exv4w1



 





Exhibit 4.1









Annual Information Form




For the Year Ended




December 31, 2007




January 22, 2008




 









 





TABLE OF CONTENTS




	 	 	 	 	 
	 	 	Page	 
	INTRODUCTORY INFORMATION
	 	 	1	 
	FORWARD LOOKING INFORMATION
	 	 	1	 
	CORPORATE STRUCTURE
	 	 	4	 
	GENERAL DEVELOPMENT OF THE BUSINESS
	 	 	4	 
	Key Events in 2007
	 	 	5	 
	Competitive Strengths and Operating Strategies
	 	 	5	 
	Our Industry
	 	 	9	 
	Our Principal Assets
	 	 	9	 
	The Project and Future Phases
	 	 	10	 
	The Long Lake Project
	 	 	13	 
	The OrCrudeTM Process
	 	 	18	 
	Marketing
	 	 	19	 
	Infrastructure
	 	 	20	 
	Project Development
	 	 	20	 
	Material Agreements Related to the Joint Venture
	 	 	21	 
	Royalties
	 	 	27	 
	Regulatory Approvals and Environmental Considerations
	 	 	28	 
	Insurance
	 	 	30	 
	RESERVES AND RESOURCES SUMMARY
	 	 	31	 
	DESCRIPTION OF CAPITAL STRUCTURE
	 	 	33	 
	CREDIT RATINGS
	 	 	36	 
	MARKET FOR SECURITIES
	 	 	37	 
	DIVIDENDS
	 	 	37	 
	DIRECTORS AND OFFICERS
	 	 	37	 
	CONFLICTS OF INTEREST
	 	 	44	 
	RISKS AND UNCERTAINTIES
	 	 	45	 
	MATERIAL CONTRACTS
	 	 	58	 
	LEGAL PROCEEDINGS AND REGULATORY ACTIONS
	 	 	58	 
	TRANSFER AGENTS AND REGISTRAR
	 	 	58	 
	INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
	 	 	58	 
	INTERESTS OF EXPERTS
	 	 	58	 
	ADDITIONAL INFORMATION
	 	 	59	 
	GLOSSARY
	 	 	60	 






	 	 	 	 	 
	APPENDIX A

	 	—
	 	RESERVES DATA AND OTHER OIL AND GAS INFORMATION
	APPENDIX B

	 	—
	 	REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES
EVALUATOR
	APPENDIX C

	 	—
	 	REPORT OF MANAGEMENT ON RESERVES DATA AND OTHER INFORMATION
	APPENDIX D

	 	—
	 	AUDIT COMMITTEE CHARTER






 









 






INTRODUCTORY INFORMATION




     Except as otherwise indicated or unless the context otherwise require the terms “OPTI,” “we,”
“our” and “us,” refer to OPTI Canada Inc. Initially capitalized terms used herein and not otherwise
defined have the meanings ascribed thereto in the Glossary located on
page 60.



     Unless otherwise indicated, all financial information included and incorporated by reference
in this AIF is determined using Canadian generally accepted accounting principles (“Canadian GAAP”)
which differs in some respects from generally accepted accounting principles in the United States.



     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 AIF contains forward looking statements and forward looking information within the
meaning of the U.S. federal securities laws and applicable Canadian securities laws. These
statements are subject to certain risks and uncertainties that could cause actual results to differ
materially from those included in the forward looking statements and forward looking information.
The words “believe,” “expect,” “intend,” “estimate,” “anticipate,” “project,” “scheduled” and
similar expressions, as well as future or conditional verbs such as “will,” “should,” “would” and
“could” often identify forward looking statements and forward looking information. These statements
and information are only predictions. Actual events or results may differ materially. In addition,
this AIF may contain forward looking statements and forward looking information attributed to third
party industry sources. Undue reliance should not be placed on these forward looking statements and
forward looking information, as there can be no assurance that the plans, intentions or
expectations upon which they are based will occur. By their nature, forward looking statements and
forward looking information involve numerous assumptions, known and unknown risks and
uncertainties, both general and specific, that contribute to the possibility that the predictions,
forecasts, projections and other forward looking statements and forward looking information will
not occur.



     Specific forward looking statements and forward looking information contained in this AIF
include, among others, statements regarding:




	 	•	 	the expected cost to construct the Project;
	 
	 	•	 	the timing of commencement of operations and the level of production achieved;
	 
	 	•	 	the operation of our facilities, including the steam-to-oil ratio (“SOR”) of the
SAGD Operation and the Premium Sweet Crude (“PSCTM”) yield of the Long Lake Upgrader;
	 
	 	•	 	our estimated general financial performance in future periods;
	 
	 	•	 	our reserve and resource estimates and our estimates of the present value of our
future net cash flow;
	 
	 	•	 	our expansion plans for our properties and our expected increases in revenues
attributable to our expansions;
	 
	 	•	 	the impact of governmental controls and regulations on our operations;
	 
	 	•	 	our competitive advantages and ability to compete
successfully; and
	 
	 	•	 	our expectations regarding the development and production potential of our properties.




 









 











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     With respect to forward looking statements and forward looking information contained in this
AIF, we have made assumptions regarding, among other things:




	 	•	 	future natural gas and crude oil prices;
	 
	 	•	 	our ability to obtain qualified staff and equipment in a timely and cost-efficient
manner to meet our demand;
	 
	 	•	 	the regulatory framework representing royalties, taxes and environmental matters in
which we conduct our business;
	 
	 	•	 	our ability to market PSCTM successfully to customers;
	 
	 	•	 	the impact of increasing competition; and
	 
	 	•	 	our ability to obtain financing on acceptable terms.





     Some of the risks that could affect our future results and could cause results to differ
materially from those expressed in our forward looking statements and forward looking information
include:




	 	•	 	the cost of constructing the Project and maintaining the Project construction
schedule and planned start-up dates;
	 
	 	•	 	difficulties encountered during the production of PSCTM;
	 
	 	•	 	costs associated with producing and upgrading bitumen;
	 
	 	•	 	the impact of competition;
	 
	 	•	 	the need to obtain required approvals and permits from regulatory authorities;
	 
	 	•	 	liabilities as a result of accidental damage to the environment;
	 
	 	•	 	compliance with and liabilities under environmental laws and regulations;
	 
	 	•	 	the uncertainty of estimates by our independent consultants with respect to our
bitumen and synthetic crude oil reserves and resources;
	 
	 	•	 	the volatility of crude oil and natural gas prices and of the differential between
heavy and light crude oil prices;
	 
	 	•	 	changes in the foreign exchange rate among the Canadian and U.S. dollar;
	 
	 	•	 	risks that our financial counterparties may not fulfill financial obligations
to us;
	 
	 	•	 	difficulties encountered in delivering PSCTM to commercial markets;
	 
	 	•	 	we may be unable to sufficiently protect our proprietary technology or may be the
subject of technology infringement claims from third parties;
	 
	 	•	 	general economic conditions in Canada and the United States,
	 
	 	•	 	failure to obtain industry partner and other third party consents and approvals,
when required;
	 
	 	•	 	royalties payable in respect of our production;
	 
	 	•	 	the impact of amendments to the Income Tax Act (Canada) on us;
	 
	 	•	 	changes in or the introduction of new government regulations, in particular related
to carbon dioxide (“CO2”), relating to our business; and
	 
	 	•	 	the uncertainty of our ability to attract capital.




 









 











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     The information contained in this AIF, including the information provided under the heading
“Risks and Uncertainties”, identifies additional factors that could affect our operating results
and performance. We urge you to carefully consider those factors and the other information
contained in this AIF.



     Our forward looking statements and forward looking information are expressly qualified in
their entirety by this cautionary statement. Our forward looking statements and forward looking
information are only made as of the date of this AIF. We undertake no obligation to update these
forward looking statements and forward looking information to reflect new information, subsequent
events or otherwise, except as required by law.




 











 





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OPTI CANADA INC.

CORPORATE STRUCTURE




     OPTI Canada Inc. was incorporated under the laws of New Brunswick on January 15, 1999 and was
continued under the Canada Business Corporations Act on May 30, 2002. On March 4, 2004, our
articles were amended to create a class of preferred shares, issuable in a series and to increase
the maximum size of the board of directors to fourteen persons. On March 5, 2004, our articles were
amended to create the first series of preferred shares, being an unlimited number of Series A
Convertible Preferred Shares (“Series A Shares”). On April 13, 2004, our articles were amended in
connection with our initial public offering to effect a reorganization of capital whereby a class
of shares designated as “common shares” was created; all Class A Voting Common Shares, Class B
Non-Voting Common Shares and Class C Voting Common Shares were changed into Common Shares on a one
for one basis; and the Class A Voting Common Shares, Class B Non-Voting Common Shares and Class C
Voting Common Shares were removed from our authorized share capital. Additionally on April 13,
2004, the restrictions on transfer were removed. On June 24, 2004, our articles were amended to
create the second series of preferred shares, being an unlimited number of Series B Convertible
Preferred Shares (“Series B Shares”) and on June 9, 2005, our articles were amended to create a
third series of preferred shares, being an unlimited number of Series C Convertible Non-Voting
Preferred Shares (“Series C Shares”). On May 10, 2006, our articles were amended to divide our
issued and outstanding common shares on a two-for-one basis which took effect on June 1, 2006. See
“Description of Capital Structure — Description of Share Capital.” All references to share
issuances and stated capital in this AIF give effect to these reorganizations of capital.



     Effective October 1, 2004, we assigned substantially all of our interests in the Project to
OPTI Long Lake L.P. (“OPTI LP”), an Alberta limited partnership. The partners of the OPTI LP were
OPTI Canada Inc., as limited partner, and OPTI G.P. Inc., a wholly-owned subsidiary of OPTI Canada
Inc., as the general partner. Effective January 1, 2008, the limited partnership was dissolved and
OPTI Canada Inc. was amalgamated with OPTI G.P. Inc. OPTI has no material subsidiaries.



     Our head office is located at Suite 2100, 555 — 4th Avenue S.W., Calgary, AB, T2P 3E7 and our
registered office is located at 3700, 400 — 3rd Avenue S.W., Calgary, Alberta, T2P 4H2. As at
December 31, 2007 we had approximately 385 employees, of which approximately 225 comprise our
operations group and are located in Fort McMurray.



GENERAL DEVELOPMENT OF THE BUSINESS




     We are a Calgary, Alberta-based oil sands development company. We and Nexen Inc. (“Nexen”),
the JV Participants, each own a 50 percent undivided interest in the Project, which upon completion
will, among other things, include the Long Lake SAGD Operation and the Long Lake Upgrader, each
with expected through-put rates of approximately 72,000 barrels per day (bbl/d) of bitumen. We
expect the yield from the Long Lake Upgrader to be 57,700 bbl/d of PSCTM and approximately 800 bbl/d
of butane. We expect PSCTM to sell at a price similar to West Texas Intermediate (“WTI”) crude oil.
We expect SAGD volumes from the Long Lake SAGD Operation to ramp-up to about 50 percent capacity in
mid-2008 in preparation for Upgrader start-up and SAGD volumes to reach full design rates of
approximately 72,000 bbl/d of bitumen in 2009. We expect that the increasing capacity of the Long
Lake Upgrader during ramp-up will enable us to process all of the forecasted SAGD volumes.



     We are the operator of the Long Lake Upgrader and Nexen is the operator of the Long Lake SAGD
Operation. Nexen Marketing is currently responsible for marketing all of the output from the
Project.









 



-5-


     The leases that support our development plans are located in the Athabasca region of
north-eastern Alberta. The Project is being developed on a portion of the Long Lake leases that are
dedicated to the Project. Additional portions of the Long Lake leases and other leases in areas
commonly referred to as Cottonwood and Leismer will be used for possible future expansion phases.



Key Events in 2007




     Selected material events in the advancement of our business in 2007 were as follows:




	 	•	 	Commencement of steam injection into all 10 well pads at the Long Lake SAGD
Operation.
	 
	 	•	 	Continued progress of Upgrader construction and commissioning. All Upgrader
units are currently on-track for expected construction completion by the end of the
first quarter of 2008.
	 
	 	•	 	The JV Participants increased the cost estimate to complete Long Lake Phase 1
to a range of $5.8 to $6.1 billion, due to difficulties securing sufficient skilled
labour, lower than expected productivity and increases in the amount of work required
to complete construction.
	 
	 	•	 	Ongoing training of operations staff in preparation for safe and reliable
operation of the Long Lake Project.
	 
	 	•	 	Continued progress of Long Lake Phase 2 engineering and planning activities in
preparation for potential project sanctioning in late 2008. This includes the ongoing
evaluation of the potential for incorporation of facilities to capture CO2
in future phases.
	 
	 	•	 	Completion of the 2007 winter drilling and seismic program and commencement of
2007/8 program to further expand our resource base and advance our expansion plans.
	 
	 	•	 	Under the Alberta Government’s proposed changes to the royalty regime, royalty
rates for oil sands projects will be indexed to WTI oil prices at $55/bbl and above
beginning in 2009.
	 
	 	•	 	Changes to the Federal Corporate tax rate were also announced in 2007,
decreasing our Federal and Provincial combined rate each year from 32 percent in 2007
to 25 percent in 2012.
	 
	 	•	 	Successful completion of a $412 million equity financing as well as a US$750
million senior secured note financing to fund Phase 1 to completion as well as to
support our future phase activities in 2008. Additionally, we repaid and cancelled our
U.S. dollar $450 million TLB credit facility. We also completed U.S. dollar $875
million of cross currency swaps to fix a portion of our interest and principal payments
in relation to our U.S. dollar long term debt.





Competitive Strengths and Operating Strategies




     Our plan is to optimize the economic recovery of reserves and resources from our lands. We
plan to achieve this objective by expanding our resource base, using a combination of proven
operating technologies to minimize risk, employing a systematic multi-staged approach to future
expansions, and maintaining an integrated approach using SAGD combined with the Integrated OrCrudeTM
Upgrader to reduce our exposure to various commodity prices.









 



-6-


     Our competitive strengths are as follows:



Large, Low Risk Exploitable Resource Base




     Our working interest share of reserves and resources on current leases are estimated to be
approximately 3.0 billion barrels of bitumen. We believe that the approval of future phases by our
board of directors and by regulatory authorities in Alberta will allow us to convert our
substantial resource base into additional proved reserves. According to McDaniel, as of December
31, 2007, we had proved reserves of 268 MMbbl, enough to sustain our anticipated levels of Project
production for in excess of 19 years. Our reserves and resources of 3.0 billion barrels is
estimated to be enough to sustain production for up to five additional phases of a similar size as
the Project for approximately 40 years. See “Reserves and Resources Summary”.



     When compared to a conventional exploration and production operation, we believe that an oil
sands operation, like our Project, generally has lower geological risk. Unlike conventional oil
exploration and production, we expect that the Project will have a constant non-declining rate of
daily production during the life of the Project and therefore would not require ongoing exploration
risk to maintain its production rate once operational. To maintain this daily rate of production,
future maintenance and sustaining capital expenditures will be required.



     Once the Project is operational, we believe that our capital expenditures in connection with
the Project will include maintenance and sustaining capital costs, which we define as those capital
costs necessary to maintain production at the anticipated level over the anticipated life of the
Project. We expect these costs to average approximately $6.00/bbl of PSCTM, bitumen and butane
produced. These costs relate to the drilling of new well pairs to sustain production and regular
maintenance capital spending on plant and facilities. The $6.00/bbl does not include expenditures
related to future phases.



Strong Margins




     We expect that the sale of PSCTM and lower operating costs, primarily due to lower
natural gas costs, will allow us to generate strong margins.



     The following financial outlook represents our current estimates of revenue, royalties,
general and administrative expenses (“G&A”), and operating costs per barrel of product sold, when
the Project is at full production capacity. The financial outlook is based on our current
assumptions with respect to commodity prices, primarily WTI and natural gas, electricity prices,
currently proposed provincial royalty regime/rate changes and the other variables described in the
notes to the table below.



     This financial outlook provides a measure of the ability of our Project to generate netbacks
assuming full production capacity. The financial outlook may not be suitable for other purposes.
The netbacks generated by our Project are expected to be lower than shown in this outlook in the
years immediately following start-up due to production ramp-up and an initially higher steam oil
ratio. We expect to reach full capacity in 2009 and have full production capacity for 2010.









 



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Estimated Phase 1 Future Project Netbacks(1)




	 	 	 	 	 
	 	 	$/bbl	 
	Revenue(2)(3)
	 	$	72.26	 
	Royalties and G&A(4).
	 	 	(2.49	)
	Operating costs(5)
	 	 	 	 
	Natural gas(6)
	 	 	(4.67	)
	Other variable(7)
	 	 	(2.78	)
	Fixed
	 	 	(10.62	)
	 
	 	 	 
	Netback
	 	$	51.70	 
	 
	 	 	 








 




			
	Notes:
	 
	(1)	 	The per barrel amounts are based on the expected yield for the Project of 57,700 bbl/d of
PSCTM and 800 bbl/d of butane, and assume that the Upgrader will have an on-stream factor of 96
percent. See “Forward Looking Information.”
	 
	(2)	 	Based on WTI of US$65.00, foreign exchange of $1.00=US$0.88, natural gas price (NYMEX) of
US$9.29, and an electricity sales price of $126.29 per megawatt hour.
	 
	(3)	 	Includes sale of PSCtm, bitumen, butane and electricity.
	 
	(4)	 	Royalties are calculated on a pre-payout basis and are based on a light/heavy differential of
US$20.89. We anticipate payout for royalty purposes to occur in 2026 based on the assumptions
noted. For more information, see “General Development of the Business — Royalties.” Based on
the royalty structure as announced by the Government of Alberta on October 25, 2007, we
estimate royalties and corporate G&A after payout to be $5.59/bbl.
	 
	(5)	 	Costs are unescalated and are based on 2008 Canadian dollars.
	 
	(6)	 	Based on our long term estimate for a SOR of 3.0.
	 
	(7)	 	Includes approximately $1.00/bbl for greenhouse gas mitigation costs based on an average
approximate 20 percent reduction of CO2 emissions at a cost of $20 per tonne of
CO2. “General Development of the Business — Regulatory Approvals and
Environmental Considerations — Greenhouse Gases and Industrial Air Pollutants.”





Significantly Advanced Project Using Previously Demonstrated Technologies




     As of December 31, 2007, SAGD reservoir warm-up was in progress with steam injection into all
well pads, construction of the Upgrader was over 95 percent complete, and commissioning and
start-up activities for the Upgrader had commenced. We expect SAGD volumes to ramp-up to about 50
percent capacity in mid-2008 in preparation for Upgrader start-up and SAGD volumes to reach full
design rates in 2009. We expect that the increasing capacity of the Long Lake Upgrader during
ramp-up will enable us to process all of the forecasted SAGD volumes.



     The Project is located in a region that has experienced a significant recent increase in oil
sands activity. A number of other operators, such as Suncor Energy Inc., Petro-Canada, Husky
Energy Inc. and EnCana Corporation, are currently utilizing SAGD recovery methods for their
projects. The Long Lake project includes SAGD in conjunction with on-site bitumen upgrading. The
Upgrader utilizes OrCrudeTM technology along with commercially available hydrocracking
and gasification technologies which have been used in many applications around the world to process
heavy oil into refinery and petrochemical feedstocks.



     Both the SAGD and OrCrudeTM technologies have been demonstrated by the JV
Participants in the form of a SAGD Pilot and an OrCrudeTM demonstration plant. The SAGD
Pilot consisted of three horizontal well pairs and associated facilities. The SAGD Pilot operated
from mid 2003 to mid 2006 and provided important design and operating information that has been
incorporated into the Project. The OrCrudeTM demonstration plant had a capacity of 500
bbl/d, was in operation from the second quarter of 2001 to the fourth quarter of 2003 and processed
over 250,000 bbls of bitumen from various sources,









 




-8-


including the SAGD Pilot. The OrCrudeTM demonstration plant provided design and
operating parameters that have been incorporated into the Project.




Integrated Approach and OrCrudeTM Technology Results in Lower Cash Flow Volatility




     The majority of in-situ bitumen projects currently being developed in Alberta are intending to
use SAGD without on-site upgrading capacity. We believe that the use of the Integrated OrCrudeTM
Upgrader offers several advantages over these other projects in that the Integrated OrCrudeTM
Upgrader provides a solution to the three traditional challenges of SAGD operations:



	 	 	 
	Challenge	 	Integrated OrCrudeTM Upgrader Solution
	Exposure to fluctuating natural gas prices

	 	Operating costs and the volatility
of netbacks are reduced since the
Integrated OrCrudeTM
Upgrader produces synthesis
gas to supply fuel and hydrogen
thereby significantly reducing the
need to purchase natural gas
	 
	 	 
	Exposure to heavy oil differentials.

	 	The Integrated OrCrudeTM Upgrader
produces a high quality 39°
API synthetic crude oil
thereby significantly reducing this
exposure
	 
	 	 
	Exposure to rising diluent prices and
potential diluent shortages

	 	The Integrated OrCrudeTM Upgrader
produces a synthetic crude oil that
does not require diluent to assist
in its transportation, thereby
limiting the Project’s exposure to
diluent pricing and availability
once the Long Lake Upgrader is
operational






Strong Joint Venture Sponsorship and Technical Expertise




     We benefit from the participation, sponsorship and execution capabilities of Nexen, one of
Canada’s largest independent oil and natural gas producers with reported production of over 260,000
barrels of oil equivalent per day (“boe/d”), prior to royalties, in the third quarter of 2007.
Nexen has extensive holdings of heavy oil and bitumen resources, including its 7.23 percent
interest in the Syncrude Project, and employs a team of geologists, engineers and other technical
personnel to support these interests. Nexen Marketing is currently responsible for marketing all of
the output from the Project. Nexen Marketing is a large marketer of crude oil and other hydrocarbon
products, marketing approximately 1.8 million boe/d in the third quarter of 2007.



Experienced Management Team




     The members of our senior management team have, on average, over 20 years of industry
experience. We and Nexen have also established technical teams for the construction and operation
of the Project who have extensive previous experience in a number of oil sands and construction
projects. Based on experience in development of the Project, our senior management team has unique
knowledge with respect to development of the Project that may apply to future phases.









 



-9-


Our Industry




     Oil sands operators produce and process bitumen, which is the extremely heavy oil trapped in
the sands. According to the EUB, Canada’s oil sands are estimated to hold 315 billion barrels of
ultimately recoverable bitumen reserves, with established reserves of 173 billion barrels at the
end of 2006, second only to Saudi Arabia and significantly more than the recoverable reserves in
the United States. According to the Canadian Association of Petroleum Producers, in 2006 oil sands
production reached over 1.1 million bbl/d and surpassed conventional production for the first time.
The EUB estimates that oil sands production will reach 3.2 million bbl/d by 2016.



     Of the 315 billion barrels of potentially recoverable bitumen estimated to be contained in
Canada’s oil sands, only about 20 percent are shallow enough to be mined, leaving the remainder of
the resource to be exploited using in-situ techniques. The in-situ techniques currently in use
employ steam to heat the bitumen, allowing it to flow into a well and to be produced to the
surface. The two most common methods of in-situ production are Cyclic Steam Injection (“CSS”) and
SAGD. The steam used in both processes is normally generated using natural gas, and natural gas is
the primary input cost of both methods. SAGD typically has higher recovery rates and is a more
energy efficient process than CSS in bitumen deposits such as ours.



     Bitumen is currently sold in two principal forms: either as a bitumen blend, in which the
bitumen is mixed with a diluent (a very light hydrocarbon liquid) so that it will flow in
pipelines; or, after upgrading, as a synthetic crude oil. Bitumen blend has many characteristics
similar to, and is generally priced like, conventional heavy oil. Synthetic crude oil, depending on
the level of upgrading it has undergone, has many characteristics similar to, and is generally
priced like, conventional medium or light oil.



     Upgrading is the process that changes bitumen into synthetic crude oil. Bitumen, like crude
oil, is a complex mixture of hydrocarbon components with a relatively high content of carbon in
relation to hydrogen compared to conventional light crude oil. Some upgrading processes remove
carbon, while others add hydrogen or change molecular structures. The main product of upgrading is
synthetic crude oil that can be later refined like conventional oil into a range of consumer
products by traditional refineries.



Our Principal Assets




     Our principal assets include:




	•	 	a 50 percent interest in the Project and our corresponding $2.7 billion investment to the end
of 2007;






	•	 	proved plus probable plus possible bitumen reserves associated with a portion of the Long
Lake Leases of 941 MMbbl;







	•	 	bitumen resources of an estimated 2.2 billion bbl contained in the remainder of the Long
Lake, Leismer and Cottonwood Leases. See “Reserves and Resources
Summary”; and






	•	 	the exclusive right to use the OrCrudeTM Process technology in Canada.













