Opti Canada (OPCDF) 40-F 2008 FY Annual report (Canada)

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 40-F

(Check One)
o	Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934
or
x	Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2008

Commission file number 333-148909

OPTI CANADA INC.

(Exact name of registrant as specified in its charter)

Canada (Province or other jurisdiction of incorporation or organization) 1311 (Primary Standard Industrial Classification Code Number (if applicable)) Not applicable (I.R.S. Employer Identification Number (if Applicable))

2100, 555-4th Avenue S.W., Calgary, Alberta, Canada  T2P 4H2

(403) 249-9425

(Address and Telephone Number of Registrant’s Principal Executive Offices)

CT Corporation System, 111 8th Avenue, New York, NY  10011

(212) 894-8940

(Name, Address (Including Zip Code) and Telephone Number

(Including Area Code) of Agent For Service in the United States)

Title of each class Common Shares   Name of each exchange on which registered Toronto Stock Exchange

Securities registered or to be registered pursuant to Section 12(b) of the Act.	None
Securities registered or to be registered pursuant to Section 12(g) of the Act	None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.	Debt Securities

                                                                ;                                  

For annual reports, indicate by check mark the information filed with this Form:

x Annual Information Form   x Audited Annual Financial Statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:  195,929,526

Indicate by check mark whether the registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”).  If “Yes” is marked, indicate the file number assigned to the registrant in connection with such rule.

Yes o                               No x

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days.

Yes x                                No o

EXHIBIT INDEX

Exhibit	Description
99.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
99.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934
99.3	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
99.4	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
99.5	Consent of PricewaterhouseCoopers LLP
99.6	Consent of McDaniel & Associates Consultants Ltd.

FORM 40-F

Principal Documents

The following documents have been filed as part of this Annual Report on Form 40-F, beginning on the following page:

(a) Annual Information Form for the fiscal year ended December 31, 2008;

(b) Management’s Discussion and Analysis for the fiscal year ended December 31, 2008; and

(c) Consolidated Financial Statements for the fiscal year ended December 31, 2008 (Note 15 to the Consolidated Financial Statements relates to United States Accounting Principles and Reporting (U.S. GAAP)).

40 - -F1

Annual Information Form

For the Year Ended

December 31, 2008

March 24, 2009

TABLE OF CONTENTS

	PAGEE
INTRODUCTORY INFORMATION		2
FORWARD LOOKING INFORMATION		2
CORPORATE STRUCTURE		4
GENERAL DEVELOPMENT OF THE BUSINESS		5
Competitive Strengths and Operating Strategies		6
Our Industry		9
Our Principal Assets		10
The Long Lake Project and Future Phase Development		10
Marketing		18
Infrastructure		18
Our Lands and Leases		19
Material Agreements Related to the Joint Venture		21
Royalties		27
Regulatory Approvals and Environmental Considerations		28
Insurance		31
RESERVES AND RESOURCES SUMMARY		32
DESCRIPTION OF CAPITAL STRUCTURE		34
CREDIT RATINGS		38
MARKET FOR SECURITIES		39
DIVIDENDS		39
DIRECTORS AND OFFICERS		39
Board of Directors		41
Officers		45
Audit Committee		47
Auditor Service Fees		48
CONFLICTS OF INTEREST		48
RISKS AND UNCERTAINTIES		49
Risks Relating to the Project and to Future Phases of Development		49
Risks Relating to Reserves and Resources		54
Risks Relating to Commodity and Currency Pricing		56
Risks Relating to Technology		57
Risks Relating to Third Parties		58
Risks Relating to Financing and Our Indebtedness		61
MATERIAL CONTRACTS.		63
LEGAL PROCEEDINGS AND REGULATORY ACTIONS		63
TRANSFER AGENTS AND REGISTRAR		64
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		63
INTERESTS OF EXPERTS..		64
ADDITIONAL INFORMATION		64
GLOSSARY		65

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 requires, the terms "OPTI," "we," "our" and "us," refer to OPTI Canada Inc. capitalized terms used herein and not otherwise defined have the meanings ascribed thereto in the Glossary located on page 66.

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 applicable U.S. federal and state securities laws and 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.

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

• the level of production expected;

• the operation of our facilities, including the SOR of the SAGD Operation and the PSC™ yield of the Long Lake Upgrader;

• our estimated 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.

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;

• the ability for the operator to obtain qualified staff and equipment for the Long Lake Project in a timely and cost-efficient manner to meet our requirements;

• the regulatory framework representing royalties, taxes and environmental matters in which we conduct our business;

• the ability to market PSC™ successfully to customers and our ability to achieve product pricing expectations;

• the impact of changing 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:

• slower than expected ramp-up of bitumen production;

• slower than expected ramp-up of the Upgrader;

• equipment downtime;

• equipment product yields;

• our ability to source process inputs including water, contract bitumen, and natural gas;

• costs associated with producing and upgrading bitumen;

• the impact of competition;

• the need to obtain required approvals and permits from regulatory authorities;

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• 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 between 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;

• difficulties in and/or costs of disposing of process by-products or wastes including liquid sulphur and gasifier ash;

• we are a non-operator and as such we rely on the operator to generate cash flow from the Project and to provide information on the status and results of operations;

• 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);

• changes in or the introduction of new government regulations, in particular related to carbon dioxide ("CO2"), relating to our business; and

• our ability to attract capital and the cost of that capital.

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

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

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.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 subsidiaries at December 31, 2008.

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

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GENERAL DEVELOPMENT OF THE BUSINESS

We are a Calgary, Alberta-based company, established in 1999 to develop major integrated bitumen and heavy oil projects in Canada using our proprietary, next-generation OrCrude™ process. Our first project, the Long Lake Project, includes the Long Lake SAGD Operation and the Long Lake Upgrader, each with expected through-put rates of approximately 72,000 bbl/d of bitumen. We expect that the Project, located near Fort McMurray, AB, will produce 58,500 barrels per day ("bbl/d") of products, primarily 39° API PSC™ with low sulphur content, a highly desirable refinery feedstock. We expect PSC™ to sell at a price similar to West Texas Intermediate ("WTI") crude oil.

The Project is the first to utilize OPTI’s OrCrude™ process, integrated with proven gasification and hydrocracking processes. Through this configuration, we substantially reduce our exposure to and the need to purchase natural gas while producing one of the highest quality synthetic crude oils from the Canadian oil sands.

The SAGD portion of the Project was completed in advance of the Upgrader in order to ramp-up bitumen production prior to Upgrader start-up. We began producing bitumen in 2008 and we announced first production of PSC™ in January 2009. We expect that SAGD volumes will reach full design rates of approximately 72,000 bbl/d of bitumen in 12 to 18 months and that the increasing capacity of the Long Lake Upgrader during ramp-up will enable us to process the forecasted SAGD Operation volumes.

From the commencement of our joint venture with Nexen Inc. (Nexen) in 2001 until December 31, 2008, each company had a 50 percent interest in the Project; OPTI was the operator of the Long Lake Upgrader and Nexen was the operator of the Long Lake SAGD Operation. In December 2008, OPTI announced that it had entered into a definitive agreement to sell a 15 percent working interest in all its joint venture assets to Nexen for $735 million. The deal closed in January 2009. Effective January 1, 2009, OPTI has a 35 percent working interest in all joint venture assets, including the Project, all future phase reserves and resources, and future phases of development. Nexen has a 65 percent working interest in all joint venture assets and is now the operator of both the SAGD operation and the Upgrader for Phase 1 and future phases. For further details on the Nexen Transaction see “The Purchase and Sale Agreement” on page 28.

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.

At December 31, 2008, OPTI had approximately 385 employees. Upon Nexen assuming operating responsibility of the Long Lake Upgrader in early 2009, it is anticipated that Nexen will make employment offers to many of OPTI's operating and Project staff. We expect that after this transition OPTI will have approximately 25 employees.

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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 using a combination of proven operating technologies, employing a multi-staged approach to future expansions when economic conditions permit, and maintaining an integrated approach using SAGD combined with the Integrated OrCrude™ Upgrader.

Our competitive strengths are as:

Operating Project Employing Previously Demonstrated Technologies

The Project began producing bitumen in 2008. We announced first production of PSC™ in January 2009, marking the start-up of only the fourth integrated oil sands project in Canada. We expect SAGD production volumes to ramp-up through 2009 and reach design volumes of 72,000 bbl/d of bitumen in 2010. We anticipate that the increasing capacity of the Upgrader during ramp-up will enable OPTI to process all of the forecasted SAGD volumes. We expect the Upgrader to produce 57,700 bbl/d of PSC™ and 800 bbl/d of butane at full capacity.

Until recently, most oil sands were extracted via mining. However, 80 percent of the Athabasca oil sands are too deep to mine economically. Where bitumen is too deep to mine, SAGD technology, first used in 1978, has become a common recovery method. The majority of existing or planned in-situ oil sands developments use SAGD. The Project includes SAGD in conjunction with on-site bitumen upgrading. The Upgrader utilizes OrCrudeTM technology along with commercially available hydro cracking and gasification technologies that have been used in many applications around the world to process heavy oil into refinery and petrochemical feedstocks.

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

Large, Exploitable Resource Base with Low Geological Risk

Our working interest share of reserves and resources on current leases are estimated to be approximately 2.2 billion barrels of bitumen, comprised of 738 million barrels of proved and possible reserves and 1,424 million barrels of best estimate contingent resources. These reserves and resources are estimated to be sufficient to support production for Long Lake Phase 1, and for up to five additional phases of a similar size as Phase 1, for approximately 40 years. We believe that the approval of future phases by our board of directors, when economic conditions permit, and by regulatory authorities in Alberta will allow us to convert our substantial resource base into additional proved reserves. See "Reserves and Resources Summary."

The timing of future phases is subject to many factors including initial performance of Phase 1, receiving clarity on proposed climate change regulations, developing cost estimates and an improved economic environment. We do not expect to consider sanctioning Phase 2 until mid-2010 at the earliest.

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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 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 rate of production, future maintenance and sustaining capital expenditures will be required.

Once the Project is complete, including construction of the steam expansion plant (expected in 2009) and the ash processing unit (expected in 2010), we expect future 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. These costs relate to the drilling of new well pairs to sustain production and regular maintenance capital spending on plant and facilities.

Strong Margins

We expect that the sale of PSC™, a high quality sweet synthetic crude, combined with lower operating costs, primarily due to lower natural gas needs, will result in strong margins.

To illustrate these expected margins, we provide a financial outlook of our estimated netback for the Project. Netback costs are updated annually as a result of the JV’s budgeting process. The netback calculation shown below is consistent with this most recent update and includes our estimates of revenue, royalties, operating costs and G&A expenses per barrel of product sold when the Project is at full capacity.

This financial outlook is intended to provide investors with a measure of the ability of our Project to generate cash flow assuming full production capacity. We believe that the ability of the Project to generate cash to fund interest payments and future phases of development is a key advantage of our Project and important to our investors. The netback measure is an appropriate financial gauge to demonstrate this ability as corporate costs, interest, and other non cash items are excluded from the calculation. The financial outlook may not be suitable for other purposes. Netbacks generated by the Project are expected to be lower than shown in this outlook in the years immediately following start-up due to the lower production volumes during ramp-up and an initially higher SOR. The netback calculation as presented is a non-GAAP measure. The closest Canadian GAAP measure to the netback calculation is cash flow from operations. However, cash flow from operations includes many other corporate items that affect cash and are independent of the operations of the Project.

The actual netbacks achieved by the Project could differ materially from these estimates. The material risk factors that OPTI has identified toward achieving these netbacks are as outlined in the Forward Looking Information section of this document. In particular; the SAGD Operation and Upgrader may not operate as planned; the operating costs of the Project may vary considerably during the operating period; our financial results of operations will depend upon the prevailing prices of oil and natural gas in the worldwide market and those prices can fluctuate substantially; we will be subject to foreign currency exchange fluctuation exposure; and our operating cash flows will be directly affected by the applicable royaltyregime relating to our business. The key assumptions relating to the netback estimate are set out in the notes beneath the table. Assumptions are considered reasonable by OPTI as at the date of this AIF.

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Estimated Future Project Netbacks(1)

In CDN$/bbl	Post-payout			Pre-payout
	$/bbl			$/bbl
Revenue(1,2)	$	86.33		$	86.33
Royalties and G&A(3)		(8.43	)		(3.84	)
Operating costs(4)
Natural gas(5)		(3.90	)		(3.90	)
Other variable(6)		(2.76	)		(2.76	)
Fixed		(12.82	)		(12.82	)
Property taxes and insurance(7)		(3.55	)		(3.55	)
Netback	$	54.87		$	59.46

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. These numbers are cash costs only and do not reflect non-cash charges. See “Forward Looking Statements.”

(2) For purposes of this projection, OPTI assumes a WTI price of US$75/bbl, foreign exchange rates of CDN$1.00=US$0.85 and an electricity sales price of $106 per megawatt hour. Revenue includes sale of PSCtm, bitumen, butane and electricity.

(3) Royaltiesare calculated based on a light/heavy differential of 30 percent of WTI. OPTI anticipates payout for royalty purposes to occur in approximately 2022 based on the assumptions noted.

(4) Costs are in 2009 dollars.

(5) Natural gas costs are based on our long term estimate for a SOR of 3.0.

(6) Includes approximately $1.00/bbl for greenhouse gas mitigation costs based on an approximate average 20 percent reduction of CO2 emissions at a cost of $20 per tonne of CO2.

(7) Property taxes are based on expected mill rates for 2009.

Sustaining capital costs required to maintain production at design rates of capacity are estimated to be approximately $8.00 to $9.00 per barrel of PSC™, assuming full design rate production adjusted for long-term on-stream expectations. The netbacks as shown are prior to abandonment and reclamation costs. We do not include these costs due to the long-term nature of our assets. The estimates do not include any expenditures related to future phases.

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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. OPTI believes that the use of the Integrated OrCrude™ Upgrader offers several advantages over these other projects in that we expect the Integrated OrCrude™ Upgrader to provide a solution to the three traditional challenges of stand alone 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 OrCrudeTM Upgrader produces synthesis gas to supply fuel for steam generation and hydrogen for hydrocracking, 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 exposure to heavy oil differentials
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

Strong Joint Venture Sponsorship and Technical Expertise

OPTI benefits 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 249,000 boe/d, prior to royalties, in the third quarter of 2008. 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.

