EXHIBIT 1
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[LOGO - WESTERN OIL SANDS]
ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2006
TABLE OF CONTENTS
PAGE
INTRODUCTORY INFORMATION......................................................1
FORWARD LOOKING INFORMATION...................................................1
CORPORATE STRUCTURE...........................................................3
GENERAL DEVELOPMENT OF THE BUSINESS...........................................4
NARRATIVE DESCRIPTION OF THE BUSINESS.........................................5
THE ATHABASCA OIL SANDS PROJECT.........................................5
MINING - BASE OPERATIONS.......................................5
OPERATING ACTIVITIES..................................6
FINANCING ACTIVITIES..................................8
PRODUCTION HISTORY....................................9
PRODUCTION ESTIMATES..................................9
EXPANSION 1....................................................9
EXPANSIONS 2 AND 3............................................10
EXPANSIONS 4 AND 5............................................10
REGULATORY APPROVALS..........................................11
RESERVES, RESOURCES AND LAND POSITION.........................12
RESERVES.............................................12
UNDEVELOPED RESERVES.................................17
COSTS INCURRED.......................................17
ABANDONMENT AND RECLAMATION COSTS....................18
SIGNIFICANT FACTORS OR UNCERTAINTIES ON
RESERVES DATA........................................18
LAND TENURE..........................................18
RESOURCES............................................19
LAND POSITION........................................20
IN-SITU PROJECTS.......................................................22
WESTERN IN-SITU PROJECT.......................................22
ELLS RIVER PROJECT............................................22
DOWNSTREAM.............................................................22
THIRD PARTY FACILITIES........................................22
MARKETING AND SALES...........................................23
KURDISTAN EXPLORATION PROJECT..........................................23
GENERAL CORPORATE INFORMATION................................................23
ROYALTIES.....................................................23
ENVIRONMENTAL CONSIDERATIONS..................................23
INSURANCE.....................................................24
RISK MANAGEMENT ACTIVITY......................................25
TAX HORIZON...................................................25
EMPLOYEES.....................................................25
DIVIDEND POLICY..............................................................26
DESCRIPTION OF SHARE CAPITAL.................................................26
COMMON SHARES.................................................26
NON-VOTING CONVERTIBLE EQUITY SHARES..........................26
CLASS C SHARES................................................27
CLASS D SHARES................................................27
MARKET FOR SECURITIES........................................................28
CREDIT RATINGS...............................................................28
DIRECTORS AND EXECUTIVE OFFICERS.............................................29
AUDIT COMMITTEE..............................................................32
COMPOSITION AND QUALIFICATIONS.........................................32
RESPONSIBILITIES AND TERMS OF REFERENCE................................33
AUDITOR SERVICE FEES...................................................34
RISKS AND UNCERTAINTIES......................................................35
TRANSFER AGENTS AND REGISTRAR................................................49
INTEREST OF EXPERTS..........................................................49
LEGAL PROCEEDINGS............................................................49
ADDITIONAL INFORMATION.......................................................49
GLOSSARY ....................................................................50
APPENDIX A - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR
APPENDIX B - REPORT OF MANAGEMENT ON RESERVES DATA AND OTHER INFORMATION
APPENDIX C - AUDIT COMMITTEE CHARTER
INTRODUCTORY INFORMATION
References in this Annual Information Form to Western Oil Sands Inc.
("Western", the "Company" or the "Corporation") includes Western and its
material wholly-owned subsidiaries, 852006 Alberta Ltd., Western Oil Sands
L.P., Western Oil Development Inc., Western Oil International Holdings Limited
and WesternZagros Limited unless the context otherwise requires. INITIALLY
CAPITALIZED TERMS USED HEREIN AND NOT OTHERWISE DEFINED HAVE THE MEANINGS
ASCRIBED THERETO IN THE GLOSSARY.
Unless otherwise indicated, all financial information included and incorporated
by reference in this Annual Information Form is determined using Canadian
generally accepted accounting principles ("Canadian GAAP"), which differs from
generally accepted accounting principles in the United States ("U.S. GAAP").
The notes to Western's audited consolidated financial statements contain a
discussion of the principal differences between Western's financial results
calculated under Canadian GAAP and under U.S. GAAP.
UNLESS OTHERWISE SPECIFIED, ALL DOLLAR AMOUNTS ARE EXPRESSED IN CANADIAN
DOLLARS, ALL REFERENCES TO "DOLLARS" OR "$" ARE TO CANADIAN DOLLARS AND ALL
REFERENCES TO "US$" ARE TO UNITED STATES DOLLARS.
FORWARD LOOKING INFORMATION
This Annual Information Form contains certain forward-looking statements
relating but not limited to Western's operations, anticipated financial
performance, business prospects, proposed expansions and strategies.
Forward-looking information typically contains statements with words such as
"anticipate", "could", "estimate", "expect", "intend" "plan", "potential",
"project" or similar words suggesting future outcomes. We caution readers and
prospective investors of the Corporation's securities not to place undue
reliance on forward-looking information as by its nature, it is based on
current expectations regarding future events that involve a number of
assumptions, inherent risks and uncertainties, which could cause actual results
to differ materially from those anticipated by Western. These risks are
described more fully under "Risks and Uncertainties" and include, but are not
limited to, risks of commodity prices in the marketplace for crude oil and
natural gas; risks associated with the extraction, treatment and upgrading of
mineable oil sands deposits; risks associated with the size, scope and
execution of expansions; risks surrounding the level and timing of capital
expenditures required to fulfill Western's growth strategy; risks of financing
these growth initiatives at commercially attractive levels; risks of being
unable to participate in expansions and corresponding loss of voting rights in
the AOSP; risks relating to the execution of the Project's optimization
strategy; risks involving the uncertainty of estimates involved in the reserve
and resource estimation process and ore body configuration/geometry,
uncertainty in the assessment of asset retirement obligations, uncertainty in
the estimation of future income taxes, and uncertainty in treatment of capital
for royalty purposes; risks associated with identifying and implementing a
downstream solution for upgrading future bitumen volumes, risks surrounding
health, safety and environmental matters; risk of foreign exchange rate
fluctuations; risks and uncertainties associated with securing the necessary
regulatory approvals for expansion initiatives; risks surrounding major
interruptions in operational performance together with any associated insurance
proceedings thereto; and risks associated with identifying, negotiating and
completing our other business development activities, both those that relate to
oil sands activities and those that do not, either domestically or abroad.
Risks associated with our international initiatives include, but are not
limited to, political and economic conditions in the countries in which we
operate or intend to operate, risks associated with acts of insurgency or
terrorism, changes in market conditions, political risks, including changes in
law or government policy, the risks associated with negotiating with foreign
governments (including ratification of the EPSA) and risks generally associated
with international activity. Forward-looking statements are not based on
historical facts but rather on the expectation of management of the Corporation
("Management") regarding the Corporation's future growth or results of
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operations, production, future capital and other expenditures (including the
amount, nature and sources of funding thereof), competitive advantages, plans
for and results of drilling activity, environmental matters, business prospects
and opportunities. These forward-looking statements are made as of the date of
the Annual Information Form, and the Corporation assumes no obligation to
update or revise them to reflect new events or circumstances, except as
required by law. For additional information relating to risk factors please
refer to "Risks and Uncertainties".
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WESTERN OIL SANDS INC.
ANNUAL INFORMATION FORM
CORPORATE STRUCTURE
Western Oil Sands Inc. was 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.,
to 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, respectively. On June 1, 2005, the Corporation amended its
articles to divide the issued and outstanding Class A Shares on a three for one
basis, such that each outstanding Class A Share resulted in three outstanding
Class A Shares (the "Share Split").
Western has the following material wholly-owned subsidiaries; 852006 Alberta
Ltd. (which together with Western owns Western Oil Sands LP which holds a 20%
undivided interest in the Project), Western Oil Development Inc., Western Oil
International Holdings Limited and WesternZagros Limited, as shown below:
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________________________
| |
-------------| Western Oils Sands Inc.|--------------
| | (Alberta) | |
100% | |________________________| | 100%
____________________ / ____________________________
| 852006 Alberta Ltd.| / General | Western Oil |
| (Alberta) | / Partner | Development Inc. |
|____________________ / | (Alberta) |
| / |___________________________
99% Limited / |
Partnership / |
Units / 1% Limited | 100%
_______________________ Partnership ____________________________
| Western Oil Sands L.P.| Units | Western Oil International |
| (Alberta) | | Holdings Limited |
|_______________________| | (Cyprus) |
| |___________________________
| |
| |
20% | | 100%
/ \ ____________________________
/ \ | WesternZagros Limited |
/ \ | (Cyprus) |
/Project \ | |
/ \ |___________________________
/____________\
Western's head office is located at 2400 Ernst & Young Tower, 440 - Second
Avenue S.W., Calgary, Alberta T2P 5E9 and its registered office is located at
Suite 3700, 400 Third Avenue S.W., Calgary, Alberta T2P 4H2.
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GENERAL DEVELOPMENT OF THE BUSINESS
Western is a Canadian corporation formed under the laws of Alberta whose vision
is to create shareholder value through the opportunity capture and development
of large, world class hydrocarbon resources. Western's primary asset is its 20
percent undivided interest in the Project. Shell and Chevron are the other
Joint Venture Owners, holding a 60 percent and 20 percent interest,
respectively. The Owners entered into the Joint Venture Agreement in December
of 1999, which together with other ancillary agreements, governs the
relationships between the Owners. The base Project, located on the west side of
Lease 13, began operations in June 2003 and current production at the Joint
Venture level exceeds design rate capacity of 155,000 barrels per day.
In October 2006, Western announced its participation in Expansion 1 of the
AOSP. Expansion 1 is a 100,000 barrel per day (20,000 barrels per day net to
Western) fully integrated expansion of the existing AOSP facilities, with both
new oil sands mining operations on Lease BT 31 and the east side of Lease 13
and associated additional bitumen upgrading at the Scotford Upgrader. It also
includes the construction of common upstream infrastructure that will be sized
to support future mining expansions. The AOSP Joint Venture has also recently
announced its intention to file applications with the applicable government
authorities that would increase permitted upstream productive capacity to
770,000 barrels (154,000 barrels net to Western). At this level, multiple
mining expansions of the AOSP would be possible.
Western continues to pursue downstream integration opportunities to maximize
value from its growing oil sands resources and undeveloped acreage position.
Related to these initiatives, Western intends to explore and pursue
alternatives that will realize the full value of our assets and future growth
potential. This may result in an acquisition or sale of assets, merger or other
corporate transaction. Western's advisors, Goldman, Sachs & Co and TD
Securities Inc., will be assisting in these activities which will involve
contacting third parties. The Board of Directors has sanctioned a committee of
independent directors to provide oversight to management and the Company's
financial advisors for these activities. There can be no assurances that any of
these activities will result in the consummation of an agreement or transaction
or result in any change to Western's current ongoing business strategy.
Western is also pursuing initiatives related to in-situ and technology
development. This includes Western's participation in the Chevron-operated Ells
River Project in the Athabasca region in which Western holds a 20 percent
interest. Chevron is planning an evaluation program for the winter of 2007, the
results of which will influence the future development strategy and timeline.
In 2005 and 2006, Western acquired three leases with potential for in-situ
development. Early stage planning for these in-situ leases is underway and
includes an evaluation drilling program of approximately 19 wells during the
2006/2007 winter drilling season.
In addition to these three focus areas, Western, through its wholly-owned
subsidiary, WesternZagros Limited ("WesternZagros"), negotiated the initial
form of an EPSA with the Kurdistan Regional Government ("KRG"), subject to
finalization of key terms and ratification by the KRG to comply with expected
federal petroleum legislation. The EPSA provided for the exploration of
conventional oil and gas in the Federal Region of Kurdistan in northern Iraq.
WesternZagros continues to work towards ratification of an EPSA with the KRG
which is expected to include the finalization of terms including its contract
area and the corresponding work program commitments.
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NARRATIVE DESCRIPTION OF THE BUSINESS
Western is a Canadian corporation formed under the laws of Alberta that holds a
20 percent undivided ownership interest in the Joint Venture to exploit the
recoverable bitumen resources found in certain oil sands deposits located in
the Athabasca region including at the Muskeg River Mine. The Muskeg River Mine
is Western's only producing asset at this time. Shell and Chevron hold the
remaining 60 percent and 20 percent undivided ownership interests,
respectively. The Muskeg River Mine is located in northern Alberta
approximately 70 km north of Fort McMurray, Alberta, abutting the Athabasca
River and the integrated Scotford Upgrader is situated near Shell's existing
refinery near Fort Saskatchewan, Alberta. The Project, which includes
facilities owned by the Joint Venture and third parties, uses 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's asset base has grown rapidly as all Joint Venture Owners
were active in 2005 and 2006 in acquiring additional acreage in the Athabasca
region which may be suitable for bitumen recovery either through surface mining
or in-situ recovery techniques. In 2006, the Joint Venture Owners sanctioned
Expansion 1, the first mining expansion of AOSP on portions of Lease BT 31 and
the east side of Lease 13. Early stage assessments are underway for subsequent
mining expansions of the AOSP on other leases in which Western has the right to
participate. Moreover, early drilling is being conducted on leases acquired by
both Western and Chevron which may be conducive for in-situ development.
Western is also actively pursuing research and development efforts to add value
to existing assets; downstream initiatives to reduce exposure to heavy oil
differentials and improve product mix; and identification and evaluation of
opportunities in resource development of oil sands and other ventures with
significant long-life hydrocarbon resource potential.
THE ATHABASCA OIL SANDS PROJECT
MINING - BASE OPERATIONS
Construction of the existing operating Mine and Upgrader was completed in
December 2002, at a total capital cost of $5.7 billion ($1.14 billion net to
Western). Bitumen production commenced at the Mine in January 2003, reaching
commercial levels in June 2003. Ramp up of production at the Project continued
through 2004 with average production of approximately 135,500 barrels per day
(87 percent of design capacity). Increasing reliability and availability of the
Extraction Plant and Upgrader was a focus during 2005, resulting in annual
production of approximately 160,000 barrels per day for 2005 (32,000 barrels
per day net to Western). During the summer of 2006, the first major planned
turnaround of the Mine and Upgrader was completed. Production subsequent to the
full turnaround has met or exceeded rates leading up to the turnaround with
production in the fourth quarter of 2006 of approximately 177,600 barrels per
day (35,520 barrels per day net to Western).
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 sale to conventional refineries where it
is used to produce petroleum products. Approximately 300,000 tonnes per day of
ore, in addition to approximately 150,000 tonnes per day of overburden, low
grade (waste) oil sand and Extraction Plant rejects are mined from the Mine.
Approximately 165,000 to 170,000 barrels per day of bitumen is extracted from
this ore in the Extraction Plant and with the addition of non-bitumen
feedstocks, approximately 190,000 barrels per day of refinery feedstocks and
synthetic crude oil blends can be produced by the Upgrader. Western takes
in-kind its pro rata share of the various crude oil streams processed through
the Upgrader and markets these products independent of the other Joint Venture
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Owners. Currently, all of Western's net revenues are derived from petroleum
products produced from the Project.
The current operating Project is an integrated oil sands development in which:
o oil sands deposits are mined using open pit techniques at the Mine
located on the western portion of Lease 13, which is a truck and
shovel mine operation;
o raw bitumen is 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 is transported from the
Mine through a dual pipeline system to the Scotford Upgrader located
near Fort Saskatchewan, Alberta;
o at the Upgrader, the bitumen feedstock is distilled to recover
diluent, and then undergoes a hydro-conversion process with
integrated hydro-treating to generate suitable product streams; and
o after the bitumen has been upgraded, it is sold as refinery
feedstock to North American refineries. Vacuum gas oil is sold to
Shell Canada's 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.
OPERATING ACTIVITIES
As of February 2007, the Project has been in commercial operation for almost
four years. The maturation of the Project has proceeded without major incident
but for the fire that occurred at the Mine on January 6, 2003 during the
start-up and commissioning. Repairs were completed and start-up recommenced on
April 4, 2003 with the Project achieving fully integrated operations between
the Mine and the Scotford Upgrader on April 19, 2003. This incident resulted in
the submission of insurance claims pursuant to various policies both by the
Project and Western itself. See "Narrative Description of the Business -
General Corporate Information - Insurance".
On June 1, 2003, Western reported the start of commercial operations as all
aspects of the facilities became fully operational and the Project achieved 50
percent of the stated design capacity of 155,000 barrels per day. Since the
commencement of commercial production, ramp-up continued uninterrupted for
2003, with production increases each quarter. Production ramped-up at the Mine
and by the end of 2003, which was nine months after start-up, the Project was
operating at 89 percent of design capacity.
Production averaged slightly over 135,500 barrels per day (27,100 barrels per
day net to Western) in 2004 which was a 15 per cent increase in daily
production from the prior year. Successive gains in production were achieved
during 2004 until the fourth quarter when two minor operational upsets
occurred. Operations were brought to full capacity at both the Mine and
Upgrader upon completion of these repairs. Design and other operational changes
were enacted to prevent future occurrence of this type of minor upset. Full
production at both the Mine and the Upgrader re-commenced on January 30, 2005.