 



-10-







The Project and Future Phases




The Project




     In 2001, we and Nexen formed a joint venture to develop integrated oil sands projects in
Canada. The first such project is Phase 1 of the Long Lake Project. We own a 50 percent undivided
interest in the Project, which upon completion will, among other assets, include the Long Lake SAGD
Operation and the Long Lake Upgrader, each with expected capacities of approximately 72,000 bbl/d
of bitumen. We expect the yield from bitumen produced from the Long Lake SAGD Operation to be
57,700 bbl/d of PSCtm and approximately 800 bbl/d of butane resulting in an
overall expected yield of approximately 81 percent. We expect PSCtm to sell at a price
similar to WTI crude oil although the selling price is expected to fluctuate above and below WTI.



     The Project is planned to be the first commercial application of the
OrCrudetm Process. The Project involves two major components, being the
recovery of bitumen and the upgrading of bitumen into PSCtm and other petroleum
products. The Project will include a cogeneration facility that generates steam for the SAGD wells
and electricity for use by the Project. The cogeneration facility will have a capacity of 170
megawatts.




     We are the operator of the Long Lake Upgrader and
have primary responsibility for all matters relating to the Long Lake Upgrader, subject to certain
approvals of the management committee of the joint venture. We are currently responsible for overseeing the
construction, commissioning and start-up and operation of the Long Lake Upgrader.



     Nexen is the operator of the Long Lake
SAGD Operation and has primary responsibility for all matters relating to such lands, plants
and operations, subject to certain approvals of the management committee of the joint venture.
Nexen was responsible for overseeing the operation of the SAGD Pilot facility, the construction
and operations of the Long Lake SAGD Operation.



     Significant progress continues to be made on the Project as we prepare for first bitumen sales
in the first quarter of 2008 with first production of PSCTM
expected in mid-2008. The SAGD plant is
operational with all 10 well pads steaming into both injector and producer wells to efficiently
heat the reservoir. We expect that we will begin to turn over some of the producer wells into operations
mode within the next several weeks. SAGD production is anticipated to reach 50 percent capacity in
mid-2008 with SAGD volumes expected to ramp-up through 2008 and reach full design rates of 72,000
bbl/d in 2009.



     Construction, start-up and commissioning activities on the Upgrader continued in the fourth
quarter of 2007. The OrCrudeTM, hydrocracker and utilities plants have been turned over to
operations. The front end of the OrCrudeTM unit has been filled with lube oil to allow the start-up
of pumps and heaters and the utility boilers are in operation providing heat and steam.



     The
gasifier and air separation units were essentially mechanically
complete in December 2007,
with current activities focused on final electrical work and insulation. A substantial amount of
progress was made on the sulphur recovery unit in the fourth quarter of 2007 and the unit remains
scheduled for mechanical completion in the first quarter of 2008.



     Once operational, we expect that the capacity of the Long Lake Upgrader during ramp-up will
enable us to process all of the forecasted SAGD volumes. As a result, we expect the Project to reach
full capacity of 58,500 bbl/d of PSCTM and other products in 2009.



     Our current total cost estimate of the Project is between $5.8 billion and $6.1 billion or
between $2.90 billion and $3.05 billion net to us. As of December 31, 2007, $5.4 billion or $2.7
billion net to us had been incurred on the Project. The risk of changes to our forecast cost to
complete and schedule are now primarily related to the typical commissioning and start-up risks
associated with any major hydrocarbon processing complex.










 



-11-


     The Project is being governed pursuant to the terms and conditions of the COJO Agreement and
the Technology Agreement. See “Material Agreements Related to the Joint Venture”.



Our Lands and Leases




     The following table sets forth our gross and net acreage in respect of the leases comprising
our lands as well as the delineation wells the JV Participants have drilled on these lands to
December 31, 2007.



	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Delineation
	 	 	Gross Acres	 	Net Acres	 	Wells
	Long Lake
	 	 	62,720	 	 	 	31,360	 	 	 	535	 
	Leismer
	 	 	93,440	 	 	 	46,720	 	 	 	140	 
	Cottonwood
	 	 	90,240	 	 	 	45,120	 	 	 	50	 
	Other
	 	 	12,800	 	 	 	6,400	 	 	 	—	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 
	Total
	 	 	259,200	 	 	 	129,600	 	 	 	725	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 





     Long Lake Leases



     We own a 50 percent interest in the rights to recover bitumen found in oil sands deposits
within the Long Lake leases. These lands are located in the Athabasca oil sands region of Alberta
approximately 40 kilometres south of Fort McMurray. The Long Lake leases cover an area of 98
sections (approximately 62,000 acres) and are estimated by McDaniel to contain approximately 1.9
billion barrels of proved, probable and possible bitumen reserves or 941 MMbbl for our working
interest share. In addition, McDaniel has estimated that resources of 1.4 billion barrels of
bitumen (or 704 MMbbl for our working interest share) are contained within the balance of the Long
Lake leases. See “Appendix A — Reserves Data and Other Oil and Gas Information.”



     Delineation of the Long Lake leases is continuing, with the 2007/2008 winter program planned
to include drilling 80 wells.



     According to the Oil Sands Tenure Regulation (AR 50/2000), the lease on which the Project is
located is a deemed primary lease and can be continued beyond its term, whether it is a producing
or non-producing lease, if minimum production levels or minimum levels of evaluation, respectively,
have been achieved. We and Nexen conducted in excess of the minimum levels of evaluation, and Lease
27 was continued in May 2002 pursuant to section 13 of the Oil Sands Tenure Regulation. The other
oil sands leases that govern the Long Lake leases are within their primary terms expiring in 2017
or 2018 unless otherwise continued.



     Leismer Leases



     We own a 50 percent interest in the rights to recover bitumen in the Leismer leases. The
Leismer leases, located approximately 64 kilometres southwest of the Project, are comprised of 146
sections of land.









 



-12-


     The Leismer leases are estimated by McDaniel to contain 1.9 billion barrels of bitumen (or 960
MMbbl for our working interest share). See “Reserves and Resources Summary — Resources Data”.



     During the 2007/2008 winter season, 30 delineation wells and 11 square miles of 3-D seismic
are planned.



     Cottonwood Leases



     We own a 50 percent interest in the rights to recover bitumen in the Cottonwood Leases. The
Cottonwood Leases, located approximately 32 kilometres southwest of the Project, are comprised of
141 sections of land.



     The Cottonwood Leases are estimated by McDaniel to contain 1.1 billion barrels of bitumen (or
542 MMbbl of bitumen resources for our working interest share). See “Reserves and Resources Summary
- Resources Data”.



     There are over 50 wells drilled on these lands, including 19 drilled by the JV Participants.
During the 2007/2008 season, a program consisting of 25 delineation wells and 12 square miles of
3-D seismic is planned.



Development of future phases




     We and Nexen believe that our lands will support approximately 360,000 bbl/d of PSCTM
production (180,000 bbl/d net to OPTI) from six phases, including the Project currently under
construction. Based on reserve and resource estimates, we believe there is potential for three
phases at Long Lake. In addition, we believe we have sufficient resources to support two phases at
Leismer and one at Cottonwood. From January 1, 2004 to December 31, 2007, we have spent
approximately $325 million on the expansion activities beyond
Phase 1 and we expect to continue to invest in
engineering and planning for future phases of development.



     We continue to advance up-front engineering and planning for Phase 2 with the intention to be
in a position to sanction the project in late 2008. Regulatory approval has been obtained for the
Phase 2 upgrader which we expect to construct adjacent to Phase 1 of the Long Lake Upgrader. The
SAGD portion of Phase 2 is planned to be located in the southern portion of the Long Lake lease
(“Long Lake South”). Planning and delineation for the Phase 2 SAGD project is ongoing. In late
2006, a regulatory application for the Long Lake South project was
filed, comprising two bitumen
phases totalling 140,000 bbl/d of bitumen production in addition to Phase 1.



     Phase 2 sanctioning will be dependent on multiple factors including Phase 1 ramp-up
performance, regulatory approval for the SAGD portion of the project, the capital cost estimate and
regulations pertaining to CO2. In addition, the Alberta government announced significant
changes to the oil sands royalty regime in late 2007. Increases in royalties will impact the
economics of our business and may impact the timing of future investment decisions.



     We currently anticipate that subsequent phases would be sanctioned every 24 months after the
approval of previous phases. To support this timeline, lease delineation and preliminary
environmental evaluations are underway. Each future phase is planned to be of a similar size and
design to the Project and anticipated to consist of integrated SAGD
and OrCrudeTM
Upgrader projects. The specific design of these phases will be dependent upon a number of
factors including key learnings from Phase 1 and our strategy to address CO2 and other
greenhouse gas emissions. We are currently evaluating alternatives to facilitate CO2
capture.









 



-13-


Project and Lease Map









The Long Lake Project




     The bitumen recovery component of the Project will use the SAGD process, as depicted below,
which involves drilling multiple pairs of horizontal wells in the oil sands. Steam is injected into
the upper well and released in the oil sands reservoir where it heats the bitumen. The heated
bitumen becomes mobile and flows with condensed water from the steam to the lower horizontal well
and then flows or is pumped to the surface.









 



-14-


The SAGD Process









     SAGD is an in-situ process that removes bitumen from the oil sand reservoir without removing
the sand. The SAGD recovery processes used by the Project will cause considerably less surface
disturbance than mining operations that physically mine the sand and bitumen, extract the bitumen
from the sand and return the sand to tailings ponds. The SAGD process was first used in 1978 and is
being employed as the recovery process in most new in-situ projects under development.



SAGD Pilot Facility




     The JV Participants operated the SAGD Pilot from the second quarter of 2003 to the third
quarter of 2006. The purpose of the SAGD Pilot was to confirm reservoir performance assumptions and
the response of the Long Lake reservoir to the SAGD process as well as to gain site specific
operational experience on the drilling, start-up and operation of SAGD well pairs at the Project.
The SAGD Pilot consisted primarily of a steam generator and bitumen processing facilities, wellsite
facilities and three horizontal well pairs. The initial phase of the SAGD Pilot, consisting of
circulating steam into all producer and injector wells, commenced in the second quarter of 2003. In
the third quarter of 2003, the wells were switched over to SAGD production mode.



     The performance of the three well pairs varied widely, as would be expected in a large scale
commercial development. Individual well performance may be influenced by geological factors,
including the presence of low bitumen saturation lean zones. Specifically lean zones were present
at the SAGD Pilot and believed to have caused the lower than expected performance of the pilot
wells. We expect similar lean zones may occur over a portion of the Project area. The 78 SAGD
commercial well pairs that have been drilled for the Project are in areas where we expect these
zones to occur less frequently than in other areas of the Long Lake leases. In the 156 horizontal
commercial wells drilled for the Project, only four wells have encountered lean zones.



     The SAGD Pilot operations have provided several important lessons that may be applied to the
Project well pairs, including start-up and operating strategies, well bore optimization,
stimulation techniques and improvement to reservoir simulation models. Based on the absence of any
sand production at the SAGD Pilot, the size of the slotted liners to be utilized in the Project
wells was increased, which we anticipate will allow for enhanced productivity.









 



-15-


     During 2006, operation of the SAGD Pilot wells and facility was suspended in order to allow
for the tie-in of the wells and portions of the facility to the Long Lake SAGD Operation. The pilot
facility has been tied in with the main SAGD facilities and the SAGD Pilot wells have been
re-activated coincident with the SAGD start-up.



SAGD Commercial Project




     To achieve approximately 72,000 bbl/d of bitumen production, we expect the Project to require
78 SAGD well pairs in addition to the three SAGD Pilot well pairs. Additional wells will be drilled
as required in future years to maintain a stable production profile of approximately 72,000 bbl/d.



     The facilities associated with the SAGD Operation are typical of in-situ projects and consist
of bitumen, gas and water processing, steam generation and cogeneration facilities and the
infrastructure, such as storage tanks, to support these facilities.



     The bitumen will be processed to remove water and solids, making it suitable for use in the
Long Lake Upgrader, or it will be blended with diluent and shipped to markets when the Long Lake
Upgrader is unavailable. Gas produced with the bitumen will be sweetened and used as fuel for the
steam generators. Over 90 percent of the water that will be produced with the bitumen will be
recycled and converted into steam for injection into SAGD wells. Impurities in the water will be
removed to allow the water to be used as a feed to the steam generators. A portion of the steam for
injection will be generated using four once-through boilers while the remainder will be produced by
the two cogeneration facilities, each of which will consist of a gas turbine and heat recovery
steam generator. Approximately 170 megawatts of electricity is expected to be produced by the
combined cogeneration facilities.



     The Project was originally designed for steam capacity to support a SOR of approximately 2.4
at a production rate of 72,000 bbl/d of bitumen. If the reservoir performance of the initial well
pairs requires operation at a higher SOR, there would not have been adequate steam capacity to
allow for the full production rate of 72,000 bbl/d based on the initial design. In order to
mitigate this risk, the JV Participants are installing additional water treatment and steam
generation facilities to allow for a SOR of up to 3.3, while maintaining the 72,000 bbl/d
production rate. Our estimated capital cost of these additional facilities is approximately $360
million, or $180 million net to us, and these costs are included in the current Project forecast
cost. We expect these additional steam facilities to be operational in the fourth quarter of 2008.
We expect the long-term average SOR for the Project to be approximately 3.0.



Long Lake Upgrader




     Upgrading of Bitumen



     The bitumen recovered by the Long Lake SAGD Operation will be upgraded in the Long Lake
Upgrader. The Long Lake Upgrader will initially have the capacity to upgrade approximately 72,000
bbl/d of bitumen, yielding approximately 57,700 bbl/d of PSCTM and approximately 800
bbl/d of butane. The JV Participants also expect to sell certain other petroleum products and
by-products produced by the Project to third parties, including bitumen blend (during SAGD start-up
and periods of major maintenance on the Long Lake Upgrader) and electricity not consumed by the
Project.



     Integrated OrCrudeTM Upgrader



     A complete upgrading process has been developed which combines the OrCrudeTM
Process with proven hydrocracking and gasification processes to produce PSCTM, a
premium sweet crude oil, and syngas, a synthesis fuel gas. The OrCrudeTM Process, when
combined with these hydrocracking and









 



-16-

gasification processes, is referred to as an “Integrated OrCrudeTM Upgrader.” ORMAT
Industries Ltd. (“ORMAT”) has been granted a patent respecting the Integrated OrCrudeTM
Upgrader configuration in the United States. ORMAT has filed a similar application in Canada.
The OPTI License includes the rights to use the Integrated OrCrudeTM Upgrader in Canada.




     The syngas produced by the Integrated OrCrudeTM Upgrader is used as clean fuel in
the Integrated OrCrudeTM Upgrader, and is also available for other purposes, such as a
fuel source for the steam required for in-situ bitumen production (i.e. when the Integrated
OrCrudeTM Upgrader is integrated with a SAGD facility) and a fuel source for a
cogeneration facility. As a result, the Project will only need to purchase limited amounts of third
party natural gas and therefore will have significantly reduced the exposure to fluctuations in
natural gas prices. The ultimate exposure to natural gas prices and cost will depend on the SOR
achieved. We expect the integration of the Integrated OrCrudeTM Upgrader and the SAGD
facility to create operating cost advantages for the Project over other oil sands projects.



     We expect the PSCTM to be produced by the Long Lake Upgrader to have a gravity of
approximately 39°API. Therefore, the Project will not be exposed to fluctuating heavy oil
differentials during regular operations. The Integrated OrCrudeTM Upgrader produces a
light synthetic crude oil which will eliminate the requirement to add diluent to assist in bitumen
transportation. Therefore, we will not need to purchase diluent for normal operations and will not
have exposure to fluctuations in diluent prices or supply when the Long Lake Upgrader is fully
operational. The Project will only need to purchase diluent for periods when the Long Lake Upgrader
is not operating.



     OrCrudeTM Unit



     The OrCrudeTM unit receives diluted bitumen (“Dilbit”) from the SAGD Operation,
recovers the diluent and recycles it back to the SAGD Operation. It then processes the bitumen and
produces the feeds to the gasifiers and the hydrocracker. Because the diluent is generated in the
OrCrudeTM unit and recycled back to the SAGD Operation, the Project is not exposed to
fluctuations in diluent prices while the Long Lake Upgrader is operational.



     The OrCrudeTM unit first desalts the Dilbit in a conventional desalter. The Dilbit
is then fed to a single train atmospheric distillation column that recovers the diluent stream, an
atmospheric gas oil distillate stream, an atmospheric bottoms stream, and some fuel gas. The
atmospheric bottoms stream is fed into a vacuum distillation unit where vacuum gas oil distillate
is recovered and a vacuum bottoms stream results, which is in turn fed to the solvent deasphalter.
There, the vacuum bottoms are deasphalted using a pentane solvent, producing asphaltenes and a
deasphalted oil.



     The asphaltenes are fed to the gasifier as a liquid stream. The deasphalted oil is fed to two
thermal crackers where it is cracked and recycled back to the distillation section where the
converted material is recovered as additional distillate. This cycle continues until 100 percent of
the original bitumen is converted to either distillate or asphaltenes. Distillates from both the
atmospheric and vacuum units are combined and form the OrCrudeTM Product stream which
is fed to the hydrocracker.



     ORMAT energy converters will be used to recover thermal energy that would otherwise be wasted
in the OrCrudeTM Process. ORMAT energy converters generate power by using the waste heat
to vaporize pentane, expanding it across a turbine to generate power and then condensing it with an
air cooler.









 



-17-


     Gasifier



     The gasification technology used in the Integrated OrCrudeTM Upgrader has been
licensed from Shell Global Solutions International B.V. (“Shell Global Solutions”). There are a
number of liquid-feed Shell Global Solutions gasification process trains currently in use around
the world today.



     The asphaltene gasification unit consists of four liquid-feed gasification trains, and a
common syngas processing train. The gasifier receives the liquid asphaltenes from the
OrCrudeTM Process and will produce syngas consisting of mostly hydrogen and carbon
monoxide.



     The oxygen required as part of the gasification process will be produced in an air separation
unit. The air separation unit consists of large compressors to compress filtered outside air, cool
it, and then expand the air to produce a low enough temperature to liquefy the air. The liquid air
is then distilled to produce high purity oxygen and nitrogen. The single train air separation unit
includes liquid oxygen storage for increased reliability.



     The syngas is purified to remove sulphur and other impurities using a SelexolTM
solvent stripping process. This is a licensed process from UOP LLC and consists of a single
train to contact the lean solvent with the impure gas, allowing impurities to dissolve in the
solvent. The impurity-rich solvent is heated and regenerated in a solvent stripper, driving off the
impurities into a concentrated gas that is further processed to remove sulphur.



     The “clean” syngas is then processed in a pressure swing adsorption unit to recover a portion
of the hydrogen from the syngas fuel. The pressure swing adsorption unit produces a high-purity
hydrogen and residual syngas fuel. The high-purity hydrogen is used in the hydrocracker. The
remaining residual syngas fuel consists of a hydrogen and carbon monoxide mixture that is sent to
the Long Lake Upgrader for use as fuel and to the Long Lake SAGD Operation to fuel the steam
generators and gas turbine generators.



     Soot produced by the gasifier will be separated from the syngas by contacting it with water,
producing a soot water slurry. The water is recycled back to the gasification unit.



     Initially the soot water slurry is processed to remove a portion of the water which is
recycled back to the gasification unit, and the resultant product will be transported by rail or
truck for sale to a metal reclaimer or disposed in an approved landfill. However, the JV
Participants have developed a method to further process the gasifier soot waste through use of wet
oxidation technology. By adding a soot processing facility, the soot solid waste stream is
eliminated by further processing into a metals rich product with about 10 percent of the original
volume. The resulting product can be marketed to vanadium processors. This facility is expected to
reduce Project operating costs, provide additional product revenue, and reduce the environmental
impact. Our capital cost estimate for the facilities is $68 million net to us and is included in
the forecast project cost. We expect these additional facilities to be operational by late 2008.



     Hydrocracker



     The hydrocracker unit contains the facilities to process OrCrudeTM Product into
PSCTM. The hydrocracking process is licensed from Chevron Lummus Global LLC (“Chevron
Lummus”). There are a number of similar hydrocrackers from Chevron Lummus currently in commercial
applications using high pressure hydroprocessing and hydrocracking.









 



-18-


     Within the hydrocracker unit, the OrCrudeTM Product is fed to a single
hydrotreating reactor, where hydrogen is added over a catalyst to remove sulphur and nitrogen
compounds in the OrCrudeTM Product by converting them into gases that are processed in
the sulphur treatment facilities. The hydrotreated oil is fed into a hydrocracking reactor where
more hydrogen is added across a catalyst to break large hydrocarbon molecules into smaller, lighter
products.



     Products from the hydrocracker are treated in two distillation columns in series to remove gas
and butane from the hydrocracked oil. Some butane produced in the units is blended into the PSC
product, and the remainder is sold as an end product.



     Sulphur Facilities



     The sulphur recovery unit will treat all of the sour gas and water streams to remove the
sulphur as a liquid product for sale. The unit is designed to remove virtually all of the total
sulphur fed to the Long Lake Upgrader, including the sulphur from the SAGD wells.



     Liquid sulphur will be loaded directly onto rail cars for transportation to markets.



The OrCrudeTM Process




Background




     The OrCrudeTM Process is a proprietary process owned by ORMAT for upgrading bitumen
and heavy oil into OrCrudeTM Product. ORMAT was our principal founding shareholder.
ORMAT has received numerous patents respecting the OrCrudeTM Process from the U.S.
Patent and Trademark Office and patents from the Canadian Intellectual Property Office, and has
additional outstanding patent applications respecting the OrCrudeTM Process in the
United States, Canada and other jurisdictions. We have an exclusive license to use the
OrCrudeTM Process anywhere in Canada for an unlimited period of time, with the right to
sub-license the technology to third parties.



     The OrCrudeTM Process consists of three main process units: the distillation unit,
the solvent deasphalting unit and the thermal cracking unit. All three processes have been employed
in conventional upgraders and refineries around the world for over 70 years. The unique feature of
the OrCrudeTM Process is the manner in which the equipment utilized in the process is
integrated to upgrade the deasphalted vacuum residue stream and recycle it to extinction.



     The OrCrudeTM Process was successfully used in a 500 bbl/d demonstration plant we
operated from May 2001 to November 2003. The design of the demonstration plant was very similar,
with the exception of the capacity, to the OrCrudeTM portion of the Long Lake Upgrader
under construction, with nearly the same number of equipment components, process streams and
control system elements.



OrCrudeTM Process License




     The OrCrudeTM Process is a proprietary process that, when combined with
commercially available hydrocracking and gasification processes, forms an Integrated OrCrudeTM
Upgrader capable of upgrading bitumen and heavy oil into PSCTM. On July 30, 1999,
ORMAT granted to its subsidiary OPTI Technologies BV (“OPTI BV”) an exclusive worldwide license
(excluding Israel) to use the OrCrudeTM Process technology for an unlimited period of
time, with the right to sub-license the technology to third parties. On that same date, OPTI BV
granted us an exclusive license to use the OrCrudeTM Process technology for an unlimited
period of time anywhere in Canada, with the right to sub-license the technology to third parties.
We refer to this sub-license as the OPTI License.









 



-19-


     The key terms of the OPTI License are as follows:




	 	•	 	OPTI Canada has undertaken to take the necessary steps to commercialize the
OrCrudeTM Process;
	 
	 	•	 	improvements made by OPTI BV or ORMAT in the OrCrudeTM Process
technology will be deemed to be included in the OPTI License, and OPTI Canada is
obligated to license to OPTI BV, at no additional cost, the rights to use and
sub-license any improvements made by OPTI Canada to the OrCrudeTM Process
technology;
	 
	 	•	 	we will pay OPTI BV a royalty based on the installed cost to the end user of
any facility using the OrCrudeTM Process. We estimate the royalty payable to
OPTI BV for the Project will be approximately $17 million, of which our share is 50
percent; and
	 
	 	•	 	OPTI BV and its affiliates have the right, but not the obligation, to engineer,
procure, construct and fabricate the solvent deasphalting units for projects using the
OrCrudeTM Process.





     OPTI BV may terminate the OPTI License if we are wound-up or become insolvent or materially
breach the terms of the OPTI License. Notwithstanding the foregoing, OPTI BV may not terminate the
OPTI License in respect of a particular facility where the royalty described above has been paid by
us. If OPTI BV’s license from ORMAT is terminated, the OPTI License will convert into a direct
license with ORMAT on substantially the same terms and conditions provided for in the OPTI License.



Marketing




     We plan to use Nexen Marketing as an agent to market our products on behalf of the joint
venture. These products primarily include Premium Synthetic Heavy (“PSH”), PSCTM,
surplus electricity from our Cogeneration Facility and sulphur production. OPTI has the right to
take such production in kind. The price OPTI receives is generally the price actually received by
Nexen, subject to certain exceptions. No marketing fees are to be charged by Nexen Marketing.