Experienced Management Team

The members of our senior management team have substantial industry experience. Technical teams have been established for the construction and operation of the Project comprised of individuals with extensive previous experience in a number of oil sands operations and construction projects. Based on experience in development of the Project, these teams have unique knowledge that will provide important expertise to future phases.

Our Industry

Oil sands operators produce and process bitumen, which is the heavy oil trapped in the sands. According to the EUB, Canada’s oil sands are estimated to hold 175 billion barrels of bitumen at the end of 2007, second only to Saudi Arabia and significantly more than the recoverable reserves in the United States. According to the Canadian Association of Petroleum Producers (CAPP), in 2007 oil sands production reached over 1.1 million bbl/d. CAPP currently estimates that oil sands production will reach 2.4 million bbl/d by 2015.

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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 economically, leaving the remainder of the resource to be recovered 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 be produced. The two most common methods of in-situ production are Cyclic Steam Stimulation ("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 OPTI’s.

Bitumen is currently sold in two principal forms: either as a bitumen blend, in which the bitumen is mixed with a lighter crude oil (to create synbit) or a very light condensate (to create dilbit) 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 hydrocarbon products.

Our Principal Assets

Our principal assets include:

• 35 percent interest in an operating project, the Long Lake Project, as of January 1, 2009;

• $3.2 billion investment to the end of 2008;

• proved plus probable plus possible bitumen reserves associated with a portion of the Long Lake Leases of 803 million bbls. See “Reserves and Resources Summary”;

• contingent and prospective bitumen resources of an estimated 1.424 billion bbls contained in the remainder of the Long Lake, Leismer and Cottonwood Leases. See "Reserves and Resources Summary"; and

• the exclusive right to the use of the OrCrude™ Process technology in Canada.

The Long Lake Project and Future Phase Development

The Long Lake Project

In 2001, OPTI formed a joint venture with Nexen to develop integrated oil sands projects in Canada. The first such project is Phase 1 of the Project, located on our Long Lake lease 42 km south east of Fort McMurray, Alberta. See:  “Our Lands and Leases.”

Effective January 1, 2009, OPTI owns a 35 percent undivided interest in the Project, which, among other assets, includes the SAGD Operation and the Upgrader, each with expected capacities of approximately 72,000 bbl/d of bitumen. The yield from bitumen produced from the SAGD Operation is expected to be 57,700 bbl/d of PSCtm and approximately 800 bbl/d of butane. OPTI expects PSCtm to sell at a price similar to WTI crude oil

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The Project is the first commercial application of the Integrated OrCrudetm Process. The Project involves two major components, being the recovery of bitumen and the upgrading of bitumen into PSCtm and other petroleum products. Included in the Project is a cogeneration facility that generates steam for the SAGD wells and electricity for use by the Project or sales to the Alberta interconnected electric system in the event of surplus. The cogeneration facility has a capacity of 170 megawatts.

From commencement of the Project until January 1, 2009, OPTI was the operator of the Upgrader and had primary responsibility for all matters relating to the Upgrader, subject to certain approvals of the management committee of the joint venture. OPTI was responsible for overseeing the construction, commissioning and start-up and operation of the Upgrader. During this period, Nexen was the operator of the SAGD Operation and had 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 has been responsible for overseeing the operation of the SAGD Pilot, as well as the construction and operations of the SAGD Operation. Upon closing the Nexen Transaction, Nexen became the operator of both the Upgrader and the SAGD Operation for Phase 1 and future phases.

There are organizations in place for the management of ongoing 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. An emphasis is placed on having operations personnel live locally in the region and be part of the local communities.

The Project is being governed pursuant to the terms and conditions of the COJO Agreement and the Technology Agreement. These agreements are reviewed in the "Material Agreements Related to the Joint Venture" section of this document.

Project Status

Major on-site construction of the Project began in mid-2005. The SAGD facilities were completed and steam injection commenced in 2007. SAGD production ramped up in 2008 to approximately 20,000 bbl/d in November. However, SAGD ramp-up has been affected by a variety of surface issues that have limited the amount of steam available to inject into the reservoir over the past few months due to power disruptions, extreme cold weather, and water temperature and treating issues. Since steam injection rates directly impact bitumen production rates, and the ability to generate steam is currently limited, bitumen production is lower than we previously expected. Solutions are being implemented to place more heat into the front-end of the water treatment process to supplement the heat returns from the reservoir and improve the water processing ramp-up capability. Given steaming constraints, only 32 of 81 well pairs are presently in production. Bitumen production in January 2009 averaged approximately 13,000 bbl/d (gross). As steam capacity increases the remaining wells will be brought on stream. The reservoir continues to perform as expected given the amount of steam injected.

Construction of the Upgrader, which intentionally lagged SAGD to ensure sufficient bitumen production at start-up, was completed in early 2008. Turnover of the Upgrader from construction to operations, and Upgrader commissioning and start-up activities, were the main focus in 2008. With all main process units operating, first production of PSC™ from the Project was achieved in January 2009. Preparation is underway to transition gasifier feed from vacuum residue to asphaltenes, the final step in Upgrader commissioning. Synthesis gas from the Upgrader is being used in SAGD operations, decreasing operating costs by reducing the requirement for purchased third-party natural gas. During the initial operating period, we expect periods of Upgrader down time but anticipate that the stability of operations will continue to improve. The Upgrader is currently gasifying and producing PSC™.

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During the final commissioning phase, prior to the operation of the solvent deasphalting and thermal cracking units, there is a high percentage of diluent that feeds the Upgrader and continues to the hydrocracker, forming part of the PSC™ stream. The Project has produced over 20,000 bbl/d (gross) of on-spec PSC™, with between 10,000 and 12,000 bbl/d (gross) of this representing upgraded bitumen. The remainder represents diluent processed through the Upgrader. The percentage of diluent in the Upgrader feed will decrease as bitumen production increases.

Based on industry experience, we expect the Upgrader to reach full production more quickly than SAGD operations. Therefore, during the SAGD ramp-up period, we expect that up to 10,000 bbl/d of externally sourced bitumen will be imported and processed. We expect the Project to reach full capacity of approximately 72,000 bbl/d of internally produced bitumen, upgraded into 58,500 bbl/d of PSC™ and other products, in 12 to 18 months.

The final cost of the Project is expected to be approximately $6.5 billion of which $3.25 billion will be net to OPTI. As of December 31, 2008, $6.4 billion or $3.2 billion net to OPTI had been incurred on the Project. As the Project is essentially complete as of December 31, 2008, nearly all expenditures were completed when OPTI retained a 50 percent working interest in the Project.  The remaining capital costs relate to the completion of the steam expansion project, expected in 2009, and the ash processing unit in the following year. The cost to complete these two projects is estimated at approximately $45 million net to OPTI’s current 35 percent working interest.

The SAGD Process

SAGD is an in-situ process that removes bitumen from the oil sand reservoir without removing the sand. The bitumen recovery component of the Project will use the SAGD process, as depicted above, which involves drilling multiple pairs of horizontal wells in the oil sands. Steam is injected into the upper well and released in the oil sands reservoir where it heats the bitumen. The heated bitumen becomes mobile and flows with condensed water from the steam to the lower horizontal well and then flows or is pumped to the surface.

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The SAGD recovery process used by the Project causes considerably less surface disturbance than mining operations that extracts both the sand and bitumen from the ground, separates the bitumen from the sand and returns the sand to tailings ponds. The SAGD process was first used in 1978 and is being employed as the recovery process in most new or developing in-situ projects.

SAGD Commercial Project

To achieve approximately 72,000 bbl/d of bitumen production, we expect that the Project will require 81 SAGD well pairs. Additional wells will be drilled as required in future years to maintain an annual average 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 is processed to remove water and solids, making it suitable for use in the Upgrader. Until start-up of the Upgrader, the bitumen was blended with diluent and shipped to markets. In the event that the Upgrader is unavailable, the JV Participants will continue to market the bitumen directly. Gas produced with the bitumen is sweetened and used as fuel for the steam generators. Over 90 percent of the water produced with the bitumen will be recycled and converted into steam for injection into SAGD wells. Impurities in the water are removed to allow the water to be used as a feed to the steam generators. The majority of the Project’s initial steam for injection is generated using two cogeneration facilities, each of which consist of a gas turbine and heat recovery steam generator, while the remainder is produced by four once-through boilers. Approximately 170megawatts of electricity are produced by the combined cogeneration facilities when at full capacity.

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 have installed 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. The capital cost of these additional facilities is approximately $615million, or $300million net to OPTI. The steam generation facilities are mechanically complete and are expected to become operational in the first half of 2009. We expect the long-term average SOR for the Project to be approximately 3.0.

SAGD Pilot Facility

The SAGD Pilot operated 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.

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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. It is expected that similar lean zones may occur over a portion of the Project area. The 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 have been 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 utilized in the Project wells was increased, which is anticipated to allow for enhanced productivity.

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 SAGD Operation. The pilot facility was then tied in with the main SAGD facilities and the SAGD Pilot wells have been re-activated coincident with the SAGD start-up in the spring of 2008.

Long Lake Upgrader

Upgrading of Bitumen

The bitumen recovered by the SAGD Operation is upgraded in the Upgrader. Once the Upgrader ramps up to full production, it will have the capacity to upgrade approximately 72,000 bbl/d of bitumen, yielding approximately 57,700 bbl/d of PSCTM and approximately 800 bbl/d of butane. The JV Participants have sold bitumen blend in the period prior to Upgrader start-up and will continue to do so in periods of Upgrader downtime including periods of major maintenance at the Upgrader. Electricity not consumed by the Project is also sold.

Integrated OrCrudeTM Upgrader

A complete upgrading process has been developed which combines the OrCrudeTM Process with proven hydrocracking and gasification processes to produce PSCTM, a premium sweet crude oil, and syngas, a synthesis fuel gas. The OrCrudeTM Process, when combined with these hydrocracking and gasification processes, is referred to as an "Integrated OrCrudeTM Upgrader." ORMATIndustries Ltd.("ORMAT")has been granted patents respecting the Integrated OrCrudeTM Upgrader configuration in the United States and Canada. The OPTI License provides OPTI with the exclusive right to the use of and the sub-license of the OrCrudeTM process in Canada.

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

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The PSCTM to be produced by the Long Lake Upgrader is expected to have a gravity of approximately 39°API. Therefore, the Project will not be exposed to fluctuating heavy oil differentials during regular operations. The Integrated OrCrudeTM Upgrader produces a light synthetic crude oil which will eliminate the requirement to add diluent to assist in bitumen transportation. There will be no need to purchase diluent for normal operations and no exposure to fluctuations in diluent prices or supply will be present when the Upgrader is fully operational. The Project will only need to purchase diluent for periods when the Upgrader is not operating.

OrCrudeTM Unit

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

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

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

Gasifier

The gasification technology used in the Integrated OrCrudeTM Upgrader is 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 Long Lake asphaltene gasification unit consists of four liquid-feed gasification trains and a common syngas processing train. The gasifier receives the liquid asphaltenes from the OrCrudeTM Process and produces syngas consisting of mostly hydrogen and carbon monoxide.

The oxygen required as part of the gasification process is produced in an air separation unit. This 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.

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

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

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

Initially the soot water slurry is processed to remove a portion of the water which is recycled back to the gasification unit, and the resultant product will be transported by rail or truck for sale to a metal reclaimer or disposed in an approved landfill. However, the JV Participants have developed a method to further process the gasifier soot waste through use of wet oxidation technology. By adding a soot processing facility, the soot solid waste stream is eliminated by further processing the stream into a metals rich product with about 10 percent of the original volume. The resulting product, ash, can be marketed to vanadium processors. This ash processing facility is expected to reduce Project operating costs, provide additional product revenue, and reduce the environmental impact of the plant. Final construction completion of the ash processing unit has been deferred to 2010.

Hydrocracker

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

Within the hydrocracker unit, the OrCrudeTM Product is fed to a single hydrotreating reactor, where hydrogen is added over a catalyst to remove sulphur and nitrogen compounds in the OrCrudeTM Product by converting them into gases that are processed in the sulphur treatment facilities. The hydrotreated oil is fed into a hydrocracking reactor where more hydrogen is added in the presence of a catalyst to crack 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 treats all of the sour gas and water streams to remove the sulphur as a liquid product for sale. The sulphur recovery unit is licensed by Fluor Intercontinental Inc. and consists of two oxygen enriched sulphur plant trains and a common hydrogenation/amine tail gas treating train to remove virtually all of the total sulphur fed to the Upgrader, including the sulphur from the SAGD wells.

Liquid sulphur is loaded directly onto rail cars for transportation to markets which are primarily in the United States.

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The OrCrudeTM Process

Background

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

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

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

OrCrudeTM Process License

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

The key terms of the OPTI License are as follows:

• Improvements made by OPTI BV or ORMAT in the OrCrudeTM Process technology will be deemed to be included in the OPTI License, and OPTI Canada is obligated to license to OPTI BV, at no additional cost, the rights to use and sub-license any improvements made by OPTI Canada to the OrCrudeTM Process technology;

• OPTI BV is paid a one-time royalty based on the installed cost to the end user of any facility using the OrCrudeTM Process. The estimate of the royalty payable to OPTI BV for the Project is approximately $12 million, of which OPTI’s share is 50 percent as the OrCrude™ unit was completed in 2008 at which time OPTI held a 50 percent interest in the JV;

• OPTI BV and its affiliates have the right, but not the obligation, to engineer, procure, construct and fabricate the solvent deasphalting units for projects using the OrCrudeTM Process.

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OPTI BV may terminate the OPTI License if OPTI were to be 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 if the royalty described above has been paid by OPTI. 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 currently use Nexen Marketing to market the products on behalf of the joint venture. These products include Premium Synthetic Heavy ("PSH"), PSCTM, surplus electricity from our Cogeneration Facility and sulphur, and bitumen in the event that the Upgrader is unavailable. OPTI has the right to take such production in kind in certain circumstances. We expect PSC™ to sell at a price similar to West Texas Intermediate (WTI) crude oil. The price OPTI receives is generally the price actually received by Nexen Marketing, subject to certain exceptions. No marketing fees are to be charged by Nexen Marketing. Payment from Nexen Marketing is due within 25 days of the month end following the date of delivery of products to Nexen Marketing.

