exv4w1

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 OrCrude™ 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 (“PSC™”) 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 PSC™ 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 PSC™;

	•		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 PSC™ 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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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 PSC™ and approximately 800 bbl/d of butane. We expect PSC™ 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.

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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 CO₂in 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 OrCrude™ Upgrader to reduce our exposure to various commodity prices.

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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 PSC™, 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 PSC^TM 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 PSC™ 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 PSC^tm, 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 OrCrude^TM 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 OrCrude^TMtechnologies have been demonstrated by the JV Participants in the form of a SAGD Pilot and an OrCrude^TMdemonstration 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 OrCrude^TM 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,

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

Integrated Approach and OrCrude™ 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 OrCrude™ Upgrader offers several advantages over these other projects in that the Integrated OrCrude™ Upgrader provides a solution to the three traditional challenges of SAGD operations:


Challenge		Integrated OrCrude™ Upgrader Solution
Exposure to fluctuating natural gas prices		Operating costs and the volatility of netbacks are reduced since the Integrated OrCrude^TMUpgrader produces synthesis gas to supply fuel and hydrogen thereby significantly reducing the need to purchase natural gas

Exposure to heavy oil differentials.		The Integrated OrCrude™ 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 OrCrude™ 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.

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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 OrCrude^TM Process technology in Canada.

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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 PSC^tm and approximately 800 bbl/d of butane resulting in an overall expected yield of approximately 81 percent. We expect PSC^tm 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 OrCrude^tm Process. The Project involves two major components, being the recovery of bitumen and the upgrading of bitumen into PSC^tm 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 PSC™ 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 OrCrude™, hydrocracker and utilities plants have been turned over to operations. The front end of the OrCrude™ 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 PSC™ 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.

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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.

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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 PSC^TMproduction (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 OrCrude^TMUpgrader 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.

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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.

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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 PSC^TMand 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 OrCrude^TM Upgrader

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

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

The syngas produced by the Integrated OrCrude^TMUpgrader is used as clean fuel in the Integrated OrCrude^TMUpgrader, 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 OrCrude^TMUpgrader 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 OrCrude^TMUpgrader and the SAGD facility to create operating cost advantages for the Project over other oil sands projects.

We expect the PSC^TMto 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 OrCrude^TMUpgrader 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.

OrCrude^TM Unit

The OrCrude^TMunit 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 OrCrude^TMunit 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 OrCrude^TM 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 OrCrude^TM 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 OrCrude^TMProcess. 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.

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Gasifier

The gasification technology used in the Integrated OrCrude^TMUpgrader 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 OrCrude^TM 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 Selexol^TMsolvent 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 OrCrude^TMProduct into PSC^TM. 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.

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Within the hydrocracker unit, the OrCrude^TMProduct is fed to a single hydrotreating reactor, where hydrogen is added over a catalyst to remove sulphur and nitrogen compounds in the OrCrude^TMProduct 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 OrCrude^TMProcess

Background

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

The OrCrude^TMProcess 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 OrCrude^TMProcess 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 OrCrude^TMProcess 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 OrCrude^TMportion of the Long Lake Upgrader under construction, with nearly the same number of equipment components, process streams and control system elements.

OrCrude^TM Process License

The OrCrude^TMProcess is a proprietary process that, when combined with commercially available hydrocracking and gasification processes, forms an Integrated OrCrude^TMUpgrader capable of upgrading bitumen and heavy oil into PSC^TM. On July 30, 1999, ORMAT granted to its subsidiary OPTI Technologies BV (“OPTI BV”) an exclusive worldwide license (excluding Israel) to use the OrCrude^TMProcess 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 OrCrude^TMProcess 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.

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The key terms of the OPTI License are as follows:

	•		OPTI Canada has undertaken to take the necessary steps to commercialize the OrCrude^TMProcess;

	•		improvements made by OPTI BV or ORMAT in the OrCrude^TMProcess 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 OrCrude^TMProcess technology;

	•		we will pay OPTI BV a royalty based on the installed cost to the end user of any facility using the OrCrude^TMProcess. 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 OrCrude^TMProcess.

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”), PSC^TM, 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 PSC^TM . We expect that while some of the Project’s PSC^TM 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. PSC^TM 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 PSC^TM, are transported to market via the Enbridge Pipelines (Athabasca) Inc. (“Enbridge”) pipeline. There are currently no firm sales contracts in place for PSH or PSC^TM.

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

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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 PSC^TM 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 PSC^TMfrom our Upgrader to occur in mid-2008.

Project Status

Significant progress continues to be made on the Project with first production of PSC™ 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.

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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 PSC™ in mid-2008. The OrCrude™ 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.

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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

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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

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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 OrCrude^TMProcess. 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.

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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.

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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 OrCrude^TM 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 OrCrude^TM Process uses virtually all of the bitumen resource and therefore produces more CO₂ per barrel. While this results in higher local CO₂ emissions, PSC^TM‘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.

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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.

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The McDaniel Report recognizes the inclusion of upgrading in our reserves. Most of the raw bitumen will be upgraded and sold as PSC™ 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		PSC™		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.

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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

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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.

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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.

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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.

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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

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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.

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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, OrCrude™ Upgrading of OPTI from its inception until June, 30, 2004. Mr. Bronicki, a co-inventor of the OrCrude™ 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 OrCrude™ 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.

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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 OrCrude™ 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

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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.

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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.

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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.

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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 OrCrude™ 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.

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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 PSC^tm 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.

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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 PSC^TM; 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.

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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.

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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

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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.

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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 PSC^tm produced from the Long Lake Upgrader.

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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;

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

The production of PSC^TM 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 PSC^TM.

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.

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Risks Relating to Technology

The Integrated OrCrude^tm 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 OrCrude^tm 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,

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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 OrCrude^tm 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,

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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

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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.

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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 OrCrude^tm 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 OrCrude^tm 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.

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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.

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

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“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;

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

“OrCrude™ 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;

“PSC^TM” means, generically, the premium, sweet, synthetic crude oil produced in the Integrated OrCrude™ Upgrader, which is produced by hydrocracking OrCrude™ 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
	(PSC^TM)				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 (PSC™)		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 (PSC™)		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,

-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.

-7-

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

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.

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

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.

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.

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

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.

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.

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

C. COMMUNICATION, AUTHORITY TO ENGAGE ADVISORS

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.

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.

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

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.

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.

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

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:

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	(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

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;

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	(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

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

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



		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.


			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

		Executed as to our report referred to above:

		McDaniel & Associates Consultants Ltd., Calgary, Alberta, Canada Dated January 8, 2008


/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