     During SAGD start-up and other periods where the Upgrader is not operational, diluent will be
purchased to blend with the bitumen to produce a bitumen blend marketed as PSH. This product will
likely be sold in the Midwest region of the U.S. to refiners capable of processing heavier crude
types. PSH has a gravity of approximately 20° API.



     Once the Upgrader begins operation the primary sales product will be PSCTM . We
expect that while some of the Project’s PSCTM may be sold in Canada, some volumes will
be exported to various refineries in the U.S. Great Lakes and Midwest regions and some may also be
sold as diluent to other bitumen producers in Canada. PSCTM has a low density (39° API)
and low sulphur (<10 parts per million). We believe these characteristics make it attractive to
other bitumen producers for use as a diluent which can improve netbacks compared to using other
synthetic crude oils. The main crude products, PSH and PSCTM, are transported to market
via the Enbridge Pipelines (Athabasca) Inc. (“Enbridge”) pipeline. There are currently no firm
sales contracts in place for PSH or PSCTM.



     We expect that molten sulphur will be transported by rail and sold in the U.S. market.









 



-20-


Infrastructure




     The Project is located 42 kilometres southeast of Fort McMurray with connections to existing
infrastructure including road access (highways 881 and 63), a natural gas supply pipeline, the
electric power transmission grid to allow for both the import and export of electricity and rail
spur access to the Athabasca Northern Railway. The JV Participants have a long term traffic
guarantee agreement with Canadian National Railway Company (“CN”) under which traffic is moved to
and from the Project site by rail and CN invests in upgrades to the Athabasca Northern Railway rail
line. The rail line will move, amongst other commodities, sulphur, catalysts, and construction
materials to and from the Project site. In addition, the JV Participants have drilled water supply
and water disposal wells, and installed pipelines to transport the water, to support the operation
of the facilities. The water supply wells consist of both fresh water and salt water sources.



     The JV Participants have an agreement with Enbridge to provide lateral facilities and
transportation services on the Enbridge Athabasca Pipeline. This pipeline will transport PSH and
PSCTM produced by the Project to Hardisty, Alberta, from which there are pipelines to
transport product to markets in Canada and the United States. In addition, the JV Participants also
have an agreement with Pembina Oil Sands Pipeline L.P. for the transportation of purchased diluent
from the Athabasca Oil Sands Project pipeline system. Purchased diluent will be required during
periods when the Upgrader is not operational.



Project Development




Project Design and Construction




     The JV Participants are using a number of large engineering firms, including Fluor Canada Ltd.
and Colt Engineering Corporation, and construction firms, including Flint Energy Services Ltd.,
Ledcor Industrial Inc. and Fluor Constructors Canada Ltd., for the engineering, procurement and
construction of the Project. These contractors are some of the largest contractors in Western
Canada and have been involved in the design and construction of many in-situ and upgrader
construction projects in Alberta.



Project Schedule




     The JV Participants and their contractors completed the necessary front-end commercial
engineering, designs and plans for the Project together with a final cost estimate for the Project.
Approvals by the boards of directors of each of the JV Participants were received in February 2004.



     Site preparation activities occurred throughout 2004 and into early 2005 with piling and
foundations. Major mechanical on site construction started in the middle of 2005. The SAGD
facilities are essentially complete and steam injection has commenced. We currently anticipate that
construction on the Project will be completed this year and expect first production of PSCTM
from our Upgrader to occur in mid-2008.



Project Status




     Significant progress continues to be made on the Project with first production of PSCTM
anticipated in mid-2008. The SAGD facilities are operational with all 10 well pads steaming and we
currently expect to reach 50 percent bitumen production capacity in mid-2008. We expect that the
capacity of the Long Lake Upgrader after mid-2008 will enable us to process all the forecasted SAGD
volumes. During 2008, we expect SAGD volumes to ramp up with completion of the two cogeneration
units. SAGD volumes are expected to reach full design rates of 72,000 bbl/d in 2009.









 



-21-


     Completion of the Upgrader intentionally lags that of SAGD to ensure sufficient bitumen
production at start-up. The Upgrader is currently on-track for production of PSCTM in mid-2008. The
OrCrudeTM and hydrocracker units as well as the main facilities are now mechanically complete, with
commissioning activities underway in these areas. The gasifier and air separation units were
essentially mechanically complete at year end 2007, with current activities focused on final
electrical work and insulation. The rate of construction progress on the sulphur recovery unit
increased in the latter half of 2007 and this unit remains scheduled for mechanical completion in
the first quarter of 2008.



     Our current total cost estimate of the Project is between $5.8 billion and $6.1 billion or
between $2.9 billion and $3.05 billion net to us. As of December 31, 2007, $5.4 billion or $2.7
billion net to us had been incurred on the Project.



Project Operations




     OPTI, as operator of the Upgrading facilities, and Nexen, as operator of the SAGD facilities,
have each put in place operating organizations for the management of commissioning and on-going
operations. These organizations include personnel experienced in the operation and maintenance of
oil and gas, petrochemical, and other industrial facilities both locally and internationally.
Facility operations are managed locally from an on-site operations administration and maintenance
complex constructed by the JV Participants. An emphasis is placed on having operations personnel
live locally in the region and be part of the local communities. The personnel are being provided
with site and process specific training with regards to the facilities being constructed, including
use of process simulators for the upgrader facilities supplemented by on-site training at existing
operating plants. For commissioning and start-up of the facilities, the operators’ employees have
been supplemented with commissioning and start-up expertise contracted from process technology
suppliers, equipment vendors and other personnel with experience in the start-up of similar types
of facilities.



Material Agreements Related to the Joint Venture




Background




     Prior to March 12, 2004, the Project was being developed by the JV Participants pursuant to
the terms and conditions of a memorandum of understanding (“MOU”) dated as of October 29, 2001. The
Project is now governed by the COJO Agreement and, with regard to the associated upgrading
technology rights, by a technology agreement between the JV Participants (the “Technology
Agreement”).



     Development of those Long Lake lands not subject to the COJO Agreement and certain other
Leismer and Cottonwood area lands is governed by additional construction, ownership and joint
operation agreements with Nexen that contain substantially the same terms as the COJO Agreement,
and are referred to as the New COJO Agreements. The Technology Agreement will govern these projects
as well.



     While the MOU was superceded by the COJO Agreement, the New COJO Agreements and the Technology
Agreement with respect to the Project and certain additional lands, the MOU continues to otherwise
govern the joint venture relationship between us and Nexen.



     The MOU provides for an Area of Mutual Interest respecting Townships 60 to 100 inclusive, and
Ranges 1 to 24 inclusive, W4M, excepting certain specific areas. The MOU will govern any new lands
jointly acquired by us and Nexen within the Area of Mutual Interest and projects thereon, unless
the parties agree otherwise.









 



-22-


COJO Agreement and the Technology Agreement




     On March 12, 2004, we and Nexen entered into an interim joint venture agreement whereby it was
agreed the COJO Agreement and the Technology Agreement superseded the MOU in respect of the subject
matter of those agreements.



     The COJO Agreement



     General



     The COJO Agreement is based on the MOU and relevant provisions of industry standard
agreements, and provides for the development, construction, ownership and operation of the Project.
The purpose of the COJO Agreement is to document the terms upon which:




	 	•	 	the Project will be constructed, owned and operated;
	 
	 	•	 	each JV Participant shall be responsible and pay for its respective share of
joint Project costs; and
	 
	 	•	 	the share of the SAGD production volumes, Upgrader products and the surplus
Project electricity will be allocated and distributed to each of the JV Participants.





     Subject to available Upgrader capacity, each JV Participant has agreed to process at the
Upgrader its entire share of the SAGD production volumes produced from the Project.



     Management Committee



     The COJO Agreement provides for the establishment of a Management Committee composed of
representatives of each JV Participant. The Management Committee exercises supervision and control
of each operator and all matters relating to the joint operation of the Project, excluding matters
specifically designated to be within the exclusive jurisdiction of an operator, any unresolved
audit claims, and the interpretation of the COJO Agreement. Each JV Participant has appointed one
representative and one alternate representative to serve on the Management Committee. If there are
only two parties to the COJO Agreement, all decisions of the Management Committee are required to
be unanimous. If there are more than two parties, different Management Committee approval
thresholds are specified. Generally, a matter being voted on by the Management Committee will be
approved only upon the affirmative vote of two or more JV Participants having a combined Project
interest of more than 75 percent. However, there are certain exceptions to these voting
requirements and, among other things, the COJO Agreement provides that the following matters will
be approved by the Management Committee only upon the unanimous approval of all JV Participants
with regards to:




	 	•	 	the approval of any design or scope change to a construction plan such that the
facility or joint operation in question is or will be substantially different than what
was provided for previously;
	 
	 	•	 	the processing at the Long Lake Upgrader of production from lands other than
the Project;
	 
	 	•	 	any matter which significantly affects the integration of the Long Lake
Upgrader and the SAGD Operation;
	 
	 	•	 	any enlargement work plan and budget, and any amendments thereto; or
	 
	 	•	 	the termination of the COJO Agreement.










 



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     Operators



     The COJO Agreement provides that the initial Upgrader operator shall be us and the initial
SAGD operator shall be Nexen. A JV Participant that is an operator will cease to be an operator and
a replacement operator will be appointed if an operator is subject to an event of insolvency, an
operator is in material default of its obligations as operator under the COJO Agreement, or in
certain other conditions.



     An operator may be removed by the vote of two or more JV Participants having a combined
Project interest of 55 percent or more under certain conditions.



     In addition, after one year from the Upgrader or SAGD operational date, as the case may be, a
JV Participant may challenge for operatorship by proposing terms which, if not matched by the
existing operator, establish the proposing JV Participant’s operatorship terms.



     Each of OPTI as the Upgrader operator and Nexen as the SAGD operator are required by the COJO
Agreement to conduct or cause to be conducted all joint operations for which it is responsible
diligently, in a good and workmanlike manner and in accordance with good petroleum industry,
construction and environmental practices and principles. Each operator is to conduct or cause to be
conducted all joint operations as would a prudent operator under the same or similar circumstances.
Each operator may sub-contract all or substantially all of its duties and responsibilities to a
reliable and competent third party subcontractor or an affiliate of that operator with the approval
of and on the terms approved by the Management Committee, provided that such operator retains full
control and supervision of such subcontract and that any third party subcontractor is retained on a
general arm’s length basis.



     Contracts, Agreements and Commitments



     A contracting policy and procedure establishes limits on each operator’s authority to enter
into agreements on behalf of the JV Participants for Project purposes.



     Force Majeure



     If prior to an operational date an event or series of events of force majeure suspends a JV
Participant’s obligations for longer than one year, any JV Participant is entitled, in certain
circumstances, to terminate the COJO Agreement.



     Default



     Under the terms of the COJO Agreement, each JV Participant has a first priority fixed and
specific lien, charge and security interest in and on the right, title, estate and interest of each
other JV Participant in the Project (including, without limitation, that JV Participant’s Project
interest) to secure payment and performance of each other JV Participant’s Project obligations.



     If a JV Participant fails to pay an amount within the time period prescribed in the COJO
Agreement or is otherwise in material default under the COJO Agreement, each non-defaulting JV
Participant will be entitled to exercise the lien and thereafter enforce the rights and remedies
set out in the COJO Agreement that include:




	 	•	 	for the period prior to the expenditure by the JV Participants of 80 percent of
the aggregate of all costs expended and to be expended in respect of the Project, treat
non-payment of amounts as a sale, assignment, transfer and conveyance to the
non-defaulting










 



-24-


	 	 	 	JV Participant of the defaulting JV Participant’s entire Project interest in and to
the Project, subject to certain exclusions, provided that such sale, assignment,
transfer and conveyance shall not be effective unless and until the non-defaulting
JV Participant pays to the defaulting JV Participant as consideration for such sale,
assignment, transfer and conveyance 80 percent of the total joint account Project
costs paid by the defaulting JV Participant. If this remedy is exercised, the
defaulting JV Participant shall have no further obligations thereafter arising in
connection with the assigned Project interest;






	 	•	 	for the non-payment of amounts occurring after the expenditure by a JV
Participant of 80 percent of such Project costs but before operation of the Project,
the JV Participant exercising the lien, upon a default in payment by the other JV
Participant, can acquire from the other JV Participant a portion of that JV
Participant’s Project interest (subject to certain exclusions) which is determined by
multiplying the defaulting JV Participant’s Project interest by the quotient obtained
by taking 125 percent of the default amount in question, and dividing that product by
the joint account expenditure amount spent in respect of the Project by the defaulting
JV Participant as of the default date. If this remedy is exercised, the defaulting JV
Participant will have no further obligations thereafter arising in connection with the
assigned Project interest;
	 
	 	•	 	withhold from the defaulting JV Participant any further information and
privileges with respect to the ongoing operations of the JV Participant, including the
right to participate in decision of the Management Committee, and in such event the
non-defaulting JV Participants will be entitled to, subject to certain limitations,
vote the defaulting JV Participant’s interest;
	 
	 	•	 	treat the non-payment of an amount as an assignment to the non-defaulting JV
Participant of the proceeds of the sale of the defaulting JV Participant’s share of
production that has been produced from the Project or has been processed at the Long
Lake Upgrader; and
	 
	 	•	 	if the default occurs after commercial production is achieved, the JV
Participant exercising the lien may sell the defending JV Participant’s interest in the
Project.





     The foregoing and certain other rights can only be exercised after notice from a
non-defaulting JV Participant and the expiry of certain cure periods.



     Additionally, if material physical damage occurs to Project property prior to the last
occurring operational date, each JV Participant shall have the right to nonetheless commence
reconstruction efforts. If in certain circumstances reconstruction is not commenced by a JV
Participant, we have the right (but not the obligation) to terminate the COJO Agreement and the
Technology Agreement.



     Technology



     Technology developed by the JV Participants in connection with the Project will be jointly
owned by the JV Participants, provided that upgrading technology included in the Technology
Agreement is expressly not subject to the COJO Agreement but rather is governed by the Technology
Agreement.



     Marketing



     Pursuant to the COJO Agreement all SAGD production volumes, Upgrader products, surplus Project
electricity, any sulphur production or any other by-product that is produced from or processed at
the SAGD Operation or the Upgrader, as the case may be, shall be marketed by Nexen Marketing on
behalf of the JV Participants, subject to each JV Participant’s right to take in kind its share of
such committed production in certain circumstances. The price to which each JV Participant shall be
entitled









 



-25-

for its committed production purchased by Nexen Marketing shall be no less than the price
actually received by Nexen, subject to certain exceptions. No marketing fees are to be charged by
Nexen Marketing.




     Right of First Offer



     If after the project sanction date a JV Participant wishes to solicit bids or has received an
unsolicited bid it is favourably considering in respect of all or any of its interest in the
Project, it will by notice (a “ROFO Notice”) advise the other JV Participants of its desire to make
the disposition. In addition, if a JV Participant executes a binding agreement respecting the sale
of all or any of its interests, it will by notice (a “ROFR Notice”) advise each other JV
Participant, by providing notice of the formal sale agreement. However, a disposing JV Participant
is not required to issue a ROFR Notice if that JV Participant had issued a ROFO Notice within the
previous 180 days and the consideration set forth in the binding agreement which forms part of the
ROFR Notice is at least 95 percent of the consideration set forth in that ROFO Notice.



     The Technology Agreement



     The Technology Agreement grants two sets of licensed rights, the AMI License relating to the
lands within the Area of Mutual Interest, and the Territory License relating to Canada, excluding
the Area of Mutual Interest (the “Territory”).



     License Rights



     Under the AMI License, we have granted to Nexen, for a term commencing on October 31, 2001 and
ending October 31, 2026 an exclusive license (with the exception of the license to Suncor) to use
the technology to process and upgrade hydrocarbons, including bitumen, oil sands and crude oil (the
“Upgrading Technology”) associated patents (while they are in force), and information, knowledge
and experience of a technical, operating or commercial nature of OPTI, referred to as the Licensor
Information, to design, engineer, construct, operate and maintain any facility using the Upgrading
Technology, including the right to sub-license the rights to third parties and affiliates.



     The Territory License is a perpetual, non-exclusive license, which grants the same rights to
Nexen in the Territory as long as that use is for an upgrader used to develop hydrocarbons,
including bitumen, oil sands and crude oil in which Nexen has an ownership interest and we have
been offered the right to participate. Nexen is able to grant sub-licenses to its affiliates
without our permission. For Nexen to grant a sub-license to a non-affiliate for use in an upgrading
facility, Nexen must have an interest in the facility, the sub-license must contain terms
consistent with the Technology Agreement, including the payment of royalties to us, and we must
consent to the issuance of such sub-license.



     For the purposes of each of the AMI License and the Territory License, improvements made by us
and our affiliates (which includes OPTI BV and ORMAT) are included in the rights licensed to Nexen.
In granting the AMI License and Territory License rights, we retain all of its rights and
entitlements, including use, associated with the Upgrading Technology. Neither the AMI License
rights nor the Territory License rights include the right to design or manufacture any other
proprietary products of ORMAT, OPTI BV or ourselves. OPTI and our affiliates’ rights under the
Technology Agreement include the right to engineer, procure, construct or fabricate solvent
deasphalter units and the right to use the improvements made by Nexen. Our right to use
improvements made by Nexen, its affiliates or sub-licensees survives the termination of the
Technology Agreement.









 



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     Royalty Provisions



     The Technology Agreement contains a royalty structure, which depends on the ownership interest
of the parties in the applicable facility and is calculated based on barrels of capacity of the
applicable upgrader. If Nexen or its sub-licensees have an interest in an upgrader which is greater
than 50 percent, Nexen must pay royalties to us based on the daily volumetric raw bitumen handling
capacity (both design capacity and actual throughput) of the upgrader. If capacity is increased,
there are provisions for corresponding increases in royalties. The calculation of such capacity
royalties differs depending on our interest in the upgrader. There are also provisions to ensure
payment of royalties from third party assignees of Nexen.



     Nexen will pay to us a royalty based on the installed cost proportionate to its working
interest of any facility using the OrCrudeTM Process. We estimate the royalty payable to
us in the first phase of the Project will be approximately $8.5 million. We are obligated to pay
the full amount of this royalty to OPTI BV under the terms of the OPTI License.



     Assignment and Termination



     Nexen may not assign the Technology Agreement without our consent, unless such assignment is
to a successor in interest, a party acquiring all or substantially all of Nexen’s assets or a
lender for the purposes of securing financing for a project other than the Project. We may assign
the Technology Agreement at our discretion without Nexen’s consent. Either party may terminate the
agreement for breach with notice, if the breach is not cured within 30 days. Additionally, either
party may terminate upon an Event of Insolvency, as such term is defined in the Technology
Agreement. Acts or omissions of a sub-licensee of Nexen, which would have constituted a breach of
the Technology Agreement by Nexen, had they been the acts or omissions of Nexen, are considered
breaches of the Technology Agreement. Upon termination for payment default by Nexen, use of the
Upgrading Technology and Licensor Information must cease. In other instances of default, Nexen
maintains limited rights to use the Upgrading Technology based partially on the royalties paid
prior to termination.



     The New COJO Agreements



     As indicated above, the New COJO Agreements are in substantially the same form as the COJO
Agreement. There are only a few material differences, namely:




	 	•	 	The New COJO Agreements contain provisions permitting one party to propose and
conduct delineation and lease-saving operations, and to propose and prepare a
development plan (in contemplation of a construction plan). If the other party does not
wish to participate in those operations or activities it will be subject to a penalty.
The penalty for non-participation in a delineation operation or the preparation of a
development plan is a before tax return of capital of 1.5309 percent calculated and
compounded monthly on the costs incurred to conduct the applicable operations and
activities. The penalty for non-participation in a lease-saving operation is the
forfeiture of that party’s interest in the applicable lease.
	 
	 	•	 	A party is required to pay for its share of costs associated with delineation
operations and development plans, plus all associated penalties, prior to either the
date the Management Committee approves the project construction plans or the project
sanction date, before it is entitled to participate in the project.










 



-27-







     As was the case under the COJO Agreement, each party to each New COJO Agreement has the right,
until the construction plans are approved by the Management Committee, to elect to participate in
the project as to less than a 50 percent interest therein. If a party exercises such right and the
other party elects to acquire the available interest, the acquiring party shall be required to pay
the disposing party various amounts, including a technology royalty, a production royalty, and
reimbursement of prior expenses incurred for the joint account in connection with the acquired
interest. If a party elects to reduce its interest but no other party elects to acquire such
interest, the project in question will be postponed.



     Similarly, if a party previously elected to participate as to a reduced interest, that party
has the right until the project sanction date under each New COJO Agreement to elect to participate
in the applicable project up to a 50 percent interest. If a party exercises such right it shall be
required to pay various amounts, including a technology royalty, a production royalty, and
reimbursement of prior expenses incurred for the joint account in connection with the acquired
interest.



Royalties




     The Government of Alberta receives royalties on production of natural resources from lands in
which it owns the mineral rights. On October 25, 2007, the Government of Alberta unveiled a new
royalty regime. The new regime will introduce new royalties for conventional oil, natural gas and
bitumen effective January 1, 2009 that are linked to commodity prices and production levels and
will apply to both new and existing oil sands projects and conventional oil and gas activities.



     Currently, in respect of oil sands projects having regulatory approval, a royalty of one
percent of gross bitumen revenue is payable prior to the payout of specified allowed costs,
including certain exploration and development costs, operating costs and a return allowance. Once
such allowed costs have been recovered, a royalty of the greater of: (a) one percent of gross
bitumen revenue; and (b) 25 percent of net bitumen revenue (calculated as being gross bitumen
revenue less operating costs and additional capital expenditures incurred since payout (“net
royalty”)) is levied.



     Under the new regime, the Government of Alberta will increase its royalty share from oil sands
production by introducing price-sensitive formulas which will be applied both before and after
specified allowed costs have been recovered. The gross royalty will start at one percent of gross
bitumen revenue and will increase for every dollar that world oil price, as reflected by the WTI
crude oil price, is above $55 per barrel, to a maximum of nine percent when the WTI crude oil price
is $120 per barrel or higher. The net royalty on oil sands will start at 25 percent of net bitumen
revenue and will increase for every dollar the WTI crude oil price is above $55 per barrel to 40
percent when the WTI crude oil price is $120 per barrel or higher. Prior to the payout of specified
allowed costs, including certain exploration and development costs, operating costs and a return
allowance, the gross royalty is payable. Once such allowed costs have been recovered, a royalty of
the greater of: (a) the gross royalty and (b) the net royalty is payable. The Government of Alberta
has announced that it intends to review and, if necessary, revise current rules and enforcement
procedures with a view to clearly defining what expenditures will qualify as specified allowed
costs.



     The implementation of the proposed changes to the royalty regime in Alberta is subject to
certain risks and uncertainties. The significant changes to the royalty regime require new
legislation, changes to existing legislation and regulation and development of proprietary software
to support the calculation and collection of royalties. Additionally, certain proposed changes
contemplate further public and/or industry consultation. There may be modifications introduced to
the proposed royalty structure prior to the implementation thereof.









 



-28-


     Our initial evaluation based on the information available to date, assuming a $65 per barrel
WTI crude oil price, is that the increase in the pre-payout royalty would be approximately $1.00
per barrel of product sold when Phase 1 of the Long Lake Project is fully operational.



     In contemplation of the new royalty regime, a Government of Alberta appointed royalty review
panel recommended a tradable royalty credit of 5 percent of eligible capital expenditures on
additional upgrading capacity in Alberta. In its response to the panel recommendations, the
Government of Alberta has rejected the recommendation for an upgrader credit at this time. The
Government indicated that the recommendation related to a tradable upgrader credit will be studied
further in the context of the province’s overall value-added strategy and that they would consider
other options such as taking bitumen in kind rather than cash for royalty amounts and directing
that bitumen to Alberta upgraders and refineries. The Government indicated that it would also
consider adjusting pipeline toll differentials to avoid subsidization of bitumen exports, requiring
value-added components in future oil sands development approvals, and government investment in
regional infrastructure that would support value-added initiatives within Alberta. The Government
has indicated that it will consult with industry on its options, determine the most effective
approach, and announce its decision in 2008.



Regulatory Approvals and Environmental Considerations




General




     The Project currently has approval from both the EUB and AE for up to 70,000 bbl/d of SAGD
operation and up to 140,000 bbl/d of upgrading capacity. These approvals were granted in 2003. In
September 2006, approval was received for routine amendments to these approvals. It is possible
that additional amendments to these approvals will be submitted prior to commencement of
operations, as is typical with projects of this nature.