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

While some PSCTM is expected to be sold in Canada, most volumes are expected to be exported to various refineries in the U.S. Great Lakes and Midwest region with some volumes sold as diluent to other bitumen producers in Canada. PSCTM has a low density (39° API) and low sulphur (<10 parts per million). We believe these characteristics make it attractive to other bitumen producers for use as a diluent which could improve OPTI’s netbacks.

The main crude products, PSH and PSCTM, are transported to market via the Enbridge Athabasca Pipeline.

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. 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 rail line north of Boyle, Alberta. The rail line will move, amongst other commodities, sulphur, catalysts, and construction materials to and from the Project site.

The JV Participants have an agreement with Enbridge to provide lateral facilities and transportation services on the Enbridge Athabasca Pipeline. This pipeline will transport PSH and PSCTM produced by the Project to Hardisty, Alberta. The products are then pipeline transported 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 to the Project.

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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, 2008.

	Gross Acres		Net Acres		Delineation Wells
Long Lake		62,720		21,952		608
Leismer		93,440		32,704		160
Cottonwood		90,240		31,584		75
Other		12,800		4,480		-
Total		259,200		90,720		843

We own a 35 percent interest in the rights to recover bitumen found in the oil sands deposits within the Long Lake, Leismer and Cottonwood leases.

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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 738 million barrels of proved and probable reserves and 254 million barrels of best estimate contingent resources for our 35 percent working interest share. See "Appendix A - Reserves Data and Other Oil and Gas Information."

OPTI’s capital program for 2009 includes funds allocated for additional core hole drilling to further delineate our nearer-term development leases at Long Lake. The 2008/2009 winter program is expected to include the drilling of 21wells and 47 square kilometres of 3D seismic.

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. The JV Participants 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

The Leismer leases, located approximately 64 kilometres southwest of the Project, are comprised of 146 sections of landand are estimated by McDaniel to contain 668 million barrels of best estimate contingent resources for our 35 percent working interest share. See "Reserves and Resources Summary - Resources Data".

At Leismer, there have been 190 delineation wells drilled by the JV Participants along with 52 square kilometres of 3D seismic gathered. In order to concentrate capital expenditures in 2009 on Phase 1 and nearer-term development projects on the Long Lake lease, nodelineation wells or seismic are planned on these leases during the 2008/2009 winter season.

Cottonwood Leases

The Cottonwood Leases, located approximately 32 kilometres southwest of the Project, are comprised of 141 sections of land and are estimated by McDaniel to contain 502 million barrels of best estimate contingent and prospective resources for our 35 percent working interest share. See "Reserves and Resources Summary - Resources Data."

There are over 75 wells drilled on these lands, including 44 drilled by the JV Participants, 25 of which were drilled in 2008. In order to concentrate capital expenditures in 2009 on Phase 1 and nearer-term development projects on the Long Lake lease, nodelineation wells or seismic are planned on these leases during the 2008/2009 winter season.

Development of Future Phases

The JV Participants believe thatthe landswill support approximately 360,000 bbl/d of PSCTM production (126,000 bbl/d net to OPTI) from six phases, including Long Lake Phase 1. Based on reserve and resource estimates, OPTI believes 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 inception, the JV Participants have spent over $800million on the expansion activities beyond Phase 1 and OPTI expects to continue to invest in engineering and planning for future phases of development.

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The sanctioning of Phase 2 will depend on multiple factors including the initial performance of Phase 1, receiving regulatory approval for Phase 2 SAGD operations, receiving clarity on proposed climate change regulations, finalizing cost estimates and an improved economic environment. OPTI therefore does not expect to consider sanctioning of Phase 2 until mid 2010 at the earliest. 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.

In 2009, the JV partners plan to advance detailed engineering on the SAGD and upgrader facilities for Phase 2 of Long Lake and conduct core hole drilling to further delineate the leases. Regulatory approval has been obtained for the Phase 2 upgrader, which is expected to be constructed 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 SAGD phases totalling 140,000 bbl/d of bitumen production in addition to Phase 1. The regulatory approval for this project was obtained in February 2009.

Lease delineation and preliminary environmental evaluations are underway for phases beyond Phase 2. Each future phase is planned to be of a similar size and design to the Project and anticipated to consist of integrated SAGD and OrCrudeTM Upgrader projects. The specific design of these phases will be dependent upon a number of factors including key learnings from Phase 1 and our strategy to address CO2 and other greenhouse gas emissions. Alternatives to facilitate CO2 capture are being evaluated.

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 MOU dated 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 subject to those material differences as summarized on page 26 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 OPTI 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 oil sands leases or petroleum and natural gas rights overlying owned oil sands leases jointly acquired by OPTI 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, OPTI 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. In such an event, a matter being voted on by the Management Committee will generally 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

Under the original COJO Agreement, OPTI was the operator of the Upgrader and Nexen was the operator of the SAGD facilities. In January 2009, Nexen became the operator of both the SAGD facilities and the Upgrader of Phase 1 and all future phases as per the Nexen Transaction.

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.

Operators 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. An 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.

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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 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 commercial 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 Project, including the right to participate in decisions 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.

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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 for its committed production purchased by Nexen Marketing shall be equivalent to 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.

Nomination Process

The Agreement allows either party to elect to reduce its participation in the project in question. If a party reduces its participation, the other party is obligated to purchase this reduced participation for an amount equal to OPTI’s sunk costs related to the reduced participation. If the other party elects not to purchase the reduced participation, then the project will stop.

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 OPTI has 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.

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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.

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 an affiliate of Nexen to which it issues a sub-license, has 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.  We are obligated to pay the full amount of this royalty to OPTI BV under the terms of the OPTI License.

Nexen will pay to us a royalty based on the installed cost proportionate to its working interest of any facility using the OrCrudeTM Process. We estimate the royalty payable to us from Nexen in the first phase of the Project will be approximately $6 million.

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. OPTI may assign the Technology Agreement at its 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.

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• 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, as applicable, before it is entitled to participate in the project.

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 its current 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 the interest it owns as of the date hereof, if the scope of the project changes. 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 together with interest thereon.

The Purchase and Sale Agreement

On December 16, 2008, OPTI and Nexen entered into a Purchase and Sale Agreement wherein OPTI agreed to sell a 15 percent working interest in Phase 1 of the Long Lake Project, all future phase reserves and resources, and future phases of development to Nexen for $735 million. Under the terms of the agreement, Nexen also assumed operatorship of the Long Lake Upgrader and all future phases. The transaction closed January 26, 2009. Effective January 1, 2009, OPTI has a 35 percent working interest in all joint venture assets, including Phase 1 of the Long Lake Project, all future phase reserves and resources, and future phases of development. Nexen has a 65 percent working interest in all joint venture assets and is now the operator of both the SAGD and upgrader facilities for Phase 1 and future phases. Pursuant to the Nexen transaction, OPTI pre-funded $85 million of its portion of the 2009 joint venture capital expenditure program.  Any additional capital expenditures allocable to our working interest share in 2009 will be funded by OPTI.

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 royalties for conventional oil, natural gas and bitumen became effective January 1, 2009 and are linked to commodity prices and production levels, and will apply to both new and existing oil sands projects as well as conventional oil and gas activities.

Prior to January 1, 2009, in respect of oil sands projects having regulatory approval, a royalty of one percent of gross bitumen revenue was 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 were 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)) was levied.

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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.

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 as an incentive for industry to increase upgrading and refining capacity in Alberta. 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.

Regulatory Approvals and Environmental Considerations

Regulatory Approvals

We have regulatory approval for SAGD and upgrading facilities for Phases 1 and 2, as well as regulatory approval for SAGD facilities for Phase 3.

The Project received approval from the ERCB (formerly the EUB) and AE for up to 70,000 bbl/d of SAGD operation and up to 140,000 bbl/d of upgrading capacity 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 as operations proceed, as is typical with projects of this nature.

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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. An application for an additional 140,000 bbl/d of SAGD production from the Long Lake lease was filed in late 2006 known as the Long Lake South Project. Regulatory approval for the Long Lake South Project was received in February 2009.

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

Throughout the operational life of the Project additional regulatory approvals and permits will be required. It is anticipated that such additional approvals and permits required for the Project will be received in the ordinary course.

Safety, Environment and Social Considerations

Many stakeholders will play a role in the ultimate success of Long Lake and our future developments - our employees, contractors and suppliers, area residents including First Nations people, government and regulatory authorities, non-government organizations, investors and others.

Recognizing the diverse needs of these stakeholders, OPTI and Nexen have adopted a Safety, Environment & Social Responsibility ("SESR") Policy that helps guide business decisions in an integrated manner and embraces the concept of sustainable development - an approach that considers environmental protection, economic growth and social responsibility.

This comprehensive policy assists OPTI and Nexen in identifying and achieving sustainability as we strive for 100 percent safe performance in all of our joint-venture operations and activities, for our employees, contractors and management.

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 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. OPTI has 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.

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To ensure we remain continuously improve our SESR performance, science-based risk assessments, cost-benefit analyses and measurable targets are some of the tools applied to our decision-making processes.

Greenhouse Gases and Industrial Air Pollutants

Canada is a signatory to the United Nations Framework Convention on Climate Change (the "Convention") 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 GHGs. The Project will be a significant producer of some GHGs covered by the Convention. We intend that the Project will comply with applicable Canadian requirements implementing the Kyoto Protocol.

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

On April 26, 2007 the Canadian Federal Government released the Regulatory Framework for Air Emissions (the "Framework") which outlines proposed new requirements governing emission of GHGs and other industrial air pollutants in accordance with the Government’s Notice of Intent to Develop and Implement Regulations and Other Measures to Reduce Air Emissions released on October 19, 2006. The Framework introduces further, but not full, detail on new GHG and other industrial air pollutant limits and compliance mechanisms that will apply to various industrial sectors, including the oil sands extraction, upgrading and electricity production industries starting in 2010. On March 10, 2008, the Canadian Federal Government elaborated on the Framework with the release of its Turning the Corner document. It is contemplated that new regulations will take effect January 1, 2010. Draft regulations were expected to be available for public comment in the Fall of 2008 and are now expected in mid-2009.

The proposed regulatory framework provides that existing oil sands facilities in operation by 2004 will be subject to an 18 percent emission intensity reduction targets requirement commencing in 2010, with 2 percent additional annual reductions thereafter until 2020.  Emission intensity is the amount of GHG emissions per unit of production or output. Facilities commissioned between 2004 to 2011 or facilities existing prior to 2004 which are between 2004 and 2011 have had a major expansion resulting in an increase of 25 percent or more in physical capacity or which undergo a significant change to processes will be exempt from the 2010 emissions intensity reduction target of 18 percent but will have to report their emissions each year and after their third year of operation will be required to reduce their emissions intensity by 2 percent annually from a baseline emissions standard which is to be determined by reference to a sector-specific cleaner-fuel standard. For oil sands facilities, it is contemplated to form the basis of new draft regulations scheduled to be released in early 2008 that there will be specific cleaner-fuel standards based on the use of natural gas for each of mining, in situ and upgrading. However, an incentive to deploy carbon capture and storage ("CCS") has been included.  CCS is where carbon dioxide is separated from a facility's process or exhaust gas emissions before they are emitted, transferred from the facility to a suitable storage location, and injected into underground geological formations and monitored to ensure they do not escape into the atmosphere. If a facility commissioned between 2004 and 2011 is built such that it is able or ready to undertake CCS, then it will be exempt from the cleaner-fuel standard until 2018 and it will only be required to reduce it's emission-intensity by 2 percent per year from its actual emissions. In situ oil sands projects and oil sands upgraders built after 2011 must have their GHG emissions profiles by 2018 equivalent to that of facilities employing CCS technology. The proposed regulatory framework further encourages widespread use of CCS by 2018 by crediting emitters that make use of CCS technology for investments in pre-certified CCS projects up to 100 percent of their regulatory obligations through 2017.

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The proposed compliance mechanisms include paying into a technology fund, fixed emission caps and an emissions credit trading system for GHGs and certain industrial air pollutants, and several options for companies to choose among to meet GHG emission intensity reduction targets and encourage the development of new emission reduction technologies., including the option of making payments into a technology fund, an emissions and offset trading system, limited credits for emission reductions created between 1992 and 2006, and international emission credits under the clean development mechanism under the Kyoto Protocol for up to 10 percent of each firm's regulatory obligation.

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 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 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 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.

• 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.

• Liability - 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. Liability exposures are insured separately under each JV Participant’s corporate insurance program.

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• 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) are insured under each JV Participant’s corporate insurance program.

This insurance program will be in place until March 31, 2009, at which time we expect to transition to a post-construction operating insurance program. We are currently working with Nexen on the placement of a joint operating insurance program. The program is expected to include physical damage and business interruption insurances.

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 February 11, 2009, evaluating the bitumen reserves and synthetic oil reserves of the Long Lake Leases effective as of December 31, 2008 (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.

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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.

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 Upgrader start-up, and thereafter during periods of Upgrader downtime, and is shown as bitumen reserves.

The McDaniel Report, as summarized in Appendix A, reflects our reserves and resources with a 50 percent working interest in the joint venture and prior to the effect of our sale to Nexen of a 15 percent working interest in the Long Lake Project and all future phase reserves and resources.  Effective January 1, 2009, we own a 35 percent working interest in the JV Participants’ reserves and resources. The following table shows our 35 percent 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, 2008

(MMbbl)

	Raw	Sales Volumes
	Bitumen	PSC™	Bitumen	Butane
Proved	194	147	11	6
Proved plus probable	738	579	15	22
Proved plus probable plus possible(1)	804	632	15	24

Note:

(1) 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 proven reserves.

(2) Probable reserves are those additional reserves that are less certain to be recovered than proven reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proven plus probable reserves.

(3) 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 proven plus probable plus possible reserves.

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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 35 percent working interest in the additional resource estimates is shown below:

Summary of Bitumen Resources (1)

December 31, 2008

(MMbbl)

	Raw Bitumen
Remainder of Long Lake leases(2)		254
Leismer(2)		668
Cottonwood(3)		502
Total		1,424

Notes:

(1) These estimates represent the "best estimate" of our resources, are not classified or recognized as 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.

