted 429 23.91 201 14.61
Exercised (229) 8.64 -- --
Cancelled (109) 8.50 (40) 8.50
- ----------------------------------------------------------------------------------------------
Outstanding at end of year 1,329 $ 14.40 1,238 $ 9.52
=================================================================================================
Exercisable at end of year 550 $ 9.02 526 $ 8.53
=================================================================================================
The following table summarizes Stock Options outstanding and exercisable
under the Stock Option Plan at December 31, 2002:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------ -------------------------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE PRICE NUMBER REMAINING EXERCISE NUMBER OF EXERCISE
OF OPTIONS LIFE PRICE OPTIONS PRICE
- --------------------------------------------------------------------------------------------------
(thousands) (months) (thousands)
$ 8.50 - $12.00 704 54.2 $ 8.55 505 8.53
$12.01 - $16.00 196 74.0 14.64 45 14.66
$20.01 - $24.00 411 81.1 23.85 -- --
$24.01 - $28.00 18 76.3 25.43 -- --
- --------------------------------------------------------------------------------------------------
1,329 65.8 $ 14.40 550 $ 9.02
==================================================================================================
The number of Common Shares reserved for issuance under the Stock Option
Plan was 3,000,000 at December 31, 2002 (3,000,000 at December 31, 2001).
(b) STOCK-BASED COMPENSATION No compensation expense has been recognized when
stock options are granted, in accordance with Note 1(f). Had compensation
expense been determined based on the fair value method for awards made
after December 31, 2001, the Company's net income and earnings per share
would have been adjusted to the proforma amounts indicated below:
YEAR ENDED
DECEMBER 31, 2002
---------------------------------------------------------------
Net loss for the year - as reported $ 9,003
Net loss for the year - proforma $ 9,706
Basic loss per share - as reported $ 0.21
Basic loss per share - proforma $ 0.23
---------------------------------------------------------------
The proforma amounts exclude the effect of stock options granted prior to
January 1, 2002. The weighted average fair value of the 429,000 options
granted during the year was $8.39 using the Black-Scholes option pricing
model. The following table sets out the assumptions used in applying the
Black-Scholes model:
13
YEAR ENDED
DECEMBER 31, 2002
--------------------------------------------------------------------
--------------------------------------------------------------------
Risk free interest rate, average for year 4.55%
Expected life (in years) 5.00
Expected volatility 0.30
Dividend per share --
--------------------------------------------------------------------
11. SHAREHOLDERS' RIGHTS PLAN
The Corporation has a shareholders' rights plan (the "Plan"). Under the Plan,
one right will be issued with each Common Share issued. The rights remain
attached to the Common Share and are not exercisable or separable unless one or
more certain specified events occur. If a person or group acting in concert
acquires 20 per cent or more of the Common Shares of the Corporation, the rights
will entitle the holders thereof (other than the acquiring person or group) to
purchase Common Shares of the Corporation at a 50 per cent discount from the
then market price. The rights are not triggered by a "Permitted Bid", as defined
in the Plan.
12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Corporation's financial instruments that are included in the Consolidated
Balance Sheets are comprised of cash, temporary investments, accounts
receivable, all current liabilities and long-term borrowings and the Convertible
Notes.
(a) COMMODITY PRICE RISK The Corporation has entered into various commodity
pricing agreements designed to mitigate the exposure to the volatility of
crude oil prices. The agreements are summarized as follows:
NOTIONAL VOLUME HEDGE PERIOD PRICE RECEIVED UNREALIZED
GAIN/(LOSS)
================================================================================================
WTI Swaps 4,500 bbls/d April 1, 2003 to March Cdn$39.72 ($1.1 million)
31, 2004
WTI Swaps 8,500 bbls/d April 1, 2004 to March Cdn$36.95 ($1.5 million)
31, 2005
================================================================================================
(b) CREDIT RISK A substantial portion of the Corporation's accounts receivable
relates to recoverable Goods & Services Tax. All crude oil swap agreements
are with major financial institutions in Canada.