     In January 2005, we filed an application to EUB and AE for approval of the Long Lake Power
Project (the “Power Project”). The Power Project consists of a cogeneration facility comprised of
two units, a main substation, a cogeneration substation, associated transmission lines, two
OrCrudeTM energy converters and a power grid connection. The Power Project was approved
by the EUB in June 2005 and AE in December 2005.



     In July 2005, we made an application to AE for a Terms of Reference (“TOR”) for a proposed
expansion to the Project. After a public notice period and input from local stakeholders AE
released the final TOR for the SAGD expansion which contained no unanticipated requests. We filed
an application for an additional 140,000 bbl/d of SAGD production from the Long Lake lease in late
2006 known as the Long Lake South Project. The application is currently before AE and the EUB.
OPTI and Nexen have received the first and second round of supplemental questions associated with
this application. There are no unanticipated requests associated with either round of supplemental
questions from the regulators. We anticipate the Long Lake South Project application will be
deemed complete by the regulators early in 2008.



     Throughout the construction and initial start-up of operations of the Project we will require
additional regulatory approvals and permits. We anticipate that such additional approvals and
permits required for the Project will be received in the ordinary course.



Environmental Considerations




     The key environmental issues and stakeholder concerns to be managed by the JV Participants in
the development of the Project encompass human health, surface disturbance, effects on historical
and









 



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traditional resources, air quality, water quality and water use, noise and cumulative effects
on ecosystems. The JV Participants have committed to monitoring programs that will track the
effects of the Project and the cumulative effects of regional development on environmental
components and ecosystems. We have participated at the executive level in the Cumulative
Environmental Management Association, the Regional Aquatics Monitoring Program, the Wood Buffalo
Environmental Association, the Regional Infrastructure Participating Group and other
multi-stakeholder regional programs that address cumulative environmental and socio-economic
project impacts.




     The JV Participants have designed the Project to meet or exceed existing standards for control
of air emissions, water emissions, water use and territorial disturbance. As with all new
industrial development, we expect regional air emissions to increase slightly as a result of the
Project. Air emission modelling results show that emission concentrations should remain under
existing AE standards for ground level concentrations in all modelled communities in the region;
however, environmental regulations are becoming increasingly stringent, and we cannot be certain
that the Project will meet future standards that might be imposed.



Greenhouse Gases and Industrial Air Pollutants




     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 greenhouse gases
(“GHGs”). The Project will be a significant producer of some GHGs covered by the Convention. We
intend that the Project will comply with applicable Canadian requirements implementing the Kyoto
Protocol.



     The Long Lake Upgrader will produce more CO2 on site per barrel than other
integrated projects that stockpile petroleum coke. The OrCrudeTM Process uses virtually
all of the bitumen resource and therefore produces more CO2 per barrel. While this
results in higher local CO2 emissions, PSCTM‘s higher product quality results
in lower CO2 emissions when it is ultimately processed by a refinery.



     On April 26, 2007 the Canadian Federal Government released the Regulatory Framework for Air
Emissions (the “Framework”) which outlines proposed new requirements governing emission of GHGs and
other industrial air pollutants in accordance with the Government’s Notice of Intent to Develop and
Implement Regulations and Other Measures to Reduce Air Emissions released on October 19, 2006. The
Framework introduces further, but not full, detail on new GHG and other industrial air pollutant
limits and compliance mechanisms that will apply to various industrial sectors, including the oil
sands extraction, upgrading and electricity production industries starting in 2010. The Government
is in the process of consulting stakeholders about the emission-intensity reduction targets which
are contemplated to form the basis of new draft regulations scheduled to be released in early 2008.



     The proposed compliance mechanisms include paying into a technology fund, fixed emission caps
and an emissions credit trading system for certain industrial air pollutants, and several options
for companies to choose among to meet GHG emission reduction targets and encourage the development
of new emission reduction technologies.



     On January 7, 2008, the National Round Table on the Environment and the Economy (“NRTEE”)
released a report entitled: Getting to 2050: Canada’s Transition to a Low-emission Future (“Getting
to 2050”). The NRTEE is an independent advisory body to the Canadian Federal Government comprised
of representatives from business, labour, universities, environmental organizations, Aboriginal
communities and municipalities. Getting to 2050 was prepared in response to a request from the
federal Minister of the Environment in November 2006 requesting NRTEE’s advice on scenarios for
achieving a 45 to 65 percent reduction in GHG emissions by 2050. In Getting to 2050, the NRTEE
recommended the implementation









 



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of a GHG emission price signal as soon as possible in the form of a GHG emission tax or a
cap-and-trade system or both. NRTEE also recommended complementary regulatory policies such as
regulatory standards, subsidies and infrastructure investments in parts of the economy that may not
respond to price signals. Initial reaction from the Government indicated that the Government will
continue to implement the Regulatory Framework for Air Emissions and that it was unlikely to
implement an additional GHG emission tax in the near future.




     We will also be subject to the Alberta Climate Change and Emissions Management Act and the
Specified Gas Emitters Regulation (the “Regulation”). Under the Regulation we will be required to
reduce the GHG emissions intensity from a baseline to be established from averaging the GHG
emissions intensity of our first three years of commercial operation. Emissions intensity is the
ratio of GHG emissions per barrel of oil produced. The required reductions in GHG emissions
intensity will start in our fourth year of commercial operations and must be at least a 2 percent
reduction from our baseline, and then a further 2 percent reduction every year thereafter until at
least a 12 percent reduction in GHG emissions intensity has been achieved.



     Under the Regulation, emissions intensity can be reduced three ways: by operational changes
which result in lowered emissions; by contributing $15.00 per tonne of GHG emitted in excess of the
required reductions to a new GHG emissions reduction technology fund; or by purchasing from third
parties emissions offset credits generated by an emissions offset project located in Alberta.



Insurance




     The JV Participants have jointly insured the Project to provide comprehensive coverage. The
joint program comprises course of construction and delay in start-up coverage for a combined single
limit of $1.2 billion for each occurrence.




	 	•	 	Course of Construction for Physical Damage — The insurance limit is to the
maximum foreseeable loss and coverage is on the broadest terms available. The policy
covers work in progress and during inland transportation, construction, installation
and start-up. A deductible has been selected that is cost effective and within the
financial capabilities of the JV Participants. Contractors, sub-contractors, suppliers
and Project lenders are included as additional insured parties to control Project costs
and potential claims.
	 
	 	•	 	Marine Cargo — Insurance for all marine transits from port of departure to the
Project site covers the cost to repair or replace lost or damaged cargo, and resultant
Delay in Start-up in the event the loss or damage delays production.
	 
	 	•	 	Liability — The limit of liability considers the potential exposure to third
parties, including limited coverage for accidental releases of pollution (subject to a
$2 million cap) arising out of the construction activities and includes damage to the
SAGD Pilot as a result of construction activity. Contractors, sub-contractors,
suppliers and Project lenders are additional insureds.
	 
	 	•	 	Delay in Start-up — Delay in start-up coverage provides financial protection
to the Project in the event a physical damage loss results in a production delay.
	 
	 	•	 	Drilling — All wells and drilling operations are being insured under each JV
Participant’s corporate control of well insurance programs.
	 
	 	•	 	Existing Facilities — Physical damage (other than damage caused by
construction activities) and liability arising out of the operation of the SAGD Pilot
are insured under each JV Participant’s corporate insurance program.










 



-31-







     We are working in conjunction with Nexen on the design and placement of a post completion
operating insurance program. The program is not complete but is expected to include certain
business interruption insurance.



RESERVES AND RESOURCES SUMMARY




     The oil sands reservoir pertaining to the Long Lake, Leismer and Cottonwood Leases is
contained within the McMurray Formation of the basal unit of the Lower Cretaceous Mannville Group.
The McMurray Formation directly overlies the sub-Cretaceous unconformity that is developed on the
Palaeozoic carbonates of the Beaverhill Lake Group. Directly overlying the McMurray Formation are
the Wabiskaw, Clearwater and Grand Rapids formations of the Mannville Group. At surface is the
Quaternary zone which overlies the Grand Rapids Formation and also exists as a deep incising
channel which cuts through the McMurray Formation on the eastern side of the Long Lake Lease.



     The average depth to the top of the McMurray Formation varies from 500 feet at the northern
part of the Long Lake Lease to more than 1,400 feet on the Cottonwood Leases.



     Over the leases, the reservoir has impairments including top water, top gas (overlying the
bitumen pay zones) and bottom water (underlying the oil sands). In addition, there are some areas
that contain intervals of low bitumen and high water saturation. These intervals are interpreted
to be generally small and discontinuous, but in some areas reach thicknesses of 8 to 10 meters,
particularly in the area of the SAGD Pilot.



     Over the Long Lake Leases, gross pay in the McMurray Formation ranges from 150 feet in areas
of abandoned channel sequences to over 400 feet in areas of channelled sand sequences. Within this
thickness, the McMurray Formation net pay can range from several feet to more than 200 feet.



     Based on core analyses, the density of the bitumen varies both aerially and with depth; at
Long Lake, ranging from 6.5 to 8.5oAPI, with an expected volume weighted average of 7.3oAPI. The
bitumen in the lower portion of the McMurray Formation has a higher density, viscosity and
asphaltene content than the bitumen in the upper portion of the formation.



Reserves Data




     McDaniel, established in 1955, is an independent petroleum consulting firm headquartered in
Calgary, Alberta. McDaniel provides specialized services to the petroleum industry in such areas as
reservoir engineering, reserve estimation, geological studies, reservoir simulation and all related
economic evaluations.



     McDaniel has prepared a report dated January 8, 2008 evaluating the bitumen reserves and
synthetic oil reserves of the Long Lake Leases effective as of December 31, 2007 (the “McDaniel
Report”). Reserves have been recognized at Long Lake in the Phase 1 area as proved, probable and
possible reserves, and in the Phase 2 area as probable and possible reserves. The recognition of
probable and possible reserves in the Phase 2 area reflects the greater certainty of their
development than in prior years and the advancement of the regulatory approval process. No reserves
have been assigned to either Leismer or Cottonwood because near term development is not
sufficiently certain.



     The McDaniel Report has been prepared in compliance with the requirements of NI 51-101, issued
by the Canadian Securities Administrators. See Appendix A for additional reserves data and other
oil and gas information presented in accordance with NI 51-101.









 



-32-


     The
McDaniel Report recognizes the inclusion of upgrading in our reserves. Most of the raw
bitumen will be upgraded and sold as PSCTM and butane, and is shown as synthetic crude oil or butane
reserves. Bitumen will be sold upon start-up of the SAGD Operation prior to Long Lake Upgrader
start-up, and thereafter during periods of Long Lake Upgrader downtime, and is shown as bitumen
reserves.



     The following table shows our working interest in the raw bitumen reserves and the
corresponding sales volumes before deducting royalties and using forecast prices and costs.



Summary of Raw Bitumen Reserves and Sales Volumes




December 31, 2007

(MMbbl)




	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Raw	 	Sales Volumes
	 	 	Bitumen	 	PSCTM	 	Bitumen	 	Butane
	Proved
	 	 	268	 	 	 	202	 	 	 	16	 	 	 	3	 
	Proved plus Probable
	 	 	803	 	 	 	620	 	 	 	29	 	 	 	9	 
	Proved plus Probable plus Possible(1)
	 	 	941	 	 	 	731	 	 	 	29	 	 	 	10	 








 




			
	Note:
	 
	(1)	 	Possible reserves are those additional reserves that are less certain to be recovered than
probable reserves. There is a 10 percent probability that the remaining quantities actually
recovered will be greater than the sum of proved plus probable plus possible reserves.





Resources Data




     In addition to estimating the reserves, McDaniel has estimated bitumen resources associated
with the remainder of the Long Lake, the Leismer and the Cottonwood Leases. A summary of our
working interest in the additional resource estimates is shown below:



Summary of Bitumen Resources (1)

December 31, 2007

(MMbbl)




	 	 	 	 	 
	 	 	Raw Bitumen
	Remainder of Long Lake leases(2)
	 	 	704	 
	Leismer(2)
	 	 	960	 
	Cottonwood(3)
	 	 	542	 
	 
	 	 	 	 
	Total
	 	 	2,206	 








 




			
	Notes:
	 
	(1)	 	These estimates represent the “best estimate” of our resource estimates, are not classified
or recognized reserves, and are in addition to our disclosed reserve volumes. These resource
estimates are categorized primarily as Contingent Resources, with some categorized as
Prospective Resources. See Notes (2) and (3), below.

	 
	 	 	
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be
potentially recoverable from known accumulations using established technology or technology
under development, but which are not currently considered to be commercially recoverable due to
one or more contingencies. Contingencies may include factors such as economic, legal,
environmental, political, and regulatory matters, or a lack of markets. It is also appropriate
to classify as Contingent Resources the estimated discovered recoverable quantities associated
with a project in the early evaluation stage. There is no certainty that it will be
commercially viable to produce any portion of the Contingent Resources.










 



-33-


			
	 
	 	 	Prospective Resources are those quantities of petroleum estimated, as of a given date, to be
potentially recoverable from undiscovered accumulations by application of future development
projects. Prospective resources have both an associated chance of discovery and a chance of
development. There is no certainty that any portion of the Prospective Resources will be
discovered. If discovered, there is no certainty that it will be commercially viable to produce
any portion of the resources.
	 
	(2)	 	The resource estimates for Leismer and Long Lake are categorized as Contingent Resources.
These volumes are classified as a resource rather than a reserve primarily due to less
delineation and the absence of regulatory approvals, detailed design estimates and near term
development plans.
	 
	(3)	 	The estimate for Cottonwood is categorized as both Contingent and Prospective Resources. The
estimate of 542 million barrels is comprised of 247 MMbbl of Contingent Resources and 295
MMbbl of Prospective Resources. These Contingent Resource volumes are classified as a resource
rather than a reserve primarily due to less delineation; the absence of regulatory approvals,
detailed design estimates and near term development plans; and less certainty of the economic
viability of their recovery. In addition to those factors that result in Contingent Resources
being classified as such, Prospective Resources are classified as such due to the absence of
proximate delineation drilling.






DESCRIPTION OF CAPITAL STRUCTURE




Description of Share Capital




     We were reorganized and continued under the Canada Business Corporations Act on May 30, 2002
and our share capital was reorganized under the Canada Business Corporations Act on April 14, 2004
pursuant to which all of our outstanding shares became Common Shares, such that the Common Shares
were the only issued and outstanding shares in our capital. Under our current articles, we are
authorized to issue an unlimited number of Common Shares without nominal or par value, and an
unlimited number of preferred shares, issuable in a series (“Preferred Shares”), of which the first
authorized series of Preferred Shares is an unlimited number of Series A Shares, the second
authorized series of Preferred Shares is an unlimited number of Series B Shares (“Series B Shares”
which together with Series A Shares shall been referred to collectively as the “Voting Convertible
Preferred Shares”), and the third authorized series of Preferred Shares is an unlimited number of
Series C Shares. As of June 1, 2006, we amended our Articles of Incorporation to divide the issued
and outstanding common shares on a two-for-one basis.



     As at December 31, 2007 there were 195,355,526 common shares issued and outstanding and no
Preferred Shares or Voting Convertible Preferred Shares were issued and outstanding. As at December
31, 2007 there were 7,208,116 common share options and 3,104,000 common share purchase warrants
(“Warrants”) issued and outstanding. Each full warrant will entitle the holder to purchase two
common shares at a price of $14.75 each at any time prior to November 30, 2008.



     Holders of Common and Voting Convertible Preferred Shares are entitled to receive notice of,
and to attend and vote at, all meetings of our shareholders, except class or series meetings at
which only holders of another class or series of our shares are entitled to vote. Each Common and
Voting Convertible Preferred Share will entitle the holder to one vote.



     Holders of Common and Voting Convertible Preferred Shares will be entitled to receive equally,
share for share, if, as and when declared by our board of directors, such dividends as may be
declared by the board of directors from time to time.



     In the event of our liquidation, dissolution or winding-up, or any other distribution of our
assets among our shareholders for the purpose of winding-up our affairs, the Voting Convertible
Preferred Shares will have the right to receive the subscription price paid for each such share in
priority to the holders of any other class of shares. Holders of Common Shares shall then be
entitled to receive equally, share for share, an amount which will result in holders of Common
Shares receiving an amount per share equal to the subscription price paid for each Voting
Convertible Preferred Share. Thereafter, holders of









 



-34-

Common and Voting Convertible Preferred Shares shall be entitled to receive equally, share for
share, any remaining value of such distribution.




Registration Rights




     In connection with prior issuances of equity securities, we have agreed with certain
shareholders that in the event we cause our shares to become listed on the NASDAQ stock market or
another national stock exchange in the United States, we will enter into a registration rights
agreement with such holders in a form reasonably acceptable to us, which will include demand rights
and piggyback rights, and will address certain other matters typically addressed in a registration
rights agreement.



     In connection with the issuance of the 8.25% Notes and the 7.875% Notes described under
“Description of Debt Capital”, we have agreed to use commercially reasonable efforts to file and
cause a registration statement relating to the notes to become effective in the United States by
the end of January 2008 and March 2008, respectively. The registration statement will allow us to
make an offer to exchange the notes for publicly registered notes that have substantially identical
terms to the existing notes and to consummate the exchange offer within 45 days after the
registration statement is declared effective.



Call Obligations




     The purpose of the call obligations is to provide assurances to us and our lenders that we
will have surplus funding available to complete the Project should cost overruns occur and we are
unable to raise new additional equity to fund such cost overruns.



     There are approximately $202 million of call obligations outstanding. These call obligations
are supported by irrevocable letters of credit, are guaranteed by entities with investment grade
credit ratings or have been provided by subscribers who are federal, provincial or state
governments or entities. We will pay to certain holders of a call obligation an annual fee equal to
the weighted average face amount of any standby letter of credit provided by such subscriber during
the prior year multiplied by 0.0025. The call obligations are not transferable or assignable
without our prior consent, subject to limited exceptions.



     The call obligations consist of unconditional and irrevocable call options whereby we, at our
option, can require a subscription for either a convertible preferred share or a common share for
the face amount of the call obligation. We can exercise the call obligations at any time until the
earlier of completion of the Long Lake Project and June 30, 2008. The exercise price per share of
the call obligations is $2.20 per share and should we exercise our options, it would result in the
issuance of 91.8 million additional common shares and gross proceeds of $202 million.



     Notwithstanding the foregoing, we may arrange interim and/or alternate financing in lieu of
exercising the call obligations. We do not expect to exercise our option under the call
obligations.



Description of Debt Capital




     We have a Revolving Credit Facility in the amount of $500 million. At December 31, 2007, the
Revolving Credit Facility was undrawn and expires on December 15, 2011.



     The conditions precedent to all drawdowns under the Revolving Credit Facility include, among
other things, evidence that our share of remaining Project costs to achieve completion of the
Project is not more than the sum of available cash, contingent equity supported by letters of
credit or high investment grade guarantees plus the aggregate amount available for drawdown under
the Revolving Credit Facility or any other qualifying commitment.









 



-35-


     Our obligations under the Term Credit Agreement are secured by a first ranking charge over all
of our assets and the assets of our present and future subsidiaries (other than immaterial
subsidiaries).



     On December 15, 2006, we issued US$1,000,000,000 principal amount of senior secured notes
which bear interest at 8.25 percent per annum (the “8.25% Notes”). Semi-annual interest payments
are due June 15 and December 15 of each year, with the final payment on December 15, 2014. We may
redeem up to 35 percent of the aggregate principal amount of the notes prior to December 15, 2009
with the net proceeds from certain equity offerings. At any time prior to December 15, 2010, we
may redeem some or all of the notes at their principal amount plus the applicable premium and
accrued interest. After December 15, 2010, we may redeem some or all of the notes at the specified
redemption price plus accrued interest. We may also redeem the notes in certain other limited
circumstances, including upon a change of control and in the event of certain tax law changes. The
notes are our general senior obligations and rank equally in right of payment with all of our
existing and future senior indebtedness and rank senior to all of our future subordinated
indebtedness. The notes are secured by a second ranking charge over all of our assets and the
assets of our present and future restricted subsidiaries.



     On July 5, 2007, we issued US$750,000,000 principal amount of senior secured notes which bear
interest at 7.875 percent per annum (the “7.875% Notes”). The terms and conditions associated with
the 7.875% Notes, with the exception of interest payable, are substantially the same as those of
the 8.25% Notes described above.



     In connection with the 8.25% Notes and 7.875% Notes, we have pre-funded interest until
December 15, 2008 which is held in an interest reserve account. At December 31, 2007, we have
US$139 million in our interest reserve account.



     In relation to OPTI’s U.S. dollar notes, OPTI entered into cross currency interest rate swaps
to fix a portion of the U.S. dollar interest and principal repayment amounts in Canadian dollars.
At the maturity date of the notes, the swaps provide for a fixed Canadian dollar payment of $928
million in exchange for receipt of US $875 million in December 2014. The swaps also provide for
semi-annual Canadian dollar interest payments until December 2014 at a fixed rate of 8.15 percent
based on notional Canadian dollar $928 million of debt.




 











 




-36-


CREDIT RATINGS




     OPTI’s notes are currently rated by two separate agencies, Moody’s Investor Service
(“Moody’s”) and Standard and Poors (“S&P”). Please refer to the table below for the respective
ratings assigned to the notes.



	 	 	 	 	 	 	 	 	 
	Type of Security	 	Moody’s	 	S&P
	8.25% Notes
	 	 	B1	 	 	BB+
	7.875% Notes
	 	 	B1	 	 	BB+






     OPTI and OPTI’s Revolving Credit Facility are currently rated by Moody’s and S&P. Please
refer to the table below for the respective ratings assigned to OPTI and OPTI’s Revolving Credit
Facility.



	 	 	 	 	 	 	 	 	 
	 	 	Moody’s	 	S&P
	OPTI Corporate Rating
	 	Ba3	 	BB-
	Revolving Credit Facility
	 	Ba3	 	BB+






     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 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 B 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.



     S&P Rating Definition — Obligations rated BB 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. BB is one level below that which is considered “Investment Grade”
under the S&P rating system.



     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.











 




-37-


MARKET FOR SECURITIES




     Our Common Shares are listed for trading on the Toronto Stock Exchange under the symbol “OPC”.
The following table sets for the high, low and closing trading prices and the volume of Common
Shares traded on the Toronto Stock Exchange for each month of 2007:



	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Month	 	High	 	Low	 	Closing	 	Volume
	January
	 	$	20.25	 	 	$	17.63	 	 	$	19.90	 	 	 	18,794,625	 
	February
	 	$	21.08	 	 	$	18.88	 	 	$	19.64	 	 	 	14,038,752	 
	March
	 	$	20.75	 	 	$	17.97	 	 	$	19.88	 	 	 	14,848,306	 
	April
	 	$	23.85	 	 	$	19.48	 	 	$	22.25	 	 	 	18,877,336	 
	May
	 	$	25.26	 	 	$	22.15	 	 	$	24.13	 	 	 	21,187,431	 
	June
	 	$	24.65	 	 	$	20.78	 	 	$	22.72	 	 	 	23,566,673	 
	July
	 	$	24.35	 	 	$	21.10	 	 	$	23.00	 	 	 	19,197,429	 
	August
	 	$	24.40	 	 	$	18.75	 	 	$	19.50	 	 	 	26,994,880	 
	September
	 	$	20.22	 	 	$	16.83	 	 	$	18.62	 	 	 	21,968,602	 
	October
	 	$	20.29	 	 	$	16.61	 	 	$	19.05	 	 	 	25,233,928	 
	November
	 	$	20.53	 	 	$	17.59	 	 	$	17.80	 	 	 	21,686,103	 
	December
	 	$	18.09	 	 	$	16.40	 	 	$	16.60	 	 	 	19,861,854	 






DIVIDENDS




     We have not paid any dividends on the Common Shares or any other class or series of shares to
date. The payment of dividends in the future will be dependent upon our earnings and financial
position and on such other factors as our board of directors consider appropriate.



     The payment of dividends may also be subject to certain restrictions pursuant to our credit
facilities.



DIRECTORS AND OFFICERS




     Set forth below are the names, titles and certain other information about our directors and
executive officers.



	 	 	 	 	 	 	 
	Name and	 	Present Position	 	Position Held	 	 
	Residence	 	and Office	 	Since(1)(2)	 	Principal Occupation
	Directors
	 	 	 	 	 	 
	 
	 	 	 	 	 	 
	Yoram Bronicki(6)

Nevada, USA

	 	Director
	 	December 29, 2001
	 	President and Chief Operating
Officer of ORMAT
Technologies Inc.
	 
	 	 	 	 	 	 
	Ian W. Delaney(4)(5)

Ontario, Canada

	 	Director
	 	November 16, 2005
	 	Executive Chairman, Sherritt

International Corporation, a

diversified resource company
	 
	 	 	 	 	 	 
	Charles L. Dunlap(3)(6)

Texas, USA

	 	Director
	 	June 29, 2006
	 	Chief Executive Officer and
President of Pasadena
Refining System Inc.
	 