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 resources rather than reserves primarily due to less delineation and the absence of regulatory approvals, detailed design estimates and near-term development plans.

(3) The resource estimate for Cottonwood is categorized as both contingent and prospective resources. The estimate of 717 million barrels prior to the sale of the 15 percent working interest would be comprised of 274 MMbbl of contingent resources and 443 MMbbl of prospective resources. After taking account for the sale of the 15 percent working interest, the estimate of 502 million barrels is comprised of 192 MMbbl of contingent resources and 310 MMbbl of prospective resources. These contingent Resource volumes are classified as resources rather than reserves 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. All references to share issuances and stated capital in this AIF give effect to these reorganizations of capital.

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

At December 31, 2008, OPTI had 195,929,526 common shares and 7,160,116 common share options outstanding. The common share options have a weighted average exercise price of $13.14 per share.  At December 31, 2008, OPTI’s fully diluted shares outstanding were 203,079,642.   There are no Voting Convertible Preferred Shares currently outstanding.

Effective November 2008, 5,991,000 common share warrants with an exercise price of $14.75 per share expired without being exercised. Effective June 2008, $202 million of call obligations with an exercise price of $2.20 per share expired without being exercised.

Rights Plan

At the Corporation's annual and special meeting of shareholders held on April 27, 2006, the shareholders of the Corporation adopted a shareholder rights plan (the "Rights Plan"), all as described in the material change report of the Corporation dated April 27, 2006. The objectives of the Rights Plan are to ensure, to the extent possible, that all shareholders of the Corporation are treated equally and fairly in connection with any takeover bid or similar offer for all or a portion of the Common Shares of the Corporation. The Rights Plan discourages discriminatory, coercive or unfair takeovers of the Corporation and gives the board of directors time if, in the circumstances, the board of directors determines it is appropriate to take such time, to pursue alternatives to maximize shareholder value in the event an unsolicited takeover bid is made for all or a portion of the outstanding Common Shares of the Corporation.

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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 at any time prior to April 15, 2009, 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.

Description of Debt Capital

We have a revolving credit facility in the maximum principal amount of $350 million that expires on December 15, 2011. Prior to the closing of the Nexen Transaction in January 2009, this facility was in the amount of $500 million. Upon closing the sale of 15 percent working interest, the facility was permanently reduced to $350 million. At February 17, 2009, after using proceeds from the Nexen Transaction to fund a partial pay-down, $87 million remained outstanding on the $350 million revolving credit facility.

An additional first lien revolving debt facility was established during the second quarter of 2008 in the maximum principal amount of $150 million. Other than maturity date and amount, the terms and conditions of this facility were the same as the $500 million revolving credit facility. Upon closing the sale of the 15 percent working interest in January 2009, this debt facility was repaid and cancelled.

Our $350 million revolving credit facility contains a number of provisions that serve to limit the amount of debt we are permitted to incur. The key maintenance covenants are with respect to debt to capitalization and the ratio of debt outstanding under the revolving credit facility to EBITDA. Maintenance covenants are ongoing conditions that must be satisfied to provide continued access to the revolving credit facility.

The first lien to EBITDA covenant as amended in January 2009 is measured quarterly and requires that this ratio must be lower than 2.5:1 commencing for the quarter ended September 30, 2009. The first three measurements of EBITDA for this covenant will annualize EBITDA as measured from July 1, 2009 to the end of the applicable covenant period. Thereafter, EBITDA will be based on a trailing four quarters. Realized cash gains on commodity contracts, such as our existing puts and forwards, are included in EBITDA for the purposes of the covenant. If we are unable to generate sufficient EBITDA, we may be required to repay all or a portion of amounts outstanding under that facility, or we may be unable to make additional borrowings under the revolving credit facility, or we may be required to request and obtain approval for a waiver from our lenders under the facility.

The debt to capitalization covenant, as amended in January 2009, requires that we do not exceed a ratio of 70 percent as calculated on a quarterly basis.  The covenant is calculated based on the book value of debt and equity. The book value of debt is adjusted for the effect of any foreign exchange derivatives issued in connection with the debt that may be outstanding. At December 31, 2008, this means that our debt would be reduced by the value of our foreign exchange forward in the amount of $32 million. With respect to US dollar denominated debt, for purposes of the debt to capitalization ratio, the debt is translated to Canadian dollars based on the average exchange rate for the quarter. The debt to capitalization is therefore influenced by the variability in the measurement of the foreign exchange forward which is subject to mark to market variability and the average foreign exchange rate changes during the quarter.

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In respect of new borrowings under the $350 million revolver facility prior to reaching completion of the Project, we are required to have sufficient funds (including cash and undrawn revolver availability) to fund our share of remaining Project costs.

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 due 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 the 7.875% Notes, we had pre-funded interest until December 15, 2008 which was held in an interest reserve account. The account was closed on December 15, 2008. On a go forward basis, interest payments will be paid from working capital.

With respect to our senior secured notes, covenants are in place primarily to limit the total amount of debt that OPTI may incur at any time. This limit is most affected by the present value of our total proved reserves using forecast prices discounted at 10 percent.  Based on our 2008 reserve report, we have sufficient capacity under this test to incur additional debt beyond our existing $350 million revolving credit facility and existing senior secured notes. However other leverage factors, such as the debt to capitalization and the total debt to EBITDA covenants, are expected to be more constraining than this limitation.

OPTI is exposed to foreign exchange rate risk on our U.S. dollar denominated debt. To partially mitigate this exposure, we have entered into US$875 million of foreign exchange forwards to manage some of the exposure to repayment risk due to decline in value of the Canadian dollar. The forward contracts provide for the purchase of U.S. dollars and the sale of Canadian dollars at a rate of approximately CDN$1.17 to US$1.00 with an expiry in April 2010. With respect to our U.S. dollar denominated debt, we believe that these forward contracts provide protection against a decline in the value of the Canadian dollar below CDN$1.17 to US$1.00 on a portion of our debt. The value of these derivatives affects our debt covenants as the value of these contracts is included in the measurement of our debt for covenant purposes.

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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").

Type of Security	Moody's	S&P
8.25% Notes	B3	B-
7.875% Notes	B3	B-

OPTI and OPTI's Revolving Credit Facility are currently rated by Moody’s and S&P.

	Moody's	S&P
OPTI Corporate Rating	B3	B-
Revolving Credit Facility	Ba3	B+

On February 26, 2009, Moody’s downgraded OPTI’s Corporate Rating and second secured note ratings, and confirmed its first secured revolver rating.  Moody’s rating outlook is negative.  According to Moody’s, the downgrades reflect a reduced likelihood that OPTI and Nexen (project operator) will have the Project adequately close to design specifications in time for OPTI to demonstrate internal support of its debt structure by year-end 2009.

The S&P ratings have been on credit watch with negative implications since November 2008.

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 Definitions - Obligations rated B are regarded as having significant speculative characteristics. An obligation rated B is more vulnerable to non-payment than obligations rated 'BB', but the obligor currently has the capacity to meet its financial commitment on the obligation. Adverse business, financial, or economic conditions will likely impair the obligor's capacity or willingness to meet its financial commitment on the obligation.

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 2008:

Month	High		Low		Closing		Volume
January	$	18.62	$	15.30	$	16.55		30,574,366
February	$	18.29	$	16.35	$	17.30		19,098,427
March	$	17.62	$	15.41	$	17.30		24,882,322
April	$	21.70	$	17.01	$	21.32		25,520,310
May	$	24.25	$	20.99	$	22.50		26,204,798
June	$	25.40	$	21.40	$	23.10		25,134,995
July	$	23.46	$	18.20	$	19.44		16,008,917
August	$	19.93	$	16.08	$	19.25		22,679,665
September	$	19.24	$	9.71	$	11.05		39,145,403
October	$	11.05	$	2.47	$	3.21		63,042,917
November	$	4.02	$	1.10	$	2.18		75,925,746
December	$	3.05	$	1.56	$	1.80		62,067,913

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 Residence	Present Position and Office	Position Held Since(1)(2)	Principal Occupation
Directors
James M. Stanford(6)                                          Alberta, Canada	Chairman and Director	May 30, 2002	President of Stanford Resource Management Inc., a financial management company
Yoram Bronicki(4)(7)                                          Nevada, USA	Director	December 29, 2001	President and Chief Operating Officer of  ORMAT Technologies Inc.
Ian W. Delaney(4)(6)                                           Ontario, Canada	Director	November 16, 2005	Chairman and Chief Executive Officer, Sherritt International Corporation, a diversified resource company
Charles L. Dunlap(3)(7) Texas, USA	Director	June 29, 2006	Management Consultant

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Name and Residence	Present Position and Office	Position Held Since(1)(2)	Principal Occupation
Sid Dykstra[14]                                          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
Edythe (Dee) A. Marcoux(5)(7) Alberta, Canada	Director	July 16, 2008	Retired oil executive
Robert G. Puchniak(3)(6)                                          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(5)(6) (15) Alberta, Canada	Director	February 1, 2007	Energy Investor
Samuel Spanglet(5)(7)                                          Alberta, Canada	Director	October 26, 2007	Retired oil executive
James van Hoften(3)(5)                                          California, USA	Director	July 12, 2007	Retired executive
Bruce Waterman(3)(4)                                          Alberta, Canada	Director	July 16, 2008	Senior Vice President, Finance and Chief Financial Officer of Agrium Inc. , a public agricultural supply company.

Officers
Sid Dykstra[14]                                          Alberta, Canada	President and CEO	July 6, 2001	see above
James Arnold(8) (9)                                          Alberta, Canada	Chief Operating Officer	October 13, 2005	Chief Operating Officer
David Halford [12]                                          Alberta, Canada	Chief Financial Officer	April 10, 2007	Chief Financial Officer
Travis Beatty [12]                                          Alberta, Canada	Vice President, Finance and Chief Financial Officer	March 1, 2009	Chief Financial Officer
Joe Bradford                                          Alberta, Canada	Vice President, Legal and Administration and Corporate Services	October 14, 2008	General Counsel and Corporate Secretary
Mary Bulmer (13)                                          Alberta, Canada	Vice President, Human Resources and Corporate Services	April 15, 2004	Vice President, Human Resources and Corporate Services
Peter Duda(10)                                          Alberta, Canada	Vice President, Operations	October 13, 2005	Vice President, Operations

William W. King                                          Alberta, Canada	Vice President, Development	August 1, 2008	Vice President, Major Projects
Alan Smith(11)                                          Alberta, Canada	Vice President, Marketing	March 1, 2009	Vice President, Marketing

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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 Environment, Health and Safety Committee.

(6) Member of the Governance and Nominating Committee.

(7) Member of the Technical Committee.

(8) Formerly Vice President, Development from January 1, 2000 to October 13, 2005.

(9) On January 31, 2009, Mr. Arnold resigned from OPTI to accept a position at Nexen.  He continues to be involved in Long Lake operations and future development.

(10) Effective February 28, 2009, Peter Duda left his employment at OPTI .

(11)  Alan Smith was appointed Vice President, Marketing effective March 1, 2009.

(12)  Effective March 1, 2009, David Halford resigned from OPTI to pursue other business opportunities, at which time Travis Beatty was appointed Vice President, Finance and Chief Financial Officer.

(13)  Effective March 31, 2009, Mary Bulmer will leave her employment at OPTI.

(14) Effective April 28, 2009, Sid Dykstra will leave his employment at OPTI and cease to be a director of OPTI.

(15)  Effective April 28, 2009, Christopher Sublicki will become President and Chief Executive Officer of OPTI.

As at December 31, 2008, our directors and officers, as a group, beneficially own, directly or indirectly, or exercise control or direction over 674,093 of our common shares or 0.34 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:

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.

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.

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.

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Ian W. Delaney

Mr. Delaney is the Chairman and Chief Executive Officer of Sherritt International Corporation of Toronto, Ontario. Since 1995, and prior to his appointment as CEO, Mr. Delaney was the Executive Chairman of Sherritt. 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 and Chairman of The Westaim Corporation, a technology investment company. He has previously served on a number of boards, including Co-Steel Inc., MacMillan Bloedel Ltd., and GoldCorp Inc.

Charles Dunlap

Prior to his current role as a Management Consultant, Mr. Dunlap was most recently the 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 2008. Mr. Dunlap is currently a member of the board of directors for Transmontaigne GP L.L.C., a publicly traded Master Limited Partnership. In addition, 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.

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.

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Mr. Dykstra is currently a director of Cinch Energy Corp. and is 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.

Mr. Dykstra will leave his employment with OPTI effective April 28, 2009.

Randall Goldstein

Mr. Goldstein is currently 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.

Edythe (Dee) A. Marcoux

Ms. Marcoux is a retired executive from the oil industry with extensive experience with several major oil and gas companies including Suncor Inc. She is currently a director of Sherritt International Corporation and SNC-Lavalin. She was a consultant to Ensyn Group Inc. a heavy oil upgrading technology company from 2002 to mid-2005 and was previously, from 2001 to 2002, Chairman and Chief Executive Officer of Ensyn Energy, a subsidiary of Ensyn Group Inc. As well, Ms. Marcoux worked as a consultant and served as a director of Southern Pacific Petroleum NL (“SPP”), a company developing shale oil reserves in Australia from 1998 to 2003. During this time, SPP’s securities were suspended from quotation on the Australian Stock Exchange prior to the commencement of trading on November 23, 2003 for a period of more than 30 consecutive days, and in respect of which receivers were appointed on December 2, 2003. SPP’s securities are not currently traded. Ms. Marcoux resigned as a director of SPP with effect from 12:00 noon on December 5, 2003.

Ms. Marcoux holds an engineering degree, a Masters of Business Administration and an honourary Ph.D., all from Queen’s University.

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 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.

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Mr. Puchniak is a director of a number of public and private corporations including 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 has been appointed President and Chief Executive Officer of OPTI effective April 28, 2009. 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 is a director of OptiSolar, Inc., Bonavista Energy Trust and Insignia Energy Inc.

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 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.

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Bruce Waterman

Mr. Waterman is the Senior Vice President, Finance and Chief Financial Officer of Agrium Inc. He joined Agrium in 2000 and has more than 30 years experience as a financial executive. Prior to joining Agrium, Mr. Waterman was the Vice President and Chief Financial Officer of Talisman Energy Inc.