(c) INTEREST RATE RISK At December 31, 2002, there would be no increase or
decrease in net earnings from a one percent change in the interest rates on
floating rate debt as all interest has been capitalized as part of the cost
of the oil sands project.
(d) FOREIGN CURRENCY RISK Foreign currency risk is the risk that a variation in
exchange rates between the Canadian dollar and foreign currencies will
affect the Corporation's operating and financial results. At December 31,
2002, the Corporation's only significant exposure to these foreign exchange
risks is in connection with its United States dollar denominated debt as
described in Note 6(a).
14
(e) FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES The fair values of
financial instruments that are included in the Consolidated Balance Sheet,
other than long-term borrowings, approximate their carrying amount due to
the relatively short period to maturity of these instruments.
The estimated fair values of long-term borrowings have been determined
based upon market prices at December 31, 2002 for other similar liabilities
with similar terms and conditions, or by discounting future payments of
interest and principal at estimated interest rates that would be available
to the Corporation at year-end.
2002 2001
=====================================================================================================
BALANCE SHEET BALANCE SHEET
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
- -----------------------------------------------------------------------------------------------------
Floating rate debt:
Revolving credit and term loan $ 65,000 $ 65,000 $ 279,481 $ 279,481
borrowings
Other long-term liabilities 50,859 50,859 88,825 88,825
Fixed rate debt:
US Senior Secured Notes 710,820 700,158 -- --
- -----------------------------------------------------------------------------------------------------
Long-term borrowings $ 826,679 $ 816,017 $ 368,306 $ 368,306
=====================================================================================================
13. COMMITMENTS AND CONTINGENCIES
a) COMMITMENTS On December 6, 1999 the Corporation executed an Authority for
Expenditure ("AFE") related to the oil sands project. The original AFE obligated
the Corporation to expend $709.4 million from 1999 to 2003. During the course of
construction, additional costs of $377.6 million have been identified that will
be required to complete the oil sands project. On the basis of this level of
expenditures, the Corporation has funding arrangements that are sufficient to
cover its share of commitments. The Corporation continues to pursue initiatives
to optimize and refine its capital structure as it progresses through project
construction to operations.
In addition, the Corporation has executed or will execute long-term third party
agreements to provide for the following services and utilities; pipeline
transportation of bitumen and upgraded products, electrical and thermal energy,
production and supply of hydrogen and transportation of natural gas. Under the
terms of these agreements, the Corporation is committed to pay for these
utilities and services on a long-term basis, regardless of the extent that such
services and utilities are actually used. If due to project delay, suspension,
shut down or other reason, the Corporation fails to meet its commitment under
these agreements, the Corporation may incur substantial costs and may, in some
circumstances, be obligated to purchase the facilities constructed by the third
parties for a purchase price in excess of the fair market value of the
facilities.
The Corporation and the other owners of the oil sands Joint Venture have entered
into long-term operating lease obligations for certain equipment related to the
oil sands project in addition to the amounts committed to under the AFE. The
term of the lease obligations is between three and seven years, and the
agreements provide for a committed payment of 85 per cent of the original cost
of the equipment to the lessor at the end of the terms. The Corporation
anticipates its share of the final value of the leased equipment will total
between $40 to $60 million. At December 31, 2002, the Corporation's share of
committed payments amounted to $37.4 million. The estimate of lease interest
obligations for the next five years, excluding any committed payments, is as
follows:
15
---------------------------------------------------
2003 $ --
2004 $ 2.9 million
2005 $ 2.6 million
2006 $ 2.4 million
2007 $ 2.9 million
---------------------------------------------------
These long-term operating leases are held within a Special Purpose Entity
("SPE") as defined in the CICA draft guideline "Consolidation of Special Purpose
Entities". The impact of consolidating the SPE at December 31, 2002 would be to
increase both capital assets and long term liabilities by approximately $23.4
million.
b) CONTINGENCIES During the year, the Corporation has submitted claims, under
its insurance policy for cost over-runs and delays in production, significantly
in excess of the policy limit of $200 million. No amounts have been reflected in
the consolidated financial statements in respect of this potential recovery.
Management of the Corporation believes that while the policy amounts will be
recovered, the timing of receipt cannot yet be ascertained.