	 	 	 	 	 	 
	Sid Dykstra

Alberta, Canada

	 	President, CEO and
Director
	 	December 29, 2001
	 	President and Chief Executive
Officer of OPTI
	 
	 	 	 	 	 	 
	Randall Goldstein(4)

California, USA

	 	Director
	 	January 18, 1999
	 	Chief Executive Officer of OptiSolar Inc., a
private solar power company














 




-38-



	 	 	 	 	 	 	 
	Name and	 	Present Position	 	Position Held	 	 
	Residence	 	and Office	 	Since(1)(2)	 	Principal Occupation
	James van Hoften(5)(6)

California, USA

	 	Director
	 	July 12, 2007
	 	Retired
	 
	 	 	 	 	 	 
	Robert G. Puchniak(3)(5)

Manitoba, Canada

	 	Director
	 	May 30, 2002
	 	Executive Vice President and
Chief Financial Officer of James Richardson &
Sons, Limited, an investment
and holding company
	 
	 	 	 	 	 	 
	Christopher P.
Slubicki(3)(4)

Alberta, Canada

	 	Director
	 	February 1, 2007
	 	Energy Investor
	 
	 	 	 	 	 	 
	Samuel Spanglet(4)(6)

Alberta, Canada

	 	Director
	 	October 26, 2007
	 	Retired
	 
	 	 	 	 	 	 
	James M. Stanford(5)

Alberta, Canada

	 	Chairman and Director
	 	May 30, 2002
	 	President of Stanford
Resource Management Inc., a
financial management company
	 
	 	 	 	 	 	 
	Officers
	 	 	 	 	 	 
	 
	 	 	 	 	 	 
	Sid Dykstra

Alberta, Canada

	 	President and CEO
	 	July 6, 2001
	 	see above
	 
	 	 	 	 	 	 
	David Halford

Alberta, Canada

	 	Chief Financial Officer
	 	April 10, 2007
	 	Chief Financial Officer
	 
	 	 	 	 	 	 
	James Arnold(7)

Alberta, Canada

	 	Chief Operating Officer
	 	October 13, 2005
	 	Chief Operating Officer
	 
	 	 	 	 	 	 
	Mary Bulmer

Alberta, Canada

	 	Vice President, Human
Resources and
Corporate Services
	 	April 15, 2004
	 	Vice President, Human
Resources and Corporate
Services
	 
	 	 	 	 	 	 
	Peter Duda

Alberta, Canada

	 	Vice President,

Operations
	 	October 13, 2005
	 	Vice President, Operations
	 
	 	 	 	 	 	 
	Jamey Fitzgibbon

Alberta, Canada

	 	Vice President,

Resource Development
	 	March 19, 2004
	 	Vice President, Resource

Development
	 
	 	 	 	 	 	 
	Dave Schleen

Alberta, Canada

	 	Vice President, Major

Projects
	 	October 1, 2007
	 	Vice President, Major Projects
	 
	 	 	 	 	 	 
	R. Craig Hoskins

Alberta, Canada

	 	Corporate Secretary
	 	August 23, 2004
	 	Partner, Macleod Dixon

llp, a law firm








 




			
	Notes:
	 
	(1)	 	All of the directors of OPTI have been elected or appointed to hold office until the next
annual meeting of shareholders or until their successor is duly elected or appointed, unless
their office is earlier vacated.
	 
	(2)	 	Indicates date of election or appointment as director or officer of OPTI.
	 
	(3)	 	Member of the Audit Committee.
	 
	(4)	 	Member of the Compensation Committee.
	 
	(5)	 	Member of the Governance and Nominating Committee.
	 
	(6)	 	Member of the Technical Committee.
	 
	(7)	 	Formerly Vice President, Development from January 1, 2000 to October 13, 2005.






 











 





-39-




     As at December 31, 2007, our directors and officers, as a group, beneficially own, directly or
indirectly, or exercise control or direction over 592,015 of our common shares or less than one
percent of our issued and outstanding common shares.



Board of Directors




     Brief biographies for each member of our board of directors are set forth below:



Yoram Bronicki




     Mr. Bronicki, President and Chief Operating Officer of ORMAT Technologies Inc. since September
2007 and July 2004, respectively, was the Vice President, OrCrudeTM Upgrading of OPTI from its
inception until June, 30, 2004. Mr. Bronicki, a co-inventor of the OrCrudeTM Process, was a project
manager with ORMAT from 1996 to 2000. Mr. Bronicki oversaw and managed the development, design,
construction, operations and testing of the one bbl/d OrCrudeTM Process pilot plant in Israel and
the demonstration plant near Cold Lake, Alberta.



     Mr. Bronicki holds a B.Sc. in mechanical engineering from the Tel Aviv University and a
certificate from the Technion Institute of Management Senior Executives Program.



Ian W. Delaney




     Mr. Delaney has been the Executive Chairman of Sherritt International Corporation of Toronto,
Ontario since 1995. From 1990 to 1995, Mr. Delaney was the Chairman and Chief Executive Officer of
Viridian Inc., a fertilizer company (formerly Sherritt Inc.) acquired by Agrium Inc. in 1996. He
was President and CEO of The Horsham Corporation, a holding company, from 1987 to 1990; and
President and Chief Operating Officer of Merrill Lynch Canada, a financial management and advisory
company, from 1984 to 1987.



     Mr. Delaney is a director of EnCana Corporation, a director and Chairman of Dynatec
Corporation, a mining company, a director and Chairman of The Westaim Corporation, a technology
investment company, and is also a trustee and Chairman of Royal Utilities Income Fund, a coal
mining investment fund. He has previously served on a number of boards, including Co-Steel Inc.,
MacMillan Bloedel Ltd., and GoldCorp Inc.



Charles Dunlap




     Mr. Dunlap is Chief Executive Officer and President of Pasadena Refining System Inc., operator
of a Houston, Texas-based refinery producing gasoline and diesel fuels with revenues of $2.6
billion in 2006. Mr. Dunlap has served on the board of directors of various publicly traded
companies over the past 14 years.



     Prior to joining Pasadena Refining, Mr. Dunlap’s career included over 30 years of senior
management experience, predominantly in the petroleum industry, including executive positions with
Crown Central Petroleum Corporation, Pacific Resources Inc., ARCO Petroleum Products Company, and
Clark Oil & Refining Corporation.



     Mr. Dunlap holds a juris doctor degree from the Saint Louis University School of Law and an
undergraduate degree from Rockhurst College.









 



-40-


Sid Dykstra




     Mr. Dykstra has been the President and Chief Executive Officer of OPTI since June 2001. From
June 2000 to March 2001, Mr. Dykstra was the President of Hunt Oil Company of Canada Inc. Mr.
Dykstra, a co-founder of Newport Petroleum Corporation, was the President and Chief Operating
Officer of Newport from 1997 to 2000, the Executive Vice President of Newport from 1994 to 1997 and
the Vice President, Engineering of Newport from 1992 to 1994. From 1980 to 1992, Mr. Dykstra held
various positions with Suncor, Inc., was the Manager of Exploitation for Pancontinental Oil Ltd.
and was an independent consultant with Maranta Resources Ltd.



     Mr. Dykstra is currently a director of Cinch Energy Corp. and a past Governor of the Canadian
Association of Petroleum Producers. Mr. Dykstra is a professional engineer in Alberta and holds
numerous professional affiliations and memberships.



     He holds a B.Sc. in chemical engineering from the University of Alberta and an M.B.A. from
Queen’s University.



Randall Goldstein




     Mr. Goldstein is currently Co-Chief Executive Officer of OptiSolar Inc. Previously, he was the
President of ORMAT Process Technologies, Inc. and was employed by the ORMAT Group of Companies. He
is a co-inventor of the OrCrudeTM Process.



     Mr. Goldstein was a co-founder of National Power Company and held the position of Chief
Financial Officer of that company from 1991 to 1994. National Power Company is a developer of
independent power projects using low value opportunity fuels. Mr. Goldstein was employed by the
Harbert Power Group from 1987 to 1991 as Manager of Project Finance. In that capacity he was
responsible for business development and financing of independent power projects, including a
number of projects fuelled by petroleum coke. Prior to that, Mr. Goldstein was employed by ORMAT
Energy Systems Inc. as Manager of Project Finance, responsible for the financing of geothermal
power plants.



     Mr. Goldstein holds a B.A. in economics from the University of California, Berkeley and a
M.Sc. in energy management and policy from the University of Pennsylvania.



James van Hoften




     Dr. van Hoften was most recently a Senior Vice President and Partner at Bechtel
Corporation (Bechtel), one of the world’s largest engineering, construction, and project management
companies. In his 20 years at Bechtel, he held responsibility for some of the world’s largest
construction projects. Dr. van Hoften is also a former NASA astronaut and flew two Space Shuttle
missions. Prior to that, Dr. van Hoften was an assistant professor of civil engineering at the
University of Houston.



     Dr. van Hoften is currently a director of Flex LNG, a London based LNG shipping and
production company. Dr. van Hoften holds a Ph.D. in hydraulic engineering from Colorado State
University, and a B.Sc. in civil engineering from the University of California at Berkeley.



Robert G. Puchniak




     Mr. Puchniak has been the Executive Vice President and Chief Financial Officer of James
Richardson & Sons, Limited, an investment and holding corporation, since March 2001 and prior
thereto, was Vice President, Finance and Investment with James Richardson & Sons, Limited since
November









 



-41-



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 is a director of a number of public and private corporations including James
Richardson International Limited, Tundra Oil & Gas Limited, Value Creation Inc., Richardson
Partners Financial Holdings Limited, OptiSolar, Inc., Strad Energy Services Ltd. and Lombard Realty
Limited. His past involvements include Director, Western Oil Sands Inc., Petrobank Energy and
Resources Ltd., Trident Resources Corp., Moffat Communications Limited 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 B.Comm. (Honours) from the University of Manitoba and was awarded the
University Gold Medal for his achievements. He earned a Chartered Financial Analyst designation in
1975.



Christopher P. Slubicki




     Mr. Slubicki was formerly the Vice Chairman of Scotia Waterous. Mr. Slubicki was one of the
founders of Waterous & Co., a private global oil and gas investment banking firm, where he was
involved in all aspects of the firm’s strategic development as Senior Managing Director and
Principal. Waterous & Co. was sold to The Bank of Nova Scotia in 2005. Prior to the founding of
Waterous, Mr. Slubicki held operations management and engineering positions within the oil and gas
industry including Placer CEGO Petroleum Ltd. and Chevron Canada Resources Limited.



     Mr. Slubicki holds a Masters of Business Administration from the University of Calgary, a
B.Sc. in Mechanical Engineering from Queen’s University, and is a professional engineer in Alberta.



Samuel Spanglet




     Mr. Spanglet was most recently the Vice President Operations, Oil Sands and President, Albian
Sands Energy Inc. at Shell Canada. There, he oversaw all oilsands operations, including the
Scotford Complex and Albian Sands. Previously, he was the general manager of the Scotford Complex,
responsible for managing Shell’s manufacturing in Western Canada, as well as overseeing the
successful integration of a newly constructed upgrader. Mr. Spanglet also held other managerial
positions within Shell Canada during his 25 year tenure.



     Mr. Spanglet holds a Bachelor of Science in chemical engineering from the Technion Institution
of Technology in Haifa, Israel, and is currently a member of the board of directors of ATCO Power.



James M. Stanford




     Mr. Stanford is the Chairman of OPTI’s board of directors. He is the President of Stanford
Resource Management Inc., and retired President, Chief Executive Officer and a director of
Petro-Canada, having held those positions from 1993 to 2000. Mr. Stanford served as the President,
Chief Operating Officer and a director of Petro-Canada from 1990 to 1993. Prior to joining
Petro-Canada in 1978, Mr. Stanford worked with Mobil Oil Canada Ltd. for 19 years in numerous
engineering and managerial positions.



     Mr. Stanford acts as Chairman of the board for Nova Chemicals Corporation, and sits on the
board of directors of EnCana Corporation. Mr. Stanford also serves on a variety of other industry
and community organizations.









 



-42-


     Mr. Stanford holds an LL.D. (Hon.) and a B.Sc. in petroleum engineering from the University of
Alberta and an LL.D. (Hon.) and a B.Sc. in mining from Concordia University. In 2004, he was
appointed an Officer of the Order of Canada.



Officers




     The following individuals make up our senior management: James Arnold, Mary Bulmer, Peter
Duda, Sid Dykstra, Jamey Fitzgibbon, David Halford, and Dave Schleen. A brief biography for Mr.
Dykstra is provided above under “— Board of Directors.” A brief biography for each of Mr. Arnold,
Ms. Bulmer and Messrs. Duda, Halford, Fitzgibbon, and Schleen is set forth below.



James Arnold




     Mr. Arnold is our Chief Operating Officer. Prior to his appointment to this position in
October 2005, he was our Vice President, Development since January 2000. During 1999, Mr. Arnold
was the General Manager and Reservoir Engineering Manager of Canadian Occidental Petroleum’s Heavy
Oil Business Unit and during 1998 was the General Manager Facilities (Domestic) of Canadian
Occidental Petroleum. Mr. Arnold held various positions with Wascana Energy Inc. (formerly Saskoil)
from 1982 to 1997, ranging from Development Engineer to General Manager, Deep/Medium Gas Business
Unit.



     Mr. Arnold holds, and has held, numerous professional affiliations and memberships with
petroleum related organizations and associations.



     Mr. Arnold is a professional engineer in Alberta. He holds a B.Sc. in mechanical engineering
from the University of Manitoba.



Mary Bulmer




     Ms. Bulmer is our Vice President, Human Resources and Corporate Services. She joined us as a
consultant in October 2003 and was promoted to her current position in April 2004. From 2000 to
2002, Ms. Bulmer was the Vice President of Human Resources and Corporate Services, Corporate
Officer of Hunt Oil Company of Canada Inc., and from 1992 to 2000, Ms. Bulmer was the Director of
Human Resources of Koch Petroleum Canada L.P.



     Ms. Bulmer holds a M.Sc. in counselling psychology from the University of Calgary and a B.A.
(Honours) from the University of Western Ontario.



Peter Duda




     Mr. Duda is presently our Vice President, Operations. He joined us in 2003 as the General
Manager, Upgrader Operations and was promoted to his current position in October 2005. From
December 2000 to 2003, Mr. Duda was the Venture Operations Manager of Petrola Hellas S.A. (Greece)
and, prior thereto, Mr. Duda held executive and managerial positions as Vice- President
Manufacturing and as a director of Chevron Canada Limited concurrent with his position as a
director of Alberta Envirofuels from 1997 to 2000. Mr. Duda was the General Manager of Alberta
Envirofuels from 1992 to 1997.



     Mr. Duda is a professional engineer in Alberta and British Columbia. Mr. Duda holds a B.A.Sc.
in mechanical engineering from the University of Alberta.









 



-43-


     Mr. Duda currently serves as a member of the Keyano College board of Governors, and has held
positions in the past as vice chair of the Keyano College Foundation and as a director for the
Strathcona Industrial Association.



Jamey Fitzgibbon




     Mr. Fitzgibbon is our Vice President, Resource Development. Prior to his appointment to this
position on March 19, 2004 he was our Manager, Resource Development since July 2002. From August
2000 to July 2002, Mr. Fitzgibbon was a Vice-President in Investment Banking at TD Securities Inc.
Prior to that, Mr. Fitzgibbon was the Heavy Oil Development Manager at Ranger Oil Limited and held
various technical and managerial positions at Ranger Oil, Elan Energy Inc., and Imperial Oil
Limited.



     Mr. Fitzgibbon is a professional engineer in Alberta and holds, and has held, numerous
professional and technical affiliations and memberships.



     Mr. Fitzgibbon holds a B.Sc. in chemical engineering from Queen’s University and an M.B.A.
from the University of Calgary.



David Halford




     Mr. Halford, our Chief Financial Officer, joined OPTI in April 2007. Most recently, Mr.
Halford held the position of Vice President and Chief Financial Officer at BA Energy in Calgary.
Prior, Mr. Halford was the Chief Financial Officer of Irving Oil, a New Brunswick-based refiner and
marketer of petroleum products. Before joining Irving Oil, Mr. Halford was a Partner in the
Corporate and Finance group in the Toronto office of Deloitte and Touche LLP.



     Mr. Halford is a Chartered Accountant and holds a B.A. from the University of Western Ontario.



Dave Schleen




     Mr. Schleen is our Vice President, Major Projects. Prior to his appointment to this position
in October 2007, he held the position of Project Director. Mr. Schleen joined OPTI in mid-2002 as
Area Project Manager Hydrocracker & Sulphur Recovery. Previously, he spent over 20 years with
Suncor Energy Inc. in a variety of management and project engineering roles, including Senior
Project Manager on the Millennium upgrader.



     Mr. Schleen holds a Bachelor of Engineering in Material Science from the University of Western
Ontario, and is a professional engineer registered in Alberta.



Audit Committee




     Our board of directors has adopted a charter for the Audit Committee which clearly defines the
committee’s responsibilities in the areas of external audit, internal controls, governance and
financial reporting. Set out in Appendix D is the text of the Audit Committee’s charter.



     The Audit Committee is comprised of Messrs. Puchniak (Chairman), Slubicki and Dunlap. All
three members are financially literate and independent for the purposes of Multilateral Instrument
52-110 “Audit Committees”, by the Canadian Securities Administrators.









 



-44-


Auditor Service Fees




     PricewaterhouseCoopers LLP has served as the auditors of OPTI since its incorporation. The
following table summarizes the total fees paid to PricewaterhouseCoopers LLP for the years ended
2007 and 2006 in thousands of dollars:



	 	 	 	 	 	 	 	 	 
	 	 	2007	 	2006
	Audit fees
	 	$	186	 	 	$	180	 
	Tax fees
	 	 	71	 	 	 	136	 
	All other fees
	 	 	269	 	 	 	48	 
	 
	TOTAL
	 	$	526	 	 	$	364	 






     Audit fees were paid for professional services rendered by the auditors for the audit of the
our annual financial statements, review of interim quarterly financial statements and services
provided for statutory and regulatory filings. All other fees are in connection with and for
services provided in connection with financing activities. Tax fees were paid for tax compliance
and planning.



     All permissible categories of non-audit services require pre-approval from the Audit
Committee.



CONFLICTS OF INTEREST




     Our right to utilize the OrCrudeTM Process technology is pursuant to an exclusive license to us
from OPTI BV, a wholly-owned subsidiary of ORMAT which is an entity that constitutes part of the
ORMAT Group of Companies. One member of our board of directors is an officer of a separate entity
that also constitutes part of the ORMAT Group of Companies and one member of our board of directors
is a former officer of an entity which is a member of the ORMAT Group of Companies and, as a result
of such positions and shareholdings, such directors of OPTI may become subject to conflicts of
interest in the future. Additionally, certain of the directors and officers of OPTI may engage in,
or are engaged in, other business activities on their own behalf or on behalf of other companies or
are directors of other companies and, as a result of such activities or positions, such directors
and officers of OPTI may become subject to conflicts of interest in the future. The Canada Business
Corporations Act provides that a director or officer shall disclose the nature and extent of any
interest that he or she has in a material contract or material transaction, whether made or
proposed, if the director or officer:




	 	•	 	is a party to the contract or transaction,
	 
	 	•	 	is a director or an officer, or an individual acting in a similar capacity, of a
party to the contract or transaction, or
	 
	 	•	 	has a material interest in a party to the contract or transaction,





     and shall refrain from voting on any matter in respect of such contract or transaction unless
otherwise provided under the Canada Business Corporations Act.



     To the extent that conflicts of interest arise, such conflicts will be resolved in accordance
with the provisions of the Canada Business Corporations Act.









 



-45-


RISKS AND UNCERTAINTIES




     We are exposed to a number of risks and uncertainties relating to our operations.



Risks Relating to the Project



The Project is in the construction stage. It may not be completed on time, on budget or at all, and
once operational, it may be subject to delays, interruptions or increased costs that may materially
adversely affect our results of operations.



The Project is in the construction stage. There have been increases in cost to complete above our
original estimates. There is a risk that the Project will not be completed within the timeframes or
costs discussed herein or at all. Additionally, there is a risk that the Project may have delays,
interruption of operations or increased costs due to many factors, including, without limitation:





	 	•	 	shortages of, or delays in obtaining qualified labour, equipment, construction
materials or services;
	 
	 	•	 	labour disputes, disruptions or declines in productivity;
	 
	 	•	 	changes in the scope of the Project or increases in the amount or cost of
materials or labour;
	 
	 	•	 	contractor or operator errors in design or construction and non-performance by,
or financial failure of, third party contractors;
	 
	 	•	 	breakdown or failure of equipment or processes;
	 
	 	•	 	delays in obtaining, or conditions imposed by, regulatory approvals;
	 
	 	•	 	challenges to our proprietary technology and/or that of our affiliates or
suppliers or of our licensors;
	 
	 	•	 	transportation or construction accidents, disruption or delays in availability
of transportation services or adverse weather conditions affecting construction or
transportation;
	 
	 	•	 	unforeseen site surface or subsurface conditions;
	 
	 	•	 	disruption in the supply of energy; and
	 
	 	•	 	catastrophic events such as fires, storms or explosions.





     Given the stage of development of the Project, various changes to it may be made prior to the
time it is completed by the JV Participants. SAGD Operations are currently in the process of
starting up and based upon current scheduling, we do not expect to start commercial
PSCtm production until mid-2008. The information contained in this AIF,
including, without limitation, reserve and economic evaluations, is conditional upon receipt of all
regulatory approvals and no material changes being made to the Project or its scope.



     The current construction and operations schedules may not proceed as planned. There may be
delays and for this and other reasons, the Project may not be completed within our current total
cost estimate of the Project of between $5.8 billion and $6.1 billion, or between $2.9 billion and
$3.05 billion net to us. Any such cost increases could be significant and may require additional
financing which may not be available when needed.









 



-46-


     The Project is our only source of potential revenue for the next several years, and if the
Project is not completed, is over budget or is late, our ability to meet our obligations, including
making debt repayments and interest payments beyond 2008, may be materially adversely affected.



Our SAGD and Long Lake Upgrader facilities may not operate as planned.




     The performance of either the SAGD Operation or the Long Lake Upgrader may differ from our
expectations. The variances from expectation may include, without limitation:




	 	•	 	the ability to operate at the expected level of throughput or production;
	 
	 	•	 	the percentage conversion of bitumen to PSC
tm;
	 
	 	•	 	the quality and characteristics of the PSCTM; and
	 
	 	•	 	the reliability or availability of the facilities.





     If the facilities do not perform to our expectations or as required by regulatory approvals,
we may be required to invest additional capital to correct deficiencies or we may not be able to
produce the expected level of production of either bitumen or PSC
tm. If these
expectations are not met, our revenue, cash flows and earnings may be reduced.



     As the Project is our only source of potential revenue for the next several years, any
significant deviation from our expectations in the operation or performance of the SAGD Operation
or the Long Lake Upgrader could compromise our ability to meet our obligations, including making
debt repayments and interest payments beyond 2008.



     There are technology license agreements in place for some SAGD and Long Lake Upgrader
facilities. If these facilities fail to perform as expected, we may not be able to recover damages
from the licensors, and if we do recover damages from the licensors, they may not be sufficient to
compensate us for our losses.


The operating costs of the Project may vary considerably during the operating period. If they
increase, our earnings may be reduced.




     The operating costs of the Project are significant components of the cost of production of the
petroleum products produced by the Project. Those operating costs may vary considerably during the
operating period. The principal factors which could affect operating costs include, without
limitation;




	 	•	 	amount and cost of labour to operate the Project;
	 
	 	•	 	cost of catalyst and chemicals;
	 
	 	•	 	actual SOR required to operate the SAGD well pairs;
	 
	 	•	 	cost of natural gas and electricity;
	 
	 	•	 	cost of complying with regulatory approvals;
	 
	 	•	 	maintenance cost of the facilities;
	 
	 	•	 	cost to transport sales products and the cost to dispose of certain by-products; and
	 
	 	•	 	cost of insurance and taxes.





     Our earnings may be reduced if we experience increases in operating costs.









 



-47-

The Project is subject to numerous operational hazards and other risks against which we may not be
insured.




     The operation of the Project will be subject to the customary hazards of recovering,
transporting and processing hydrocarbons, such as fires, explosions, gaseous leaks, migration of
harmful substances, blowouts and oil spills. A casualty occurrence might result in the loss of
equipment or life, as well as injury or property damage. We do not and will not carry insurance
with respect to all potential casualty occurrences and disruptions. There can be no assurance that
our insurance will be sufficient to cover any casualty occurrences or disruptions that may occur in
the future. The Project could be interrupted by natural disasters or other events beyond the
control of the JV Participants. Losses and liabilities arising from uninsured or under-insured
occurrences could have a material adverse effect on the Project and, accordingly, on our business,
financial condition and results of operations.