In 2005, the Project and Western itself achieved many operational and financial
records. Successive quarterly production records were established in the
second, third and fourth quarters reaching a level of 178,000 barrels per day
(35,600 barrels net to Western) which lead to a record annual production of
160,000 barrels per day (32,000 barrels per day net to Western). During 2006,
Albian became the first company in Canada to become ISO 14001 certified under
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the new standards and achieved one year without a lost time incident on July 1,
2006. July 5th of that year marked four million person hours without a lost
time incident. Financially, records were established in revenue, net income and
cash flow. The strong financial performance resulted in Western aggressively
repaying amounts owed under its Revolving Credit Facility. These solid results,
both operationally and financially, set the stage for continued operational
stability and profitability for the Project and Western.
Early in 2006, a longitudinal tear in the conveyor belt used to transport
bitumen ore from the primary crushers at the Mine to the Extraction Plant
occurred resulting in an unplanned slowdown at the Mine. The Project operated
at approximately one-third of stated design rates while the replacement belt
was prepared for installation. The installation was completed with production
curtailed for three weeks. Full production resumed on March 20, 2006 and,
subsequent to this repair to the end of the first quarter of 2006, production
averaged 34,000 barrels per day net to Western (compared to the design rate of
31,000, net to Western).
In May 2006, the Project undertook its first major turnaround of all of the
units at the Mine and the Upgrader with full production resuming in mid-July
2006. Following the initial cleaning and inspection of the equipment, it was
determined that additional maintenance and repair work at the Upgrader was
required in order to remove large amounts of coke from the reactor vessels and
to complete other work to enhance long-term performance. The turnaround period
totalled 56 days. As a result of the full turnaround, production was reduced,
averaging 15,540 barrels per day net to Western for the second quarter of 2006.
Operating expenses increased significantly due to the associated expenses
incurred with the turnaround. Following the turnaround, production exceeded
rates achieved leading up to the turnaround. Further reliability and minor
production optimization activities over the next several years are expected to
result in sustained production of approximately 200,000 barrels per day.
Noteworthy 2006 milestones include:
o production of over 183 million barrels of bitumen in just over three
and a half years of operation;
o successful completion of the first major planned turnaround;
o record stream day bitumen production rate of nearly 219,000 barrels
achieved in the fourth quarter of 2006 (post-turnaround);
o near record cash flow from operations for Western despite a two
month turnaround process;
o Muskeg River Mine expansion permit approval in December 2006; and
o only one lost time injury accident resulting in a record Lost Time
Injury Frequency ("LTIF") factor for the Project of 0.02 per 200,000
man hours.
The Project's demonstrated ability to safely extract, transport and process
significant volumes of bitumen provides comfort that production targets
established by the Joint Venture (which could see production range between
180,000 to 200,000 barrels per day in the next several years) are attainable.
These production goals will be achieved through the systematic implementation
of production optimization activities primarily at the Upgrader.
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Operating costs for 2006 were $28.38 per processed barrel, or $24.50 excluding
turnaround costs, up from $22.06 per processed barrel in 2005, largely due to
inflationary impacts to labour and associated with the robust commodity market,
partially offset by lower natural gas costs.
FINANCING ACTIVITIES
Western has used a combination of debt and equity capital to fund its share of
Project capital costs associated with construction and its share of operating
costs. Western's credit position has improved significantly over the last
several years as excess free cash flow has been aggressively applied to reduce
its revolving bank facilities. The following outlines key financing activities
undertaken by the Corporation in the last three years up to and including
fiscal 2006:
o a $68 million bought-deal equity offering consisting of 6,000,000
Common Shares at a price of $11.33 per share (adjusted to reflect
the Share Split) was completed on April 8, 2004;
o in March 2005, Western successfully refinanced its $100 million
Senior Credit Facility by the assumption of this full amount into
Western's Revolving Credit Facility, thereby increasing the
Revolving Credit Facility to $340 million (although only $305
million could be drawn due to covenant restrictions in Western's
note indenture). The additional $100 million is subject to the same
terms and conditions as those contained in the Revolving Credit
Facility;
o in October 2005, Western successfully amended its $340 million
Revolving Credit Facility with respect to lower pricing or spreads
on both drawn and un-drawn allocations to reflect Western's improved
credit position. Western also amended the structure of the Revolving
Credit Facility from a 364-day revolver with a two year term-out
provision for non-revolving allocations to a three-year revolving
facility extendible annually at the lenders' discretion;
o during 2006, Western successfully re-financed its share of the
Hydrogen Manufacturing Unit Credit Facility to bring the financing
terms in line with the terms of Western's Revolving Credit Facility
whereby financing rates charged are a function of a financial
covenant; and
o debt credit facilities increased by $35 million during the course of
fiscal 2006 (which resulted in full access to Western's $340 million
Revolving Credit Facility) to partially finance $312 million in
capital expenditures.
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PRODUCTION HISTORY
The following table sets forth certain information in respect of production,
product prices received, royalties, production costs and netbacks received by
Western for its synthetic crude oil production for each quarter of its most
recently completed financial year:
THREE MONTHS ENDED
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MARCH 31, 2006 JUNE 30, 2006 SEPTEMBER 30, 2006 DECEMBER 31, 2006
-------------- ------------- ------------------ -----------------
Average Daily Production -
dry bitumen basis (bbl/day) 25,945 15,540 32,836 35,515
Average Net Prices Received
($Cdn/bbl) 79.38 96.95 90.04 70.69
Royalties ($Cdn/bbl) 0.27 0.51 0.51 0.36
Operating Expenses ($Cdn/bbl) 27.38 63.28 22.00 20.34
Feedstocks ($Cdn/bbl) 19.79 29.63 21.76 12.92
Netback Received ($Cdn/bbl)(2) 31.94 3.53 45.77 37.08
Notes:
(1) All per barrel amounts are stated on a dry production bitumen basis.
(2) Netback is calculated as oil sands revenue less royalties, operating
expenses and feedstocks on a per barrel of production basis.
PRODUCTION ESTIMATES
Western estimates that bitumen production from the AOSP will be between 165,000
to 175,000 barrels per day (33,000 to 35,000 barrels per day, net to Western)
for 2007. Production from the Project accounts for 100 percent of Western's
estimated production in 2007. See "Forward-Looking Information" and "Risks and
Uncertainties".
EXPANSION 1
A key strategic milestone for the AOSP was the sanctioning of Expansion 1 in
the fourth quarter of 2006, the first major expansion of the AOSP. This
expansion represents the first of several anticipated expansions of the AOSP
over the next 10 to 15 years. Expansion 1 is a 100,000 barrel per day (20,000
barrels per day net to Western) fully integrated expansion of the existing
Project facilities, with both new oil sands mining operations on Lease BT 31
and the east side of Lease 13 and associated additional bitumen upgrading using
similar process as that of the Scotford Upgrader. It also includes the
construction of common upstream infrastructure that will be sized to support
future mining expansions. The capital cost estimate for Expansion 1 is
approximately $11.2 billion ($2.2 billion net to Western), with contingencies
and Owners' costs representing a significant portion of this estimate.
Expansion 1 is the first phase in the long-term AOSP's goal to construct a
series of similar 100,000 barrel per day expansions that could result in
production capacity of the AOSP surpassing 770,000 barrels per day from mining
operations alone in the next seven to ten years. This "building-block" strategy
has several competitive advantages including economies of scale in engineering
design, procurement of components and materials and labour retention.
Of the total $11.2 billion capital cost estimate, approximately 77 percent
represents component and labour costs, 20 percent represents the combination of
Owners' costs and contingencies (the majority of which are contingency related)
with the remaining three percent comprised of inflation adjustments. As at the
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end of 2006, Western had incurred $222.8 million on the Expansion 1 in respect
of its 20 percent interest. Long-lead items such as the reactors have been
ordered to ensure the Project maintains its cost and schedule. First production
from the upstream operations north of Fort McMurray is anticipated in late 2009
with first production of synthetic oil from the Upgrader towards the end of
2010. As part of Expansion 1, Kinder Morgan will be expanding the Corridor
pipeline that connects the extraction and ore preparation facilities near Fort
McMurray to the upgrading facilities outside of Edmonton. The pipeline
expansion will include construction of a 42 inch diameter pipeline to parallel
the existing dual pipeline system. The 24 inch line which is currently
transporting the diluted bitumen will be reversed to become the diluent return
line. The existing 12 inch line which currently fulfills this purpose will be
taken out of the pipeline rate base and used by the pipeline owner for its own
purposes. The expanded Corridor pipeline will be dedicated exclusively for the
benefit of the Joint Venture Owners and is sized to facilitate the
transportation of diluted bitumen for the next several expansions.
As currently designed, expansion plans would result in the AOSP's production
from mining operations increasing from 180,000 to 200,000 barrels per day upon
the completion of minor production optimization initiatives to 770,000 barrels
per day (154,000 barrels per day net to Western) by 2015. See "Forward-Looking
Information" and "Risks and Uncertainties".
EXPANSIONS 2 AND 3
In addition to Expansion 1, the Owner's longer term optimization plan includes
development of additional resources associated with the Jackpine Mine.
Resources associated with Expansion 2 and 3 would support two discrete trains
of approximately 100,000 barrels per day of bitumen production. This additional
production of 200,000 barrels per day from Expansions 2 and 3 is anticipated in
the 2013-2014 timeframe.
Mining expansions of the AOSP beyond Expansion 1 at the Joint Venture level
will be limited only to upstream or mining operations. The Joint Venture Owners
have contemplated combining Expansions 2 and 3 in order to achieve greater
economies of scale and accelerate the production profile of future expansions.
Shell will be filing with applicable government authorities an application that
will enable the AOSP to mine up to 770,000 barrels per day (154,000 barrels per
day net to Western). The permitting capacity under this application also
involves resources on Leases 88, 89 and 9 which are associated with Expansions
3, 4 and 5 (described below). This permit does not consider any future
development of leases recently acquired by Shell which are located north of
Lease 9 which have not been formally evaluated to this point. This additional
acreage, should recoverable resources be found on them, could have the
potential to support two additional expansions of the AOSP.
Completion of Expansions 2 and 3 is subject to a number of risks and
uncertainties and constitutes forward-looking information. See "Forward-Looking
Information" and "Risks and Uncertainties.
EXPANSIONS 4 AND 5
With the mining leases owned by Joint Venture Owners under the Participation
and AMI Agreement, it is estimated that sufficient resources exist to support
expansions beyond the first three phases. Following Expansions 1, 2 and 3, the
Owner's longer term optimization plan involves development of additional
resources associated with the Pierre River Mine which initially will be located
on the west side of the Athabasca River on Lease 9. As further core-hole
drilling is completed to delineate the resource potential of the Pierre River
Mine, Western believes that two additional 100,000 barrels per day (20,000
barrels per day net to Western) expansions of the AOSP (Expansions 4 and 5) may
be supported. The regulatory permit application referred to above would address
-11-
these volumes. An active core hole drilling program is planned on Lease 17 and
any recoverable resource established for this lease would form part of the
Pierre River Mine. At this point, no formal evaluation has been completed on
Lease 17.
As additional acreage is acquired and evaluated, future expansions will be
included as part of the Project should the Owners choose to participate. It is
anticipated that the Owners will undertake the following activities as part of
their longer term optimization plan:
o evaluation of additional mineable leases acquired recently by Shell
in the Athabasca region, namely Leases 15, 309, 310, 350, 351, 631
and 632;
o evaluation drilling on the substantial land base acquired by both
Chevron and Western. Chevron acquired approximately 75,000 acres in
2006 while Western acquired over 21,000 acres in 2006 which may
support in-situ development. Western's view is that the Ells River
Project could contain bitumen in place (with pay thickness of
greater than 18 metres) suitable for in-situ development in excess
of 7.4 billion barrels (approximately 1.5 billion barrels net to
Western). Based on this estimate, production from the Ells River
Project, combined with volumes from Western's in-situ project (in
which the Company holds an average 64 per cent land interest), could
support production in excess of 50,000 barrels per day net to
Western; and
o analyses of processes and/or equipment that will result in a
reduction of unit operating costs in the extraction process for both
mineable and in-situ resources along with the dependency on natural
gas, together with assessments of procedures and/or introduction of
equipment designed to increase the production throughput of the
facilities for a significantly lower capital intensity than an
initial construction project.
Taken as a whole, forecasted expansion plans for both in-situ and mining
operations would increase Western's total bitumen production to more than
200,000 barrels per day within the next 15 to 20 years. The timing and details
of any expansion will be subject to the outcome of future evaluations of
economics, market needs, regulatory requirements and sustainable development
considerations. There can be no assurance that any expansion will proceed on
the basis contemplated or at all. See "Forward-looking Information" and "Risks
and Uncertainties".
REGULATORY APPROVALS
On April 23, 2004, Western announced that the AOSP received approval from both
the provincial and federal government cabinet for the first phase of the
Jackpine Mine in the Athabasca oil sands region of northern Alberta. Since
these approvals have been received, the Owners have advanced the continuous
construction scenario and filed a regulatory permit in April 2005, which
included a revision to the existing Mine permit to accommodate certain
de-bottlenecking volumes as well as the first phase of the Jackpine Mine
expansion. With permits in place and those recently filed, the goal is to
produce 300,000 barrels per day by the end of 2009. The first expansion phase
intends to extract resources from portions of Lease BT 31 and the east side of
Lease 13 and includes a mining and extraction facility. The Project received
the final necessary regulatory approval on December 21, 2006 to mine from the
Expansion 1 area.
In addition, Western announced that the Joint Venture is preparing an omnibus
regulatory permit that, once submitted and approved, would enable the Project
to produce 770,000 barrels per day (154,000 barrels per day net to Western). It
is envisioned that this permit will be submitted during 2007 with the
expectation that approval will be received in mid-2009. This will increase the
approved permitting capacity of the Joint Venture by 300,000 barrels per day
-12-
over the 470,000 barrels per day originally in place. The incremental 300,000
barrels per day can be allocated into a further 100,000 barrels per day at the
Jackpine Mine area with an incremental 200,000 barrels per day allocated for
the Pierre River Mine. It is currently envisioned that this permitting capacity
would be sufficient for the first five mining expansions of the AOSP.
The timing and receipt of regulatory approvals is subject to certain risks and
uncertainties. See "Forward-Looking Information" and "Risks and Uncertainties".
RESERVES, RESOURCES AND LAND POSITION
RESERVES
Lease 13 encompasses 49,872 acres and lies within the mineable oil sands area
of the Athabasca deposits. Bitumen has been extracted from the west side of
Lease 13 for nearly three years. The operating Mine covers a 121 square
kilometre portion of the western portion of Lease 13. Bitumen production from
the east side of Lease 13 is anticipated to occur in 2009 with synthetic oil
from the upgrading facilities sometime during 2010.
GLJ Petroleum Consultants Ltd. ("GLJ") prepared a reserve report dated February
7, 2007 (the "GLJ Reserves Report") which evaluated the reserves attributable
to Western as of December 31, 2006. The combination of the Muskeg River Mine
and the Jackpine Mine has been estimated by GLJ to contain approximately 577
million barrels of working interest oil reserves. Of this total approximately
496 million barrels net to Western are proved reserves while 81 million barrels
net to Western are considered probable reserves. Based on GLJ's forecasted
AOSP's undiluted bitumen production rate of 175,000 barrels per day for 2007,
the proved plus probable reserves have a reserve life index of 44 years.
The following table below outlines the Joint Venture's proved and probable
reserves on Lease 13 as estimated by GLJ.
- --------------------------------------------------------------------------------
WESTERN'S
TOTAL SHARE
PROVED AND PROBABLE SYNTHETIC CRUDE OIL RESERVES (MMbbls) (MMbbls)
- --------------------------------------------------------------------------------
JOINT VENTURE (RESERVES)
Muskeg River Mine (Western portion of Lease 13) 1,545 309
Jackpine Mine (Eastern portion of Lease 13) 1,339 268
----------------------
TOTAL RESERVES 2,884 577
- --------------------------------------------------------------------------------
The tables below summarize the upgraded bitumen reserves ("synthetic crude
oil") and the value of future net revenue attributable to Western's ownership
as evaluated in the GLJ Reserves Report. Synthetic crude oil reserves do not
include blendstock volumes. The information set forth below relating to
Western's reserves constitutes forward-looking information which is subject to
certain risks and uncertainties. See "Forward-Looking Information" and "Risks
and Uncertainties".
All evaluations of future revenue are after the deduction of future income tax
expenses, unless otherwise noted in the tables, royalties, development costs
and production costs, but before consideration of indirect costs such as
administrative, overhead and other miscellaneous expenses. THE ESTIMATED FUTURE
NET REVENUES CONTAINED IN THE FOLLOWING TABLES DO NOT NECESSARILY REPRESENT THE
FAIR MARKET VALUE OF THE CORPORATION'S RESERVES. THERE IS NO ASSURANCE THAT THE
FORECAST PRICE AND COST ASSUMPTIONS CONTAINED IN THE GLJ RESERVES REPORT WILL
BE ATTAINED AND VARIANCES COULD BE MATERIAL. Other assumptions and
qualifications relating to costs and other matters are included in the GLJ
-13-
Reserves Report. The recovery and reserves estimates attributable to Western's
ownership in the Project are estimates only. Actual reserves may be greater or
less than those calculated.