Mr. Waterman holds a Bachelor of Commerce from Queen's University and is a Chartered Accountant.

Officers

At December 31, 2008, our management team was comprised of the following individuals:  Sid Dykstra, Jim Arnold, David Halford, Joe Bradford, Mary Bulmer, Peter Duda and William King.

As a result of the Nexen Transaction, there have been changes to OPTI’s management team as reflected below.

Jim Arnold

Prior to his appointment to this position in October 2005, Mr. Arnold 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.

Mr. Arnold resigned from OPTI effective January 31, 2009, to accept a position at Nexen.  He continues to be involved in Long Lake operations and future development.  

Travis Beatty

Travis Beatty was appointed Vice President, Finance and Chief Financial Officer of OPTI effective March 1, 2009. Mr. Beatty joined OPTI in 2002 as Controller and since then has also held the roles of Treasurer and Director, Planning. Prior to joining OPTI, Mr. Beatty was the VP Finance and Chief Financial Officer of International Datashare Corporation from 2000 to 2002,  Mr. Beatty also worked for Hunt Oil Company of Canada (formerly Newport Petroleum Canada) and KPMG LLP.

Mr. Beatty is a Chartered Accountant and a Chartered Financial Analyst, and holds a Bachelor of Commerce from the University of Calgary.

David Halford

Mr. Halford 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.

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

Mr. Halford resigned to pursue other business opportunities effective March 1, 2009.

Joseph Bradford

Mr. Bradford joined OPTI in October 2008 in the newly created role of General Counsel and Corporate Secretary.  Effective March 1, 2009, he was appointed Vice President, Legal and Administration and Corporate Services.  Prior to joining OPTI, he held a number of senior management positions including Senior Vice President, Commercial and Legal with Advanced Biodiesel Group and Vice President, Regulatory and Legal at Electricity Supply Board International (Alberta), Alberta’s first independent electrical transmission administrator.  Additionally, he was a board member of Veridian Corporation, one of Ontario’s largest distributors of electricity and has consulted to the United Horsemen of Alberta.

Mr. Bradford holds a L.L.B. from Queen’s University, a B.A. (Hons.) from St. Francis Xavier University and a Queen’s Commission from the Canadian School of Infantry.  He is a member of the Law Society of Alberta and the Law Society of Upper Canada.

Mary Bulmer

Ms. Bulmer is our Vice President, Human Resources and Corporate Services. She joined OPTI 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.

Ms. Bulmer’s employment with OPTI will end on March 31, 2009.

Peter Duda

Mr. Duda joined OPTI in 2003 as the General Manager, Upgrader Operations and was promoted to Vice President, Operations, 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.

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.

Mr. Duda’s employment with OPTI ended effective February 28, 2009.

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William King

Mr. King is currently Vice President, Development.  He joined OPTI in mid-2004 as Area Project Manager, OrCrude. Before being promoted to his current position, Mr. King was Director, Phase 2 Upgrader and Vice President, Major Projects. Prior to joining OPTI, he held project management positions with ConocoPhillips, Gulf Indonesia and Gulf Canada.

Mr. King holds, and has held, numerous professional affiliations and memberships with petroleum related organizations and associations, including the Project Management Institute and the Canadian Gas Processors Association. He is currently a member of APEGGA. Mr. King is a Professional Engineer in Alberta and holds a B.Sc. in Chemical Engineering from the University of Alberta.

Alan Smith

Mr. Smith is presently the Vice President, Marketing of OPTI. He joined OPTI in 2006 as Director of Marketing, and was appointed to his present position effective March 1, 2009. Mr. Smith possesses over 27 years of petroleum industry experience in disciplines including upstream heavy oil, upgrading and synthetic production, midstream marketing, and downstream refining. From 2000 until his time with OPTI, Mr. Smith was Manager of Market Development at Chevron Canada Resources. He also worked as Business Coordinator and Supervisor for a Chevron Products plant in California and held various positions with Chevron Canada’s Burnaby plant. In addition, Mr. Smith held positions as operations manager at Alberta Envirofuels and in project engineering at Turbo Resources.

Mr. Smith is a professional engineer in Alberta with membership in both APEGGA and APEGBC. He holds a B.A.Sc. in Chemical Engineering from the University of Waterloo.

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), Dunlap, van Hoften and Waterman. All four 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 2008 and 2007 in thousands of dollars:

	2008			2007	**
Audit fees	$	187	$	158
Audit-related fees		49		249
Tax fees		68		66
Other		37		-
TOTAL	$	347	$	473

** 2007 fees were adjusted for a fee credit that was received in 2008.

Audit fees were paid for professional services rendered by the auditors for the audit of our annual financial statements, review of interim quarterly financial statements and services provided for statutory and regulatory filings. Audit-related fees are in connection with language translation of public documents and services provided in connection with financing activities. Tax fees were primarily related to the completion of our corporate tax returns. Other fees in 2009 are related to environmental evaluation services provided.  PricewaterhouseCoopers LLP was engaged, based on associated expertise, to conduct a high level assessment of the readiness of OPTI’s Environmental Compliance Systems in anticipation of the start-up of operations.

As per the audit committee charter, 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 and to Future Phases of Development

The Project may be subject to delays, interruptions or costs that may materially adversely affect our results of operations.

There is a risk that the Project may have delays, interruption of operations or costs due to many factors, including, without limitation:

• labour disputes, disruptions or declines in productivity;

• 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 accidents, disruption or delays in availability of transportation services or adverse weather conditions affecting transportation;

• unforeseen site surface or subsurface conditions;

• disruption in the supply of energy; and

• catastrophic events such as fires, storms or explosions.

The information contained in this AIF, including, without limitation, reserve and economic evaluations, is conditional upon receipt and maintenance of all regulatory approvals and no material delays, interruptions of operations or unforeseen costs.

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

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

• the ability to ramp-up bitumen production or the Upgrader;

•  the ability to operate at the expected design rates of throughput or production;

•  the percentage conversion of bitumen to PSCtm; 

•  the quality and characteristics of the PSCTM; and

•  the reliability or availability of the facilities.

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

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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 Upgrader could compromise our ability to meet our obligations, including making debt repayments and interest payments.

There are technology license agreements in place for some SAGD and 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.

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.

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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 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 are currently in the process of putting operating insurance in place.  There is no guarantee that we will secure insurance as expected or at all.

The pool of project employees with the skills required for the Project is limited, so the Project  may not be able to hire all of the labour force required 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. The Project will compete with 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, the recent transaction with Nexen, and 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 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 (126,000 bbl/d net to OPTI). 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, stability in the financial markets and global economies, 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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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 (126,000 bbl/d net to OPTI). 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 currently in a period of significant retraction with low commodity prices, volatility in financial markets and weakness in global economies. As a result, Phase 2 and all future phases of the multistage expansion plan have been deferred to 2010 and beyond. Participation in the 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 and future expansions 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 future expansions, and reclamation of the associated 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 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 releasedthe 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. On March 10, 2008, the Canadian Federal Government elaborated on the Framework with the release of its Turning the Corner document.  It is contemplated that new regulations will take effect January 1, 2010.  Draft regulations were expected to be available for public comment in the Fall of 2008 and are now expected in mid-2009.

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The proposed regulatory framework provides that existing oil sands facilities in operation by 2004 will be subject to an 18 percent emission intensity reduction requirement commencing in 2010, with 2% additional annual reductions thereafter until 2020.  Emission intensity is the amount of GHG emissions per unit of production or output.  Facilities commissioned between 2004 to 2011 or facilities existing prior to 2004 which between 2004 and 2011 have had a major expansion resulting in an increase of 25 percent or more in physical capacity or which undergo a significant change to processes will be exempt from the 2010 emissions intensity reduction target of 18 percent but will have to report their emissions each year and after their third year of operation will be required to reduce their emissions intensity by 2 percent annually from a baseline emissions standard which is to be determined by reference to a sector-specific cleaner-fuel standard.  For oil sands facilities, it is contemplated that there will be specific cleaner-fuel standards based on the use of natural gas for each of mining, in situ and upgrading.  However, an incentive to deploy carbon capture and storage (CCS) has been included.  CCS is where carbon dioxide is separated from a facility's process or exhaust gas emissions before they are emitted, transferred from the facility to a suitable storage location, and injected into underground geological formations and monitored to ensure they do not escape into the atmosphere.  If a facility commissioned between 2004 and 2011 is built such that it is able or ready to undertake CCS, then it will be exempt from the cleaner-fuel standard until 2018 and it will only be required to reduce it's emission-intensity by 2 percent per year from its actual emissions.  In situ oil sands projects and oil sands upgraders built after 2011 must have their GHG emissions profiles by 2018 equivalent to that of facilities employing CCS technology.  The proposed regulatory framework further encourages widespread use of CCS by 2018 by crediting emitters that make use of CCS technology for investments in pre-certified CCS projects up to 100 percent of their regulatory obligations through 2017.

The proposed compliance mechanisms include an emissions credit trading system for GHGs and certain industrial air pollutants, and several options for companies to choose among to meet GHG emission intensity reduction targets and encourage the development of new emission reduction technologies, including the option of making payments into a technology fund, an emissions and offset trading system, limited credits for emission reductions created between 1992 and 2006, and international emission credits under the clean development mechanism under the Kyoto Protocol for up to 10 percent of each firm's regulatory obligation.

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.

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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.

American climate change legislation could negatively affect markets for crude and synthetic crude oil

Environmental legislation regulating carbon fuel standards in jurisdictions that import crude and synthetic crude oil in the United States could result in increased costs and/or reduced revenue.  For example, both California and the United States federal government have passed legislation which, in some circumstances, considers the lifecycle greenhouse gas emissions of purchased fuel and which may negatively affect marketing of our products, or require the purchase of emissions credits in order to affect sales in such jurisdictions.

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.

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

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

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

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 one year of production ramp-up on the Long Lake leases. Although we conducted pilot tests on the Long Lake leases reservoir and now have almost 12 months of data from ramp-up of the well pairs of Phase 1, there can be no assurance 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. However, based on early reservoir results, we believe our current estimates of SOR are reasonable. 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.

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Risks Relating to Commodity and Currency 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 among other things. 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;

• 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 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 PSCtmwill depend upon the demand for it, which is not currently proven.

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

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

We will be subject to foreign currency exchange fluctuation exposure.

Crude oil prices are generally based on a U.S. dollar market price, while certain of our operating and capital costs will be primarily in Canadian dollars. Fluctuations in exchange rates between the U.S. and Canadian dollar will therefore give rise to foreign currency exchange exposure. A material increase in the value of the Canadian dollar relative to the U.S. dollar may negatively affect our revenue by decreasing the Canadian dollars we receive for a given U.S. dollar price. OPTI is also exposed to foreign exchange rate risk on our U.S. dollar denominated debt. We may mitigate the impact of exchange rate fluctuations on the revenue from the Project or the U.S. dollar denominated debt 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.

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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.

Risks Relating to Technology

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

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

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

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

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

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

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

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

Risks Relating to Third Parties

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

Nexen is the operator of the Long Lake Project. We rely on Nexen’s operating expertise to generate cash flow from the Project and to provide information on the status and results of operations.

There are no assurances that Nexen will be able to generate forecasted SAGD volumes, which could compromise OPTI’s financial results.  Furthermore, there is no assurance that Nexen will be able to provide adequate financial and operational information on a timely basis.

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We will be subject to the risk of default by Nexen in meeting its financial commitments and/or other obligations to us, the Project, or future phases of project development. Such default by Nexen may adversely affect the continuation of the Project or future phases, the construction or operations of future phases, or other facets of the Project or future phases, 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.

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 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, 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.

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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 externally supplied natural gas;

• a railway spur for the transportation of Long Lake Upgrader products and by-products including sulphur disposal; 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 positions could have an adverse impact on the use of derivative instruments to effectively hedge our position.

Our banks could encounter financial difficulties.

We maintain significant cash balances and undrawn revolving credit facilities, primarily with large Canadian banks.  These banks could encounter financial difficulties that could prevent us from accessing these funds.

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 new royalty regime in Alberta, effective January 1, 2009, 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.

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.

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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 had announced plans to enter the oil sands business and begin production of synthetic crude oil, or expand existing operations. However similar to our announcement to delay the sanctioning of Phase 2 of our Project, these companies have also delayed or cancelled their expansion plans given the current economic climate. Consequently we are one of only two new Upgraders currently going on stream and there might not be any new Upgraders or refineries constructed for at least a few years. In the short term, this could be to our advantage. However, development of the Canadian oil sands region will continue in the future and 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.

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

We are subject to liquidity risk.

Liquidity risk is the risk that we are not able to meet our financial obligations as they fall due.  We incur monthly interest and standby payments relating to our Revolving Credit Facility, and full principal repayment of our Revolving Credit Facility is due in 2011.

We also have semi-annual interest payments due each year on our senior secured notes and full principal repayment of these notes is due in December 2014.

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During 2007 and 2008, global capital markets experienced a number of economic crises related to subprime lending and structured finance products, among other factors, which also impacted financial markets within Canada.  As a result, there has been a tightening of global credit markets characterized by a decline in liquidity and higher borrowing costs.  Although our current financial resources are considered sufficient for Phase 1, further deterioration of commodity prices and or operating issues with our SAGD or Upgrader operations could result in additional funding requirements.  Should the company require such funding, it may be difficult to obtain such financing on terms attractive to the company or at all.

If are not able to meet our debt covenants, we may need to repay our debt

Our Revolving Credit Facility contains certain covenants that serve to limit the amount of debt we are permitted to incur .  These maintenance covenants are ongoing conditions that must be satisfied to provide continued access to the Revolving Credit Facility.  If we are unable to meet the conditions of the debt covenants, we may be obligated to repay principal on the debt in advance of its maturity date.  At December 31, 2008, OPTI was in full compliance with its debt covenants relating to the Revolving Credit Facility.  (see: Description of Debt Capital)

If we are unable to obtain sufficient funding, we may lose our ownership interest in the Project and future phases.

Significant amounts of financing are required to develop the Project.  While the Project has begun operations, we continue to have financial obligations relating to completion of the steam debottlenecking plant and the ash processing unit, as well as sustaining capital costs.  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.