     Recovering bitumen from oil sands and upgrading the recovered bitumen into synthetic crude oil
and other products involve particular risks and uncertainties. The Project is susceptible to loss
of production, slowdowns, or restrictions on its ability to produce higher value products due to
the interdependence of its component systems. Severe climatic conditions can cause reduced
production and in some situations result in higher costs. SAGD bitumen recovery facilities and
development and expansion of production can entail significant capital outlays. The costs
associated with synthetic crude oil production are largely fixed and, as a result, operating costs
per unit are largely dependent on levels of production.



     The bitumen upgrading facilities of the Project are subject to numerous risks related to the
operation of upgrading facilities and other distribution facilities, including loss of product or
disruptions and slowdowns due to equipment failures or other accidents.



     The SAGD Operation and Long Lake Upgrader will process large volumes of hydrocarbons at high
pressure and at high temperatures in equipment with fine tolerances and will handle large volumes
of high pressure steam. Equipment failures could result in damage to the Project’s facilities and
liability to third parties and regulators against which we may not be able to fully insure or may
elect not to insure because of high premium costs or for other reasons.



     Certain components of the Project will produce sour gas, which is gas containing hydrogen
sulphide. Sour gas is a colourless, corrosive gas which is toxic at relatively low levels to
plants, animals and humans. The Project will include integrated facilities for handling and
treating the sour gas, including the use of gas sweetening units, sulphur recovery systems and
emergency flaring systems. Failures or leaks from these systems or other exposure to sour gas
produced as part of the Project could result in damage to other equipment, liability to third
parties, adverse effect to humans, animals and the environment, or the shut-down of operations.


We plan to expand the Project through development of future phases and these expansions may not
proceed on our expected timeline or at all.




     We have announced a multistage expansion plan, including plans to increase total production to
360,000 bbl/d in our joint venture with Nexen. In order to proceed with such development, we will
need to establish that the development will exceed our required conditions for development. Phase
2 sanctioning will be dependent on multiple factors including Phase 1 ramp-up performance,
regulatory approval for the SAGD portion of the project, the capital cost estimate, the commodity
price environment as well as further clarity on CO2 regulations. There is a risk that
these factors in aggregate may not be sufficient for our criteria to sanction Phase 2 or future
phases.









 



-48-

The pool of employees with the skills required for the Project is limited, so we may not be able to
hire all of the labour force we require at the compensation levels budgeted for or at all.




     The Project will require experienced employees with particular areas of expertise. There can
be no assurance that all of the required employees with the necessary expertise will be available.
There are other oil sands projects and expansions currently under construction and significant
projects and expansions have been announced by other oil sands developers. We currently anticipate
that some of these projects and expansions will proceed in the same time frame as the Project. This
means that we will compete with these other projects for experienced employees and such competition
may impact the availability of employees and/or may result in increases to compensation paid to
such employees.


Our business may suffer if we lose key personnel.




     We face numerous risks due to the stage of development of our company, as well as certain
other factors. Our success will depend in part on the ability, expertise, judgment, discretion and
good faith of our management and our ability to retain them. We do not maintain key-man life
insurance with respect to any of our employees. If we lose any key personnel, it may have a
material adverse effect on our business, financial condition or results of operations.


We plan to expand the Project and we may not be able to efficiently manage or finance such
expansion, which could have a material adverse effect on our business, financial condition or
results of operations.




     We have announced a multistage expansion plan, including plans to increase total production to
360,000 bbl/d in our joint venture with Nexen. In order to proceed with such development, we will
require additional financing in order to fund a portion of our share of costs associated with such
expansion. Our participation in any additional phases of the Project will be subject to
substantially all of the same risks as those set forth in this AIF for the Project in general.



     The industry is in a period where unprecedented oil sands development and industrial activity
is planned at a time when activity in many other sectors is also high. Our expansion projects will
need to compete for equipment, supplies, services, and labour in this environment, which could
result in increased costs or, shortages of goods and services that delay progress, or both. In
addition, participation in expansion projects will significantly increase the demands on our
management and administrative resources and require significant financing. We may not be able to
effectively manage or finance the expansions, and any failure to do so could have a material
adverse effect on our business, financial condition or results of operations. See “Risks and
Uncertainties — Risks Related to Financing and Our Indebtedness.”


The Project must obtain and maintain regulatory approvals under and comply with stringent
environmental laws and regulations. The failure to attain such approvals and comply with any of
these laws and regulations could, among other things, prevent or limit our operations or subject us
to substantial liability, which, in turn, could have a material adverse effect on our business and
financial condition.




     The construction, operation and decommissioning of the Project and reclamation of the
Project’s lands are conditional upon various environmental and regulatory approvals issued by
governmental authorities. There is no assurance such approvals will be issued, or once issued, not
appealed, or renewed, or that they will not contain terms and conditions which make the Project
uneconomic or cause us and our partners to significantly alter the Project. Further, the
construction, operation and decommissioning of the Project and reclamation of the Project’s lands
are and will be subject to approvals, laws and regulations









 



-49-



relating to environmental protection and operational safety. Risks of substantial costs and
liabilities are inherent in oil sands recovery and upgrading operations, as well as operations
associated with the cogeneration facility, and there can be no assurance that substantial costs and
liabilities will not be incurred or that the Project will be permitted to carry on operations.
Moreover, it is possible that other developments, such as increasingly strict environmental and
safety laws, regulations and enforcement policies thereunder, and claims for damages to property or
persons resulting from the Project’s operations, could result in substantial costs and liabilities
to us or delays to, or abandonment of, the Project.



     No assurance can be given that future environmental approvals, processes, laws or regulations
will not adversely impact our ability to operate the Project or increase or maintain production of
the Project or will not increase our unit costs of production. 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 GHGs. The Project will
be a significant producer of some GHGs covered by the Convention. On April 26, 2007 the Canadian
Federal Government released the Framework which outlines proposed new requirements governing the
emission of GHGs and other industrial air pollutants, including sulphur oxides, volatile organic
compounds, particulate matter, and possibly additional sector-specific pollutants, in accordance
with the Canadian Federal Government’s Notice of Intent to Develop and Implement Regulations and
Other Measures to Reduce Air Emissions released on October 19, 2006. The Framework introduces
further, but not full, detail on new GHG and industrial air pollutant limits and compliance
mechanisms that will apply to various industrial sectors, including the oil sands extraction,
upgrading and electricity production industries starting in 2010. The Canadian Federal Government
is in the process of consulting stakeholders about the emission-intensity reduction targets which
are contemplated to form the basis of new draft regulations scheduled to be released in early 2008.
The proposed compliance mechanisms include fixed emission caps and an emissions credit trading
system for certain industrial air pollutants, and several options for companies to choose among to
meet GHG emission reduction targets and encourage the development of new emission reduction
technologies.



     These future federal industrial air pollutant and GHG emission reduction targets, together
with provincial emission reduction requirements contemplated in Alberta’s Climate Change and
Emissions Management Act, or emission reduction requirements in future regulatory approvals, may
require the reduction of emissions or emissions intensity from our operations and facilities,
payments to a technology fund or purchase of emission reduction or off-set credits. The required
emission reductions may not be technically or economically feasible for the Project and the failure
to meet such emission reduction requirements or other compliance mechanisms may materially
adversely affect our business and result in fines, penalties and the suspension of operations. As
well, equipment from suppliers which can meet future emission standards may not be available on an
economic basis and other compliance methods of reducing emissions or emission intensity to required
levels in the future may significantly increase our operating costs or reduce output of the
Project. Emission reduction or off-set credits may not be available for acquisition by the Project
or may not be available on an economic basis. There is also the risk that the provincial government
could impose additional emission or emission-intensity reduction requirements, or that the federal
and/or provincial governments could pass legislation which would tax such emissions.



     To operate the facilities, the Project relies on groundwater, which is obtained under licenses
from Alberta Environment (“AE”). There can be no assurance that the licenses to withdraw
groundwater will not be rescinded or that additional conditions will be not be added to these
licenses. There can be no assurance that we will not have to pay a fee for the use of water in the
future or that any such fees will be reasonable. In addition, the expansion of the Project relies
on securing licenses for additional water withdrawal, and there can be no assurance that these
licenses will be granted on terms favourable to the company or at all, or that such additional
water will in fact be available to divert under such licenses.









 



-50-

We will be responsible for abandonment and reclamation costs which may be substantial but which we
cannot currently estimate.




     We will be responsible for compliance with terms and conditions of environmental and
regulatory approvals and all laws and regulations regarding the abandonment of the Project and
reclamation of the Project lands at the end of their economic life. Abandonment and reclamation
costs may be substantial. A breach of such legislation and/or regulations may result in the
imposition of fines and penalties, including an order for cessation of operations at the site until
satisfactory remedies are made. It is not possible to estimate reliably the abandonment and
reclamation costs since they will be a function of regulatory requirements at the time and the
value of the salvaged equipment may be more or less than the abandonment and reclamation costs. In
addition, in the future we may determine it prudent or be required by applicable laws, regulations
or regulatory approvals to establish and fund one or more reclamation funds to provide for payment
of future abandonment and reclamation costs.



Risks Relating to Reserves and Resources



Undue reliance should not be placed on estimates of reserves and resources, since these estimates
are subject to numerous uncertainties, and our actual reserves could be lower than such estimates.




     There are numerous uncertainties inherent in estimating quantities of reserves and resources,
including many factors beyond our control, and no assurance can be given that the indicated level
of reserves or recovery of bitumen will be realized. In general, estimates of economically
recoverable bitumen reserves and resources and the future net revenues therefrom are based upon a
number of factors and assumptions made as of the date on which the reserve and resource estimates
were determined, such as geological and engineering estimates which have inherent uncertainties,
the assumed effects of regulation by governmental agencies and estimates of future commodity prices
and operating costs, all of which may vary considerably from actual results. All such estimates
are, to some degree, uncertain and classifications of reserves and resources are only attempts to
define the degree of uncertainty involved. For these reasons, estimates of the economically
recoverable bitumen, the classification of such reserves and resources based on risk of recovery
and estimates of future net revenues expected therefrom, prepared by different engineers or by the
same engineers at different times, may vary substantially. References to “resources” in this AIF
should be distinguished from “reserves.” See “Reserves and Resources Summary” and Appendix A to
this AIF for more information.



     Estimates with respect to reserves and resources that may be developed and produced in the
future are often based upon volumetric calculations, probabilistic methods and upon analogy to
similar types of reserves or resources, rather than upon actual production history. Estimates based
on these methods generally are less reliable than those based on actual production history.
Subsequent evaluation of the same reserves or resources based upon production history will result
in variations, which may be material, in the estimated reserves or resources.



     Reserve and resource estimates may require revision based on actual production experience.
Such figures have been determined based upon assumed oil prices and operating costs. Market price
fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen.
Moreover, short term factors relating to oil sands resources may impair the profitability of the
Project in any particular period.



     No assurance can be provided as to the quality of bitumen produced from the Long Lake leases.
The quality of the bitumen can ultimately determine the amount of syngas and
PSCtm produced from the Long Lake Upgrader.









 



-51-

The SAGD bitumen recovery process is subject to uncertainty.




     The recovery of bitumen using the SAGD process is subject to uncertainty. The SAGD process has
had limited operating history in commercial projects and has only had limited testing on the Long
Lake leases. Although we have conducted pilot tests on the Long Lake leases reservoir, there can be
no assurance that the Project will achieve the same or similar results as the SAGD Pilot which was
used to evaluate well design, confirm reservoir performance and obtain site specific operating
experience in respect of the Project or that the Long Lake SAGD Operation will produce bitumen at
the expected levels or on schedule.



     We have a limited operating history with respect to the SOR for the Project. Although we
believe our current estimates of SOR are reasonable, there can be no assurance that the estimates
will be achieved. Should the actual SOR in commercial operations be higher than these estimates, it
may result in some or all of the following:




	 	•	 	an increase in operating costs;
	 
	 	•	 	lower bitumen production; or
	 
	 	•	 	the requirement for additional facilities.





     Any of these could have a significant adverse impact on the future activities and economic
performance of the Project.



     Full use of the upgrading capacity of the Long Lake Upgrader may depend on the supply of third
party bitumen, which may not be available at all or at commercially acceptable prices. We may enter
into long-term agreements with others for the supply of such bitumen but there is no guarantee that
such suppliers will be able to meet their commitments to us under such agreements.



Risks Relating to Commodity Pricing



Our results of operations will depend upon the prevailing prices of oil and natural gas in the
worldwide markets, and those prices can fluctuate substantially.




     Our revenues, cash flows, earnings, cost of capital, asset values, results of operations and
financial condition will be dependent upon the prevailing price of crude oil and natural gas. Oil
prices have historically been extremely volatile and fluctuate significantly in response to
regional, national and global supply and demand factors beyond our control. Among the factors that
can cause oil price and natural gas price fluctuation are:




	 	•	 	the level of consumer product demand;
	 
	 	•	 	the domestic and foreign supply of natural gas and crude oil, including the
decisions of the Organization of Petroleum Exporting Countries relating to export
quotas and their compliance or non-compliance with such self-imposed quotas;
	 
	 	•	 	weather conditions, including hurricanes, floods and other natural disasters;
	 
	 	•	 	domestic and foreign governmental regulations;
	 
	 	•	 	the effect of worldwide conservation of resources;
	 
	 	•	 	the price and availability of alternative fuels, including liquefied natural gas;
	 
	 	•	 	political conditions in crude oil and natural gas producing regions, including
wars, terrorist activities and other hostilities;










 



-52-








	 	•	 	the proximity of reserves to, and capacity of, transportation facilities;
	 
	 	•	 	the price of foreign imports of crude oil and natural gas;
	 
	 	•	 	overall global and domestic economic conditions; and
	 
	 	•	 	concern over climate change or GHG emissions.





     Any material decline in oil prices or, prior to Upgrader start-up, any material rise in
natural gas prices could result in a material reduction of our operating results, production
revenue, reserves and overall value. In addition, any prolonged period of low oil prices could
result in a decision by us and/or Nexen to suspend or reduce production. Any such suspension or
reduction of production would result in a corresponding substantial decrease in our revenues and
earnings and could materially impact our ability to meet our debt servicing obligations and could
expose us to significant additional expense as a result of any future long-term contracts. If
production was not suspended or reduced during such period, the sale of the petroleum products
produced by the Project at such reduced prices would lower our revenues.



     We conduct an assessment of the carrying value of our assets to the extent required by GAAP.
If oil prices decline, the carrying value of our assets could be subject to downward revision, and
our earnings could be adversely affected.



The price we receive for PSC
tm will depend upon the demand for it, which is not
currently proven.




     The price we will receive for PSCtm will be dependent on the demand for
it. PSCtm will compete against other synthetic crude oils and natural crude
oils. As PSCtm will be a new synthetic crude oil product, no assurance can be
given as to the price and marketability of PSCtm.



     The production of PSCTM may generate GHG emissions that are higher than those
generated during the production of other synthetic or conventional oils, which could limit our
ability to sell PSCTM.


We will be subject to foreign currency exchange fluctuation exposure.




     Crude oil prices are generally based on a U.S. dollar market price, while certain of our
operating and capital costs will be primarily in Canadian dollars. Fluctuations in exchange rates
between the U.S. and Canadian dollar will therefore give rise to foreign currency exchange
exposure. A material increase in the value of the Canadian dollar relative to the U.S. dollar may
negatively affect our revenue by decreasing the Canadian dollars we receive for a given U.S. dollar
price. We may mitigate the impact of exchange rate fluctuations on the revenue from the Project by
entering into currency hedges, but there is no assurance that any hedges we may enter into will be
successful and, if not successful, those hedges could result in serious adverse effects on our
financial condition and business.


We enter into commodity price hedging arrangements, which may subject us to additional risks.




     The nature of our operations will result in exposure to fluctuations in commodity prices. We
use financial instruments and may also use physical delivery contracts to hedge our exposure to
these risks. If we continue to engage in hedging, we will be exposed to credit-related losses in
the event of non-performance by counterparties to the financial instruments. Additionally, if
product prices increase above those levels specified in any future hedging agreements, we could
lose the cost of floors or ceilings or a fixed price could prevent us from receiving the full
benefit of commodity price increases. Our current and any future hedging arrangements could cause
us to suffer financial loss if we are unable to commence operations on schedule, if we are unable
to produce sufficient quantities of oil to fulfill our obligations, if we are required to pay a
margin call on a hedge contract or if we are required to pay royalties based on a market or
reference price that is higher than our fixed ceiling price.
















 





-53-




Risks Relating to Technology



The Integrated OrCrudetm Upgrading Process may not be successful, which could
have a significant adverse impact on our financial condition of the Project.




     There can be no assurance that the Long Lake Upgrader will achieve the same performance
results as the OrCrudetm demonstration plant owned and operated by us from 2001
to 2003, nor that the Long Lake Upgrader will have the same level of success in upgrading the
bitumen production from the Long Lake leases and other lands owned by the JV Participants to the
desired product specifications, at the expected levels, on schedule or at all. If we are unable to
upgrade the bitumen for any reason, we may decide to, or may be forced to, sell it as bitumen
without upgrading it. Bitumen blend is not as readily marketable as conventional light oil and
market prices are lower for bitumen blend on a comparable basis. This could have a significant
adverse impact on our financial performance and future activities of the Project and expansion
projects.


Our results of operations, business and financial condition are dependent in large part on our
ability to protect our proprietary technology.




     Our future results of operations depend to a significant extent on our proprietary technology,
the proprietary technology of third parties that has been, or is required to be, licensed by us,
and our ability, and that of such third parties, to prevent others from copying or infringing upon
such proprietary technologies. We currently rely on intellectual property rights and other
contractual or proprietary rights, including (without limitation) copyright, trademark, trade
secrets, confidentiality procedures, contractual provisions, licenses and patents, to protect our
proprietary technology, and on third parties, from whom licenses have been received, to protect
their proprietary technology. From time to time, we may have to engage in litigation in order to
protect patents or other intellectual property rights, or to determine the validity or scope of the
proprietary rights of others. This kind of litigation can be time-consuming and expensive,
regardless of whether or not we are successful. The process of seeking patent protection can itself
be long and expensive, and there can be no assurance that any currently pending or future patent
applications by us, or by such third parties will actually result in issued patents, or that, even
if patents are issued, they will be of sufficient scope or strength to provide meaningful
protection or any commercial advantage to us. Even if patents are issued, our licensors may fail to
maintain these patents or may determine not to pursue litigation against other companies that are
infringing these patents. Such failures or determinations could adversely affect the intellectual
property we license, and our competitive position could be harmed.



     Despite our efforts, or those of such third parties, our intellectual property rights,
particularly in existing or future patents, may be invalidated, circumvented, challenged, infringed
or required to be licensed to others. There can be no assurance that any steps we, or such third
parties, may take to protect our and their intellectual property rights and other rights to such
proprietary technologies that are central to our operations will prevent misappropriation or
infringement. One or more of our licensors may allege that we have breached our license agreement
with them and, accordingly, may seek to terminate our license. If successful, this could result in
our loss of the right to use the licensed intellectual property, which could adversely affect our
ability to operate the Project and/or to commercialize these technologies or services, as well as
harm our competitive business position and business prospects.



     With respect to proprietary know-how that is not patentable, we rely on trade secret
protection and confidentiality agreements. We require all employees, consultants and collaborators
who are involved in the development of our technology to enter into confidentiality agreements.
There can be no assurance,









 



-54-



however, that these agreements will provide adequate protection or
remedies for any breach, or that our trade secrets will not otherwise become known or independently
discovered by our competitors.



     There is also a risk that we may not be able to enter into licensing arrangements with third
parties for the hydrocracking, gasification and other technologies required for the expansion plans
as announced by us or for future Integrated OrCrudetm Upgraders that we may
desire to build.


We may be the subject of claims by third parties that we, or our licensors, have infringed their
intellectual property rights.




     A third party may claim that we or our licensors have infringed such third party’s rights or
may challenge our right in that third party’s intellectual property. In such event, we will
undertake a review to determine what, if any, actions we should take with respect to such claim.
Any claim, whether or not with merit, could be time-consuming to evaluate, result in costly
litigation, cause delays or interruptions in our operations or the Project or require us to enter
into licensing agreements that may require the payment of a license fee or royalties to the owner
of the intellectual property. Such royalty or licensing agreements, if required, may not be
available on terms that are commercially reasonable or acceptable to us, if at all. In addition, if
we were to lose an intellectual property infringement litigation, we may be required to cease
operations or pay significant monetary damages and to redesign our technology to avoid future
infringement. Our agreements with our licensors generally include exclusions of indirect or
consequential damages and limits on the recovery of direct damages. Accordingly, if an infringement
claim relates to a licensed technology, we may not be able to claim reimbursement and/or damages
from our licensors.



Risks Relating to Third Parties



The success of the Project is dependent in part upon our joint venture partner Nexen.




     Our business, and the Project in particular, is also subject to the risk that Nexen may change
its business strategies and future phases of project development and/or decide to not engage in any
future activities with us.



     We will be subject to the risk of default by Nexen in meeting its financial commitments and/or
other obligations to the Project. Such default by Nexen may adversely affect the continuation of
the Project, the construction or operations of the Project or other facets of the Project, any of
which may adversely affect us. In addition, subject to certain conditions, Nexen may sell its
interest in the joint venture and our new partner may not have the resources or experience that
Nexen has.



     The Project is being undertaken jointly by the JV Participants pursuant to the Construction,
Ownership and Joint Operation of the Project Agreement (the “COJO Agreement”). The COJO Agreement
provides for the creation of a management committee which is responsible for the supervision and
direction of the management and operation of the Project, the supervision and control of the
operators and all other matters relating to the development of the Project. If our interest in the
Project falls below 25 percent as a result of a sale of our working interest or is reduced due to
failure to maintain financial commitments, Nexen may be able to make decisions respecting the
Project without input from us, which may adversely affect us or our operations.


We are subject to extensive government regulation. We may have to expend substantial amounts for
compliance with regulations or we may become liable for failure to comply with regulations.




     The oil and gas industry in Canada, including the oil sands industry, operates under Canadian
federal, provincial and municipal legislation and regulation governing such matters as land tenure,
prices,









 



-55-



royalties, production rates, environmental protection controls, income, the exportation of
crude oil, natural gas and other products, the use of groundwater in our operations, as well as
other matters. The industry is also subject to regulation by federal, provincial and municipal
governments in such matters as
the awarding or acquisition of exploration and production rights, oil sands or other
interests, the imposition of specific drilling obligations, environmental protection controls,
control over the development and abandonment of fields and mine sites (including restrictions on
production) and possibly expropriation or cancellation of contract rights.



     Government regulations may be changed from time to time in response to economic or political
conditions. The exercise of discretion by governmental authorities under existing regulations, the
implementation of new regulations or the modification of existing regulations affecting the crude
oil and natural gas industry could reduce demand for crude oil and natural gas, increase our costs
and have a material adverse impact on us.



     Before proceeding with the Project, the JV Participants must obtain all required regulatory
approvals. To date, we believe the Project has received substantially all of the approvals
currently required. The regulatory approval process can involve stakeholder consultation,
environmental impact assessments, public hearings and appeals to tribunals and courts, among other
things. In addition, regulatory approvals may be subject to conditions including security deposit
obligations and other commitments. Failure to obtain regulatory approvals, or failure to obtain
them on a timely basis, could result in delays or restructuring of the Project and increased costs,
all of which could have a material adverse affect on us. The Project is also subject to periodic
inspections by regulatory authorities to ensure our compliance with the conditions of regulatory
approvals. Negative inspection results may lead to the imposition of fines or penalties or the
suspension or rescission of the Project’s regulatory approvals.


The Project will depend on utility infrastructure owned and operated by third parties, and the
failure by those third parties to provide services required by the Project could have a material
adverse effect on our business and results of operations.




     The Project will depend on successful operation of certain infrastructure owned and operated
by others, including, without limitation:




	 	•	 	pipelines for the transportation of feedstocks to the Long Lake Upgrader and
petroleum products to be sold from the Long Lake Upgrader;
	 
	 	•	 	pipelines for the transportation of natural gas;
	 
	 	•	 	a railway spur for the transportation of Long Lake Upgrader products and
by-products; and
	 
	 	•	 	electricity transmission systems for the provision and/or sale of electricity.





     The failure of any or all of these utilities to supply service will negatively impact the
operation of the Project which, in turn, may have a material adverse effect on our business or
results of operations.


The inability of counterparties to fulfill their obligations to us could adversely impact us.