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
Reserves Report presents net revenue projections prepared for the reserves
attributable to the ownership interest of Western along with a discussion of
the evaluation.
SUMMARY OF RESERVES AS AT DECEMBER 31, 2006
CONSTANT PRICES AND COSTS FORECAST PRICES AND COSTS
------------------------- -------------------------
SYNTHETIC CRUDE OIL SYNTHETIC CRUDE OIL
------------------------- -------------------------
GROSS NET GROSS NET
(MMBBL) (MMBBL) (MMBBL) (MMBBL)
------- ------- ------- -------
Proved Developed Producing 268 242 268 244
Proved Developed Non-Producing 7 6 7 6
Proved Undeveloped 221 202 221 204
--------------------------------------------------------
Total Proved 496 450 496 454
Total Probable 81 72 81 71
------- ------- ------- -------
Total Proved Plus Probable 577 522 577 525
======= ======= ======= =======
NET PRESENT VALUES OF FUTURE NET REVENUE
BASED ON CONSTANT PRICES AND COSTS
BEFORE DEDUCTING INCOMES TAXES AFTER DEDUCTING INCOME TAXES
------------------------------------ ----------------------------------
DISCOUNTED AT DISCOUNTED AT
UNDISCOUNTED 10% UNDISCOUNTED 10%
(MM$) (MM$) (MM$) (MM$)
------------- ----------- --------- -----------
Proved Developed Producing 8,402 3,449 6,347 2,763
Proved Developed Non-Producing 294 141 203 93
Proved Undeveloped 4,874 41 3,438 (129)
------------- ----------- --------- -----------
Total Proved 13,570 3,631 9,988 2,726
Total Probable 3,190 902 2,258 654
------------- ----------- --------- -----------
Total Proved Plus Probable 16,760 4,533 12,247 3,381
------------- ----------- --------- -----------
The following tables present the estimated future net revenue attributable to
Western, as set forth in the GLJ Reserves Report:
-14-
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
BASED ON CONSTANT PRICES AND COSTS
FUTURE FUTURE
NET NET
ABANDONMENT REVENUE REVENUE
AND BEFORE AFTER
OPERATING DEVELOPMENT RECLAMATION INCOME INCOME INCOME
REVENUE ROYALTIES COSTS COSTS COSTS TAXES TAXES TAXES
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
--------- ---------- ---------- ------------- -------------- ---------- -------- --------
Total Proved 29,666 2,709 9,447 3,940 - 13,570 3,581 9,988
Total Proved
Plus
Probable 34,517 3,279 10,288 4,191 - 16,760 4,513 12,247
FUTURE NET REVENUE BY PRODUCTION GROUP
BASED ON CONSTANT PRICES AND COSTS
The future net revenue before income taxes and discounted at 10% per year in
respect of the total proved and total proved plus probable synthetic crude oil
reserves attributable to Western's ownership interest in the Project as at
December 31, 2006 are $3,631 million and $4,533 million, respectively, based on
constant prices and costs.
NET PRESENT VALUES OF FUTURE NET REVENUE
BASED ON FORECAST PRICES AND COSTS
BEFORE DEDUCTING INCOME TAXES AFTER DEDUCTING INCOME TAXES
DISCOUNTED AT DISCOUNTED AT
------------------------------------------ ------------------------------------------
0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
------- ------- -------- ------- ------- -------- ------- ------- -------- -------
Proved Developed Producing 7,684 4,561 3,049 2,239 1,762 5,819 3,569 2,470 1,873 1,515
Proved Developed
Non-producing 281 196 127 80 49 192 131 81 47 25
Proved Undeveloped 4,699 1,059 (220) (706) (898) 3,292 617 (343) (718) (871)
------- ------- -------- ------- ------- -------- ------- ------- -------- -------
Total Proved 12,663 5,816 2,957 1,613 913 9,303 4,317 2,208 1,201 668
Total Probable 3,554 1,616 912 607 451 2,510 1,158 669 459 352
------- ------- -------- ------- ------- -------- ------- ------- -------- -------
Total Proved Plus Probable 16,217 7,432 3,868 2,220 1,365 11,813 5,475 2,877 1,660 1,020
======= ======= ======== ======= ======= ======== ======= ======= ======== =======
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
BASED ON FORECAST PRICES AND COSTS
FUTURE FUTURE
NET NET
ABANDONMENT REVENUE REVENUE
AND BEFORE AFTER
OPERATING DEVELOPMENT RECLAMATION INCOME INCOME INCOME
REVENUE ROYALTIES COSTS COSTS COSTS TAXES TAXES TAXES
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
--------- ---------- ---------- ------------- -------------- ---------- -------- --------
Total Proved 34,799 3,012 14,149 4,975 - 12,663 3,360 9,303
Total Proved
Plus Probable 40,954 3,737 15,267 5,373 - 16,217 4,404 11,813
FUTURE NET REVENUE BY PRODUCTION GROUP
BASED ON FORECAST PRICES AND COSTS
The future net revenue before income taxes and discounted at 10% per year in
respect of the total proved and total proved plus probable synthetic crude oil
reserves attributable to Western's ownership interest in the Project as at
December 31, 2006 are $2,957 million and $3,868 million, respectively, based on
forecast prices and costs.
-15-
RECONCILIATION OF NET RESERVES BY PRINCIPAL PRODUCT TYPE
BASED ON CONSTANT PRICES AND COSTS
Both fiscal 2006 and 2005 represent full years of production. The following
table sets forth a reconciliation of the changes in Western's bitumen reserves
as at December 31, 2006 against such reserves as at December 31, 2005 based on
the constant price and cost assumptions set forth in Note 8 below:
SYNTHETIC CRUDE OIL
------------------------------------------------
NET PROVED PLUS
NET PROVED NET PROBABLE PROBABLE
(MMBBL) (MMBBL) (MMBBL)
------- ------- -------
At December 31, 2005 186 109 295
------- ------- -------
MRM Extension 79 (73) 6
Improved Recovery - - -
Technical Revisions - 2 2
Discoveries - - -
AOSP Expansion 1 Addition 202 42 244
Dispositions - - -
Economic Factors (7) (8) (15)
Production (10) - (10)
------- ------- -------
At December 31, 2006 450 72 522
RECONCILIATION OF CHANGES IN NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% BASED ON CONSTANT PRICES AND COSTS
The following table sets forth changes between future net revenue estimates
attributable to net proved reserves as at December 31, 2006 against such
reserves as at December 31, 2005:
(MM$)
-----
Estimated Future Net Revenue at December 31, 2005 2,575
-----
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties (339)
Net Change in Prices, Production Costs and Royalties Related to Future Production (232)
Changes in Previously Estimated Development Costs Incurred During the Period 66
Changes in Estimated Future Development Costs (256)
Extensions and Improved Recovery 507
Discoveries -
Acquisitions of Reserves 41
Dispositions of Reserves -
Net Change Resulting from Revisions in Quantity Estimates -
Accretion of Discount Pre Tax 334
Net Change in Income Taxes 30
Changes Resulting from Technical Revisions -
-----
Estimated Future Net Revenue at December 31, 2006 2,726
=====
Notes:
(1) Reserve definitions consistent with National Instrument 51-101 -
Standards of Disclosure for Oil and Gas Activities ("NI 51-101") have
been used in the GLJ Reserves Report, where:
"Proved" reserves are those reserves that can be estimated with a high
degree of certainty to be recoverable. The targeted level of certainty
under a specific set of economic conditions is at least a 90 percent
probability that the quantities actually recovered will equal or exceed
the estimated proved reserves
"Proved Undeveloped" reserves are those reserves expected to be recovered
from known accumulations where a significant expenditure is required to
render them capable of production.
"Probable" reserves are those reserves that are less certain to be
recovered than proved reserves.
"Proved Plus Probable" reserves include those additional reserves that
are less certain to be recovered than proved reserves. The targeted level
of certainty under a specific set of economic conditions is at least a 50
percent probability that the quantities actually recovered will equal or
exceed the sum of the estimated proved plus probable reserves.
-16-
(2) Project reserves associated with the Muskeg River Mine are all classified
as "developed". The proved non-producing reserves relate to recovery
factor and capacity improvements associated with de-bottlenecking capital
investments. Although the capital is significant relative to the cost of
drilling a well, classifying the non-producing reserves as undeveloped is
not considered appropriate for this particular Mine. All of the reserves
associated with the AOSP Expansion 1 are classified as undeveloped
reserves given the significant capital investment to bring them to
production. Western's share of the capital costs associated with AOSP
Expansion 1 is estimated at approximately $2.2 billion.
(3) Although preliminary resource base assessments have been conducted on
some of the leases held through the Joint Venture, no reserves have been
attributed to Leases 88, 89, 90, 9, 15, 17, 309, 310, 351, 352, 631, and
632.
(4) Reserves are stated on a synthetic crude oil basis. This recognizes that
intrinsic in the Project's operations, bitumen production from the Mine
receives an uplift as a result of the hydrotreating/hydroconversion
process. GLJ has used an uplift of two percent on the total proved
reserves and three percent on the probable reserves
(5) The oil price forecasts reflect total revenues associated with the output
from the Upgrader less the purchase costs associated with feedstock.
Changes to the product mix and associated feedstock composition will
occur relative to what they have been. In the constant price case, GLJ
estimates the oil pricing to be the December 31, 2006 Edmonton Par less
$7.87/bbl in 2006, reflecting the average December 2006 offset to
Edmonton Par for each feedstock product and marketable product stream and
anticipated composition of feedstock and sales. Western's sales mix is a
combination of heavy and light materials. Each product type trades at
either a premium or discount to an appropriate benchmark based on the
crude qualities. In the forecast price case, these offsets change based
on the forecasted prices of the underlying commodity. For the purpose of
2007 in the forecast case, GLJ estimates the oil pricing to be Edmonton
Par less $8.85/bbl.
(6) Bitumen production has been forecast by GLJ to be 163,000 barrels per day
in 2007 in the total proved category growing to 265,000 barrels per day
by 2014 in the total proved category. In the proved plus probable case,
production is forecast to grow from a rate of 175,000 barrels per day in
2007 to an average rate of 290,000 barrels per day by 2014. The
incremental production for the probable reserves reflect the current mine
plan as well as improved extraction recovery relative to the proved
category. Significant increase under each scenario reflects the addition
of production from the AOSP Expansion 1.
(7) Royalties are paid at the Mine boundary using a deemed bitumen revenue.
In the constant price case, GLJ has used a bitumen price of $39.00/bbl
based upon the December 2006 offset and a posted December 31, 2006 price
for LLB Crude Oil at Hardisty. In the forecast price case, GLJ has
deducted $0.50/bbl to GLJ's price for 12 degree heavy oil at Hardisty to
reflect historic royalty calculations. The capital expense base for the
Project at December 31, 2006 is estimated at $1,650 million.
(8) The constant price reflects December 31, 2006 prices of $67.58/bbl
Edmonton Par oil, $47.62/bbl LLB Crude Oil at Hardisty, $6.07/MMBTU gas
and zero inflation. In the forecast price assumptions, the following GLJ
price forecast was used:
EXCHANGE WTI CRUDE OIL AT LIGHT, SWEET CRUDE OIL AT HEAVY CRUDE OIL ALBERTA PLANT
YEAR INFLATION RATE CUSHING OKLAHOMA EDMONTON (40 API, 0.3% S) (12 API) AT HARDISTY SPOT GAS
(%) ($US/$CDN) ($US/BBL) ($CDN/BBL) ($CDN/BBL) ($/MMBTU)
- ---------------------------------------------------------------------------------------------------------------------
2007 2.0 0.87 62.00 70.25 39.25 7.00
2008 2.0 0.87 60.00 68.00 40.00 7.25
2009 2.0 0.87 58.00 65.75 39.75 7.55
2010 2.0 0.87 57.00 64.50 39.75 7.60
2011 2.0 0.87 57.00 64.50 40.25 7.65
2012 2.0 0.87 57.50 65.00 41.50 7.95
2013 2.0 0.87 58.50 66.25 42.50 8.10
2014 2.0 0.87 59.75 67.75 43.50 8.30
2015 2.0 0.87 61.00 69.00 44.25 8.50
2016 2.0 0.87 62.25 70.50 45.25 8.65
2017 2.0 0.87 63.50 71.75 46.00 8.85
2018+ 2.0 0.87 2.0 %/yr 2.0%/yr 2.0%/yr 2.0%/yr
In consideration of oil sands mining cost pressures, rather than the
Projected inflation of 2.0 percent above, GLJ assumed a 5.0 percent
inflation factor for the upstream or bitumen production component of the
project during the period 2007 through 2009, 4.0 percent in 2010, 3.0
percent in 2011 followed by 2.0 percent thereafter.
(9) Western's weighted average historical realized price for 2006 was $60.51
per synthetic barrel sold. Western had no crude oil hedges in place
during 2006.
(10) GLJ is an independent qualified reserves evaluator appointed pursuant to
NI 51-101.
-17-
FUTURE DEVELOPMENT COSTS
The following table sets forth the future development costs associated with the
development of Western's reserves as set forth in the GLJ Reserves Report.
TOTAL PROVED TOTAL PROVED TOTAL PROVED PLUS
ESTIMATED USING ESTIMATED USING PROBABLE ESTIMATED
CONSTANT PRICES AND FORECAST PRICES AND USING FORECAST
COSTS COSTS PRICES AND COSTS
(MM$) (MM$) (MM$)
------------------- ------------------- --------------
2007 603 625 626
2008 763 821 824
2009 549 608 611
2010 282 313 325
2011 69 82 91
Total for all years of reserve life,
undiscounted 3,940 4,975 5,373
Total for all years discounted at 10%/year 2,342 2,663 2,745
Western intends to finance these development costs through a combination of
free cash-flow from operations together with existing banking facilities and
incremental debt financings. To the extent that bank facilities or other debt
financings increase, costs associated with this borrowing would likely be
similar to the rates that have been incurred in the prior years. This
anticipated financing strategy would not affect the reserve balances nor the
estimated future net revenue associated with these reserves listed above.
UNDEVELOPED RESERVES
The entire volume of undeveloped reserves relates to Expansion 1. During 2006,
all Joint Venture Owners sanctioned the construction of Expansion 1. It is
anticipated that the capital costs associated with this expansion will be
approximately $11.2 billion (approximately $2.2 billion net to Western). This
construction effort will take place over several years with first oil from the
mine operations anticipated to occur during 2009. Two separate crude streams
are expected to be produced from this expansion. One stream will be a heavy
synthetic oil similar to the heavy synthetic stream currently produced from the
base operations, while a second stream will be light sour synthetic oil. It is
currently envisioned that VGO will not be produced with this expansion as the
Scotford Refinery, which takes the VGO as feedstock from the base operations,
does not have the capacity to take further VGO volumes.
COSTS INCURRED
The following table sets forth costs incurred by Western in respect of the
Project for the year ended December 31, 2006:
PROPERTY ACQUISITION COSTS EXPLORATION COSTS DEVELOPMENT COSTS
(MM$) (MM$) (MM$)
- --------------------------------------- ----------------- -----------------
PROVED PROPERTIES UNPROVED PROPERTIES
- ----------------- -------------------
nil $25.0(1) Nil $251.1(2)
Notes:
(1) Represents amounts spent on in-situ land acquisitions for both Western's
interest in Chevron's Ells River Project as well as Western's operated
in-situ properties.
(2) Includes $184.6 million incurred to fund Western's commitments pursuant
to the first phase of Expansion 1.
-18-
ABANDONMENT AND RECLAMATION COSTS
Western has abandonment and reclamation liabilities relating to the Mine,
Upgrader and related facilities. Western estimates the abandonment liability,
net of salvage, for these assets with consideration given to the expected cost
to abandon and reclaim the lands and facilities. These estimates are based on
prevailing industry conditions, regulatory requirements and past experience.
The value is determined by Western first estimating the anticipated timing and
amount of net cash outflows using third party costs for future dismantlement
and site restoration. These future payments are then present valued using a
credit adjusted risk free rate appropriate for Western.
The liability is estimated in the period in which the liability is incurred.
These estimates are prepared annually and adjustments are made quarterly for
material changes in the amount of the liability or the timing of abandonment.
Where material differences are identified, adjustments to the liabilities or
accretion expense are made on a prospective basis.
Western's share of the present value of abandonment and reclamation costs that
require recognition in its financial statements at December 31, 2006 is $20.8
million ($85.1 million undiscounted). These liabilities relate to Western's 20
percent working interest in the Project's future dismantlement costs and site
restoration costs for the Mine, Upgrader and related facilities. GLJ has not
included any abandonment and reclamation costs in the GLJ Report. The
Corporation's share of the asset retirement obligation at December 31, 2006 was
approximately $20.8 million which is less than one per cent of the total
discounted cash flows of the proved plus probable reserves under the constant
pricing case. Western does not anticipate any material expenditures relating to
abandonment and reclamation during the next three years as the current mine
plan contemplates development over 30 years.