Subsequent to possible sanctioning of Phase 2, which is currently scheduled for consideration in 2010, we expect capital requirements in excess of operating cash flows. Unless we have stable operations at or near capacity for the Project and relatively high commodity prices, such external financing requirements will be significant.  We expect that these financing requirements will come at a higher cost and contain more restrictions than the prior financings completed by OPTI.  Current market conditions would not support such a financing requirement and therefore some improvement will be required between now and 2010 in order to support such development.

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 Project obligations. Should we fail to meet all or some part of our Project obligations, Nexen has the right, in certain circumstances, to acquire some or all of our interest in the Project (excluding our rights to the OrCrudetm Process technology and certain royalties payable to us) at 80 percent of cost.

We have 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 if we fail to meet all or some of our future phase obligations (excluding our rights to the OrCrudetm Process technology and certain royalties payable to us). See "Material Agreements Related to the Joint Venture - The New COJO Agreements".

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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.

MATERIAL CONTRACTS

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

1. the Purchase and Sale Agreement between OPTI and Nexen as more particularly described under the heading “Material Agreements Related to the Joint Venture”;

2. MOU between OPTI and Nexen as more particularly described under the heading "Material Agreements Related to the Joint Venture";

3. the COJO Agreement and New COJO Agreements between OPTI and Nexen as more particularly described under the heading "Material Agreements Related to the Joint Venture"; and

4. 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.

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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.

ADDITIONAL INFORMATION

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

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

Investor Relations

OPTI Canada Inc.

2100, 555 - 4th Avenue S.W.

Calgary, Alberta

T2P 3E7

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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 March 24, 2009;

"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;

“boe/d” means barrels of oil equivalent 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;

“EBITDA” means earnings before interest, depreciation, taxes and amortization.

"EUB" means the Alberta Energy and Utilities Board.  Effective January 1, 2008, the Alberta Energy and Utilities Board (EUB) has been realigned into two separate regulatory bodies: the  Energy Resources Conservation Board and the Alberta Utilities Commission.

“ERCB” means the Energy Resources Conservation Board, an independent, quasi-judicial agency of the Government of Alberta that regulates the safe, responsible, and efficient development of Alberta's energy resources: oil, natural gas, oil sands, coal, and pipelines.

“GHGs” means greenhouse gases, including water vapour, carbon dioxide, methane, and ozone, among others.

"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 PSCTM and syngas, as further described under the heading entitled "The OrCrude™ Process - Integrated OrCrude™ Upgrader";

“JV” means the joint venture between OPTI and Nexen;

“JV Participants means OPTI and Nexen;

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"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";

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

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

"MMbbl" means millions of barrels;

"mmbtu" means millions of British thermal units;

“Nexen Transaction” means the transaction, closed in January 2009, wherein OPTI sold  a 15 percent working interest in its joint venture assets to Nexen, as further desceibed under the heading “    “

"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 numerous U.S. and Canadian patents and patent applications;

"Phase 1" means the Long Lake Project, in a currently in a 65 percent (Nexen Inc.) / 35 percent (OPTI) joint venture.  This phase consists of 72,000 (bbl/d) of SAGD bitumen production integrated with an upgrading facility expected to produce 58,500 bbl/d of products, primarily 39° API premium sweet crude;

"PSCTM" means, generically, the premium, sweet, synthetic crude oil produced in the Integrated 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 was 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.

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APPENDIX A

RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The McDaniel Report, summarized below, reflects OPTI’s reserves and resources as of December 31, 2008 and with a 50 percent working interest in the joint venture. On January 27, 2009, OPTI announced that we had completed the sale of a 15 percent working interest in our joint venture assets to Nexen. Effective January 1, 2009, OPTI has a 35 percent working interest in all joint venture assets, including Phase 1 of the Long Lake Project, all future phase reserves and resources, and future phases of development.

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 1,147,842 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 are representative of the fair market value of the reserves.

Oil and Gas Reserves Based on Forecast Prices and Costs(9)
	Synthetic Crude Oil (PSCTM)				Bitumen						Butane
	Gross(1)		Net(1)		Gross(1)			Net(1)			Gross(1)		Net(1)
	(mbbl)		(mbbl)		(mbbl)			(mbbl)			(mbbl)		(mbbl)
Proved Developed Producing(2)(5)(6)		49,992		47,071		1,143			1,077			1,909		1,797
Proved Developed Non-Producing(2)(7)
Proved Undeveloped(2)(8)		159,634		136,534		14,927			12,999			6,095		5,213
Total Proved		209,626		183,606		16,071			14,076			8,004		7,011
Probable(3)		617,802		503,542		5,912			4,360			23,590		19,227
Total Proved Plus Probable		827,427		687,147		21,983			18,436			31,594		26,237
Possible (4)		75,037		53,476		(251	)		(475	)		2,865		2,042
Total Proved Plus Probable Plus Possible		902,465		740,623		21,732			17,961			34,459		28,279

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)	2,968	2,404	1,991	1,680	1,441	2,968	2,404	1,991	1,680	1,441
Proved Non-Producing	-	-	-	-	-	-	-	-	-	-
Proved Undeveloped(2)(8)	8,755	4,325	2,355	1,394	885	6,580	3,250	1,777	1,060	680
Total Proved	11,723	6,729	4,346	3,074	2,326	9,548	5,654	3,768	2,740	2,121
Probable (3)	43,652	9,742	2,500	485	(191)	32,541	7,106	1,660	147	(352)
Total Proved Plus Probable	55,376	16,471	6,846	3,559	2,135	42,089	12,760	5,428	2,887	1,769
Possible 4)	8,874	1,616	575	361	289	6,612	1,226	461	306	255
Total Proved Plus Probable Plus Possible	64,249	18,087	7,421	3,920	2,424	48,701	13,986	5,889	3,194	2,024

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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)
	Revenue		Royalties		Operating Costs		Development Costs		Abandonment Costs		Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
	(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)
Total Proved(2)		24,832		2,379		8,344		2,454		60		11,723		2,176		9,548
Total Proved Plus Probable(2)(3)		124,120		15,824		36,692		16,049		309		55,376		13,287		42,089
Total Proved Plus Probable Plus Possible(2)(3)(4)		139,012		18,609		38,944		17,011		328		64,250		15,548		48,701

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)
	Production Group	Future Net Revenue Before Income Taxes (Discounted at 10%/Year)
		Total		Unit Basis
		(MM$)		($/bbl of raw bitumen)
Total Proved(2)	Bitumen, synthetic crude oil, and butane		4,346		15.65
Total Proved Plus Probable(2)(3)	Bitumen, synthetic crude oil, and butane		6,846		6.49
Total Proved Plus Probable Plus Possible(2)(3)(4)	Bitumen, synthetic crude oil, and butane		7,421		6.47

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Reserves Reconciliation

The following table sets forth the changes between the reserve volume estimates made as at December 31, 2008 and the corresponding estimates as at December 31, 2007, 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, 2007		16,055			201,709		2,769		220,553			13,417			417,864			5,736		437,017		29,471			619,573		8,504		657,548
Extensions		16			7,917		165		8,098			6,456			199,938			2,760		209,154		6,472			207,855		2,925		217,253
Improved Recovery		-			-		-		-			-			-			-		-		-			-		-		-
Technical Revisions		1,685			-		5,070		6,755			(13,961	)		-			15,094		1,133		(12,276	)		-		20,164		7,888
Discoveries		-			-		-		-			-			-			-		-		-			-		-		-
Acquisitions		-			-		-		-			-			-			-		-		-			-		-		-
Dispositions		-			-		-		-			-			-			-		-		-			-		-		-
Economic Factors		-			-		-		-			-			-	��		-		-		-			-		-		-
Production (Estimate)		(1,685	)		-		-		(1,685	)		-			-			-		-		(1,685	)		-		-		(1,685	)
Dec 31, 2008		16,071			209,626		8,004		233,701			5,912			617,802			23,590		647,304		21,983			827,427		31,594		881,004

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)
	First Attributed			Synthetic Cumulative		First Attributed			Bitumen Cumulative		First Attributed			Butane Cumulative
2005		175,060			175,060		19,989			19,869		2,403			2,403
2006		(31,913	)		143,147		(17,484	)		2,385		(438	)		1,965
2007		58,562			201,709		13,670			16,055		804			2,769
2008		(42,075	)		159,634		(1,128	)		14,927		3,326			6,095

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)
	First Attributed			Synthetic Cumulative		First Attributed			Bitumen Cumulative		First Attributed			Butane Cumulative
2005		172,591			172,591		1,726			1,726		2,369			2,369
2006		(6,540	)		166,051		3,554			5,280		(90	)		2,279
2007		251,813			417,864		8,137			13,417		3,457			5,736
2008		194,073			611,937		(7,640	)		5,777		17,628			23,364

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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 proved and probable undeveloped reserves associated with Phase 2.   We plan to be in a position to sanction Phase 2 in mid-2010 at the earliest.  Subsequent to Phase 2 sanctioning, 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, we would expect no change in reserves or future net revenue, and does not expect it to make the development of the property uneconomic.

Future Development Costs Based on Forecast Prices and Costs
	Total Proved(2)		Total Proved Plus Probable(2)(3)
	(MM$)		(MM$)
2009		109		139
2010		66		180
2011		141		521
2012		12		871
2013		44		997
Total for all years undiscounted		2,454		16,049
Total for all years discounted at 10%/year		939		4,115

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.

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	Oil			Synthetic Oil		Condensate	Butane	Natural Gas	Bitumen			Inflation Rate	Exchange Rate
	WTI Crude Oil Price $US/bbl	Edmonton Light Oil Price $Cdn/bbl	WCS Hardisity Oil Price $Cdn/bbl	Edmonton Synthetic Oil Price $Cdn/bbl	PSC at Long Lake Synthetic Oil Price $Cdn/bbl	Edmonton Condensate Price $Cdn/bbl	Field Butane Price $Cdn/bbl	Alberta Spot Gas Price $Cdn/mmbtu	DilBit at Hardisty CDN$/Bbl		Bitumen Netback CDN$/Bbl	%/ year	$US/$Cdn
Forecast
2009	60.00	69.60	53.65	73.60	74.31	71.60	47.35	7.02		53.65	40.23	2.0	0.850
2010	71.40	83.00	63.84	85.00	85.73	85.00	57.08	7.59		63.84	48.20	2.0	0.850
2011	83.20	91.40	70.26	92.90	93.64	93.50	63.20	8.01		70.26	52.90	2.0	0.900
2012	90.20	93.90	72.16	94.90	95.66	96.00	64.92	8.34		72.16	54.39	2.0	0.950
2013	97.40	96.30	74.02	96.30	97.07	98.50	66.55	8.58		74.02	55.83	2.0	1.000
2014	99.40	98.30	75.54	97.80	98.59	100.50	67.97	8.77		75.54	56.99	2.0	1.000
2015	101.40	100.30	77.06	99.30	100.10	102.60	69.39	8.96		77.06	58.10	2.0	1.000
2016	103.40	102.30	78.58	100.80	101.62	104.60	70.71	9.10		78.58	59.25	2.0	1.000
2017	105.40	104.20	80.10	102.67	103.51	106.50	72.02	9.29		80.10	60.45	2.0	1.000
2018	107.60	106.40	81.78	104.84	105.69	108.80	73.54	9.48		81.78	61.68	2.0	1.000
2019	109.70	108.50	83.37	106.91	107.78	110.90	75.05	9.67		83.37	62.90	2.0	1.000
2020	111.90	110.70	85.04	109.08	109.96	113.20	76.56	9.86		85.04	64.12	2.0	1.000
2021	114.10	112.80	86.72	111.14	112.05	115.30	77.97	10.05		86.72	65.44	2.0	1.000
2022	116.40	115.10	88.46	113.41	114.33	117.70	79.58	10.24		88.46	66.72	2.0	1.000
2023	118.80	117.50	90.29	115.78	116.72	120.10	81.17	10.48		90.29	68.12	2.0	1.000
2024	121.18	119.85	92.09	118.09	119.05	122.50	82.79	10.69		92.09	69.48	2.0	1.000
2025	123.60	122.25	93.94	120.45	121.43	124.95	84.45	10.90		93.94	70.87	2.0	1.000
2026	126.07	124.69	95.81	122.86	123.86	127.45	86.14	11.12		95.81	72.29	2.0	1.000
2027	128.59	127.19	97.73	125.32	126.34	130.00	87.86	11.34		97.73	73.73	2.0	1.000
2028	131.16	129.73	99.69	127.83	128.87	132.60	89.62	11.57		99.69	75.21	2.0	1.000
2029	133.79	132.32	101.68	130.38	131.44	135.25	91.41	11.80		101.68	76.71	2.0	1.000
2030	136.46	134.97	103.71	132.99	134.07	137.96	93.24	12.04		103.71	78.24	2.0	1.000
2031	139.19	137.67	105.79	135.65	136.76	140.72	95.10	12.28		105.79	79.81	2.0	1.000
2032	141.98	140.42	107.90	138.36	139.49	143.53	97.00	12.52		107.90	81.41	2.0	1.000
2033	144.82	143.23	110.06	141.13	142.28	146.40	98.94	12.77		110.06	83.03	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, 2009 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.

Oil Wells

As at December 31, 2008, we had an interest in 81 gross (40.5 net) SAGD well pairs.  These well pairs are contained within the Long Lake SAGD operation and are comprised of 78 gross (39 net) oil wells and 78 gross (39 net) injection wells, the remainder are within the SAGD Pilot and are comprised of 3 gross (1.5 net) producing oil wells and 3 gross (1.5 net) injection wells.

Properties with No Attributed Reserves

The Long Lake Leases comprise 98 sections. Proved, probable and possible reserves have been assigned, in whole and in part, on 70 sections of these lands and 28 sections have no reserves assigned.  resources have been assigned to some of these 28 sections. At January 26, 2009, we have a 35 percent working interest in all of these lands.

At January 26, 2009, we have a 35 percent working interest in an additional306 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.

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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 amended financial statements at December 31, 2008 is $8 million for our 50 percent working interest. The total undiscounted future amount of abandonment liabilities expected to be incurred is $151million based on measurement criteria under Canadian GAAP. These liabilities relate to facilities and wells completed or under construction at the end of 2008. At December 31, 2008, there are 81 gross wells for which abandonment liabilities have been recognized.  These gross wells include the SAGD Pilot wells and the commercial SAGD 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 $56 million net to us.