     Our oil revenue and associated accounts receivable will be concentrated among a limited number
of counterparties. There is a risk that theses counterparties will not pay amounts owing to us on
a timely basis or at all. Derivative instruments expose us to certain risks, including the risk of
loss from fluctuating commodity prices, credit risks if a counterparty is unable to meet its
contractual obligations and the risk of margin calls from third-parties. The inability to close out
options, futures and forward









 



-56-



positions could have an adverse impact on the use of derivative
instruments to effectively hedge our position.


Our operating cash flows will be directly affected by the applicable royalty regime.




     We are currently required to pay a royalty to the Government of the Province of Alberta on our
bitumen production. The implementation of the proposed changes to the royalty regime in Alberta is
subject to certain risks and uncertainties. The significant changes to the royalty regime require
new legislation, changes to existing legislation and regulation and development of proprietary
software to support the calculation and collection of royalties. Additionally, certain proposed
changes contemplate further public and/or industry consultation. There may be modifications
introduced to the proposed royalty structure prior to the implementation thereof.


Changes in tax laws may adversely affect us, the Project and future expansion phases.




     Income tax laws or government incentive programs relating to the oil and gas industry and in
particular the oil sands sector may in the future be changed or interpreted in a manner that
adversely affects us, the Project and future expansion phases. There is also the risk that the
provincial government could impose additional emission or emission-intensity reduction
requirements, or that the federal and/or provincial governments could pass legislation which would
tax such emissions.


Our industry is highly competitive and many of our competitors have greater resources than we do.




     The Canadian and international petroleum industry is highly competitive in all aspects,
including the exploration for, and the development of, new sources of supply, the acquisition of
oil interests and the distribution and marketing of petroleum products. The Project will compete
with other producers of synthetic crude oil blends and other producers of conventional crude oil.
Some of the conventional producers have lower operating costs than we are anticipated to have, and
many of them have greater resources then we have. The petroleum industry also competes with other
industries in supplying energy, fuel and related products to consumers.



     A number of companies other than our company have announced plans to enter the oil sands
business and begin production of synthetic crude oil, or expand existing operations. Expansion of
existing operations and development of new projects could materially increase the supply of
synthetic crude oil and other competing crude oil products in the marketplace. Depending on the
levels of future demand, increased supplies could have a negative impact on prices of synthetic
crude oil and, accordingly our results of operations and cash flows.


Unforeseen title defects may result in a loss of entitlement to production and reserves.




     We have not obtained title opinions in respect of the leases that we intend to develop and,
accordingly, our ownership of the leases could be subject to prior unregistered agreements or
interests or undetected claims or interests. If such were the case, our entitlement to the
production and reserves associated with such leases could be jeopardized, which could have a
material adverse effect on our financial condition, results of operations and our ability to
execute our business plan in a timely manner or at all.









 



-57-

The land on which the Project is located is subject to Aboriginal claims which, if determined
adversely to us, could have a significant adverse effect on the Project and on us.




     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, the
Province of
Alberta, certain governmental entities and the regional municipality of Wood Buffalo (which
includes the City of Fort McMurray, Alberta) claiming, among other things, 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 a
significant adverse effect on the Project and on us.



Risks Relating to Financing and Our Indebtedness



If we are unable to obtain sufficient funding, we may lose our ownership interests in the Project.




     Significant amounts of financing are required to develop the Project. Our current estimated
total cost of the Project is between $5.8 billion and $6.1 billion, or between $2.9 billion and
$3.05 billion net to us. If our current cost estimates were to increase, it is not certain that we
would be able to finance our portion of the increased capital cost. Future capital requirements are
subject to capital market risks, primarily the availability and cost of capital. In the future,
there can be no assurance that sufficient capital will be available to us on acceptable terms, or
on a timely basis or at all.



     Nexen has a first priority fixed lien, charge and security interest in our ownership interest
in the Project to secure payment and performance of our obligations. Should we fail to meet all or
some part of our obligations to the Project, Nexen has the right, in certain circumstances, to
acquire some or all of our interest in the Project (excluding our rights to the
OrCrudetm Process technology and certain royalties payable to us) at 80 percent
of cost.



     We have announced a multi-stage expansion plan. Expenditures are necessary and we will need to
secure additional financing to proceed according to the multi-stage expansion plans. The inability
to complete these financings on a timely basis or at all would have a material adverse effect on
our expansion plans potentially causing the delay or cancellation of future phases of the Project.
Nexen has the right, in certain circumstances, to acquire some or all of our interest in the
expansion phases (excluding our rights to the OrCrudetm Process technology and
certain royalties payable to us). See “Material Agreements Related to the Joint Venture — The New
COJO Agreements”.


We may not be able to draw down on the Revolving Credit Facility which may have a material adverse
effect on our business.




     We must satisfy a number of conditions precedent prior to each borrowing under the Revolving
Credit Facility, including that we have sufficient funding to complete the Project. There can be no
assurance that we will be able to satisfy all of the conditions precedent, in which case we will
not be able to access the Revolving Credit Facility to satisfy our capital commitments in respect
of the Project.


We borrow funds in U.S. dollars.




     A significant portion of our debt is denominated in U.S. dollars. We have hedged a portion of
this exposure through the completion of certain cross currency swaps as noted in “Description of
Debt Capital”. Fluctuations in exchange rates may significantly increase the amount of debt
recorded on our financial statements and negatively impact our reported earnings.









 



-58-


MATERIAL CONTRACTS




     Set forth below are agreements that may be considered material to OPTI:




	 	1.	 	MOU between OPTI and Nexen as more particularly described under the heading
“Material Agreements Related to the Joint Venture”;
	 
	 	2.	 	the COJO Agreement between OPTI and Nexen as more particularly described under
the heading “Material Agreements Related to the Joint Venture”; and
	 
	 	3.	 	the Technology Agreement among OPTI and Nexen as more particularly described
under the heading “Material Agreements Related to the Joint Venture”.





LEGAL PROCEEDINGS AND REGULATORY ACTIONS




     There are no material legal proceedings and regulatory actions against us.



TRANSFER AGENTS AND REGISTRAR




     Valiant Trust Company at its principal office in Calgary, Alberta is the transfer agent and
registrar of our Common Shares and BNY Trust Company of Canada at its principal office in Toronto,
Ontario is the transfer co-agent and registrar of our Common Shares.



INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS




     Our directors, officers and principal shareholders (and their known associates and affiliates)
have had no material interest, direct or indirect, in any transaction within the three most
recently completed financial years or during the current financial year that has materially
affected or will materially affect us, other than as set forth in this AIF.



INTERESTS OF EXPERTS




     PricewaterhouseCoopers LLP are our auditors and are independent in accordance with the rules
of professional conduct of the Canadian Institute of Chartered Accountants. McDaniel, our
independent petroleum consultants, prepared the McDaniel Report, referenced herein. As at the date
of the McDaniel report, the principals of McDaniel, as a group, owned beneficially, directly or
indirectly, less than one percent of our outstanding Common Shares. McDaniel did not receive nor
will they receive any interest, direct or indirect, in any securities or other property of us or
our affiliates in connection with the preparation of its report.









 



-59-


ADDITIONAL INFORMATION




     Additional information relating to us may be found on SEDAR at www.sedar.com.



     Additional information including directors’ and officers’ remuneration and indebtedness,
principal holders of our securities and securities authorized for issuance under equity
compensation plans is contained in our information circular for our most recent annual meeting of
shareholders that involved the election of directors. Additional financial information is provided
in our comparative financial statements and our management’s discussion and analysis for our most
recently completed financial year. Additional copies of this AIF may be obtained from us, please
contact:


Alison Trollope, Investor Relations

OPTI Canada Inc.

2100, 555 — 4th Avenue S.W.

Calgary, Alberta

T2P 3E7










 



-60-




GLOSSARY




     In this AIF, the following terms shall have the meanings set forth below, unless otherwise
indicated:


“AE” means Alberta Environment;



“AIF” means this annual information form dated January 22, 2008;



“API” means degrees API, a measure of hydrocarbon density;



“Area of Mutual Interest” means the area of mutual interest with Nexen as described in “Material
Agreements Related to the Joint Venture”;



“bbl” means barrels, which are equal to 0.15899 cubic metres;



“bbl/d” means barrels per day;



“Cogeneration Facility” means the cogeneration facility to be constructed in connection with the
Long Lake SAGD Operation, as further described under the heading entitled “The Project and Futures
Phases”;



“COJO Agreement” means the Construction, Ownership and Joint Operation of the Long Lake Project
Agreement between the JV Participants;



“Cottonwood Leases” means our lands in the Cottonwood area;



“EUB” means the Alberta Energy and Utilities Board;



“in-situ” means, when referring to oil sands, a process for recovering bitumen from oil sands by
means other than surface mining;



“Integrated OrCrudeTM Upgrader” means an upgrader which uses the OrCrudeTM Process combined with
additional third party technology to upgrade bitumen and heavy oil to produce PSCTM and
syngas, as further described under the heading entitled “The OrCrudeTM Process —  Integrated
OrCrudeTM Upgrader”;



“Leismer Leases” means our lands in the Leismer area;



“Long Lake Leases” includes the Project land and our interest in other lands in the Long Lake area;



“Long Lake Project” or the “Project” means Phase 1 of the Long Lake SAGD Operation, Phase 1 of the
Long Lake Upgrader and the related lands;



“Long Lake SAGD Operation” or “SAGD Operation” means the facilities to be constructed for the
purpose of producing bitumen from the Project lands using the SAGD process, together with the SAGD
Pilot and the Cogeneration Facility, all as further described under the heading entitled “The Long
Lake Project — Long Lake SAGD Operation”;



“Long Lake Upgrader” or “Upgrader” means the Integrated OrCrudeTM Upgrader to be constructed for the
purpose of upgrading bitumen produced from the Project lands, as further described under the
heading entitled “The Long Lake Project — Long Lake Upgrader”;










 



-61-



“Management Committee” means the committee comprised of representatives of each of OPTI and Nexen
who pursuant to the MOU and the New COJO Agreements will exercise supervision and direction of the
management and operation of the Project and certain future phase development;



“McDaniel” means McDaniel & Associates Consultants Ltd., an independent petroleum consulting firm;



“MMbbl” means millions of barrels;



“mmbtu” means millions of British thermal units;



“OrCrudeTM Product” means the partially-upgraded crude oil produced in the OrCrudeTM Process;



“OrCrudeTM Process” means the proprietary methods and means for upgrading bitumen and heavy oil
based on the numerous U.S. and Canadian patents and patent applications;



“Phase 1” means the Long Lake Project, in a 50/50 joint venture with Nexen. This phase consists of
72,000 barrels per day (bbl/d) of SAGD (steam assisted gravity drainage) bitumen production
integrated with an upgrading facility expected to produce 58,500 bbl/d of products, primarily 39°
API premium sweet crude;



“PSCTM” means, generically, the premium, sweet, synthetic crude oil produced in the
Integrated OrCrudeTM Upgrader, which is produced by hydrocracking OrCrudeTM Product;



“SAGD” means steam assisted gravity drainage, an in-situ process used to recover bitumen from oil
sands located too deep to be profitably mined;



“SAGD Pilot” means the SAGD pilot project which is being used to evaluate well design, confirm
reservoir performance and obtain site specific operating experience in respect of the Long Lake
Project;



“syngas” means synthesis fuel gas produced through gasification; and



“Technology Agreement” means the Technology Licence for Upgrading Technology Agreement between the
JV Participants.















 





APPENDIX A




RESERVES DATA AND OTHER OIL AND GAS INFORMATION




Reserves and Future Net Revenue




     The following tables of reserves and net present values of future net revenue for OPTI have
been prepared on the assumption that total proved plus probable plus possible reserves are 940,557
mbbl of raw bitumen reserves and do not take into account any additional bitumen resources. It
should not be assumed that the present values of future net revenue shown below is representative
of the fair market value of the reserves.



Oil and Gas Reserves

Based on Forecast Prices and Costs(9)




	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Synthetic Crude Oil	 	 	 	 
	 	 	(PSCTM)	 	Bitumen	 	Butane
	 	 	Gross(1)	 	Net(1)	 	Gross(1)	 	Net(1)	 	Gross(1)	 	Net(1)
	 	 	(mbbl)	 	(mbbl)	 	(mbbl)	 	(mbbl)	 	(mbbl)	 	(mbbl)
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Proved Developed Producing(2)(5)(6)
	 	 	—	 	 	 	—	 	 	 	64,856	 	 	 	64,207	 	 	 	—	 	 	 	—	 
	Proved Developed Non-Producing(2)(7)
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Proved Undeveloped(2)(8)
	 	 	201,709	 	 	 	192,044	 	 	 	(48,801	)	 	 	(48,922	)	 	 	2,769	 	 	 	2,636	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Total Proved
	 	 	201,709	 	 	 	192,044	 	 	 	16,055	 	 	 	15,285	 	 	 	2,769	 	 	 	2,636	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Probable Additional(3)
	 	 	417,864	 	 	 	383,668	 	 	 	13,417	 	 	 	12,105	 	 	 	5,736	 	 	 	5,266	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Total Proved Plus Probable
	 	 	619,573	 	 	 	575,712	 	 	 	29,471	 	 	 	27,390	 	 	 	8,504	 	 	 	7,902	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Possible Additional(4)
	 	 	110,976	 	 	 	91,278	 	 	 	(506	)	 	 	(945	)	 	 	1,523	 	 	 	1,253	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Total Proved Plus Probable Plus Possible
	 	 	730,549	 	 	 	666,989	 	 	 	28,966	 	 	 	26,445	 	 	 	10,028	 	 	 	9,155	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 






Net Present Values of Future Net Revenue

Based on Forecast Prices and Costs(9)




	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Before Deducting Income Taxes Discounted At	 	After Deducting Income Taxes 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
(2)(6)
	 	 	853	 	 	 	673	 	 	 	543	 	 	 	446	 	 	 	372	 	 	 	853	 	 	 	673	 	 	 	543	 	 	 	446	 	 	 	372	 
	Proved Non-Producing
	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 
	Proved
Undeveloped
(2)(8)
	 	 	9,361	 	 	 	5,231	 	 	 	3,247	 	 	 	2,194	 	 	 	1,583	 	 	 	7,521	 	 	 	4,323	 	 	 	2,763	 	 	 	1,919	 	 	 	1,418	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Total Proved
	 	 	10,214	 	 	 	5,905	 	 	 	3,789	 	 	 	2,639	 	 	 	1,955	 	 	 	8,374	 	 	 	4,996	 	 	 	3,305	 	 	 	2,364	 	 	 	1,790	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Probable
Additional
(3)
	 	 	23,688	 	 	 	6,907	 	 	 	2,115	 	 	 	412	 	 	 	(303	)	 	 	17,675	 	 	 	5,016	 	 	 	1,372	 	 	 	66	 	 	 	(486	)
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Total Proved Plus
Probable
	 	 	33,902	 	 	 	12,812	 	 	 	5,904	 	 	 	3,051	 	 	 	1,651	 	 	 	26,049	 	 	 	10,012	 	 	 	4,677	 	 	 	2,430	 	 	 	1,304	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Possible
Additional
(4)
	 	 	10,907	 	 	 	2,673	 	 	 	1,113	 	 	 	696	 	 	 	535	 	 	 	8,159	 	 	 	2,041	 	 	 	892	 	 	 	588	 	 	 	471	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Total Proved Plus
Probable Plus
Possible
	 	 	44,809	 	 	 	15,485	 	 	 	7,017	 	 	 	3,747	 	 	 	2,186	 	 	 	34,208	 	 	 	12,052	 	 	 	5,570	 	 	 	3,019	 	 	 	1,775	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 














 





-2-



     The following table presents the estimated total future net revenue of OPTI, undiscounted,
based on forecast prices and costs, as estimated in the McDaniel Report. It should not be assumed
that the estimated total future net revenue shown below is representative of the fair market value
of the reserves.



Total Future Net Revenue (Undiscounted)

Based on Forecast Prices and Costs(9)




	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Future Net	 	 	 	 	 	Future Net
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Revenue	 	 	 	 	 	Revenue
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Before	 	 	 	 	 	After
	 	 	 	 	 	 	 	 	 	 	Operating	 	Development	 	Abandonment	 	Income	 	Income	 	Income
	 	 	Revenue	 	Royalties	 	Costs	 	Costs	 	Costs	 	Taxes	 	Taxes	 	Taxes
	 	 	(MM$)	 	(MM$)	 	(MM$)	 	(MM$)	 	(MM$)	 	(MM$)	 	(MM$)	 	(MM$)
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Total Proved(2)
	 	 	18,246	 	 	 	552	 	 	 	5,355	 	 	 	2,052	 	 	 	73	 	 	 	10,214	 	 	 	1,840	 	 	 	8,374	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Total Proved Plus
Probable(2)(3)
	 	 	63,607	 	 	 	2,799	 	 	 	16,905	 	 	 	9,695	 	 	 	306	 	 	 	33,902	 	 	 	7,353	 	 	 	26,049	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Total Proved Plus
Probable Plus

Possible
(2)(3)(4)
	 	 	78,792	 	 	 	4,171	 	 	 	19,294	 	 	 	10,146	 	 	 	373	 	 	 	44,809	 	 	 	10,601	 	 	 	34,208	 






     The following table presents the estimated total future net revenue by production group, of
OPTI, based on forecast prices and costs, as estimated in the McDaniel Report. It should not be
assumed that the estimated total future net revenue by production group shown below is
representative of the fair market value of the reserves.



Future Net Revenue By Production Group

Based Upon Forecast Prices and Costs(9)




	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	Future Net Revenue Before Income Taxes
	 	 	Production Group	 	(Discounted at 10%/Year)
	 	 	 	 	 	 	Total	 	Unit Basis
	 	 	 	 	 	 	(MM$)	 	($/bbl of raw
	 	 	 	 	 	 	 	 	 	 	bitumen)
	Total Proved(2)
	 	Bitumen, synthetic crude oil, and butane	 	 	3,789	 	 	 	14.15	 
	Total Proved Plus Probable(2)(3)
	 	Bitumen, synthetic crude oil, and butane	 	 	5,904	 	 	 	7.36	 
	Total
Proved Plus Probable Plus
Possible(2)(3)(4)
	 	Bitumen, synthetic crude oil, and butane	 	 	7,017	 	 	 	7.46	 






Reserves Reconciliation




     The following table sets forth the changes between the reserve volume estimates made as at
December 31, 2007 and the corresponding estimates as at December 31, 2006, based on forecast
prices, net of royalties.



	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Proved	 	Probable	 	Proved and Probable
	 	 	Bitumen	 	Synthetic Oil	 	Butane	 	Total	 	Bitumen	 	Synthetic Oil	 	Butane	 	Total	 	Bitumen	 	Synthetic Oil	 	Butane	 	Total
	 	 	mbbl	 	mbbl	 	mbbl	 	mbbl	 	mbbl	 	mbbl	 	mbbl	 	mbbl	 	mbbl	 	mbbl	 	mbbl	 	mbbl
	Dec 31, 2006
	 	 	13,544	 	 	 	184,200	 	 	 	2,528	 	 	 	200,272	 	 	 	5,280	 	 	 	166,051	 	 	 	2,279	 	 	 	173,610	 	 	 	18,824	 	 	 	350,252	 	 	 	4,808	 	 	 	373,884	 
	Extensions
	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	12,627	 	 	 	238,979	 	 	 	3,280	 	 	 	254,886	 	 	 	12,627	 	 	 	238,979	 	 	 	3,280	 	 	 	254,886	 
	Improved Recovery
	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 
	Technical Revisions
	 	 	2,511	 	 	 	17,509	 	 	 	241	 	 	 	20,261	 	 	 	(4,490	)	 	 	12,834	 	 	 	177	 	 	 	8,521	 	 	 	(1,979	)	 	 	30,343	 	 	 	418	 	 	 	28,782	 
	Discoveries
	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 
	Acquisitions
	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 
	Dispositions
	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 
	Economic Factors
	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 
	Production
(Estimate)
	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	Dec 31, 2007
	 	 	16,055	 	 	 	201,709	 	 	 	2,769	 	 	 	220,533	 	 	 	13,417	 	 	 	417,864	 	 	 	5,736	 	 	 	437,017	 	 	 	29,471	 	 	 	619,573	 	 	 	8,504	 	 	 	657,548	 
	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 














 





-3-


Undeveloped Reserves




     The following table sets forth the volumes of our share of gross proved undeveloped reserves
that were attributed for each of our product types based on forecast prices:



	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Synthetic Crude Oil (PSCTM)	 	Bitumen	 	Butane
	 	 	(mbbl)	 	(mbbl)	 	(mbbl)
	 
	 	 	 	 	 	 	 	 	 	 	 	 
	2005
	 	 	175,060	 	 	 	19,869	 	 	 	2,403	 
	2006
	 	 	143,147	 	 	 	2,385	 	 	 	1,965	 
	2007
	 	 	201,709	 	 	 	(48,801	)	 	 	2,769	 








 




			
	Note:	 	The Proved Developed Producing (“PDP”) category acknowledges the producing status of the 81
well-pairs in operation as of December 31, 2007. While these 81 well-pairs will provide raw
bitumen feed to the Long Lake Upgrader, the financial benefits of the Upgrader have been
classified as Proved Undeveloped as of December 31, 2007, due to the amount of capital
remaining to be spent in 2008. Therefore, the PDP volumes are booked as bitumen sales, not
synthetic and butane sales.
	 
	 	 	The Proved Undeveloped category acknowledges that much of this production will be upgraded and
sold as synthetic crude oil and butane. For this reason, in the Proved Undeveloped category,
the sales volumes resulting from the production of the existing 81 well-pairs are
re-classified from bitumen sales to synthetic and butane sales volumes. Therefore, the bitumen
sales volume is negative.





     The following table sets forth the volumes of our share of gross probable undeveloped reserves
that were attributed for each of our product types based on forecast prices.



	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Synthetic Crude Oil (PSCTM)	 	Bitumen	 	Butane
	 	 	(mbbl)	 	(mbbl)	 	(mbbl)
	 
	 	 	 	 	 	 	 	 	 	 	 	 
	2005
	 	 	172,591	 	 	 	1,726	 	 	 	2,369	 
	2006
	 	 	166,051	 	 	 	5,280	 	 	 	2,279	 
	2007
	 	 	417,864	 	 	 	13,417	 	 	 	5,736	 






     There
are proved and probable undeveloped resources associated with Phase 1 of the Long Lake
Project. We plan to develop these reserves to maintain sufficient bitumen feed to the Upgrader.
This development is expected to occur over the life of the Project.



     There are probable undeveloped reserves associated with Phase 2. We plan to be in a position
to sanction Phase 2 in late 2008. Subsequent to Phase 2 sanctioning, which has not occurred,
development of these reserves is expected to occur over the life of this project.



     Future Development Costs



     We anticipate that the future development costs will be financed through working capital,
existing debt facilities and internally generated cash flow.



     In the event such sources of funds are insufficient to fund the future development costs, a
combination of debt or equity financing may be required. We anticipate that the costs of such
financing would be a small percentage of the future development costs and the cost of such
financing is implicit in the discount rate used to calculate the net present values. In the event
these financing costs were incurred,











 





-4-



we would expect no change in reserves or future net revenue, and does not expect it to make
the development of the property uneconomic.



Future Development Costs

Based on Forecast Prices and Costs




	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	Total Proved Plus
	 	 	Total Proved(2)	 	Probable(2)(3)
	 	 	(MM$)	 	(MM$)
	2008
	 	 	277	 	 	 	550	 
	2009
	 	 	108	 	 	 	1,134	 
	2010
	 	 	74	 	 	 	1,041	 
	2011
	 	 	13	 	 	 	653	 
	2012
	 	 	18	 	 	 	98	 
	Total for all years undiscounted
	 	 	2,052	 	 	 	9,695	 
	Total for all years discounted at 10%/year
	 	 	925	 	 	 	3,988	 














 





-5-




 




			
	Notes to the preceding tables:
	 
	(1)	 	“Gross Reserves” are the reserves held by us before Crown royalties. “Net Reserves” are the
reserves held by us after Crown royalties.
	 
	(2)	 	“Proved” reserves are those reserves that can be estimated with a high degree of certainty to
be recoverable. It is likely that the actual remaining quantities recovered will exceed the
estimated proved reserves.
	 
	(3)	 	“Probable” reserves are those additional reserves that are less certain to be recovered than
proved reserves. It is equally likely that the actual remaining quantities recovered will be
greater or less than the sum of the estimated proved plus probable reserves.
	 
	(4)	 	“Possible” reserves are those additional reserves that are less certain to be recovered than
probable reserves. There is a 10% probability that the actual remaining quantities recovered
will exceed the sum of the estimated proved plus probable plus possible reserves.
	 