SIGNIFICANT FACTORS OR UNCERTAINTIES ON RESERVES DATA
Western's reserves to date represent the addition of reserves associated with
the current producing Muskeg River Mine on the west side of Lease 13, together
with reserves associated with the Jackpine Mine on Lease BT 31 and the east
side of Lease 13. All infrastructure components are in place to extract the
independently evaluated reserves for the Muskeg River Mine, and the Owners
formally sanctioned the construction of the Jackpine Mine which is projected to
cover a period of four years. Significant capital costs have already been
incurred for the Project, however, the exposure to rising capital costs is
heightened with respect to the Jackpine Mine as the construction period is in
the early stages. Significant capital cost pressures would have an impact on
both the volume and future net revenue associated with the Jackpine Mine.
Certain maintenance capital costs will be expended over the life of the
reserves to repair and replace certain components, particularly at the Mine and
Extraction Plant given the abrasive nature of the ore being processed. However,
risk remains with respect to ore quality, existence of deleterious materials
such as water or clay fines and ore body geometry such as strip ratio.
Important economic factors in the determination of the future net revenues
associated with the reserves are forecasted prices of crude oil and natural
gas. Should future prices vary significantly from prices used by GLJ in their
independent assessment, the corresponding future net revenues associated with
the reserves may be materially different. See section titled "Risks and
Uncertainties".
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
-19-
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.
RESOURCES
The Participation and AMI Agreement provides that the Owners have rights to
participate in any additional leases that are acquired by any one of the other
Owners in the Athabasca region prior to December 6, 2009. Western is entitled
to participate in all future expansions on Lease 13 and in the other oil sands
opportunities with Shell and Chevron in respect of Shell's Other Athabasca
leases, and within a defined area of mutual interest.
In respect of an ongoing delineation drilling program on Leases 88, 89, 90, 9
and the remainder of Lease 13, Western engaged Norwest to prepare volumetric
estimates of recoverable bitumen associated with mining pits. GLJ used these
geological and mining assessments to determine Contingent Resources as detailed
in the GLJ Contingent Resource Report. Western will disclose reserves and
resources on a project basis rather than lease by lease, as the mine plans
straddle lease boundaries and contingent resources are related to a specific
mine plan. Disclosure in this manner will also create alignment with regulatory
permits and proposed mine plans.
As per the COGE Handbook, contingent resources are those quantities of oil and
gas estimated on a given date to be potentially recoverable from known
accumulations but are not currently economic. GLJ has categorized the
potentially recoverable resources as contingent in view of ownership,
regulatory applications and Owner commitment issues and not as a result of
current economics. Western believes these contingent resources will be economic
to develop in the future. Over time, with additional project development and
financial commitment, Western would expect these contingent resources to be
converted to reserves.
The GLJ best estimate of contingent resources (in addition to the reserves
detailed above) on a total AOSP Joint Venture basis exceeds 4.4 billion
barrels, of which Western's share would be 891 million barrels. All contingent
resources are reported on a synthetic crude oil basis. This estimate of
contingent resources is based on several key assumptions, namely, minimum
bitumen by weight of seven per cent to total weight, minimum mining thickness
of three metres and a range of total volume to bitumen in place (TV:BIP) of
12:1, consistent with regulated operating criteria, and up to a TV:BIP ratio of
16:1 as a high estimate. The upgrading yield assumptions are consistent with
the reserve estimates.
-20-
The following table outlines the independently evaluated volume of contingent
resources available for future expansion opportunities on each of the various
projects that have been sanctioned by the AOSP or that are planned for
subsequent development. The results of the GLJ Contingent Resource Report are
detailed below.
- -------------------------------------------------------------------------------------------------------------
WESTERN'S SHARE OF MINEABLE SYNTHETIC CRUDE OIL VOLUMES (mmbbls)
- -------------------------------------------------------------------------------------------------------------
PROVED PLUS PROBABLE
RESERVES PLUS
CONTINGENT RESOURCES (1) RESERVES CONTINGENT RESOURCES
- ------------------------------------------------------- ---------------------------- ------------------------
PROVED PLUS
PROJECT AREAS LOW BEST HIGH PROVED PROBABLE BEST HIGH
- ------------------------------------------------------- ---------------------------- ------------------------
Muskeg River Mine (2) 188 228 291 275 309 537 600
Jackpine (3) 314 458 645 220 268 726 913
Pierre River (4,5) 102 205 306 - - 205 306
- ------------------------------------------------------- ---------------------------- ------------------------
TOTAL 604 891 1,242 495 577 1,468 1,819
- ------------------------------------------------------- ---------------------------- ------------------------
Notes:
(1) Contingent resources have been evaluated for Leases 13, 88, 89, 90 and 9.
Categories of Low, Best and High are used as recommended in the COGE
Handbook.
(2) Includes the west side of Lease 13, 90 and Sharkbite areas. Reserve status
has been assigned only to the portion of Muskeg River Mine pit located to
the east of Highway 63.
(3) Includes the east side of Lease 13 and Leases 88 and 89 and represents
Expansions 1 through 3. Reserve status has only been assigned to part of
the east side of Lease 13.
(4) Includes volumes only for Lease 9. Lease 17 was not included in this
determination as core hole drilling to assess resource potential continues
on this lease.
(5) Represents Expansions 4 and 5.
In addition to the above, Western's view is that the Ells River Project could
contain bitumen in place (with pay thickness of greater than 18 metres)
suitable for in-situ development in excess of 7.4 billion barrels of original
oil in place (approximately 1.5 billion barrels net to Western). Based on this
estimate, production from the Ells River Project, combined with volumes from
Western's in-situ project (in which the Company holds an average 64 per cent
land interest), could support production in excess of 50,000 barrels per day
net to Western.
These in-situ volumes, together with production associated with the recently
announced future mineable expansions, would increase Western's total bitumen
production to more than 200,000 barrels per day net to Western within the next
15 to 20 years. See "Forward-looking Information" and "Risks and
Uncertainties".
LAND POSITION
During 2005, Shell purchased Leases 15, 309, 310, 351, 352, 631 and 632 at
public land auctions held by the Alberta Government. These lands have not yet
been evaluated through core-hole drilling and analysis. Pursuant to the
Participation and AMI Agreement, Western has the right to participate to its 20
percent interest in the development of these leases. An extensive 2,500
core-hole drilling program over the next five years is planned to evaluate the
resource potential of these additional leases.
In August 2006, Western exercised its option to participate to a 20 percent
interest in Chevron's Ells River Project. The Ells River Project is located
approximately 50 kilometers northwest of Fort McMurray in the Athabasca oil
sands region. An evaluation program is planned on these leases during the
2006/2007 winter drilling program to further delineate the resource potential.
-21-
Western's undeveloped land position also includes in-situ leases acquired
during 2005 and 2006 covering 21,000 gross acres, namely Leases 353, 442 and
472. Both Shell and Chevron have elected to participate to their 20 percent
interest in Lease 353 pursuant to a separate agreement among the Owners and
only Shell has elected to participate for a 33? percent interest in Leases 442
and 472. In the absence of specific agreements, the Participation and AMI
Agreement provides that Owners are entitled to participate for an equal
interest in leases acquired by the Owners in the Athabasca region.
Only a fraction of Western's undeveloped land position has been evaluated. The
lands associated with Western's proved and probable reserves represent
approximately 11 per cent of the more than 69,000 net acres of total
undeveloped lands in which Western has the right to participate. As delineation
of these lands continues, Western expects its reported resources and reserves
to increase and will be updated accordingly
The following table summarizes the gross and net area associated with each of
these Leases together with existing leases.
GROSS WESTERN NET AREA TO
AREA INTEREST WESTERN
(ACRES) (%) (ACRES)
--------------------------------------------
AOSP MINEABLE (EVALUATED)
Lease 13 48,216 20% 9,643
Lease 88 23,176 20% 4,635
Lease 89 14,763 20% 2,953
Lease 90 2,882 20% 576
Lease 9 14,895 20% 2,979
Additional Leases (1) 8,010 20% 1,602
- --------------------------------------------------------------------------------
111,942 - 22,388
- --------------------------------------------------------------------------------
ADDITIONAL MINEABLE LEASES (UNEVALUATED)
Lease 15 3,795 20% 759
Lease 17 21,507 20% 4,301
Lease 351 22,772 20% 4,554
Lease 352 16,447 20% 3,289
Lease 631/632 6,642 20% 1,328
Lease 309 11,386 20% 2,277
Lease 310 7,591 20% 1,518
- --------------------------------------------------------------------------------
90,140 - 18,026
- --------------------------------------------------------------------------------
IN-SITU LEASES (UNEVALUATED)
Lease 353 (Western) 8,223 60% 4,934
Lease 442 (Western) 10,121 67% 6,747
Lease 472 (Western) 3,163 67% 2,109
Chevron Leases (2) 74,643 20% 14,929
- --------------------------------------------------------------------------------
96,150 - 28,719
- --------------------------------------------------------------------------------
TOTAL 298,232 - 69,133
- --------------------------------------------------------------------------------
Notes:
(1) Includes Leases AT30, AT34, AT36, BT30 AND BT31.
(2) Includes Leases 348,349,350,673,675.
-22-
IN-SITU PROJECTS
WESTERN IN-SITU PROJECT
During 2005, Western acquired Lease 353 and in 2006, acquired Leases 442 and
472 which are contiguous to Lease 353 in the Athabasca region. All of these
leases are considered prospective for in-situ development. Taken together,
these three leases bring the total acreage under leases which would be operated
by Western to over 21,000 acres or nearly 14,000 acres net to Western. Western
is currently executing a 2006/2007 winter core hole drilling program on these
leases consisting of approximately 19 wells. See "Narrative Description of the
Business - The Athabasca Oil Sands Project - Reserves, Resources and Land
Position - Land Position".
ELLS RIVER PROJECT
Western holds a 20 percent interest in the Chevron operated Ells River Project.
An evaluation program is planned for the 2006/2007 winter season. See
"Narrative Description of the Business - The Athabasca Oil Sands Project -
Reserves, Resources and Land Position - Land Position".
Both of these in-situ developments are suitable for SAGD application, a
technology utilizing injected steam to mobilize the bitumen source. As a
precursor to development, these projects are proceeding with initial appraisal
drilling during the winter of 2006/2007. To assist in the critical analysis of
these opportunities and develop any Western led in-situ project, Mr. Graig
Ritchie was hired during 2006 to lead this team. Mr. Ritchie was formerly with
EnCana Corporation and Imperial Oil where he was involved in all aspects of
production, engineering and market development.
DOWNSTREAM
Beyond Expansion 1, Western is independently pursuing its own downstream
integration opportunity to maximize value from its growing oil sands resources
and undeveloped acreage position. Western's overall objective with respect to
this key strategic initiative is to reduce capital intensity and improve
product realizations. Western intends to explore and pursue opportunities that
will realize the full value of the Corporation's assets and future growth
opportunities. These opportunities may be within or outside of Canada and will
focus on North American demand. This may result in an acquisition or sale of
assets, merger or other corporate transaction. Western's advisors, Goldman,
Sachs & Co and TD Securities Inc., will be assisting in these activities which
will involve contacting third parties. There can be no assurances that any of
these activities will result in the consummation of an agreement or transaction
or result in any change to Western's current ongoing business strategy.
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") constructed the dual
Corridor pipeline system that connects the Mine to the Scotford Upgrader and
the Scotford Upgrader to certain third party pipelines. Terasen was acquired in
2005 by Kinder Morgan, Inc. ("Kinder Morgan"). Kinder Morgan now operates this
pipeline system directly. The Owners are severally responsible for the costs of
transportation on the Corridor pipeline system, which is on a take or pay
basis. As part of Expansion 1, Kinder Morgan is currently in the process of
expanding the Corridor pipeline system which will include upgraded pump
stations and a new 42 inch pipeline. Once completed, the new pipeline
infrastructure will support the next several expansions of the AOSP.
-23-
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.
ATCO Pipelines owns and operates the Muskeg River Gas Pipeline which provides
natural gas supply to the Muskeg River Mine. The Owners are severally
responsible for the costs of this pipeline.
MARKETING AND SALES
Shell Canada Products Limited takes 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 sells
approximately 12,000 barrels per day of vacuum gas oil to Shell Canada Products
Limited under this arrangement representing its 20 percent share of such total
sales. The remaining production from the Upgrader and any third party
feedstocks currently form the basis of two streams of synthetic crude oil (one
heavy and one light) other than the volume sold to Shell Canada Products
Limited, Western sells all of its production volumes into the traditional North
American markets.
KURDISTAN EXPLORATION PROJECT
Western, through its wholly-owned subsidiary, WesternZagros, negotiated the
initial form of an EPSA with the Kurdistan Regional Government ("KRG"), subject
to finalization of key terms and ratification by the KRG to comply with
expected federal petroleum legislation. The EPSA provided for the exploration
of conventional oil and gas in the Federal Region of Kurdistan in northern
Iraq. WesternZagros continues to work towards ratification of an EPSA with the
KRG which is expected to include the finalization of terms including its
contract area and the corresponding work program commitments.
GENERAL CORPORATE INFORMATION
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 the 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 carry-forwards.
ENVIRONMENTAL CONSIDERATIONS
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.
-24-
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 is operating with emissions that
are approximately 27 percent lower than the original case that was approved by
the Alberta Energy and Utilities Board and a number of further initiatives are
under development. 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. The Project's goal is to further reduce emissions by
another 40 percent by 2010 through a combination of energy efficiency projects.
To achieve this goal, the Owners are pursuing a multi-faceted plan, which
includes energy conservation and efficiency projects, investigation of cleaner
technology, the purchase of offsets and tree-planting offset programs.
INSURANCE
The Owners obtained insurance to protect against certain risks of loss during
the construction of the Mine, the Extraction Plant and the Upgrader. The
insurance policy (the "Policy") is typical for a project of this nature.
In addition, Western obtained, for its own account, $200 million of coverage
under Section IV of the Policy which, throughout the period March 2000 through
April 2004, covered 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 directly related to achieving the guaranteed
production levels; and (iv) debt servicing costs related to obligations
incurred to finance any of (i), (ii) or (iii).
Western has filed insurance claims for the full $200 million limit under
Section IV of the Policy as a result of cost overrun and Project delay claims.
Arbitration proceedings (the "Arbitration") have been initiated seeking payment
of approximately $181 million together with interest and legal costs. A second
arbitration seeking payment of $16.5 million from insurers who provided cost
overrun and Project delay coverage pursuant to a separate policy is currently
being held in abeyance. In addition, Western has commenced an action against
the brokers involved in the placement of the Section IV Policy coverage which
has been stayed pending the conclusion of the Arbitration.
Western has also received certain payments from insurers as a result of
property damage and loss of profits claims relating to the January, 2003 fire.
To date, Western has received $16.1 million from insurers in respect of claims
relating to the fire and ensuing freeze damage. Those insurers who are also
involved in the Arbitration with Western have withheld insurance proceeds
payable to Western for damages related to the January 2003 fire and related
freezing damage. See "Narrative Description of the Business - The Athabasca Oil
Sands Project - Mining - Base Operations".
During 2005, the Joint Venture announced it had reached a settlement with the
insurers on its loss of profits claim under Section III of the Policy. The
final settlement amount totalled $220 million ($44 million net to Western), of
which Western received $19.4 million. Amounts withheld are by those common
-25-
insurers on Western's Section IV cost overrun and Project delay coverage under
the Policy which, as discussed above, is currently in Arbitration.
The principal amount of Western's outstanding insurance claims is $244 million.
There can be no assurance that Western will receive any or all of these
outstanding amounts. The potential benefit of collection of insurance proceeds
is not factored into Western's financing strategy. Should these proceeds, or
part thereof be received, Western would conduct an appropriate analysis to
determine where to best deploy the funds.
Western, together with its other Joint Venture Owners, have secured appropriate
construction and delay and start-up insurance for Expansion 1. These policies
will be in place until certain milestones are achieved once construction is
complete. As operations commence with Expansion 1, Western will reassess its
corporate insurance policies to ensure appropriate levels of coverage exist.
RISK MANAGEMENT ACTIVITY
Western has entered into various commodity pricing agreements designed to
mitigate the exposure to the volatility of crude oil prices in U.S. dollars
with the objective of solidifying the Corporation's balance sheet in the years
where significant capital expenditures are planned. Western no longer holds
fixed price swap contracts but utilizes a combination of a series of put and
call options in order to provide a floor West Texas Intermediate ("WTI") price
yet maintain upside potential on a portion of the Corporation's base volumes
should commodity prices continue to rise. As at January 1, 2007, the following
positions are in place:
Period (calendar year)
=================================
2007 2008 2009
---------- ---------- ----------
Put options purchased (bbls/d) 20,000 20,000 20,000
Avg. put strike price (US$/bbl) 52.50 54.25 50.50
Call options sold (bbls/d) 10,000 15,000 15,000
Avg. call strike price (US$/bbl) 92.50 94.25 90.50
GLJ has not included any effects of hedging activities in the GLJ Reserves
Report.
TAX HORIZON
Western is currently not required to pay cash income taxes. Western estimates
that cash income taxes will become payable within five to seven years,
depending on commodity prices, foreign exchange rates, operating costs,
interest rates, future annual taxable income levels, capital cost
classification of the AOSP expansions and other business activities. Changes in
these factors from estimates used by Western could result in Western paying
income taxes earlier or later than expected.