We incurred negligible abandonment costs in 2008 and expect to incur none in the next two years.

Tax Horizon

We did not pay any current income taxes in our fiscal year ended December 31, 2008. 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.

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Costs Incurred

The following table sets forth costs incurred by us for Oil and Gas activities for the year ended December 31, 2008:

($ millions) Property Acquisition Costs (1)
Proved Properties	Unproved Properties	Exploration Costs	Development Costs (2)
$0	$0	$71	$361

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, 2008, costs incurred by us in relation to the Upgrader were $282 million.

Exploration and Development Activities

During 2008, no SAGD horizontal wells were drilled.

Production Estimates

McDaniel estimates, based on the proved plus probable case, that the Project will produce on average approximately 41,150 bbl/d (20,575 bbl/d net to OPTI’s 50 percent working interest) of raw bitumen in 2009.  The start-up of the Upgrader and commencement of synthetic crude oil and butane sales occurred in January, 2009.

It is assumed that adequate well pairs will be drilled to keep the upgrader full until the cumulative recoverable 2P reserves are produced.  With regards to the production profile in the near term, the production rate has been based on McDaniel & Associates assumptions of well-pair productivity and well-pair drilling schedule.  McDaniel holds different views regarding well-pair productivity than OPTI and Nexen.  The result of which is the requirement for additional wells in the next few years to reach facility production capacity.  

Production History

The Long Lake Project began producing bitumen in the second quarter of 2008.  The Upgrader started up in the first quarter of 2009.  During the initial operating period, we expect periods of Upgrader down time but anticipate that the stability of operations will continue to improve.  It is anticipated that the Project will ramp-up through 2009 and reach design rates of 72,000 bbl/d of bitumen, upgraded into 58,500 bbl/d of PSC™ and other products, in 2010.

Prior to stable Upgrader operations, the SAGD operation will consume a significant amount of natural gas.  At full production, we expect to self-supply the equivalent of 100 million cubic feet per day of natural gas through the use of our proprietary integrated OrCrude™ process.

The netbacks illustrated below are not representative of expected commercial operations.  They reflect relatively low production volumes during the initial ramp-up of SAGD volumes.  Further, they are calculated for SAGD operations only, as the Upgrader was not yet operational in 2008.

For an illustration of expected netbacks upon reaching full commercial production, see “Estimated Future Project Netbacks” on page 8 of this document.

	Q3 2008	Q4 2008
Bitumen production (bbl/day) (1)	5,215	6,596

Netback

In CDN$/bbl (2)		Q3 2008			Q4 2008
	$/bbl			$/bbl
Revenue (3)	$	71.91		$	0.28
Royalties		(0.67	)		(0.07	)
Production costs (4)		(77.20	)		(78.33	)
Netback	$	(5.96	)	$	(78.12	)

Notes:

(1) Bitumen production is OPTI’s share only.  Volumes prior to Q3 2008 are not considered material.

(2) Per barrel calculations are based on bitumen production.

(3)	Bitumen revenue per barrel is based on the value assigned to bitumen for royalty calculation purposes.
(4)	Production costs only include SAGD operating costs.

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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 "Company"):

1. We have evaluated the Corporation's reserves data as at December 31, 2008. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2008, estimated using forecast prices and costs.

2. The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook.

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us, for the year ended December 31, 2008, and identifies the respective portions thereof that we have evaluated and reported on to the Company’s management:

		Net Present Value of Future Net Revenue (before income taxes, 10 percent discount rate, in $MM)
Preparation Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated	Reviewed	Total
February 11, 2009	Canada	-	6,846	-	6,846

5. 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.

6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation date.

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

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Executed as to our report referred to above:

McDaniel & Associates Consultants Ltd., Calgary, Alberta, Canada

Dated February 11, 2009

(signed)"C.B. Kowalski P.Eng”

Vice President

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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, 2008, estimated using forecast prices and costs and the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated the Corporation's reserves data. The report of the independent qualified reserves evaluator is presented in Appendix B to this Annual Information Form.

The Technical Committee of the board of directors of the Corporation has:

(a) reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

The Technical Committee of the board of directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Technical Committee, approved:

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

(b) the filing Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and

(c) the content and filing of this report.

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

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(signed) "Sid W. Dykstra"

President and Chief Executive Officer

(signed) “William King”

Vice President, Development

(signed) "Charles Dunlap"

Director

(signed) "Edythe (Dee) Marcoux"

Director

Dated  March 24, 2009

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APPENDIX D

AUDIT COMMITTEE CHARTER

A.            FUNCTION

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

B.           CONSTITUTION

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

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

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

C.           COMMUNICATION, AUTHORITY TO ENGAGE ADVISORS

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

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

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

D.            MEETINGS, MINUTES AND REPORTING

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

(a) the Audit Committee meets at least quarterly;

(b) the Audit Committee shall meet prior to Board meetings for the purpose of reviewing and preparing recommendations to the Board;

(c) agendas and preparation documents are sent to members with sufficient time for study prior to the meetings;

(d) there be a quorum of two members present in person or via phone;

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(e) in the absence of the Audit Chair, a chair for a meeting is chosen at the meeting;

(f) resolutions are decided by a majority vote, the chair not having a second or casting vote; and

(g) the Audit Committee shall hold in camera sessions at every meeting, (1) without management present, and (2) without the auditor present.

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

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

E.            STEWARDSHIP FUNCTIONS

Relationship with External Auditor

1. The Audit Committee shall:

(a) consider and make a recommendation to the Board as to the appointment of the external auditor, ensuring that such auditor is a participant in good standing pursuant to applicable securities laws;

(b) consider and make a recommendation to the Board as to the compensation of the external auditor;

(c) oversee the work of the external auditor and oversee the resolution of any disagreements between management of the Corporation and the external auditor;

(d) review and discuss with the external auditor all significant relationships that the external auditor and its affiliates have with the Corporation and its affiliates in order to determine the external auditor's independence, including, without limitation:

(i) requesting, receiving and reviewing, on a periodic basis, a formal written statement from the external auditor delineating all relationships that may reasonably be thought to bear on the independence of the external auditor with respect to the Corporation;

(ii) discussing with the external auditor any disclosed relationships or services that may impact the objectivity and independence of the external auditor; and

(iii) recommending that the Board take appropriate action in response to the external auditor's report to satisfy itself of the independence of the external auditor;

(e) review and approve the audit plan of the external auditor with the external auditor, including the staffing thereof, prior to the commencement of the audit;

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(f) as may be required by applicable securities laws, rules and guidelines, either:

(i) pre-approve all non-audit services to be provided by the external 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

1. 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

1. 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

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS

For the year ended

December 31, 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis (MD&A) dated February 24, 2009 should be read in conjunction with the audited financial statements for the year ended December 31, 2008.

FORWARD-LOOKING INFORMATION

The MD&A is a review of our financial condition and results of operations. Our financial statements are prepared based upon Canadian Generally Accepted Accounting Principles (GAAP) and all amounts are in Canadian dollars unless specified otherwise.  Certain statements contained herein are forward-looking statements, including, but not limited to, statements relating to: the expected production performance of the Long Lake Project; OPTI Canada Inc.'s (OPTI) other business prospects, expansion plans and strategies; the cost, development and operation of the Long Lake Project and OPTI's relationship with Nexen Inc. (Nexen); OPTI's financial outlook respecting the estimate of the netback for Phase 1 of the Project; OPTI's anticipated financial condition and liquidity over the next 12 to 24 months; and our estimated future tax liability. Forward-looking information typically contains statements with words such as “intends,” "anticipate," "estimate," "expect," "potential," "could," “plan” or similar words suggesting future outcomes. Readers are cautioned not to place undue reliance on forward-looking information because it is possible that expectations, predictions, forecasts, projections and other forms of forward-looking information will not be achieved by OPTI. By its nature, forward-looking information involves numerous assumptions, inherent risks and uncertainties. A change in any one of these factors could cause actual events or results to differ materially from those projected in the forward-looking information. Although OPTI believes that the expectations reflected in such forward-looking statements are reasonable, OPTI can give no assurance that such expectations will prove to be correct.  Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by OPTI and described in the forward-looking statements or information.  The forward-looking statements are based on a number of assumptions which may prove to be incorrect.  In addition to other assumptions identified herein, OPTI has made assumptions regarding, among other things: market costs and other variables affecting operating costs of the Project;  the ability of the Long Lake Project joint venture partners to obtain equipment, services and supplies, including labour, in a timely and cost-effective manner; the availability and costs of financing; oil prices and market price for the Premium Sweet Crude (PSC™) output of the OrCrude™ Upgrader; foreign currency exchange rates and hedging risks;  government regulations and royalty regimes; and the degree of risk that governmental approvals may be delayed or withheld.  Other specific assumptions and key risks and uncertainties are described elsewhere in this document and in OPTI's other filings with Canadian securities authorities.

Readers should be aware that the list of assumptions, risks and uncertainties set forth herein are not exhaustive.  Readers should refer to OPTI's current Annual Information Form (AIF), which is available at www.sedar.com, for a detailed discussion of these assumptions, risks and uncertainties. The forward-looking statements or information contained in this document are made as of the date hereof and OPTI undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable laws or regulatory policies.

2

Reserve and Resource Estimates: The estimates of resources and of economically recoverable bitumen reserves contained herein are forward-looking statements. The estimates 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 government 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 are only attempts to define the degree of uncertainty involved. The estimates contained herein with respect to reserves and resources that may be developed and produced in the future have been based upon volumetric calculations and upon analogy to similar types of reserves and 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 and resources based upon production history will result in variations, which may be material, in the estimated reserves and resources.

Additional information relating to our Company, including our AIF, can be found at www.sedar.com.

FINANCIAL SUMMARY

In millions		Years ended December 31
		2008			2007			2006
Earnings (loss)	$	(257)		(1)	$	(9	)	$	(10	)
Total oil sands expenditures (2)			775			961			1,056
Working capital (deficiency)  (3)			(25	)		271			554
Shareholders’ equity	$		1,556		$	1,816		$	1,444
Common shares outstanding (basic)		195.9		(4)		195.4			172.7

Notes:

(1) Includes $392 million pre-tax asset impairment provision related to working interest sale to Nexen.

(2) Capital expenditures related to Phase 1 and future phase development. Capitalized interest, hedging gains/losses and non-cash additions or charges are excluded.

(3) Includes current portion of interest reserve account where applicable and amounts due in June 2009 in relation to our $150 million revolving debt facility.  This $150 million facility was repaid and cancelled in January 2009.

(4) Common shares outstanding at the end of 2008 after giving effect to the exercise of common share options would be approximately 203 million common shares.

OVERVIEW

OPTI Canada Inc. is a Calgary, Alberta-based company focused on developing major oil sands projects in Canada using our proprietary OrCrude™ process. Our first project, Phase 1 of the Long Lake Project (the Project), consists of 72,000 barrels per day of SAGD (steam assisted gravity drainage) bitumen production integrated with an upgrading facility. The Upgrader uses the OrCrude™ process combined with commercially available hydrocracking and gasification. Through gasification, this configuration substantially reduces the exposure to and the need to purchase natural gas. On a 100 percent basis, the Project is expected to produce 58,500 bbl/d of products, primarily 39 degree API Premium Sweet Crude (PSC™) with low sulphur content, making it a highly desirable refinery feedstock. Due to its premium characteristics, we expect PSCTM to sell at a price similar to West Texas Intermediate (WTI) crude oil. The Project is being operated in a joint venture with Nexen Inc. (Nexen).

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PROJECT STATUS

First production of PSC™ from the Long Lake Project was achieved in January 2009. Preparation is underway to transition gasifier feed from vacuum residue to asphaltenes, the final step in Upgrader commissioning. Synthesis gas from the Upgrader has been used in SAGD operations, decreasing operating costs by reducing the requirement for purchased third-party natural gas.  During the initial operating period, we expect periods of downtime but anticipate that the stability of operations will continue to improve. The Upgrader is currently gasifying but not producing PSC™ due to issues with water supply and treating but is expected to resume production in the near future.  Essentially all of the PSC™ produced to date has been used as diluent.

During the final commissioning phase, prior to the operation of the solvent deasphalting and thermal cracking units, there is a high percentage of diluent that feeds the Upgrader and continues to the hydrocracker, forming part of the PSC™ stream. We have produced over 20,000 bbl/d (gross) of on-spec PSC™, with between 10,000 and 12,000 bbl/d (gross) of this representing upgraded bitumen. The remainder represents diluent processed through the Upgrader. The percentage of diluent in the Upgrader feed will decrease as bitumen production increases.

We expect Upgrader capacity during ramp-up will be capable of processing all of the forecasted SAGD volumes and we expect the Project to reach full capacity of approximately 58,500 bbl/d of PSC™ and other products in 12 to 18 months.

The reservoir continues to perform as expected given the amount of steam we have injected. However, SAGD ramp-up has been affected by a variety of surface issues that have limited the amount of steam we have been able to inject into the reservoir over the past few months due to power disruptions, extreme cold weather, and water temperature and treating issues. Since steam injection rates directly impact bitumen production rates, and the ability to generate steam is currently limited, bitumen production is lower than previously expected. Solutions are being developed to place more heat into the front end of the steaming process to supplement the heat returns from the reservoir. Given steaming constraints, allocation of steam was necessary and accordingly only 32 of 81 well pairs are presently in production mode. January bitumen production averaged approximately 13,000 bbl/d (gross). As steam capacity increases, the remaining wells will be brought on-stream.

ADVANCING FUTURE PHASES

Our capital program for 2009 includes funds allocated to advance detailed engineering on the SAGD and Upgrader facilities for Phase 2 of the Project and also includes funds for additional core hole drilling to further delineate our nearer-term development leases.

Regulatory approval for Phases 2 and 3 of SAGD development at Long Lake (Long Lake South) was received in February 2009. Phase 2 sanctioning will depend on multiple factors including initial performance of Phase 1, receiving regulatory approval for Phase 2 SAGD operations, receiving clarity on proposed climate change regulations, developing cost estimates and an improved economic environment. We therefore do not expect to consider sanctioning Phase 2 until mid-2010 at the earliest.