	(5)	 	“Developed” reserves are those reserves that are expected to be recovered from existing wells
and installed facilities or, if facilities have not been installed, that would involve a low
expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on
production.
	 
	(6)	 	“Developed Producing” reserves are those reserves that are expected to be recovered from
completion intervals open at the time of the estimate. These reserves may be currently
producing or, if shut-in, they must have previously been on production, and the date of
resumption of production must be known with reasonable certainty.
	 
	(7)	 	“Developed Non-Producing” reserves are those reserves that either have not been on
production, or have previously been on production, but are shut in, and the date of resumption
of production is unknown.
	 
	(8)	 	“Undeveloped” reserves are those reserves expected to be recovered from know accumulations
where a significant expenditure (for example, when compared to the cost of drilling a well) is
required to render them capable of production. They must fully meet the requirements of the
reserves classification (proved, probable, possible) to which they are assigned.
	 
	(9)	 	The pricing assumptions used in the McDaniel Report with respect to net values of future net
revenue (forecast) as well as the inflation rates used for operating and capital costs are set
forth below. McDaniel is an independent qualified reserves evaluator appointed pursuant to NI
51-101.





	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Inflation	 	Exchange
	 	 	Oil	 	Synthetic Oil	 	Condensate	 	Butane	 	Natural Gas	 	Bitumen	 	Rate	 	Rate
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	PSC at	 	 	 	 	 	 	 	 	 	 	 	 	 	Field	 	Field	 	 	 	 
	 	 	 	 	 	 	Edmonton	 	WCS	 	Edmonton	 	Long Lake	 	Edmonton	 	Field	 	Alberta	 	Bitumen	 	Bitumen	 	 	 	 
	 	 	WTI Crude	 	Light Oil	 	Hardisity	 	Synthetic	 	Synthetic	 	Condensate	 	Butane	 	Spot Gas	 	Oil Price	 	Oil Price	 	 	 	 
	 	 	Oil Price	 	Price	 	Oil Price	 	Oil Price	 	Oil Price	 	Price	 	Price	 	Price	 	Pre-Upgr	 	Post-Upgr	 	 	 	 
	 	 	$US/bbl	 	$Cdn/bbl	 	$Cdn/bbl	 	$Cdn/bbl	 	$Cdn/bbl	 	$Cdn/bbl	 	$Cdn/bbl	 	$Cdn/mmbtu	 	$Cdn/bbl	 	$Cdn/bbl	 	%/ year	 	$US/$Cdn
	Forecast
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	2008
	 	 	90.00	 	 	 	89.00	 	 	 	60.30	 	 	 	90.25	 	 	 	89.69	 	 	 	91.00	 	 	 	58.66	 	 	 	6.45	 	 	 	34.74	 	 	 	38.76	 	 	 	2.0	 	 	 	1.000	 
	2009
	 	 	86.70	 	 	 	85.70	 	 	 	58.09	 	 	 	86.70	 	 	 	86.13	 	 	 	87.70	 	 	 	56.29	 	 	 	7.00	 	 	 	32.45	 	 	 	37.26	 	 	 	2.0	 	 	 	1.000	 
	2010
	 	 	83.20	 	 	 	82.20	 	 	 	55.74	 	 	 	82.95	 	 	 	82.37	 	 	 	84.30	 	 	 	53.83	 	 	 	7.00	 	 	 	31.17	 	 	 	35.75	 	 	 	2.0	 	 	 	1.000	 
	2011
	 	 	79.60	 	 	 	78.50	 	 	 	53.33	 	 	 	79.00	 	 	 	78.40	 	 	 	80.60	 	 	 	51.16	 	 	 	7.00	 	 	 	30.08	 	 	 	34.40	 	 	 	2.0	 	 	 	1.000	 
	2012
	 	 	78.50	 	 	 	77.40	 	 	 	52.60	 	 	 	77.40	 	 	 	76.79	 	 	 	79.60	 	 	 	50.39	 	 	 	7.10	 	 	 	30.04	 	 	 	34.22	 	 	 	2.0	 	 	 	1.000	 
	2013
	 	 	77.30	 	 	 	76.20	 	 	 	51.79	 	 	 	75.70	 	 	 	75.08	 	 	 	78.40	 	 	 	49.42	 	 	 	7.30	 	 	 	29.90	 	 	 	33.93	 	 	 	2.0	 	 	 	1.000	 
	2014
	 	 	78.80	 	 	 	77.70	 	 	 	52.80	 	 	 	76.70	 	 	 	76.06	 	 	 	80.00	 	 	 	50.45	 	 	 	7.55	 	 	 	30.86	 	 	 	34.89	 	 	 	2.0	 	 	 	1.000	 
	2015
	 	 	80.40	 	 	 	79.30	 	 	 	53.87	 	 	 	77.80	 	 	 	77.16	 	 	 	81.60	 	 	 	51.47	 	 	 	7.80	 	 	 	31.92	 	 	 	35.95	 	 	 	2.0	 	 	 	1.000	 
	2016
	 	 	82.00	 	 	 	80.80	 	 	 	54.94	 	 	 	79.27	 	 	 	78.61	 	 	 	83.10	 	 	 	52.40	 	 	 	8.00	 	 	 	32.61	 	 	 	36.71	 	 	 	2.0	 	 	 	1.000	 
	2017
	 	 	83.70	 	 	 	82.50	 	 	 	56.08	 	 	 	80.94	 	 	 	80.27	 	 	 	84.90	 	 	 	53.52	 	 	 	8.25	 	 	 	33.30	 	 	 	37.48	 	 	 	2.0	 	 	 	1.000	 
	2018
	 	 	85.30	 	 	 	84.10	 	 	 	57.15	 	 	 	82.51	 	 	 	81.82	 	 	 	86.50	 	 	 	54.55	 	 	 	8.45	 	 	 	33.88	 	 	 	38.16	 	 	 	2.0	 	 	 	1.000	 
	2019
	 	 	87.00	 	 	 	85.80	 	 	 	58.29	 	 	 	84.18	 	 	 	83.48	 	 	 	88.30	 	 	 	55.67	 	 	 	8.70	 	 	 	34.57	 	 	 	38.93	 	 	 	2.0	 	 	 	1.000	 
	2020
	 	 	88.80	 	 	 	87.50	 	 	 	59.50	 	 	 	85.84	 	 	 	85.13	 	 	 	90.00	 	 	 	56.79	 	 	 	8.95	 	 	 	35.46	 	 	 	39.89	 	 	 	2.0	 	 	 	1.000	 
	2021
	 	 	90.60	 	 	 	89.30	 	 	 	60.70	 	 	 	87.61	 	 	 	86.89	 	 	 	91.90	 	 	 	57.90	 	 	 	9.20	 	 	 	36.05	 	 	 	40.58	 	 	 	2.0	 	 	 	1.000	 
	2022
	 	 	92.40	 	 	 	91.10	 	 	 	61.91	 	 	 	89.38	 	 	 	88.64	 	 	 	93.70	 	 	 	59.12	 	 	 	9.40	 	 	 	36.83	 	 	 	41.45	 	 	 	2.0	 	 	 	1.000	 
	2023
	 	 	94.25	 	 	 	92.92	 	 	 	63.15	 	 	 	91.16	 	 	 	90.41	 	 	 	95.57	 	 	 	60.30	 	 	 	9.59	 	 	 	37.57	 	 	 	42.28	 	 	 	2.0	 	 	 	1.000	 
	2024
	 	 	96.13	 	 	 	94.78	 	 	 	64.41	 	 	 	92.99	 	 	 	92.22	 	 	 	97.49	 	 	 	61.51	 	 	 	9.78	 	 	 	38.32	 	 	 	43.13	 	 	 	2.0	 	 	 	1.000	 
	2025
	 	 	98.06	 	 	 	96.68	 	 	 	65.70	 	 	 	94.85	 	 	 	94.06	 	 	 	99.44	 	 	 	62.74	 	 	 	9.98	 	 	 	39.09	 	 	 	43.99	 	 	 	2.0	 	 	 	1.000	 
	2026
	 	 	100.02	 	 	 	98.61	 	 	 	67.01	 	 	 	96.74	 	 	 	95.94	 	 	 	101.42	 	 	 	63.99	 	 	 	10.17	 	 	 	39.87	 	 	 	44.87	 	 	 	2.0	 	 	 	1.000	 
	2027
	 	 	102.02	 	 	 	100.58	 	 	 	68.35	 	 	 	98.68	 	 	 	97.86	 	 	 	103.45	 	 	 	65.27	 	 	 	10.38	 	 	 	40.67	 	 	 	45.77	 	 	 	2.0	 	 	 	1.000	 
	2028
	 	 	104.06	 	 	 	102.59	 	 	 	69.72	 	 	 	100.65	 	 	 	99.82	 	 	 	105.52	 	 	 	66.58	 	 	 	10.59	 	 	 	41.48	 	 	 	46.68	 	 	 	2.0	 	 	 	1.000	 
	2029
	 	 	106.14	 	 	 	104.65	 	 	 	71.11	 	 	 	102.67	 	 	 	101.82	 	 	 	107.63	 	 	 	67.91	 	 	 	10.80	 	 	 	42.31	 	 	 	47.61	 	 	 	2.0	 	 	 	1.000	 
	2030
	 	 	108.26	 	 	 	106.74	 	 	 	72.54	 	 	 	104.72	 	 	 	103.85	 	 	 	109.78	 	 	 	69.27	 	 	 	11.01	 	 	 	43.16	 	 	 	48.57	 	 	 	2.0	 	 	 	1.000	 
	2031
	 	 	110.43	 	 	 	108.87	 	 	 	73.99	 	 	 	106.81	 	 	 	105.93	 	 	 	111.98	 	 	 	70.65	 	 	 	11.23	 	 	 	44.02	 	 	 	49.54	 	 	 	2.0	 	 	 	1.000	 
	2032
	 	 	112.64	 	 	 	111.05	 	 	 	75.47	 	 	 	108.95	 	 	 	108.05	 	 	 	114.22	 	 	 	72.07	 	 	 	11.46	 	 	 	44.90	 	 	 	50.53	 	 	 	2.0	 	 	 	1.000	 
	Thereafter
	 	+2.0%/yr	 	+2.0%/yr	 	+2.0%/yr	 	+2.0%/yr	 	+2.0%/yr	 	+2.0%/yr	 	+2.0%/yr	 	+2.0%/yr	 	+2.0%/yr	 	+2.0%/yr	 	 	2.0	 	 	 	1.000	 







Pricing Assumptions:




     WTI, Edmonton Light, Edmonton Synthetic, WCS Hardisty, Edmonton Condensate, Edmonton Butane
and Alberta Spot Gas Price forecasts were based on the McDaniel January 1, 2008 price forecast.
PSC pricing is based on a $0.70/bbl premium to Edmonton synthetic. Transportation costs for
bitumen, PSC and Butane were supplied by the JV Participants.




 











 





-6-




Oil Wells




     As at December 31, 2007, we had an interest in 81 gross (40.5 net) SAGD well pairs. These
well pairs are contained within the SAGD Pilot and are comprised of 3 gross (1.5 net) producing oil
wells and 3 gross (1.5 net) injection wells, the remainder are contained in the Long Lake SAGD
operation and are comprised of 78 gross (39 net) oil wells and 78 gross (39 net) injection wells.



Properties with No Attributed Reserves




     The Long Lake Leases comprise 98 sections. Proved, Probable and Possible reserves have been
assigned on 39 sections of these lands and 59 sections have no reserves assigned. Resources have
been assigned to some of these 59 sections. We have a 50 percent working interest in all of these
lands.



     We have a 50 percent working interest in an additional 307 sections of land, also in the
Athabasca region. These lands, contained primarily within the Leismer and Cottonwood Leases, have
had no reserves assigned to them.



     There are no work commitments associated with any of these lands.



Abandonment and Reclamation Costs




     We have abandonment and reclamation liabilities relating primarily to SAGD Pilot facilities
and wells, and facilities for the Upgrader and SAGD operation. The future commercial development
will result in additional drilling and the construction of upgrading and resource facilities.



     We estimate the abandonment liability, net of salvage, for these assets with consideration
given to the expected cost to abandon and reclaim wells, facilities and surface area. These
estimates are based on prevailing industry conditions, regulatory requirements and past experience.
Estimates are required for the amount, timing and nature of the abandonment in order to determine
the present value of the liability. Financial estimates such as inflation and interest rates also
impact the calculation of the present value of the abandonment liability.



     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.



     Our share of the present value of abandonment and reclamation costs that require recognition
in the financial statements at December 31, 2007 is $7 million. The total undiscounted future
amount of abandonment liabilities expected to be incurred is $149 million based on measurement
criteria under Canadian GAAP. These liabilities relate to facilities and wells completed or under
construction at the end of 2007. At December 31, 2007, there are 150 net wells for which
abandonment liabilities have been recognized. These net wells include the SAGD Pilot wells, the
commercial SAGD wells and certain observation and water sources wells. In addition, we have
abandonment liabilities in relation to SAGD and Upgrader facilities currently under construction.
The undiscounted amount used in the constant dollar, proved plus probable plus case of the McDaniel
report is $102 million net to us.



     We incurred negligible abandonment costs in 2007 and expect to incur none in the next two
years.









 



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Tax Horizon




     We did not pay any current income taxes in our fiscal year ended December 31, 2007.
Considering the capital costs associated with Phase 1 only and pricing and cost estimates developed
by us and our existing tax pools, we do not anticipate paying income taxes until approximately
2014, based on the Proved plus Probable case in the McDaniel Report. This estimate will be impacted
by, among other factors, the final construction cost of the Project, commodity prices, foreign
exchange rates, operating costs, interest rates, expansions of the Project and OPTI’s other
business activities. Changes in these factors from estimates used by us could result in us paying
income taxes earlier or later than expected.



Costs Incurred




     The following table sets forth costs incurred by us for Oil and Gas activities for the year
ended December 31, 2007:



	 	 	 	 	 	 	 	 	 	 	 	 	 
	($ millions) Property Acquisition Costs	 	 	 	 
	Proved Properties	 	Unproved Properties	 	Exploration Costs	 	Development Costs
	$nil
	 	$	5	 	 	$	55	 	 	$	309	 








 




			
	Notes:
	 
	(1)	 	All of these costs were capitalized by OPTI.
	 
	(2)	 	Development Costs do not include capital associated with the Upgrader. In the year ended
December 31, 2007, costs incurred by us in relation to the Upgrader were $583 million.





Exploration and Development Activities




     During 2007, no SAGD horizontal wells were drilled.



Production Estimates




     We estimate, based on the proved plus probable case, that we will produce on average
approximately 26,000 bbl/d (13,000 bbl/d net to OPTI) of raw bitumen in 2008. The start-up of the
Upgrader and commencement of synthetic crude oil and butane sales is planned for mid-2008.









 



 


APPENDIX B




FORM 51-101 F2

REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR





	 	 	To the board of directors of OPTI Canada Inc. (the “Corporation”):
	 
	1.	 	We have evaluated the Corporation’s reserves data as at December 31, 2007. The reserves data
are estimates of proved reserves and probable reserves and related future net revenue as at
December 31, 2007, estimated using forecast prices and costs.
	 
	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.
	 
	3.	 	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).
	 
	4.	 	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.
	 
	5.	 	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, 2007, and identifies the
respective portions thereof that we have evaluated and reported on to the Corporation’s board
of directors:





	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Location of	 	Net Present Value of Future Net Revenue
	 	 	Reserves (Country	 	(before income taxes, 10 percent discount rate)
	Preparation Date of	 	or Foreign	 	($MM)
	Evaluation Report	 	Geographic Area)	 	Audited	 	Evaluated	 	Reviewed	 	Total
	January 8, 2008
	 	Canada	 	 	—	 	 	 	5,904	 	 	 	—	 	 	 	5,904	 







	6.	 	In our opinion, the reserves data evaluated by us have, in all material respects, been
determined and are in accordance with the COGE Handbook. We express no opinion on the
reserves data that we have reviewed but did not audit or evaluate.






	7.	 	We have no responsibility to update our reports referred to in paragraph 5 for events and
circumstances occurring after their respective preparation dates.






	8.	 	Because the reserves data are based on judgements regarding future events, actual results
will vary and the variations may be material. However, any variations should be consistent
with the fact that reserves are categorized according to the probability of their recovery.










 



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	 	 	Executed as to our report referred to above:
	 
	 	 	McDaniel & Associates Consultants Ltd., Calgary, Alberta, Canada                    Dated January 8, 2008





(signed)
“Greg M. Heath”









 



 


APPENDIX C




FORM 51-101 F3

REPORT OF MANAGEMENT ON RESERVES DATA AND OTHER INFORMATION




     Management of OPTI Canada 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 are
estimates of proved reserves and probable reserves and related future net revenue as at December
31, 2007, estimated using forecast prices and costs and 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 B to this Annual
Information Form.



     The Technical 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 Technical 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
Technical Committee, approved:




	 	(a)	 	the content and filing with securities regulatory authorities of Form 51-101F1
containing reserves data and other oil and gas information;
	 
	 	(b)	 	the filing Form 51-101F2 which is 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. However, any variations should be consistent with the fact
that reserves are categorized according to the probability of their recovery.









 



-2-

	 	 	 	 	 
	/s/ Sid W. Dykstra
 	 	 
	Sid W. Dykstra
 	 	 
	President and Chief Executive Officer 	 	 
	 	 	 
	 
	/s/ James Fitzgibbon
 	 	 
	James Fitzgibbon
 	 	 
	Vice President, Resource Development 	 	 
	 	 	 
	 
	/s/
Charles Dunlap
 	 	 
	Charles Dunlap
 	 	 
	Director 	 	 
	 	 	 
	 
	/s/
Yoram Bronicki 	 	 
	Yoram Bronicki 	 	 
	Director 	 	 




Dated January 22, 2008












 



 




APPENDIX D

AUDIT COMMITTEE CHARTER




A. FUNCTION





     The Audit Committee is part of the board of directors and its function is to assist the Board
in fulfilling its stewardship with respect to: (i) financial statements and financial reporting,
(ii) the relationship with the external auditor, (iii) the adequacy and effectiveness of internal
controls and management information systems and (iv) financial risk management. The Audit Committee
provides assistance by reviewing, reporting, and recommending such matters to the Board for
consideration and decision.



B. CONSTITUTION





	1.	 	The Audit Committee members shall be appointed by the Board and serve at the pleasure of the
Board until they are succeeded or resign. Where a vacancy occurs at any time in the membership
of the Audit Committee, it shall be filled by the Board.






	2.	 	The Audit Committee shall be constituted with a minimum of three directors, each of whom
shall satisfy the independence, financial literacy and experience requirements of applicable
statutes and regulations.






	3.	 	A recording assistant for the Audit Committee shall be appointed by the Board.







C. COMMUNICATION, AUTHORITY TO ENGAGE ADVISORS





	1.	 	The Audit Committee shall have access to such officers and employees of the Corporation, the
Corporation’s external auditor and information respecting the Corporation as it considers
necessary or advisable in order to perform its duties and responsibilities.






	2.	 	The Audit Committee provides an avenue for communication with the external auditor and
financial management and the Board. The external auditor shall have a direct line of
communication to the Audit Committee through its Chair and shall report directly to the Audit
Committee.






	3.	 	In discharging its obligations and in appropriate circumstances, the Audit Committee may
engage outside advisors at the expense of the Corporation.





D. MEETINGS, MINUTES AND REPORTING





	1.	 	The Audit Committee shall determine the number of, dates and times, place and the procedures
for meetings provided that:






	 	(a)	 	the Audit Committee meets at least quarterly;
	 
	 	(b)	 	the Audit Committee shall meet prior to Board meetings for the purpose of
reviewing and preparing recommendations to the Board;
	 
	 	(c)	 	agendas and preparation documents are sent to members with sufficient time for
study prior to the meetings;
	 
	 	(d)	 	there be a quorum of two members present in person or via phone;










 



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	 	(e)	 	in the absence of the Audit Chair, a chair for a meeting is chosen at the
meeting;
	 
	 	(f)	 	resolutions are decided by a majority vote, the chair not having a second or
casting vote; and
	 
	 	(g)	 	the Audit Committee shall hold in camera sessions at every meeting, (1) without
management present, and (2) without the auditor present.






	2.	 	The recording assistant of Audit Committee shall record minutes of the meetings and, after
review by the chair, ensure minutes are included in the next subsequent Board meeting book, as
information for all directors.






	3.	 	The Audit Chair shall make a report, verbal or written, of each meeting and recommendations
at the next Board meeting following such Audit Committee meeting.





E. STEWARDSHIP FUNCTIONS





	 	 	Relationship with External Auditor






	1.	 	The Audit Committee shall:






	 	(a)	 	consider and make a recommendation to the Board as to the appointment of the
external auditor, ensuring that such auditor is a participant in good standing pursuant
to applicable securities laws;
	 
	 	(b)	 	consider and make a recommendation to the Board as to the compensation of the
external auditor;
	 
	 	(c)	 	oversee the work of the external auditor and oversee the resolution of any
disagreements between management of the Corporation and the external auditor;
	 
	 	(d)	 	review and discuss with the external auditor all significant relationships that
the external auditor and its affiliates have with the Corporation and its affiliates in
order to determine the external auditor’s independence, including, without limitation:






	 	(i)	 	requesting, receiving and reviewing, on a periodic basis, a
formal written statement from the external auditor delineating all
relationships that may reasonably be thought to bear on the independence of the
external auditor with respect to the Corporation;
	 
	 	(ii)	 	discussing with the external auditor any disclosed
relationships or services that may impact the objectivity and independence of
the external auditor; and
	 
	 	(iii)	 	recommending that the Board take appropriate action in
response to the external auditor’s report to satisfy itself of the independence
of the external auditor;






	 	(e)	 	review and approve the audit plan of the external auditor with the external
auditor, including the staffing thereof, prior to the commencement of the audit;
	 
	 	(f)	 	as may be required by applicable securities laws, rules and guidelines, either:










 



-3-








	 	(i)	 	pre-approve all non-audit services to be provided by the
external auditor to the Corporation (and its subsidiaries, if any), or, in the
case of inadvertent non-audit services where the aggregate fees for such
services is no more than five percent of all the fees paid to the external
auditor, 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 auditor for the purposes of the provision of non-audit services;
and






	 	(g)	 	review and decide the hiring practices of the Corporation regarding partners
and employees and former partners and employees of the present and former external
auditor of the Corporation.






	 	 	Financial Statements and Financial Reporting 






	2.	 	The Audit Committee shall:






	 	(a)	 	review with management and the external auditor, and recommend to the Board for
decision, the annual financial statements of the Corporation and related financial
reporting, including annual report, management’s discussion and analysis and related
press releases;
	 
	 	(b)	 	upon completion of each audit, review with the external auditor the results of
such audit, which includes but not be limited to:






	 	(i)	 	reviewing the scope of the audit work performed;
	 
	 	(ii)	 	reviewing the capability of the Corporation’s key financial
personnel;
	 
	 	(iii)	 	reviewing the co-operation received from the Corporation’s
financial personnel during the audit;
	 
	 	(iv)	 	reviewing the internal resources used;
	 
	 	(v)	 	reviewing significant transactions outside of the normal
business of the Corporation; and
	 
	 	(vi)	 	reviewing significant proposed adjustments and recommendations
for improving internal accounting controls, accounting principles or management
systems;






	 	(c)	 	review with management and the external auditor, and approve the interim
financial statements of the Corporation and related financial reporting, including
interim report, management’s discussion and analysis and related press releases;
	 
	 	(d)	 	review Audit Committee information within the information/proxy circular and
annual information form and recommend changes to the Board for decision;
	 
	 	(e)	 	review with management and recommend to the Board for decision, any financial
statements of the Corporation which have not previously been approved by the Board and
which are to be included in a prospectus or other public disclosure document of the
Corporation;










 



-4-








	 	(f)	 	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 public disclosure referred to
in clauses 2(a) and 2(c) above), and periodically assess the adequacy of such
procedures;
	 
	 	(g)	 	review with management, the external auditor and legal counsel any litigation,
claim or contingency, including tax assessments, that could have a material effect upon
the financial position of the Corporation, and the manner in which these matters have
been or may be disclosed in the financial statements; and
	 
	 	(h)	 	review accounting, tax, legal and financial aspects of the operations of the
Corporation as the Audit Committee considers appropriate.






	 	 	Internal Controls






	3.	 	The Audit Committee shall:






	 	(a)	 	review with management and the external auditor, 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).
	 
	 	(b)	 	review the external auditor’s recommendations regarding any matters, including
internal control and management information systems and procedures, and management’s
responses thereto;
	 
	 	(c)	 	review practices concerning the expenses and perquisites of the CEO, including
the use of the assets of the Corporation; and






	 	 	Matters Delegated by Board






	4.	 	The Audit Committee may deal with any other matters requested by the Board.