EMPLOYEES
As at December 31, 2006, Western had 58 employees. Most of these employees are
dedicated exclusively to the development of the reserve and resource base of
the AOSP. Western significantly increased its internal organizational
capabilities during 2006 with the addition of various senior technical staff
for the in-situ business initiative as well as Western's conventional oil and
gas initiative in Kurdistan. This expanded technical team gives Western the
-26-
ability to make assessments of both the Shell and Chevron property rights, in
addition to pursuing the purchase of undeveloped properties directly and
offering reciprocal participation rights to Shell and Chevron.
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 in the immediate or
foreseeable future. In addition, the credit agreement governing Western's bank
facilities and the note indenture governing the Notes contain restrictions on
the Corporation's ability to pay dividends or distributions of any kind. See
"Credit Ratings".
DESCRIPTION OF SHARE CAPITAL
The authorized share capital of the Corporation includes an unlimited number of
Common Shares, an unlimited number of Non-voting Convertible Class B Equity
Shares ("Non-voting Convertible Equity Shares"), an unlimited number of Class C
Preferred Shares ("Class C Shares") and an unlimited number of Class D
Preferred Shares, issuable in series ("Class D Shares").
The following is a brief description of the attributes of the Corporation's
Common Shares, Non-voting Convertible Equity Shares, Class C Shares and Class D
Shares.
COMMON SHARES
The holders of Common Shares are entitled, subject to specified preferences in
favour of holders of Class C Shares and Class D Shares, to dividends if, as and
when declared by the directors and to one vote per share at meetings of the
holders of Common Shares and, upon liquidation, subject to specified
preferences in favour of holders of Class C Shares and Class D Shares, to share
equally share for share with the Non-voting Convertible Equity Shares in the
remaining assets of the Corporation.
NON-VOTING CONVERTIBLE EQUITY SHARES
The holders of Non-voting Convertible Equity Shares are entitled to dividends
in parity with the Common Shares if, as and when declared by the directors and,
upon liquidation, subject to specified preferences in favour of holders of
Class C Shares and Class D Shares, to share equally share for share with the
Common Shares in the remaining assets of the Corporation. Holders of Non-voting
Convertible Shares are not entitled to receive notice of, attend or vote at any
meetings of shareholders unless otherwise entitled pursuant to applicable laws.
Each Non-voting Convertible Equity Share shall entitle the holder to acquire
(subject to adjustment), at no additional cost, one Common Share at 4:30 p.m.
(Calgary time) (the "Acquisition Expiry Time") on the earlier of: (i) five (5)
business days following the date upon which a receipt for a prospectus (the
"Qualifying Prospectus") to be filed by Western with respect to the
distribution of the Common Shares upon conversion of the Non-voting Convertible
Equity Shares has been issued by the last of the securities commissions or
similar regulatory authorities in the Province of Alberta and such other
provinces of Canada in which the Corporation files such Qualifying Prospectus
(based upon the residences of Canadian subscribers); and (ii) 12 months from
the date of issuance of the Non-voting Convertible Equity Shares. Non-voting
Convertible Equity Shares outstanding at the Acquisition Expiry Time shall be
deemed to be converted by the holder, without any further action on the part of
the holder, at the Acquisition Expiry Time. As at the date hereof, there are no
outstanding securities of this class.
-27-
CLASS C SHARES
The Corporation is authorized to make one issuance of Class C Shares. The
holders of Class C Shares shall not be entitled to receive notice of, attend or
vote at any meetings of the shareholders of the Corporation unless otherwise
entitled pursuant to applicable laws but shall be entitled to receive in
respect of each calendar year, if, as and when declared by the directors, a
non-cumulative preferential dividend in the amount (if any) declared by the
directors. No dividends shall be declared or paid in any year on the Common
Shares, Non-voting Convertible Equity Shares, Class D Shares or any other
shares of the Corporation ranking junior to the Class C Shares from time to
time with respect to the payment of dividends, unless all dividends which shall
have been declared and which remain unpaid on the Class C Shares then issued
and outstanding shall have been paid or provided for at the date of such
declaration or payment. Upon liquidation, holders of Class C Shares shall be
entitled to payment of an amount (subject to adjustment) equal to the amount or
value of the consideration paid for such shares (the "Redemption Amount") in
priority to the Common Shares, the Non-voting Convertible Equity Shares, the
Class D Shares and any other shares ranking junior to the Class C Shares from
time to time. The Class C Shares are redeemable by the Corporation or the
holders of Class C for the Redemption Amount. As at the date hereof, there are
no outstanding securities of this class.
CLASS D SHARES
The Class D Shares are entitled to receive notice of, attend and vote at any
meetings of shareholders and are convertible into Common Shares, prior to
redemption, on a one-for-one basis. The Class D Shares are redeemable by the
Corporation at a price equal to their issue price plus a cumulative dividend of
12% per annum compounded semi-annually until January 1, 2007, from which date
the dividend increases by 3% per quarter to a maximum of 24% per annum. As at
the date hereof, there are no outstanding Class D Shares.
-28-
MARKET FOR SECURITIES
The Common Shares of the Corporation are listed for trading on the Toronto
Stock Exchange ("TSX") under the symbol "WTO". The following table sets for the
high, low and closing trading prices and the volume of Common Shares traded on
the TSX for each monthly of the most recently completed financial year.
MONTH HIGH LOW CLOSING VOLUME
- ---------------- ------------- --------------- --------------- ----------------
January 36.09 28.57 34.86 14,482,839
February 38.90 29.82 31.00 13,258,128
March 34.39 30.59 32.39 13,322,284
April 38.09 32.85 33.81 19,880,830
May 36.25 29.50 30.78 24,814,811
June 33.69 25.70 30.94 26,728,260
July 31.60 24.50 25.96 25,993,181
August 30.40 24.60 29.50 40,370,355
September 30.55 25.71 28.60 59,495,169
October 29.95 24.47 28.95 35,429,462
November 32.45 27.17 31.85 18,225,089
December 34.00 30.23 32.71 8,290,068
CREDIT RATINGS
On April 23, 2002, Western 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. Western's Notes are currently rated by two separate
agencies, Standard and Poors ("S&P") and Moody's Investor Service ("Moody's").
Please refer to the table below for the respective ratings assigned to the
Notes.
- -------------------------------------------------------------------------------
TYPE OF SECURITY S&P MOODY'S
- -------------------------------------------------------------------------------
US$450 Million Senior Secured Notes BBB- Ba3
- -------------------------------------------------------------------------------
S&P Rating Definition - Western's Notes previously were assigned a rating of
BB+ but were upgraded to BBB- on December 27, 2006. Obligations rated BBB- or
higher are generally considered "Investment Grade" under the S&P rating system.
This implies that adequate protection parameters exist on the credit issue.
However, adverse economic conditions or changing circumstances are more likely
to lead to a weakened capacity of the obligor to meet its financial commitment
on the obligation. Ratings below this threshold are regarded as having
significant speculative characteristics. An obligation rated BB is less
vulnerable to non-payment than other speculative issues. However, it faces
major ongoing uncertainties or exposure to adverse business, financial, or
economic conditions which could lead to the obligor's inadequate capacity to
meet its financial commitment on the obligation. The (-) sign is added to show
relative standing within the major rating categories. The corporate rating
assigned to Western is BB+ with a stable outlook which indicates that the
current rating implies Western will be able to manage its capital spending
commitments an maintain debt levels within its current credit profile.
Moody's Rating Definition - Moody's long-term obligation ratings are opinions
of the relative credit risk of fixed-income obligations with an original
maturity of one year or more. They address the possibility that a financial
-29-
obligation will not be honoured as promised. Such ratings reflect both the
likelihood of default and any financial loss suffered in the event of default.
Obligations rated Ba are judged to have speculative elements and are subject to
substantial credit risk. Moody's appends numerical modifiers 1, 2, and 3 to
each generic rating classification from Aa through Caa. The modifier 1
indicates that the obligation ranks in the higher end of its generic rating
category; the modifier 2 indicates a mid-range ranking; and the modifier 3
indicates a ranking in the lower end of that generic rating category.
Investment grade under the Moody's rating system would be Baa3 and higher.
Moody's has assigned a Ba2 corporate rating to Western.
A security rating is not a recommendation to buy, sell or hold securities and
may be subject to revision or withdrawal at any time by the rating
organization.
DIRECTORS AND EXECUTIVE OFFICERS
The following table lists the names of the directors and executive officers of
Western as at the date hereof, their municipalities of residence, positions and
offices with Western and principal occupations during the preceding five years:
NAME AND MUNICIPALITY OF PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST DIRECTOR SINCE
RESIDENCE AND OFFICE FIVE YEARS
- ------------------------------- ---------------- ------------------------------------------ --------------------
DIRECTORS
David J. Boone(4)(5) Director President of Escavar Energy Inc., a May 2005
Calgary, Alberta; Canada private oil and gas corporation, since
2003. Prior to 2003, Executive
Vice-President of EnCana Corporation and
President of the EnCana Corporation's
Offshore and International Operations and
Executive Vice-President and Chief
Operating Officer of PanCanadian Energy.
Prior to 2001, various executive roles
with Imperial Oil Limited, an integrated
oil and gas company.
Geoffrey A. Cumming(3)(5) Lead Director Managing Director of Zeus Capital October 1999
Auckland, New Zealand Limited, a private New Zealand investment
corporation, since March 2003.
Vice-Chairman of Gardiner Group Capital
Limited, a private Canadian investment
corporation, to June 2003 and prior to
July 2002, Chief Executive Officer of
Gardiner Group Capital Limited.
Fred Dyment((1))(2)(8) Director Independent businessman. Formerly, January 2007
Calgary, Alberta Chief Executive Officer of Ranger Oil
Limited (sold to Canadian Natural
Resources Limited in 2000) with
increasingly senior positions prior
thereto, including Chief Financial
Officer. Currently serving on the board of
a number of public corporations.
James C. Houck President, Chief President and Chief Executive Officer of May 2005
Calgary, Alberta; Canada Executive the Corporation since April 2005.
Officer and Previously principal of FrontStreet
Director Partners, a private United States
investment firm, since 2003. President of
ChevronTexaco's Worldwide Power and
Gasification Inc. from 1998 to 2003.
President of Texaco Development
Corporation from 1996 to 2001.
-30-
NAME AND MUNICIPALITY OF PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST DIRECTOR SINCE
RESIDENCE AND OFFICE FIVE YEARS
- ------------------------------- ---------------- ------------------------------------------ --------------------
Oyvind Hushovd(1)(2)(3) Director Chairman and Chief Executive Officer of December 2003
Kristiansand, Norway Gabriel Resources Ltd., a mining
corporation, from March 2003 to May
2005. President and Chief Executive
Officer of Falconbridge Ltd., a mining
corporation, from 1996 to February 2002.
John W. Lill(2)(4) Director Executive Vice President and Chief December 2003
Toronto, Ontario; Canada Operating Officer of Dynatec Corporation,
a mining corporation, since November 2003.
President and Chief Operating Officer
(Base Metals) with BHP Billiton, a mining
corporation, from 2001 to 2003 and Chief
Operating Officer (Copper) with BHP
Billiton from 2000 to 2001. From 1998 to
2001, Vice President of Mining Operations
for Rio Algom Ltd., a mining corporation.
Randall Oliphant(1)(5) Director Chairman and Chief Executive Officer of February 2005
Toronto, Ontario; Canada Rockcliff Group Limited, a private
company investing mainly in the mining
sector, since 2003. Prior thereto, served
in various senior financial roles in
Barrick Gold Corporation culminating in
appointment as Chief Executive Officer in
1999 until 2003.
Robert G. Puchniak(1) Director Executive Vice President and Chief October 1999
Winnipeg, Manitoba; Canada 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(7) Chairman and Chairman of the Board of Directors. July 1999
Calgary, Alberta; Canada Director Prior to April 2005, President and Chief
Executive Officer of Western from July
1999. Also, Chairman of Fort Chicago
Energy Partners, L.P. since September
1997 and Chief Executive Officer until
December 2002.
Mac H. Van Wielingen(3)(6) Director Co-Chairman of ARC Financial December 1999
Calgary, Alberta; Canada Corporation ("ARC"), a private investment
management company focused on the energy
sector, and Chairman of ARC Energy Trust.
Previously, Chief Executive Officer of ARC
from 1989 until June 2000.
OFFICERS WHO ARE NOT DIRECTORS
Steve Reynish Executive Executive Vice-President and Chief --
Calgary, Alberta; Canada Vice-President Operating Officer of Western since
and Chief January 1, 2006; prior thereto,
Senior Operating Officer Vice President
Mining Operations including secondment to
Albian Sands Energy as Chief Operating
Officer since 2002
-31-
NAME AND MUNICIPALITY OF PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST DIRECTOR SINCE
RESIDENCE AND OFFICE FIVE YEARS
- ------------------------------- ---------------- ------------------------------------------ --------------------
David A. Dyck Senior Vice-President, Finance and Chief --
Calgary, Alberta; Canada Vice-President, Financial Officer of Western since
Finance and April 2000; prior thereto, Senior Vice
Chief Officer Financial President Finance & Administra-
tion 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.
Joanne L. Alexander (9) Corporate Vice President, General Counsel and --
Calgary, Alberta; Canada Secretary Corporate Secretary of the Corporation
since January 2007. Prior thereto General
Manager, Stakeholder Engagement and
Regulatory Affairs at ConocoPhillips
Canada from April 2006 to January 2007 and
prior thereto Vice President, Legal and
Corporate Secretary of Burlington
Resources Canada Ltd. since May 2000.
NOTES:
(1) Member of the Audit Committee.
(2) Member of the Compensation Committee.
(3) Member of the Governance Committee.
(4) Member of the Health, Safety and Environment Committee.
(5) Member of the Reserves and Business Risk Committee.
(6) Mr. Van Wielingen was a director of Gauntlet Energy Corporation
("Gauntlet") from September 1999 to December 2003. On June 17, 2003, an
order was granted under the Companies Creditors Arrangement Act which
provided creditor protection to Gauntlet to develop a financial
restructuring plan that was approved by its creditors.
(7) On May 10 1998, Mr. Turcotte resigned as a director of Chauvco
International Ltd. ("Chauvco"). On January 26, 1999, a bankruptcy
receiving order was granted by the Alberta Court of Queen's Bench against
Chauvco and it was subsequently ceased traded for failing to file
financial statements and other related documents.
(8) Appointed to the Board and Committees effective January 1, 2007.
(9) Charles W. Berard resigned as Corporate Secretary in connection with the
appointment of Ms. Alexander.
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 February 21, 2007, 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 3,486,578 Common
Shares or approximately 2% of the issued and outstanding voting securities of
the Corporation. Not included in the amount above is 5,138,581 Common shares
owned by Turcotte Family Holdings Ltd. ("Turcotte Holdings"). Mr. Turcotte is a
discretionary beneficiary under a family trust that exercises voting control
over Turcotte Holdings. Mr. Turcotte does not own, directly or indirectly, or
exercise control or direction over any voting shares of Turcotte Holdings.
Investors should be aware that some of the directors and officers of the
Corporation are directors and officers of other private and public companies.
Some of these private and public companies may, from time to time, be involved
in business transactions, banking relationships or relationships with companies
that have competing businesses which may create situations in which conflicts
might arise. Any such conflicts shall be resolved in accordance with the
procedures and requirements of the relevant provisions of the BUSINESS
CORPORATIONS ACT (Alberta), including the duty of such directors and officers
to act honestly and in good faith with a view to the best interests of the
Corporation.
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AUDIT COMMITTEE
COMPOSITION AND QUALIFICATIONS
The Audit Committee consists of four outside independent directors: Robert G.
Puchniak (Chair), Randall Oliphant, Oyvind Hushovd and Fred Dyment all of whom
are financially literate. Mr. Dyment was appointed to the Audit Committee
commensurate with his appointment to the Board of Directors on January 1, 2007.
In considering criteria for the determination of financial literacy, the Board
of Directors looks at the ability to read and understand a balance sheet, an
income statement and a cash flow statement of a public company.
The Board of Directors reviews committee membership periodically to ensure
appropriate utilization of expertise, experience and time of the Corporation's
directors. Changes to committee membership occur from time to time as a result
of this assessment.
The following is a brief description of the education and experience of each of
the members of the Audit Committee:
ROBERT G. PUCHNIAK, CHAIRMAN AND INDEPENDENT DIRECTOR
Mr. Puchniak was appointed Executive Vice-President and Chief Financial Officer
of James Richardson & Sons, Limited, an investment and holding corporation, in
March 2001 and prior thereto was Vice-President, Finance and Investment with
James Richardson & Sons, Limited since November 1996. Mr. Puchniak was
President and Chief Executive Officer of Tundra Oil & Gas Limited, a private
oil and gas corporation, from January 1989 to April 2003. Mr. Puchniak has also
held positions with Gendis Inc. and Richardson Securities Limited. Mr. Puchniak
is a director of a number of public and private corporations including James
Richardson International Limited, Tundra Oil and Gas Ltd., Opti Canada Inc.,
Trident Resources Corp, Petrobank Energy and Resources Ltd., Richardson
Partners Financial Holdings Limited, Strad Energy Services Ltd and Lombard
Realty Limited. Past involvements include Director, Moffat Communications
Limited, Terraquest Energy Corporation and Richland Petroleum Corporation;
Chairman, Manitoba Teachers' Retirement Fund; Chairman, Council of Examiners,
Institute of Chartered Financial Analysts; and President, Winnipeg Society of
Financial Analysts. Mr. Puchniak holds a Bachelor of Commerce (Honours) degree
from the University of Manitoba and was awarded the University Gold Medal for
his achievements. He earned a Chartered Financial Analyst designation in 1975.