14. SUPPLEMENTARY INFORMATION
(a) NET CHANGE IN NON-CASH WORKING CAPITAL
SOURCE/(USE) 2002 2001
- --------------------------------------------------------------------------------
Operating Activities
Accounts receivable $ (4,071) $ --
Inventory (4,175) --
Accounts payable and accrued liabilities 281 --
------------------------
$ (7,965) $ --
------------------------
Investing Activities
Accounts receivable $ 4,675 $ --
Accounts payable and accrued liabilities (10,550) (18,231)
------------------------
$ (5,875) $(18,231)
================================================================================
(b) CUMULATIVE STATEMENT OF CASH FLOW The following represents the
Corporation's cumulative statement of cash flow from June 18, 1999 to December
31, 2002.
16
CUMULATIVE
FROM INCEPTION
================================================================================
CASH PROVIDED BY (USED IN)
OPERATING
Net loss for the period $ (21,440)
Non-cash items
Write-off of deferred financing costs 22,759
Future income tax recovery (22,551)
Amortization 532
================================================================================
CASH FROM OPERATIONS (20,700)
Increase in non-cash working capital (7,965)
- --------------------------------------------------------------------------------
(28,665)
- --------------------------------------------------------------------------------
FINANCING
Issue of share capital 448,280
Increase in long-term debt 1,053,320
Repayment of long-term debt (279,481)
Increase in long-term liabilities 4,250
Issue of Convertible Notes 88,000
Charge for Convertible Notes (1,283)
Repayment of long-term liabilities (57,032)
Debt issue and deferred charges (50,181)
- --------------------------------------------------------------------------------
CASH GENERATED 1,205,873
- --------------------------------------------------------------------------------
INVESTING
Capital expenditures (1,199,996)
Restricted cash --
Decrease in non-cash working capital 37,216
- --------------------------------------------------------------------------------
CASH INVESTED (1,162,780)
- --------------------------------------------------------------------------------
Increase in cash 14,428
Cash at beginning of period --
- --------------------------------------------------------------------------------
CASH AT END OF PERIOD $ 14,428
================================================================================
15. SUBSEQUENT EVENTS
(a) EQUITY OFFERING On February 7, 2003, the Corporation completed a public
offering for the issuance of 2,050,000 Common Shares for aggregate proceeds of
$50.2 million. The offering was underwritten by a syndicate of Canadian
underwriters and undertaken through the filing of a short form prospectus.
(b) CREDIT FACILITY On January 30, 2003, the Corporation increased the
availability under its Revolving Facility described in Note 6(c) above by $25
million, with the addition of another Canadian chartered bank to the syndicate.
17
16. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING
The consolidated financial statements have been prepared in accordance with
accounting principles generally accepted in Canada (Canadian GAAP) which, in
most respect, conform to accounting principles generally accepted in the United
States (US GAAP). Canadian GAAP differs from US GAAP in the following respects:
RECONCILIATION OF NET LOSS UNDER CANADIAN GAAP TO US GAAP
YEAR ENDED DECEMBER 31
-------------------------------
NOTE 2002 2001 2000
---- -------------------------------
Net Loss - Canadian GAAP $ 9,003 $ 7,015 $ 5,422
Impact of US GAAP
Borrowing costs v 3,295 4,410 5,369
Loss on derivative financial viii 39 -- --
instruments
Interest on Convertible notes ix (163) -- --
Pre-operating costs vi 1,374 -- --
Deferred Income Tax iii 19,929 -- --
-------------------------------
Net Loss - US GAAP $ 33,477 $ 11,425 $ 10,791
===============================
Net Loss per Share
Basic and diluted - Canadian GAAP $ 0.21 $ 0.17 $ 0.21
-------------------------------
Basic and diluted - US GAAP $ 0.69 $ 0.28 $ 0.41
-------------------------------
CONSOLIDATED STATEMENT OF CASH FLOWS - US GAAP