Mr. Puchniak has been determined to be an "Audit Committee financial expert".
RANDALL OLIPHANT, INDEPENDENT DIRECTOR
Mr. Randall Oliphant is the Chairman and Chief Executive Officer of Rockcliff
Group Limited, a private corporation actively involved in the strategic
planning and corporate development of its investee companies, principally in
the mining sector. He is on the Advisory Board of Metalmark Capital LLC
(formerly Morgan Stanley Capital Partners) and serves on the Boards of a number
of public, private companies and not-for-profit organizations. Until 2003, he
was the President and Chief Executive Officer of Barrick Gold Corporation, and
served in senior financial positions since joining the company in 1987 prior to
being appointed Chief Executive Officer in 1999. Mr. Oliphant holds a Bachelor
of Commerce Degree from the University of Toronto and is a Chartered
Accountant. Mr. Oliphant has been determined to be an "Audit Committee
financial expert".
-33-
OYVIND HUSHOVD, INDEPENDENT DIRECTOR
Mr. Oyvind Hushovd was the Chairman and Chief Executive Officer of Gabriel
Resources Ltd., a public mining corporation, from March 2003 to May 2005. Prior
to that, he was the President and Chief Executive Officer of Falconbridge Ltd.,
a public mining corporation, from 1996 to February 2002. Mr. Hushovd holds a
Masters of Economics and Business Administration from the Norwegian School of
Business, Bergen and a Master of Law from the University of Oslo. Mr. Hushovd
has been determined to be an "Audit Committee financial expert"
FRED DYMENT, INDEPENDENT DIRECTOR
Mr. Dyment is currently is an independent businessman and serves on the Board
of Directors of Tesco Corporation and ZCL Composites Inc., two leading design,
manufacture and service companies. In addition, Mr. Dyment is a director of ARC
Energy Trust and Transglobe Energy Corporation. Previously, he spent the bulk
of his career at Ranger Oil Limited holding the positions of Controller, Vice
President Finance, Chief Financial Officer and finally Chief Executive Officer.
After Ranger Oil Limited was sold to Canadian Natural Resources in 2000, he
served as CEO of Maxx Petroleum Company from 2000 to 2001. Mr. Dyment also
served as Governor of the Canadian Association of Petroleum Producers (CAPP)
from 1995 - 1997. He holds a Chartered Accountant designation. Mr. Dyment has
been determined to be an "Audit Committee financial expert"
RESPONSIBILITIES AND TERMS OF REFERENCE
The following is a summary of the key roles and responsibilities of the Audit
Committee. Full particulars are set out in the Audit Committee Charter which is
attached as Appendix C hereto.
The Audit Committee approves Western's interim unaudited consolidated financial
statements, press releases and reviews the annual audited consolidated
financial statements and certain corporate disclosure documents including the
annual information form, management's discussion and analysis, offering
documents including all prospectuses and other offering memoranda before they
are approved by the Board. The Committee reviews and makes a recommendation to
the Board in respect of the appointment of the external auditor and it monitors
accounting, financial reporting, control and audit functions. The Audit
Committee meets to discuss and review the audit plans of the external auditors
and is directly responsible for overseeing the work of the external auditor
with respect to the preparing or issuing of the auditor's report or the
performance of other audit, review or attest services including the resolution
of disagreements between management and the external auditor regarding
financial reporting. The Committee questions the external auditor independently
of management and reviews a written statement of the external auditors'
independence based on the criteria found in the recommendations of the Canadian
Institute of Chartered Accountants. The Committee considers and makes a
recommendation to the Board as to the compensation of the external auditor and
ensures that fees paid to the external auditor for audit and non-audit services
are publicly disclosed. The Committee must be satisfied that adequate
procedures are in place for the review of the Corporation's public disclosure
of financial information extracted or derived from its financial statements and
it periodically assesses the adequacy of those procedures. In addition, it
reviews the internal control procedures to determine their effectiveness to
ensure compliance with applicable legal requirements, regulatory requirements
and Western's policies. The Audit Committee reviews the controls in place with
respect to officers' expenses and perquisites, reviews insurance coverage for
significant business risks and uncertainties and reviews material litigation
and its impact on financial reporting. The Committee has established procedures
for dealing with complaints, submissions or concerns on an anonymous and
confidential basis which come to its attention with respect to accounting,
internal accounting controls or audit matters.
-34-
AUDITOR SERVICE FEES
PricewaterhouseCoopers LLP has served as the auditors of Western since its
incorporation. The following table summarizes the total fees paid to
PricewaterhouseCoopers LLP for the years ended December 31, 2006 and December
31, 2005
2006(1) 2005
------- ----
Audit Fees $296,529(2) $146,396(4)
Tax Fees Nil(3) $133,108
- ------------------------------------------------------------------------------
TOTAL $296,529 $279,504
Notes:
(1) Paid or estimated to be payable for 2006 services.
(2) Includes $160,000 related to initial year of compliance with Sarbanes
Oxley legislation.
(3) Western engaged independent tax advisors to address taxation matters
during 2006.
(4) Includes audit fees relating to 2004 of approximately $38,000.
Audit fees were paid for professional services rendered by the auditors for the
audit of the Corporation's annual financial statements, services provided in
connection with statutory and regulatory filings and for costs related to
professional services rendered by the auditors for the audit of the
Corporation's internal control over financial reporting. Tax fees were paid for
tax advice and assistance with tax audits.
All permissible categories of non-audit services require pre-approval from the
Audit Committee.
-35-
RISKS AND UNCERTAINTIES
The Corporation is exposed to a number of risks and uncertainties relating to
its operations. The following is a listing of the material risks that affect or
may affect Western's stated business initiatives, however it is not meant to be
exhaustive.
THE PRICE OF CRUDE OIL AND NATURAL GAS MAY FLUCTUATE AND NEGATIVELY IMPACT
FINANCIAL RESULTS.
Western's financial results are dependent upon the prevailing price of crude
oil and natural gas. Oil and natural gas prices fluctuate significantly in
response to global and regional supply and demand factors beyond Western's
control. Worldwide economic growth, political developments, especially in the
Middle East, compliance or non-compliance with quotas imposed upon members of
the Organization of Petroleum Exporting Countries and weather, among other
things, can affect world oil supply and demand and oil prices. Natural gas
prices realized by Western are primarily affected by North American supply and
demand and by prices of alternative sources of energy.
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 Western 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 product at reduced prices would lower revenues.
In addition, because natural gas comprises a substantial part of Western's
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 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;
o entering into fixed priced swap 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
-36-
increases. In addition, by entering into these hedging activities, Western may
suffer financial loss if it is unable to produce sufficient quantities of oil
or have sufficient cash flow to fulfil its 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.
FLUCTUATIONS IN THE US AND CANADIAN DOLLAR EXCHANGE RATE MAY CAUSE WESTERN'S
OPERATING COSTS AND CAPITAL COSTS RELATING TO AOSP EXPANSION 1 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
undertakes certain hedging activities against currency fluctuations. There can
be no assurance that current activities or more expansive hedging programs in
the future that Western may adopt are or would be successful.
Secondly, a portion of the capital costs associated with AOSP Expansion 1 will
be denominated in US dollars. Capital costs may rise when converted to Canadian
dollars should the Canadian dollar weaken against that of the US dollar.
WESTERN MAY EXPERIENCE PRICING PRESSURE ON ITS SHARE OF THE PROJECT'S SYNTHETIC
CRUDE OIL PRODUCTION DUE TO OVERSUPPLY AND COMPETITION.
Western sells its share of synthetic crude oil production to refineries in
North America. These sales 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. In addition the differential to
West Texas Intermediate for certain product streams can vary dramatically and
can have a material impact on Western's revenues.
WESTERN COMPETES WITH LARGER COMPANIES AND ALTERNATIVE FUELS WHEN IT SELLS 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 competes with established oil sands operators which have established
operating histories and greater financial and other resources than Western. In
addition, Western competes with other producers of synthetic crude oil blends
and producers of conventional crude oil, including Shell and Chevron, some of
whom may have lower operating costs and may have proprietary downstream assets.
The crude oil industry also competes with other industries and alternative
energy sources in supplying energy, fuel and related products to consumers.
THE MINE, EXTRACTION PLANT AND UPGRADER MAY NOT PERFORM AS PLANNED.
The Project may encounter interruptions in production or additional costs due
to many factors, including:
o breakdown or failure of equipment or processes;
-37-
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 run on an
integrated and co-ordinated basis. There can be no assurance that each
component will continuously operate as designed or expected or that the
necessary levels of integration and co-ordination will continuously be
achieved. There can be no assurance that all components of the mining and
extraction facility will continue to perform as expected or that the costs to
operate this facility will not be significantly higher than expected.
Processing of bitumen ore is dependant on ore quality. As the mining operator
mines the pit, mixing techniques are employed to produce a consistent
bituminous sand from the mine to manage ore quality and optimize throughput at
the mine site. There can be no assurances that future ore qualities will remain
at current levels which could potentially result in lower throughput and higher
costs.
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 HMU 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 is provided by the
Muskeg River cogeneration facility. If the Muskeg River cogeneration facility
fails to continuously 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 continuously 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 is provided by the Upgrader
cogeneration facility. There can be no assurance that, in the event the
Upgrader cogeneration facility fails to continuously 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 fails to
perform continuously 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.
-38-
The Project relies on transportation of bitumen and Upgrader output from a
pipeline system owned and operated by Kinder Morgan. 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 Kinder Morgan, 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.
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 remaining areas of Lease 13 in
addition to Shell's Other Athabasca Leases and the AMI Leases. The Owners are
evaluating potential long-term development opportunities relating to resources
contained within Lease 13 and Shell's Other Athabasca Leases and the AMI
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.
STATUS OF THE FIRST EXPANSION OF THE ATHABASCA OIL SAND PROJECT.
Expansion 1 will be entering the construction stage. Western's share of the
total costs to construct the Expansion 1 has been estimated at $2.2 billion.
There is a risk that the Expansion 1 will not be completed on time or on budget
or at all. Additionally, there is a risk that Expansion 1 may experience
delays, result in interruption of existing mineable operations or increased
costs due to many factors, including, without limitation:
o inability to attract sufficient numbers of qualified workers;
o breakdown or failure of equipment or processes;
o construction performance falling below expected levels of output or
efficiency;
o changes in scope;
o shortages of, or delays in obtaining equipment, construction materials
or services;
o increases in materials or labour costs;
o contractor or operator errors;
o non-performance by, or financial failure of, third party contractors;
o disruption or delays in availability of transportation services;
o delays in obtaining, or conditions imposed by, regulatory approvals;
o design errors;
o errors in construction
o start-up and commissioning;
-39-
o labour disputes, disruptions or declines in productivity;
o adverse weather conditions affecting construction or transportation;
o transportation or construction accidents;
o unforeseen site surface or subsurface conditions;
o violation of permit requirements;
o disruption in the supply of energy; and
o catastrophic events such as fires, earthquakes, storms or explosions.
Given the stage of development of the Expansion 1, various changes may be made
prior to the Owners completing the Expansion 1. Based upon current scheduling,
full start-up of Expansion 1 is expected in late 2010. There can be no
assurances that the current construction schedules will continue as planned
without any delays or on budget. Any such delays will likely increase the costs
of the Expansion Project and may require additional financing.
IF WESTERN DOES NOT PARTICIPATE IN CERTAIN EXPANSIONS, WESTERN WILL LOSE VOTING
OR SIGNIFICANT EXPANSION RIGHTS.
If Western does not participate in certain future expansions, some of Western's
voting interests 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 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 on Shell's Other Athabasca Leases and will lose any rights
to participate in an area of mutual interest with the other Owners. Shell and
Chevron, have significantly greater capital resources than that of Western. If
the other Owners decide to undertake expansions, there can be no assurance that
Western will be able to fund its share of the expansion. Western's
participation in any expansion would be subject to numerous conditions,
including Western's satisfaction with feasibility studies and Western's access
to the necessary capital resources.
UPGRADING CAPACITY BEYOND THE EXPANSION 1 HAS NOT BEEN SECURED.
Expansions beyond Expansion 1 will not include a joint upgrading solution
therefore management continues to pursue alternate downstream solutions for
future volumes beyond Expansion 1. However, there can be no assurance that a
downstream solution can be found in time to process additional volumes from the
future planned expansions. This could result in significantly lower realized
prices from selling bitumen rather than a synthetic crude blend as planned.
Additional capital funding and a commitment of management resources will be
required to identify, develop and implement a downstream solution.
Western has engaged third party advisors to assist in these activities which
will involve contacting third parties. This may result in an acquisition or
sale of assets, merger or other corporate transaction. There can be no
assurances that any of these activities will result in the consummation of an
agreement or transaction or result in any change to Western's current ongoing
business strategy.
COMPETITION FOR LABOUR AND MATERIALS.
With the expansion of the industry and the impact of new entrants to the
business, risks in the form of availability/competition for skilled labour and
materials supply continue to build. There are other oil sands projects
currently under construction and significant expansions have been announced by
other oil sands developers. Western anticipates that some of these projects and
expansions will proceed in the same time frame as its proposed expansions. This
means Western will compete with these other projects for equipment, supplies,
services, and labour in this environment which could result in increased costs,
-40-
shortages of goods and services that delay progress, or both. In addition
participation in expansions will significantly increase the demands on
Western's management and administrative resources. Western may not be able to
effectively manage the expansions, and any failure to do so could have a
material adverse effect on Western's business, financial condition or results
of operations.
WESTERN MAY NOT BE ABLE TO EFFECTIVELY MANAGE ITS GROWTH.
The Joint Venture Agreement permits participation in certain expansion
opportunities. Participation in any expansion opportunities would significantly
increase the demands on Western's management resources. Western 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.
EXPANSIONS MAY NOT PROCEED AS PLANNED.
The expansion strategy and configuration currently envisioned may not proceed
as planned with respect to scope, timing and execution. This may directly
impact the volume, quality and timing of producing marketable products.
SHELL AND CHEVRON MAY NOT AGREE WITH WESTERN ON MATTERS RELATED TO THE PROJECT
INCLUDING EXPANSION 1.
The Project including Expansion 1 is a joint venture among Shell, Chevron and
Western. Future plans, 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 Chevron. 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 unit 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 affect Western.
SHELL AND CHEVRON MAY NOT MEET THEIR OBLIGATIONS TO THE PROJECT OR EXPANSION 1.
Western is subject to the risk of non-payment by Shell or Chevron in meeting
their payment obligations to the Project including Expansion 1. 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 certain of those
obligations.
IF WESTERN DEFAULTS ON ITS OBLIGATIONS UNDER THE JOINT VENTURE AGREEMENT, SHELL
AND CHEVRON 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 its obligations under the Joint Venture
Agreement, 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 fair market value (subject to certain adjustments for future
reclamation costs).
-41-
SHELL MAY NOT FULFIL ITS OBLIGATIONS TO WESTERN UNDER THE LONG-TERM SALES
CONTRACT.
Western sells its share of vacuum gas oil produced by the Project to a
subsidiary of Shell on a long-term basis. Since a large portion of our revenues
will be received from a subsidiary of Shell, Western will have a concentration
of credit risk. Furthermore, if the Shell subsidiary 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. Modifications to the
Scotford Refinery were undertaken to permit it to take the expected vacuum gas
oil output. If the subsidiary of Shell were to default on, or not be required
to fulfil its obligations to Western, 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
subsidiary, or at all.
Additionally, the price Western receives for products sold to the subsidiary 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 subsidiary 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.
PRODUCTION FROM EXPANSION 1 MAY NOT MEET THE PLANNED SCHEDULE OR BUDGET.
There is a risk that production from Expansion 1 may not commence when planned,
or at the costs anticipated. Many factors in addition to the risks described
below under "Risk Factors - The Mine, Extraction Plant and Upgrader may not
perform as planned" could impact the pace of Expansion 1 start-up and economic
efficiency of production including:
o the operation of any part of Expansion 1 falling below expected levels
of performance, output or efficiency; and
o unanticipated or unplanned shutdowns or curtailments of any component
of the Expansion 1.
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.
IN-SITU EXTRACTION MAY NOT BE ECONOMIC OR SUSTAINABLE.
In-situ developments are based on expectations of successful exploration
drilling results. While the Athabasca resource in composite is significant,
lease specific resource qualities may vary greatly and can only be confirmed
through exploration and full delineation. Only after this drilling is complete
and feasibility studies of the appropriate technology to apply to the resource
are done can the potential of there resource be quantified.
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THE PROJECT MAY EXPERIENCE EQUIPMENT FAILURES FOR WHICH WESTERN DOES NOT HAVE
SUFFICIENT INSURANCE.
The Upgrader processes 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 with adequate
insurance, delays in realizing on claims and replacing damaged equipment could
adversely affect Western's operations and revenues.
VARIOUS HAZARDS INHERENT IN WESTERN'S OPERATIONS COULD RESULT IN LOSS OF
EQUIPMENT OR LIFE.
The operation of the Project is 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 does not carry insurance with respect to all casualty
occurrences and disruptions. There is no assurance that Western's 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.
THE PROJECTIONS AND ASSUMPTIONS ABOUT WESTERN'S FUTURE PERFORMANCE MAY PROVE TO
BE INACCURATE.
Western has only a few years of operating results. Western's long-term
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. These projections and assumptions may prove to be inaccurate.
Debt levels could limit future flexibility in obtaining additional debt
financing and in pursuing business opportunities.
As at December 31, 2006, Western had approximately $723 million of debt
(including obligations under the HMU lease and net option premiums deferred
associated with Western's strategic crude oil hedging program). Western may
also incur significant additional indebtedness for various purposes, including
expansions. Western's debt level and restrictive covenants will have an
important effect 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.
WESTERN MAY NOT BE ABLE TO SECURE FINANCING FOR FUTURE EXPLORATION,
DEVELOPMENT, PRODUCTION, EXPANSION AND ACQUISITION PLANS.
Depending on Western's future exploration, development, production or
acquisition plans, Western may require additional financing. The ability of the
Corporation to arrange such financing in the future will depend in part upon
prevailing financing market conditions as well as the business performance of
Western. If Western's petroleum's revenues or reserves decline, it may not have
the capital necessary to undertake or complete future drilling programs or
expansions. There can be no assurance that debt or equity financing or cash
generated by operations will be available or sufficient to meet these
requirements or for other corporate purposes or, if debt or equity financing is
available, that it will be on terms acceptable to Western. Transactions
-43-
financed partially or wholly with debt may increase Western's debt levels above
industry standards. The inability of Western to access sufficient capital for
its operations and planned expansions could have a material adverse effect on
Western's business and financial condition. If additional financing is raised
by the issuance of shares from treasury of Western, control of Western may
change and shareholders may suffer dilution.
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.
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, royalties,
transportation, production, exports, labour standards, occupational health,
waste disposal, protection and remediation of the environment, aboriginal
matters, mine safety, hazardous materials, toxic substances and other matters.
Amendments to current laws and regulations and the introduction of new laws and
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 affect the viability of the Project.
There can be no assurance that the various government licenses and approvals or
amendments thereto that from time to time may be sought will be granted at all
or with conditions satisfactory to Western 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 any expansions, and the mining,
oil sands and oil and gas industries generally, will not be changed in a manner
which may adversely affect Western.
Oil sands leases may be subject to the OIL SANDS TENURE REGULATION (Alberta)
which was introduced in 2000. This legislation deems certain leases to continue
beyond their primary term to the extent that the lessee has attained the
minimum level of evaluation of the oil sands or the lease 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 or other oil sands products 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 their leases. Additionally, the OIL
SANDS TENURE REGULATION (Alberta) expires on December 1, 2008 and, if such
legislation is not renewed in its present or similarly favourable form, the
status of certain leases may be in question.
THE PROJECT MAY FAIL TO COMPLY WITH VARIOUS ENVIRONMENTAL APPROVALS WHICH MAY
EITHER CAUSE THE WITHDRAWAL OF THESE APPROVALS OR IMPOSE OTHER COSTS.
The 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 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
-44-
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
(including any expansions) will be a significant producer of some greenhouse
gases covered by the treaty. The Government of Canada indicated it intends to
put forward an emission reduction plan for Canada and Clean Air Act legislation
that will set greenhouse gases emission reduction requirements for various
industrial activities, including oil and gas production. Future federal
legislation, together with existing provincial emission reduction legislation,
such as in Alberta's 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 such legislation 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 not be
achievable or may significantly increase operating costs or reduce output.
CHANGES IN THE WESTERN'S OIL SANDS CROWN ROYALTIES POSITION AND OIL SANDS
TAXATION MAY NEGATIVELY IMPACT FINANCIAL RESULTS.
Western, through its 20 percent undivided interest in the Project, is subject
to a provincially administered royalty and income tax regime in terms of the
determination royalty payments until the Project has recovered the costs
associated with Mine and in terms of certain accelerated deductions for income
tax purposes. However, there can be no assurance that this royalty or income
tax regime will not change in a manner that would adversely affect Western,
either through changes in law or through further interpretation of law. The
classification of future expansions for both royalty calculations and
accelerated deductions, and the availability of these expenditures for
allowable costs for royalty purposes or as accelerated deductions for income
tax purposes, can have a significant impact on Western's royalty and income tax
expenses and payments.
CANADA REVENUE AGENCY ("CRA") MAY RULE NEGATIVELY ON EXTENT OF QUALIFYING
EXPENDITURE AS IT RELATES TO RENUNCIATION ON FLOW-THROUGH SHARES.
In connection with the issuance of flow-through shares in 2001 and 2002,
Western renounced Canadian exploration expenses in the aggregate amount of
$29.2 million and $19.5 million, respectively. Under the mechanics of
renouncing qualifying expenditures pursuant to flow-through shares, individual
shareholders can reduce their income subject to personal income taxes. During
the third quarter of 2006, it was communicated to Western that the CRA proposes
to challenge the characterizing of certain expenditures capitalized as Canadian
Exploration Expense which were incurred in 2001 and 2002. If CRA is successful
in assessing a change in the characterization of these expenditures, any
resulting reduction in the renunciations could impact Western's obligations
under the indemnity provisions in these subscription agreements and in turn,
will impact Western's reported results. The subscription agreements for
such-flow through shares stipulate that Western has indemnified subscribers. if
such renunciations are reduced under the Income Tax Act (Canada).
-45-
ABORIGINAL CLAIMS MAY BE MADE AGAINST WESTERN OR THE PROJECT, INCLUDING
EXPANSION 1.
Aboriginal peoples may make claims against Western or the Project including
Expansion 1, regarding the lands on which the Project including Expansion 1 are
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.
INVESTMENTS IN BUSINESS DEVELOPMENT ACTIVITIES UNRELATED TO THE OIL SANDS
INDUSTRY
Western has previously announced its business strategy of investigating, at any
one time, several separate projects which could significantly enhance
shareholder value. These projects may be domiciled outside Canada and may not
be related to the oil sands industry. These potential investments may involve
such risks as uncertain political, economic, legal, regulatory and tax
environments. They may also include, among other things, currency restrictions
and exchange rate fluctuations, risk of loss of revenue, property and equipment
as a result of hazards such as expropriation, nationalization, war,
insurrection, acts of terrorism and other political risks, risks of increases
in taxes and governmental royalties, renegotiation of contracts with
governmental entities and quasi-governmental agencies, changes in laws and
policies governing operations of foreign-based companies and other
uncertainties arising out of foreign government sovereignty over an investment
that Western may make abroad.
EXPLORING IN THE FEDERAL REGION OF KURDISTAN, POLITICAL AND REGULATORY
INSTABILITY
In May 2006, Western, through its wholly owned subsidiary, WesternZagros
Limited, entered into the EPSA with the Kurdistan Regional Government to
explore for conventional oil and gas in the Federal Region of Kurdistan pending
ratification by the KRG. The Federal Region of Kurdistan is in Northern Iraq.
Iraq is currently experiencing periods of civil unrest and political and
economical instability. Oil and gas exploration and development activities in
this jurisdiction may be affected in varying degrees by political instability,
government regulations relating to the oil and gas industry and foreign
investors therein and the policies of other countries in respect of those
nations. Any changes in regulations or shifts in political condition are beyond
the control of Western and may adversely affect its business.
Operations may be affected in varying degrees by government regulations,
policies or directives with respect to restrictions on production or sales,
price controls, export controls, repatriation of income, income taxes, carried
interests for the state, expropriation of property and environmental
legislation. Western will also be required to negotiate property development
agreements with the government having jurisdiction over some of its properties.
Such government may impose conditions that will affect the viability of the
project such as providing the government with free carried interests or
providing subsidies for the development of the local infrastructure or other
social assistance. There can be no assurance that Western will be successful in
concluding such agreements on commercially acceptable terms or that these
agreements will be successfully enforced in the foreign jurisdiction in which
Western's properties are located. Operations may also be affected in varying
degrees by political and economic instability, economic or other sanctions
imposed by the other countries, terrorism, civil wars, guerrilla activities,
military repression, crime, material fluctuations in currency exchange rates
and high inflation. The political status of the Kurdistan Region on Iraq in
which Western operates may make it more difficult for Western to obtain any
required project financing from senior lending institutions because such
lending institutions may not be willing to finance projects in this region due
to the perception of investment risk.
-46-
No assurances can be given that WesternZagros will be able to maintain or
obtain effective security or insurance of any of its assets or personnel in
Iraq where, at times, terrorism and insurgent activities have disrupted various
business activities during the past and may affect Western's operations or
plans in the future. Current military participation from the United States of
America and other allied countries are operating within Iraq to assist the new
local government to maintain peace and national security and law and order at
the national level. There can be no assurances to the commitment of these
foreign nations to continue to maintain their military presence nor can there
be assurances that the local government of Iraq can assert the ability
themselves to provide the necessary degree of peace, order and security. As
such, WesternZagros' ability to maintain effective security over its assets may
be adversely impacted. A high degree of security is also required to mitigate
the risk of loss by theft, either by Western's employees, contractors or third
parties.
Infrastructure development in the Kurdistan Region of Iraq is limited. In
addition, WesternZagros' properties are located in remote areas, many of which
are difficult to access. These factors may affect WesternZagros' ability to
explore and develop its properties and to store and transport its oil and gas
production. There can be no assurance that future instability in this region,
actions by companies doing business there, or actions taken by the
international community will not have a material adverse effect on this region
and in turn on WesternZagros' financial condition or operations.
THE EPSA MAY NOT BE RATIFIED.
The EPSA is not effective until it is passed into law. Although Western
continues to work towards ratifying the EPSA, there is no assurance that it
will be passed into law and thus may not be effective. Any change in the
Kurdistan local or Iraqi national government or legislation may affect the
status of WesternZagros' contractual arrangements or its ability to meet its
contractual obligations and may result in the loss of its interests in its oil
and gas properties. The laws of Canada do not apply to any of these contractual
arrangements and no assurances can be given that these contractual arrangements
will be enforced or interpreted in the same manner or to the same extent as
would be the case if the laws of Canada did apply.
TERMS OF THE EPSA, IF RATIFIED, MAY DIFFER FROM THOSE OF THE INITIAL CONTRACT.
The terms of the initial EPSA may be modified from those previously negotiated
in the spring of 2006 as a result of the ratification process. There is the
possibility that these amended terms, if agreed to by all parties, may reduce
the economic value attributable to WesternZagros. These amended terms may
include, but are not limited to, modifications to concession area, term and
work commitments.
TITLE MATTERS IN THE FEDERAL REGION OF KURDISTAN
As a result of the limited infrastructure present in the Federal Region of
Kurdistan, land titles systems are not developed to the extent found in many
industrialized nations and Western is subject to potential competing claims.
No assurance can be given that applicable governments will not revoke, or
significantly alter the conditions of, the applicable exploration and
development authorizations and that such exploration and development
authorizations will not be challenged or impugned by third parties. There is no
certainty that such rights or additional rights applied for will be granted or
renewed on terms satisfactory to WesternZagros. There can be no assurance that
claims by third parties against WesternZagros' properties will not be asserted
at a future date.
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RISKS ASSOCIATED WITH EXPLORATION AND DEVELOPMENT OF HYDROCARBON RESOURCES MAY
NEGATIVELY IMPACT WESTERN AND ITS SUBSIDIARIES.
The energy industry is highly competitive in all aspects, including the
exploration for and the development of new sources of hydrocarbon resource.
Western will compete for the exploration and the development of new sources of
hydrocarbon resource with major integrated oil and gas companies, as well as
various independent oil and gas companies. Western will do so through its 20
percent ownership interest in the AOSP and also through direct investments made
by Western into oil sands, through the ESPA and other ventures with significant
long-life hydrocarbon resource potential.
Western's 20 percent ownership interest in the AOSP gives Western the option,
upon satisfying certain conditions, to earn a working interest in additional
leases in the Athabasca region of Alberta that Shell or Chevron may purchase.
Western may also make certain of its investments involved in the exploration
and development of new sources of hydrocarbon resource in domestic or
international jurisdictions. Investments in international jurisdictions have
various inherent risks, including but not limited to political, economic,
legal, regulatory and foreign exchange risks. The exploration and development
of new sources of hydrocarbon resource can have various inherent risks,
including but not limited to encountering unexpected formations or pressures,
blow-outs, equipment failures, uncontrollable flows of oil, natural gas or well
fluid, and various environmental risks. Western will assess and mitigate to the
extent possible these inherent risks of international jurisdictions and the
inherent risks of exploration and development as these investments are
evaluated and pursued.
Western will also compete in the highly competitive energy industry for any
downstream initiatives it pursues, including the acquisition of upgrading and
refining capacity for heavy crude oil. There can be no assurance that Western
will be able to secure such opportunities and, if secured, will be able to
finance the complete such opportunities.
Western's future international conventional oil and natural gas exploration may
involve unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce sufficient net revenues to return a profit after
drilling, operating and other costs. Completion of a well does not assure a
profit on the investment or recovery of drilling, completion and operating
costs. In addition, drilling hazards or environmental damage could greatly
increase the cost of operations and various field operating conditions may
adversely affect the production from successful wells.
Whether Western ultimately undertakes an exploration or development project
depends upon a number of factors, including availability and cost of capital,
current and projected oil and gas prices, receipt of government approvals,
access to the property, the costs and availability of drilling rigs and other
equipment, supplies and personnel necessary to conduct these operations,
success or failure of activities in similar areas and changes in the estimates
to complete the projects. Failure by the Corporation to secure necessary
equipment could adversely affect the Western's business, results of operations
or financial condition.
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.
-48-
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 pre-tax 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 limited production and operating history of the Project;
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 a limited 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 from them, 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.
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 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 by the prescribed time period, 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.
INDEPENDENT REVIEWS MAY BE INACCURATE.
Although independent and qualified 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.
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FUTURE LITIGATION COULD ADVERSELY AFFECT WESTERN'S BUSINESS, RESULTS OF
OPERATIONS OR FINANCIAL CONDITION.
From time to time, Western is subject to litigation arising out of its
operations. Damages claimed under such litigation may be material or may be
indeterminate, and the outcome of such litigation may materially impact
Western's business, results of operations or financial condition. While Western
assesses the merits of each lawsuit and defends itself accordingly, it may be
required to incur significant expenses or devote significant resources to
defending itself against such litigation. In addition, the adverse publicity
surrounding such claims may have a material adverse effect on Western's
business.
TRANSFER AGENTS AND REGISTRAR
Valiant Trust Company at its principal office in Calgary, Alberta is the
transfer agent and registrar of the Common Shares of the Corporation and BNY
Trust Company of Canada at its principal office in Toronto, Ontario is the
co-agent and registrar of the Common Shares of the Corporation.
INTEREST OF EXPERTS
GLJ Petroleum Consultants Ltd., independent petroleum consultants to the
Corporation, prepared the GLJ Reserve Report and Contingent Resource Report,
both referenced herein. As at the date of the respective reports, the
principals of Norwest and GLJ, as respective groups, owned beneficially,
directly or indirectly, less than 1% of the outstanding Common Shares. GLJ
neither received nor will receive any interest, direct or indirect, in any
securities or other property of Western or its affiliates in connection with
the preparation of its reports.
LEGAL PROCEEDINGS
There are no legal proceedings which Western is a party to that involve a claim
for damages that exceed ten percent of the current assets of Western. Western
is however involved in arbitration proceedings arising from insurance claims.
See "Narrative Description of the Business - The Athabasca Oil Sands Project -
Mining - Base Operations".
ADDITIONAL INFORMATION
Additional information relating to the Corporation may be found on SEDAR at
www.sedar.com.
Additional information including directors' and officers' remuneration and
indebtedness, principal holders of the Corporation's securities and securities
authorized for issuance under equity compensation plans, 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 and MD&A for its most recently completed financial year.
GLOSSARY
IN THIS ANNUAL INFORMATION FORM, THE FOLLOWING TERMS SHALL HAVE THE MEANINGS
SET FORTH BELOW, UNLESS OTHERWISE INDICATED:
"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;
"AMI LEASES" Oil sands leases in the Athabasca oil sands region (other than
Shell's other Athabasca leases) which are acquired by an Owner and which are
subject to the Participation and AMI Agreement.