YEAR ENDED DECEMBER 31
----------------------------------------------
2002 2001 2000
----------------------------------------------
Cash provided by (used in)
Operating activities $ (21,074) $ (11,255) $ (10,621)
Financing activities 512,722 404,941 185,644
Investing activities (530,193) (434,824) (147,069)
----------------------------------------------
(Decrease) Increase in Cash $ (38,545) $ (41,138) $ 27,954
==============================================
18
CONSOLIDATED BALANCE SHEET
AS AT DECEMBER 31
--------------------------------------------------------
2002 2001
--------------------------------------------------------
NOTE AS REPORTED US GAAP AS REPORTED US GAAP
---- ----------- ------- ----------- -------
ASSETS
Current Assets $ 25,227 $ 25,227 $ 60,201 $ 60,201
Capital Assets v,vi,ix 1,306,989 1,293,987 761,939 752,160
Deferred Charges 27,422 27,422 32,254 32,254
--------------------------------------------------------
$ 1,359,638 $ 1,346,636 $ 854,394 $ 844,615
========================================================
LIABILITIES
Current Liabilities ix $ 45,008 $ 128,953 $ 51,222 $ 54,922
Financial liabilities viii -- 2,600 -- --
Long-term Debt 775,820 775,820 279,481 279,481
Other long-term liabilities iii 51,313 50,859 88,825 88,825
--------------------------------------------------------
872,141 958,232 419,528 423,228
SHAREHOLDERS' EQUITY
Share Capital x 426,275 445,580 447,303 443,603
Convertible Notes ix 83,945 -- -- --
Deficit v,ix,x (22,723) (55,693) (12,437) (22,216)
Accumulated other vii
Comprehensive Income -- (1,483) -- --
--------------------------------------------------------
$ 1,359,638 $ 1,346,636 $ 854,394 $ 844,615
========================================================
i. STOCK BASED COMPENSATION
The Corporation accounts for its stock-based compensation plans under CICA 3870,
under which no compensation expense is recognized in the consolidated financial
statements when stock options are granted. If compensation expense had been
recorded in accordance with Statement of Financial Accounting Standard ("FAS")
No. 123, the Corporation's net loss and net loss per share would approximate the
following pro forma amounts:
YEAR ENDED DECEMBER 31
-----------------------------
2002 2001 2000
-----------------------------
Compensation Expense $ 703 $ 596 $ 552
Net Loss:
As reported - US GAAP 33,477 11,425 10,791
Pro Forma 34,180 12,021 11,343
Net Loss per Share:
As reported - US GAAP 0.69 0.28 0.41
Pro Forma 0.71 0.29 0.43
-----------------------------
The fair value of each option granted is estimated on the date of grant using
the Black-Scholes pricing model with weighted average assumptions for grants as
follows:
19
YEAR ENDED DECEMBER 31
----------------------
2002 2001 2000
----------------------
Risk free interest rate, average for year 4.55% 5.20% 5.94%
Expected life (in years) 5.00 4.00 4.00
Expected volatility 0.30 0.22 0.20
Dividend per share -- -- --
ii. RECENT ACCOUNTING PRONOUNCEMENTS
a) FAS 145 Accounting for Gains and Losses on Settlement of Debt
In April 2002, FAS 145 was issued rescinding the requirement to include
gains and losses on the settlement of debt as extraordinary items. FAS
145 is applicable for fiscal years beginning on or after May 15, 2002.
The standard has been adopted by the Corporation with no impact.
b) FAS 146 Accounting for Costs Associated with Exit or Disposal Activities
In June 2002, FAS 146 was issued. The standard requires that
liabilities for exit or disposal activity costs be recognized and
measured at fair value when the liability is incurred. This standard is
effective for disposal activities initiated after December 31, 2002.
c) FAS 148 Accounting for Stock-based Compensation - Transition and Disclosure
In December 2002, FASB issued FAS 148 as an amendment to FAS 123
"Accounting for Stock-Based Compensation", to provide alternative
methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. FAS 148 is
applicable for fiscal years beginning after December 15, 2003. The
Corporation does not expect that the adoption of this pronouncement
will have an impact on its financial statements.
d) FASB Interpretation 46 Consolidation of Variable Indirect Entities
In February 2003, FASB issued FASB Interpretation 46, to be effective
for the first interim or annual reporting period beginning after June
14, 2003. The standard mandates that certain special-purpose entities
be consolidated by their primary beneficiary. At December 31, 2002, the
Corporation has an operating lease that may be consolidated under the
new standard; refer to Note 13 `Commitments and Contingencies'.
e) Hedge Accounting
The CICA issued Accounting Guideline 13 "Hedging Relationships",
effective for fiscal years beginning on or after July 1, 2003. The
guideline establishes certain conditions for when hedge accounting may
be applied, but does not specify hedge accounting methods. The
Corporation does not expect that the adoption of this pronouncement
will have an impact on its financial statements.
20
f) FAS 143 Accounting for Asset Retirement Obligations
FASB issued FAS 143, effective for fiscal years beginning after June
15, 2002. FAS 143 applies to legal obligations associated with the
retirement of a tangible long-lived asset that result from the
acquisition, construction, development and/or the normal operation of a
long-lived asset, except for certain obligations of lessees. The effect
on the Corporation's consolidated financial statements has not been
determined at this time.
iii. INCOME TAXES
Under US GAAP, the net deferred income tax liability as at December 31, 2002 and
2001 consists of:
YEAR ENDED DECEMBER 31
-----------------------
2002 2001
- --------------------------------------------------------------------------------
Future Income Tax assets
Net losses carried forward $ 19,069 $ 11,584
Share issue costs 2,096 3,191
Debt issue costs 1,386 --
Financial liabilities in excess of tax values 1,078 --
Future Income Tax liabilities
Renunciation of deductions for flow-through shares (23,005) --
Tax values in excess of book capital assets (579) --
Debt issue costs -- (4,132)
Less: valuation allowance (45) (10,643)
- --------------------------------------------------------------------------------
NET FUTURE INCOME TAX LIABILITY - US GAAP $ -- $ --
================================================================================
The following table reconciles income taxes calculated at the Canadian statutory
rate of 42.12% (2001 - 42.62%) with actual income taxes:
YEAR ENDED DECEMBER 31
-----------------------
2002 2001
- --------------------------------------------------------------------------------
Loss before income taxes - Canadian GAAP $(28,649) $ (5,480)
US GAAP adjustments (4,545) (4,410)
-----------------------
Loss before income taxes - US GAAP (33,194) (9,890)
-----------------------
Expected income tax (13,981) (4,215)
Unrecognized benefit of losses -- 4,215
Recognition of losses brought forward (7,946) --
Large Corporations Tax 2,905 1,535
Renunciation of deductions for flow-through shares 19,305 --
- --------------------------------------------------------------------------------
INCOME TAX EXPENSE - US GAAP $ 283 $ 1,535
================================================================================
21
iv. CAPITAL ASSET IMPAIRMENT
Under Canadian GAAP when the net carrying value of a capital asset, less its
related provision for future removal and site restoration costs and future
income taxes, exceeds the estimated undiscounted future net cash flows together
with its residual value, the excess is charge to earnings. Under US GAAP the
Corporation would account for long-lived assets in accordance with the United
States provision FAS 144 "Accounting for the Impairment of Long-Lived Assets and
for the Long-Lived Asset to be Disposed of". This Statement requires that
long-lived assets and certain identifiable intangibles be reviewed for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Recoverability of assets to
be held and used is measured by a comparison of the carrying amount of an asset
to future net cash flows expected to be generated by the asset. If such assets
are considered to be impaired, the impairment to be recognized is measured by
the amount by which the carrying amount of the assets exceeds the fair value of
the assets.
v. BORROWING COSTS
Under Canadian GAAP, standby fees and foreign exchange gains or losses
associated with borrowing facilities can be deferred as costs incurred during
the pre-operating period. Under US GAAP, these costs would be expensed as
incurred. The effect of this difference is to increase expenses by $3.3 million
for the year ended December 31, 2002 (2001 - $4.4 million, 2000 - $5.4 million),
to increase Deficit brought forward by $9.8 million (2001 - $5.4 million, 2000 -
$nil) and to reduce capital assets at December 31, 2002 by $13.1 million (2001 -
$9.8 million, 2000 - $5.4 million).