"AOSP" or the "PROJECT" Athabasca Oil Sands 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
Lease 13 in addition to any Bitumen Recovery Project implemented pursuant to
the Participation and AMI Agreement;
"ATCO" ATCO Power Canada Limited;
"BBLS" Barrels. One barrel equals 0.15891 cubic metres at 15(0) Celsius;
"CHEVRON" Chevron Canada Limited;
"COGE HANDBOOK" Canadian Oil and Gas Evaluation Handbook;
"COMMON SHARES" The Class A shares of Western;
"DOW" Dow Chemicals Canada Inc.;
"ELLS RIVER PROJECT" Chevron's proposed oil sands in-situ project which is
located approximately 50 kilometers northwest of Fort McMurray in the Athabasca
Oil Sands region;
"EPSA" Exploration and Production Sharing Agreement dated May 4, 2006 with the
Kurdistan Regional Government to explore for conventional oil and gas in the
Federal Region of Kurdistan;
"EXPANSION 1" The fully integrated expansion of the existing Project
facilities, with both new mining operations which includes the Jackpine Mine
and associated additional bitumen upgrading at the Scotford Upgrader, with
construction of common upstream infrastructure to support future expansions;
"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 are located 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;
"GLJ" GLJ Petroleum Consultants Ltd., independent petroleum consultants;
"GLJ RESERVES REPORT" The report prepared by GLJ dated February 7, 2007
evaluating the reserves attributable to Western as of December 31, 2006;
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"GLJ CONTINGENT RESOURCE REPORT" The report prepared by GLJ dated February 7,
2007 evaluating the mineable resources attributable to Leases 88, 89, 90, 9 and
the remainder of Lease 13 not included in the Muskeg River Mine or the Jackpine
Mine and after giving effect to the swaps with Syncrude Canada and Imperial
Oil, as well as Permits 15 and 631;
"HMU" The hydrogen manufacturing unit which supplies hydrogen to the Upgrader;
"JACKPINE MINE" The first planned expansion area to be developed by the Joint
Venture physically located on the east side of the Muskeg River;
"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, the western portion of which is the site
for the Muskeg River Mine and the eastern portion of which is the site for the
Jackpine Mine;
"MD&A" Management Discussion & Analysis;
"MM$" Millions of dollars and "M$" thousands of dollars;
"MMBBLS" Millions of barrels;
"MUSKEG RIVER MINE" or "MINE" The open pit mine located 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 Corporation, independent mining consultants;
"NOTES" Western's senior secured notes having a principal amount of US$450
Million bearing interest at a rate of 8.375% per annum and maturing on May 1,
2012;
"OWNERS" or "JOINT VENTURE OWNERS" The owners of undivided ownership interests
in the Project which include Shell, as to a 60% undivided ownership interest,
Chevron, as to a 20% undivided ownership interest, and Western, as to a 20%
undivided ownership interest;
"PARTICIPATION AND AMI AGREEMENT" The Participation and Area of Mutual Interest
Agreement dated December 6, 1999 among the Owners;
"PIERRE RIVER MINE" The anticipated expansion area to be developed by the Joint
Venture as Expansions 4 and 5, physically located on the west side of the
Athabasca River, initially on Leases 9 and 17;
"SAGD" Steam-assisted gravity drainage;
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"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
processes 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;
"SHELL" Shell Canada Limited; and
"SHELL'S OTHER ATHABASCA LEASES" Alberta Crown Oil Sands Lease Nos. 7288080T88,
7288080T89, 7288080T90, 7280050T26, 7281010T93, 7281030T53, 7281030T45,
7280080T28, 7400120009, 7401100017, 7405080351, 7405080352, 74058090631,
7405090632, 7405120015, 7405120309, 740512031, AT30 - 728009AT30, AT34 -
728011AT34, BT31 - 728010BT31, AT36 - 728101AT36, BT30 - 728009BT30 and all
renewals, extensions, replacements and amendments in respect of same, granted
to Shell by the Government of Alberta.
APPENDIX A
REPORT ON RESERVES DATA
BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR
To the board of directors of Western Oil Sands Inc. (the "Corporation"):
1. We evaluated the Corporation's reserves data as at December 31, 2006. The
reserves data consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves estimated
as at December 31, 2006, using forecast prices and costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and gas reserves estimated as at December 31, 2006,
using constant prices and costs; and
(ii) the related estimated future net revenue.
2. The reserves data are the responsibility of the Corporation's management.
Our responsibility is to express an opinion on the reserves data based on
our evaluation.
We carried out our evaluation in accordance with standards set out in the
Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared
jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter)
and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum
Society).
3. Those standards require that we plan and perform an evaluation to obtain
reasonable assurance as to whether the reserves data are free of material
misstatement. An evaluation also includes assessing whether the reserves
data are in accordance with principles and definitions in the COGE
Handbook.
4. The following table sets forth the estimated future net revenue (before
deduction of income taxes) attributed to proved plus probable reserves,
estimated using forecast prices and costs and calculated using a discount
rate of 10 percent, included in the reserves data of the Corporation
evaluated by us for the year ended December 31, 2006, and identifies the
respective portions thereof that we have evaluated and reported on to the
Corporation's board of directors:
Location of
Reserves
Description and (Country or Net Present Value of Future Net Revenue
Preparation Date of Foreign (Before Income Taxes, 10% Discount Rate)
Evaluation Geographic -------------------------------------------------
Report Area) Audited Evaluated Reviewed Total
------ ----- ------- --------- -------- -----
February 7, 2007 Canada 0 $3,868 MM$ 0 $3,868 MM$
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5. In our opinion, the reserves data respectively evaluated by us have, in
all material respects, been determined and are in accordance with the COGE
Handbook.
6. We have no responsibility to update our report referred to in paragraph 4
for events and circumstances occurring after the preparation date.
7. Because the reserves data are based on judgements regarding future events,
actual results will vary and the variations may be material.
Executed as to our report referred to above:
GLJ Petroleum Consultants Ltd.,
Calgary, Alberta, Canada Dated: February 7, 2007
ORIGINALLY SIGNED BY
James H. Willmon, P. Eng.
Vice-President
APPENDIX B
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
Management of Western Oil Sands Inc. (the "Corporation") are responsible for
the preparation and disclosure of information with respect to the Corporation's
oil and gas activities in accordance with securities regulatory requirements.
This information includes reserves data, which consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves estimated
as at December 31, 2006 using forecast prices and costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and gas reserves estimated as at December 31, 2006
using constant prices and costs; and
(ii) the related estimated future net revenue.
An independent qualified reserves evaluator has evaluated the Corporation's
reserves data. The report of the independent qualified reserves evaluator is
presented in Appendix A to this Annual Information Form.
The Reserves and Business Risk Committee of the Board of Directors of the
Corporation has:
(a) reviewed the Corporation's procedures for providing information to
the independent qualified reserves evaluator;
(b) met with the independent qualified reserves evaluator to determine
whether any restrictions affected the ability of the independent
qualified reserves evaluator to report without reservation; and
(c) reviewed the reserves data with management and the independent
qualified reserves evaluator.
The Reserves and Business Risk Committee of the Board of Directors has reviewed
the Corporation's procedures for assembling and reporting other information
associated with oil and gas activities and has reviewed that information with
management. The Board of Directors has, on the recommendation of the Reserves
and Business Risk Committee, approved:
(a) the content and filing with securities regulatory authorities of the
reserves data and other oil and gas information;
(b) the filing of the report of the independent qualified reserves
evaluator on the reserves data; and
(c) the content and filing of this report.
Because the reserves data are based on judgements regarding future events,
actual results will vary and the variations may be material.
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(signed) James C. Houck, President and Chief Executive Officer
(signed) Steve Reynish, Executive Vice President and Chief Operating Officer
(signed) Randall Oliphant, Director
(signed) David J. Boone, Director
(signed) Geoff Cumming, Lead Director
February 22, 2007
APPENDIX C
AUDIT COMMITTEE CHARTER
PURPOSE
The purpose of the Audit Committee of the Board is to assist the Board in
fulfilling its oversight responsibilities in relation to the review and
approval of the financial statements and financial reporting of the Corporation
and the assessment of internal control and management information of the
Corporation. The Audit Committee shall also be directly responsible for
overseeing all audit processes and the relationship of the external auditors
with the Corporation and the external auditors shall report directly, and be
accountable, to the Audit Committee.
The role of the Audit Committee is one of supervision, stewardship and
oversight. Management is responsible for preparing the financial statements and
financial reporting of the Corporation and for maintaining internal control and
management information. The external auditors are responsible for the audit or
review of the financial statements and other services they provide.
MANDATE
1. FINANCIAL STATEMENTS AND FINANCIAL REPORTING.
The Audit Committee shall:
(a) review with management and the external auditors, and recommend to
the Board for approval, the annual financial statements of the
Corporation, the reports of the external auditors thereon and related
financial reporting, including Management's Discussion and Analysis
and earnings press releases prior to the public disclosure of such
information;
(b) review with management and the external auditors, and approve, the
interim financial statements of the Corporation and related financial
reporting, including Management's Discussion and Analysis and
earnings press releases prior to the public disclosure of such
information;
(c) review with management and recommend to the Board for approval, the
Corporation's Annual Information Form;
(d) review with management and recommend to the Board for approval, any
financial statements of the Corporation which have not previously
been approved by the Board and which are to be included in a
prospectus of the Corporation or any other document required to be
filed or publicly disclosed pursuant to applicable legal and
regulatory requirements;
(e) consider and be satisfied that adequate procedures are in place for
the review of the Corporation's public disclosure of financial
information extracted or derived from the Corporation's financial
statements (other than disclosure referred to in clauses (a) and (b)
above), and periodically assess the adequacy of such procedures;
(f) review with management, the external auditors and, if necessary,
legal counsel, any litigation, claim or contingency, including tax
assessments, that could have a material effect upon the financial
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position of the Corporation, and the manner in which these matters
may be, or have been, disclosed in the financial statements;
(g) review the appropriateness of the accounting practices and policies
of the Corporation and review any proposed changes thereto;
(h) review and discuss any new or pending developments in accounting and
reporting standards that may affect the Corporation; and
(i) review accounting, tax and financial aspects of the operations of the
Corporation as the Audit Committee considers appropriate.
2. RELATIONSHIP WITH EXTERNAL AUDITORS.
The Audit Committee shall:
(a) consider and make a recommendation to the Board as to the appointment
or re-appointment of the external auditors, ensuring that such
auditors are participants in good standing pursuant to applicable
securities laws;
(b) consider and make a recommendation to the Board as to the
compensation of the external auditors;
(c) review and approve the annual audit plan of the external auditors
(including without limitation, engagement letters, objectives and
scope of the external audit, procedures for quarterly review of
financial statements, materiality limits, areas of audit risk,
staffing, timetables and proposed fees);
(d) oversee the work of the external auditors in performing their audit
or review services and oversee the resolution of any disagreements
between management and the external auditors;
(e) review and discuss with the external auditors all significant
relationships that the external auditors and their affiliates have
with the Corporation and its affiliates in order to determine the
external auditors' independence, including, without limitation, (A)
requesting, receiving and reviewing, on a periodic basis, a formal
written statement from the external auditors delineating all
relationships that may reasonably be thought to bear on the
independence of the external auditors with respect to the
Corporation, (B) discussing with the external auditors any disclosed
relationships or services that the external auditors believe may
affect the objectivity and independence of the external auditors, and
(C) recommending that the Board take appropriate action in response
to the external auditors' report to satisfy itself of the external
auditors' independence;
(f) as may be required by applicable securities laws, rules and
guidelines, either:
(i) pre-approve all non-audit services to be provided by the
external auditors to the Corporation (or its subsidiaries, if
any), or, in the case of de minimus non-audit services, approve
such non-audit services prior to the completion of the audit; or
(ii) adopt specific policies and procedures for the engagement of the
external auditors for the purpose of the provision of non-audit
services;
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(g) be satisfied that the fees paid by the Corporation to the external
auditors for audit and non-audit services are publicly disclosed; and
(h) review and approve the hiring policies of the Corporation regarding
partners, former partners, employees and former employees of the
present and former external auditors of the Corporation.
3. Internal Controls.
The Audit Committee shall:
(a) review with management and the external auditors, the adequacy and
effectiveness of the internal control and management information
systems and procedures of the Corporation (with particular attention
given to accounting, financial statements and financial reporting
matters and to being satisfied that such systems are reliable and
that they operate effectively to produce accurate, appropriate and
timely management and financial information) and determine whether
the Corporation is in compliance with applicable legal and regulatory
requirements and with the Corporation's policies;
(b) review the external auditors' recommendations regarding any matters,
including internal control and management information systems and
procedures, and management's responses thereto;
(c) establish procedures for the receipt, retention and treatment of
complaints, submissions and concerns regarding accounting, internal
accounting controls or auditing matters on an anonymous and
confidential basis;
(d) review policies and practices concerning the expenses and perquisites
of the Chairman, including the use of the assets of the Corporation;
(e) review with external auditors any corporate transactions in which
directors or officers of the Corporation have a personal interest;
(f) review insurance coverage of significant business risks and
uncertainties;
(g) review material litigation and its impact on financial reporting; and
(h) review policies and procedures for the review and approval of
officers' expenses and perquisites.
COMPOSITION AND PROCEDURES
1. COMPOSITION OF COMMITTEE.
The Audit Committee shall consist of not less than three directors, none
of whom shall be an officer or employee of the Corporation or any of its
subsidiaries or any affiliate thereof. Each Audit Committee member shall
satisfy the independence, experience and financial literacy requirements
of applicable securities laws, rules or guidelines, any applicable stock
exchange requirements or guidelines and any other applicable regulatory
rules. In addition, the Chair shall have "accounting or related financial
expertise". The Board has defined "financial literacy" as the ability to
understand a balance sheet, income statement and a cash flow statement in
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accordance with Canadian GAAP and the Board has defined "accounting or
financial expertise" as the ability to analyze and understand a full set
of financial statements, including the notes attached thereto in
accordance with Canadian GAAP. Each member of the Audit Committee shall
have no direct or indirect material relationship with the Corporation or
any affiliate thereof which could reasonably be expected to interfere with
the exercise of the member's independent judgment, other than interests
and relationships arising from the holdings of shares of the Corporation.
Determinations as to whether a particular director satisfies the
requirements for membership on the Audit Committee shall be made by the
full Board and shall be reviewed at least annually.
If a member of the Audit Committee ceases to be independent for reasons
outside that member's reasonable control, the member shall immediately
notify the Chair of the Board as to this fact and shall resign his or her
position as a member of the Audit Committee on the earliest of (i) the
appointment of his or her successor; (ii) the next annual meeting of
shareholders of the Corporation; and (iii) the date that is six months
from the occurrence of the event which caused the member to not be
independent.
2. APPOINTMENT OF COMMITTEE MEMBERS
Members of the Audit Committee shall be appointed from time to time and
shall hold office at the pleasure of the Board. Where a vacancy occurs at
any time in the membership of the Audit Committee, it may be filled by the
Board. The Board shall fill any vacancy if the membership of the Audit
Committee is less than three directors.
3. ABSENCE OF COMMITTEE CHAIR
If the Chair of the Audit Committee is not present at any meeting of the
Audit Committee, one of the other members of the Audit Committee who is
present at the meeting shall be chosen by the Audit Committee to preside
at the meeting.
4. AUTHORITY TO ENGAGE EXPERTS
The Audit Committee has the authority to engage independent counsel and
other advisors as it determines necessary to carry out its duties and to
set the compensation for any such counsel and advisors, such engagement to
be at the Corporation's expense.
5. MEETINGS
The Audit Committee shall meet at least four times per year and shall meet
at such other times during each year as it deems appropriate, provided
that meetings shall be scheduled so as to permit timely review of the
quarterly and annual financial statements and reports. In addition, the
Chair of the Audit Committee may call a special meeting of the Audit
Committee at any time. The Audit Committee shall meet with the external
auditors on a regular basis in the absence of management and, if so
requested by a member of the Audit Committee, the external auditor shall
attend every meeting of the Audit Committee held during the term of office
of the external auditor. The Chair of the Audit Committee, the Chairman of
the Board, any two members of the Audit Committee or the external auditors
may call a meeting of the Audit Committee. The external auditors shall be
provided with notice of every meeting of the Audit Committee and, at the
expense of the Corporation, shall be entitled to attend and be heard
thereat. The Chair of the Audit Committee shall hold in camera meetings of
the Audit Committee, without management present, at every Audit Committee
meeting.
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6. QUORUM
A majority of the members of the Audit Committee, present in person or by
telephone or by other telecommunication device that permits all person
participating in the meeting to communicate with each other, shall
constitute a quorum.
7. PROCEDURE, RECORDS AND REPORTING
Subject to any statute or the articles and by-laws of the Corporation, the
Audit Committee shall fix its own procedures at meetings, keep records of
its proceedings and report to the Board when the Audit Committee may deem
appropriate (but not later than the next meeting of the Board).
8. DELEGATION
The Audit Committee may delegate from time to time to any person or
committee of persons any of the Audit Committee's responsibilities that
lawfully may be delegated.
9. REVIEW OF TERMS OF REFERENCE
The Audit Committee shall review and reassess the adequacy of its Terms of
Reference at least annually, and otherwise as it deems appropriate, and
recommend changes to the Board. Such review shall include the evaluation
of the performance of the Audit Committee against criteria defined in the
Audit Committee mandate as well as the Directors' Charter.