vi. END OF PRE-OPERATING PERIOD
Under Canadian GAAP, the Corporation is deemed to have ended its pre-operating
period upon commencement of commercial production. Until that time, training and
start-up costs associated with the Project during the pre-operating period are
deferred and capitalized as part of the Project. Under US GAAP, the Corporation
is deemed to have ended its pre-operating period upon mechanical completion of
the Project, which occurred on December 1, 2002, such that training and start-up
costs are expensed thereafter. The effect of this difference is to increase
expenses by $1.4 million for the year ended December 31, 2002 and to reduce
capital assets at December 31, 2002 by $1.4 million.
vii. OTHER COMPREHENSIVE INCOME
Comprehensive income is measured in accordance with FAS 130 "Reporting
Comprehensive Income". This Standard defines comprehensive income as all changes
in equity other than those resulting from investments by owners and
distributions to owners. During the year ended December 31, 2002, the
Corporation had other comprehensive income arising due to unrealized losses on
derivative financial instruments designated as hedge transactions. At December
31, 2002 this other comprehensive income amounted to a loss net of tax of $1.48
million.
viii. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING
Under Canadian GAAP, the derivative financial instruments qualify for hedge
accounting and the payments or receipts on these contracts are recognized in
earnings concurrently with the hedged transaction and changes in the fair values
of the contracts are not reflected in the consolidated financial statements. US
GAAP requires that all derivative financial instruments be recorded on
22
the balance sheet as either assets or liabilities at their fair values. When
specific hedging criteria is met, then changes in the derivative's fair value
can be recorded in other comprehensive income and any ineffectiveness of the
hedge is recorded in earnings for the period. Management has designated the
derivative financial instruments as hedges and as a result, under US GAAP, the
effect is to record the change in the fair value of the hedges of $2.56 million
($1.48 million net of tax) in other comprehensive income and $0.04 million in
expenses. In addition, liabilities increase by $2.6 million, being the full
amount of the unrealized losses.
ix. CONVERTIBLE NOTES
Under Canadian GAAP, amounts drawn under the Note Purchase Facility are deemed
to consist of both an equity and a liability component, recognized as
convertible notes. The initial carrying amount of the equity component is
adjusted for accretion to bring it up to the stated principal amount of the Note
Purchase Facility at maturity. This accretion is charged to the Deficit. Under
US GAAP, all amounts drawn under the Note Purchase Facility are classified as a
liability and any charges paid on these notes are treated as interest expense.
As the Note Purchase Facility is in place to finance the oil sands project, the
interest can be capitalized as part of the oil sands project costs. The effect
of this difference is to reclass convertible notes of $83.9 million from
shareholders' equity to current liabilities. In addition, the accretion is
reversed and interest expensed under this facility can be capitalized as part of
the oil sands project. The effect is to decrease expenses by $0.16 million,
decrease the Deficit by $1.28 million and increase capital assets by $1.44
million.
x. FLOW-THROUGH SHARES
Under Canadian GAAP flow-through shares are recorded at their face value within
share capital. When the expenditures are renounced and the tax deductions
transferred to the shareholders, future income tax liabilities will increase and
the share capital will be reduced. Under US GAAP when the shares are issued the
proceeds are allocated between the offering of the shares and the sale of tax
benefits. The allocation is made based on the difference between the quoted
price of the existing shares and the amount the investor pays for the
flow-through shares (given no other differences between the securities). A
liability is recognized for this difference. The liability is reversed when tax
benefits are renounced and a deferred tax liability recognized at that time.
Income tax expense is the difference between the amount of the deferred tax
liability and the liability recognized on issuance. At December 31, 2002, the
Corporation had recognized all renouncements of the tax deductions to the
investors. The effect of this difference is to increase share capital by $19.3
million (2001 - decrease of $3.7 million) and increase deferred income tax
expense by $19.3 million (2001 - $nil) and no effect on current liabilities
(2001 - an increase of $3.7 million).