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COMPLETION OF ASSET SALE AND DEBT FACILITY AMENDMENT

On January 27, 2009, OPTI announced that we had completed the sale of a 15 percent working interest in our joint venture assets to our partner Nexen for $735 million. Effective January 1, 2009 , OPTI has a 35 percent working interest in all joint venture assets, including Phase 1 of the Project, all future phase reserves and resources, and future phases of development.

As a result of the asset sale, our revolving debt facilities were amended on January 27, 2009. Significant changes include:

• $150 million revolving credit facility was repaid and cancelled;

• $500 million revolving credit facility was reduced to $350 million, a total of approximately $400 million was repaid through February 17, 2009, and applicable interest rates were increased by approximately 2 to 4 percent depending on our debt ratings;

• First lien to earnings before interest, tax, depreciation and amortization (EBITDA) covenant commences in the third quarter of 2009 with a maximum ratio 2.5:1 as defined in Note 10 to the audited financial statements for the year ended December 31, 2008 (previously the first quarter of 2009 and a ratio of 3.5:1);

• Debt to capitalization ratio was increased to 70 percent from 65 percent also as defined in Note 10 to the audited financial statements for the year ended December 31, 2008; and

• The Canadian measurement of our U.S. dollar-denominated debt was changed from a period end exchange rate to an average rate for the preceding quarter.

CORPORATE UPDATE

OPTI’s management team is transitioning as a result of the asset sale to Nexen.  David Halford, Chief Financial Officer, Mary Bulmer, VP Human Resources and Corporate Services, and Peter Duda, VP Operations will be leaving to pursue other business opportunities. They will remain with OPTI for various periods to continue to facilitate the transition.

Travis Beatty has been appointed Vice President, Finance and Chief Financial Officer of OPTI effective March 1, 2009. Mr. Beatty joined OPTI in 2002 as Controller and since then has also held the roles of Treasurer and Director, Planning. Mr. Beatty is a Chartered Accountant and a Chartered Financial Analyst, and holds a B.Comm from the University of Calgary.

Al Smith has been appointed Vice President, Marketing effective March 1, 2009. Mr. Smith joined OPTI in 2006 as Director, Marketing. Mr. Smith is a professional engineer in Alberta and is a member of both APEGGA and APEGBC. He holds a B.A.Sc. in Chemical Engineering from the University of Waterloo.

Going forward, OPTI’s senior management team will consist of: Sid Dykstra, President and Chief Executive Officer; Travis Beatty, VP Finance and CFO; Joe Bradford, VP Legal and Administration and Corporate Secretary; Bill King, VP Development; and Al Smith, VP Marketing.

5

RESERVES AND RESOURCES

OPTI has a significant presence in the Athabasca oil sands, with a 35 percent interest in over 385 sections of land on three leases:  Long Lake, Leismer and Cottonwood.  We believe our existing lands will support approximately 360,000 bbl/d of PSCTM production (126,000 bbl/d net to OPTI) from six phases including Long Lake Phase 1. Based on reserve and resource estimates, we believe there is potential for three phases at Long Lake, two phases at Leismer and one at Cottonwood. With a limited delineation program in the 2007/2008 winter drilling season, total reserve and resource volumes did not change significantly.

Reserves

McDaniel & Associates (McDaniel), our reserves and resources evaluator, has prepared a report evaluating the bitumen reserves and synthetic oil reserves of the Long Lake leases effective December 31, 2008. Due to the advanced nature of our Long Lake Phase 2 project, previously recognized Contingent Resources are now booked as probable and possible reserves.  

For 2008, McDaniel has also recognized probable and possible reserves associated with lands outside the Phase 2 initial development area to include certain lands pertaining to Phase 3 development. This is due, in part, to the inclusion of Phase 3 lands in the Long Lake South Environmental Impact Assessment, requisite levels of delineation being met on the Phase 3 lands, as well as McDaniels’ confidence in the development of these lands now that Phase 1 is commercial.

The McDaniel evaluation of our lands recognizes the impact of upgrading on the resources. 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 was sold prior to Upgrader start-up, is planned to be sold during periods of Upgrader downtime, and is shown as bitumen reserves.

The following table shows OPTI’s 50 percent working interest in the raw bitumen reserves and the corresponding sales volumes at December 31, 2008, prior to taking account of the sale of the 15 percent working interest.

2008 (prior to the sale of the 15 percent working interest)

	Raw Bitumen		Gross Sales Volumes
All volumes are millions of barrels			PSC™		Bitumen		Butane
Proven (1)		278		210		16		8
Proven plus probable (2)		1,054		827		22		32
Proven plus probable plus possible (3)		1,148		902		22		34

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The following table shows OPTI’s 35 percent working interest in the raw bitumen reserves and the corresponding sales volumes as at December 31, 2008 after taking account of the sale of the 15 percent working interest.

2008 (subsequent to the sale of the 15 percent working interest)

	Raw Bitumen		Gross Sales Volumes
All volumes are millions of barrels			PSC™		Bitumen		Butane
Proven (1)		194		147		11		6
Proven plus probable (2)		738		579		15		22
Proven plus probable plus possible (3)		803		632		15		24

Notes to both reserve tables:

(1) Proven 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 proven reserves.

(2) Probable reserves are those additional reserves that are less certain to be recovered than proven reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proven plus probable reserves.

(3) 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 proven plus probable plus possible reserves.

Resources

In addition to estimating our reserves, McDaniel has estimated bitumen resources on all of OPTI’s lands including the Long Lake, the Leismer and the Cottonwood leases.  A summary of the additional resource estimates as at December 31, 2008, on a 50 percent working interest basis prior to taking into account the 15 percent working interest sale is shown below:

2008 (prior to the sale of the 15 percent working interest)

All volumes are millions of barrels	Raw Bitumen (1)
Remainder of Long Lake leases (2)		363
Leismer (2)		954
Cottonwood (3)		717
Total		2,033

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The following table shows OPTI’s 35 percent working interest in the additional resource estimates after taking account of the sale of the 15 percent working interest.

2008 (subsequent to the sale of the 15 percent working interest)

All volumes are millions of barrels	Raw Bitumen(1)
Remainder of Long Lake leases (2)		254
Leismer (2)		668
Cottonwood (3)		502
Total		1,424

Notes to both resource tables:

(1) These estimates represent the "best estimate" of our resources, are not classified or recognized as 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.

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 resources rather than reserves primarily due to less delineation and the absence of regulatory approvals, detailed design estimates and near-term development plans.

(3) The resource estimate for Cottonwood is categorized as both Contingent and Prospective Resources. The estimate of 717 million barrels prior to the sale of the 15 percent working interest would be comprised of 274 MMbbl of Contingent Resources and 443 MMbbl of Prospective Resources. After taking account for the sale of the 15 percent working interest, the estimate of 502 million barrels is comprised of 192 MMbbl of Contingent Resources and 310 MMbbl of Prospective Resources. These Contingent Resource volumes are classified as resources rather than reserves 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.

NETBACKS

We provide a financial outlook of our estimated netback for Phase 1 of the Project that was last updated in our third quarter MD&A dated October 28, 2008. The netback calculation shown below is consistent with this most recent update and includes our estimates of revenue, royalties, operating costs and General and Administrative (G&A) expenses per barrel of product sold.

This financial outlook is intended to provide investors with a measure of the ability of our Project to generate netbacks assuming full production capacity. We believe that the ability of the Project to generate cash to fund interest payments and future phases of development is a key advantage of our Project and important to our investors. The netback measure is the most appropriate financial gauge to demonstrate this ability as corporate costs, interest, and other non-cash items are excluded from the calculation. The financial outlook may not be suitable for other purposes. Netbacks generated by our Project are expected to be lower than shown in this outlook in the years following start-up due to the lower production volumes during ramp-up and an initially higher steam-to-oil ratio (SOR). The netback calculation as presented is a non-GAAP measure. The closest GAAP measure to the netback calculation is cash flow from operations. However, cash flow from operations includes many other corporate items that affect cash and are independent of the operations of the Project.

8

The actual netbacks achieved by the Project could differ materially from these estimates. The material risk factors that we have identified toward achieving these netbacks are as outlined in the Forward-Looking Information section of this document and in our 2007 Annual Information Form (AIF).  In particular; the SAGD and Long Lake Upgrader facilities may not operate as planned; the operating costs of the Project may vary considerably during the operating period; our results of operations will depend upon the prevailing prices of oil and natural gas in the worldwide market and those prices can fluctuate substantially; we will be subject to foreign currency exchange fluctuation exposure; and our operating cash flows will be directly affected by the applicable royaltyregime relating to our business.  The key assumptions relating to the netback estimate are set out in the notes beneath the table.

Estimated Future Project Netbacks(1)

In CDN$/bbl	Post-payout			Pre-payout
	$/bbl			$/bbl
Revenue(1,2)	$	86.33		$	86.33
Royalties and G&A(3)		(8.43	)		(3.84	)
Operating costs(4)
Natural gas(5)		(3.90	)		(3.90	)
Other variable(6)		(2.76	)		(2.76	)
Fixed		(12.82	)		(12.82	)
Property taxes and insurance(7)		(3.55	)		(3.55	)
Netback	$	54.87		$	59.46

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. These numbers are cash costs only and do not reflect non-cash charges.  See “Forward-Looking Statements.”

(2) For purposes of this projection, we assume a WTI price of US$75/bbl, foreign exchange rates of CDN$1.00 to US$0.85 and an electricity sales price of $106 per megawatt hour. Revenue includes sale of PSCtm, bitumen, butane and electricity.

(3) Royaltiesare calculated based on a light/heavy differential of 30 percent of WTI. We anticipate payout for royalty purposes to occur in approximately 2022 based on the assumptions noted.

(4) Costs are in 2009 dollars.

(5) Natural gas costs are based on our long-term estimate for a SOR of 3.0.

(6) Includes approximately $1.00/bbl for greenhouse gas mitigation costs based on an approximate average 20 percent reduction of CO2 emissions at a cost of $20 per tonne of CO2.

(7) Property taxes are based on expected mill rates for 2009.

Sustaining capital costs required to maintain production at design rates of capacity are estimated to be approximately $8 to $9 per barrel of PSC™, assuming full design rate production adjusted for long-term on-stream expectations.  The netbacks as shown are prior to abandonment and reclamation costs.  We do not include these costs due to the long-term nature of our assets.

9

CAPITAL EXPENDITURES

Our financial condition to date has been affected primarily by capital expenditures in connection with the construction, commissioning and start-up of the Project, related financings and the capital expenditures associated with the development of future phases.

The Project is essentially complete as of December 31, 2008.  The remaining capital costs relate to the completion of the steam expansion project, expected in 2009, and the ash processing unit in the following year.  The cost to complete these two projects is approximately $45 million net to OPTI.

The table below identifies historical expenditures incurred by us in relation to the Project, other oil sands activities and other capital expenditures.

In millions	Year ended 2008			Year ended  2007			Year ended  2006
Long Lake Project - Phase 1
Upgrader	$	282		$	529		$	476
SAGD		195			282			440
Sustaining capital and capitalized operations		164			54			-
Total Long Lake Project		641			865			916
Other oil sands activities		134			96			140
Total oil sands expenditures		775			961			1,056
Capitalized interest		177			130			47
Other capital expenditures		35			17			6
Realized gain on foreign currency hedging instruments		(114	)		-			-
Total cash expenditures		875			1,108			1,109
Non-cash capital charges		309			(212	)		66
Total capital expenditures	$	1,184		$	896		$	1,175

For the year ended December 31, 2008, we incurred capital expenditures of $1,184 million. Phase 1 expenditures related to Upgrader and SAGD were primarily related to the completion of construction, commissioning and start-up of the Upgrader, and ongoing construction of the steam expansion project. Sustaining capital in 2008 related primarily to the installation of electric submersible pumps on some of our wells and engineering and resource delineation for future Phase 1 well pads.

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For the year, our share of the net SAGD operations was a net cost of $101 million.  The SAGD operating results during the year were comprised of Premium Synthetic Heavy (PSH) sales of $268 million, power sales of $19 million, operating costs of $141 million, diluent and feedstock volumes consumed costs of $236 million and transportation costs of $11 million. These operating results reflect early stage SAGD operations and relatively low production volumes during the second half of 2008. During the three months ended September 30, 2008, our net SAGD operating results resulted in a cost of $5 million. During the three months ended December 31, 2008, our net SAGD operating results resulted in a cost of $96 million. The fourth quarter net operations costs were due in part to natural gas purchases of $22 million and diluent purchases of $70 million; with the start-up of the Upgrader in January 2009, these costs will largely be avoided. Continuing challenges with SAGD surface equipment also kept volumes relatively low in the quarter. As a result of the timing of certain of our purchases and light heavy spreads during the fourth quarter, our diluent costs approximated our revenue from PSH.  We will not have exposure to bitumen blend revenue or diluent costs in periods when the Upgrader is in normal operation.

The expenditures of $134 million for other oil sands activities during the year related to engineering costs and resource delineation for future phases. This was comprised primarily of $56 million related to engineering and regulatory work, $55 million related to core hole delineation and seismic costs associated with future phases of development and $7 million in contract cancellation costs related to a reduction in the scope of our 2008/2009 winter drilling program.

Capitalized interest includes interest of $160 million on our senior secured notes (Notes) and $17 million with respect to our revolving credit facilities. The other capital expenditures of $36 million in the period related primarily to $21 million on corporate assets and $15 million for costs associated with the working interest sale to Nexen.  Partially offsetting these costs is a realized gain of $114 million related to our foreign currency contracts.

The $309 million of non-cash capital charges related primarily to a $373 million capitalized translation loss with respect to the re-measurement of our U.S.-dollar-denominated long-term debt, cash and interest reserve account, and a charge of $25 million for capitalized future taxes. The $373 million translation loss was primarily the result of the translation to Canadian dollars of our $1,750 million U.S.-dollar-denominated debt, due to a change in the exchange rate from CDN$0.99 to US$1.00 at the end of 2007 to CDN$1.22 to US$1.00 at the end of 2008. The translation loss was partially offset by realized gains of $114 million and unrealized gains of $91 million on forward exchange hedging instruments.

RESULTS OF OPERATIONS

Year Ended December 31, 2008

In millions	2008			2007			2006
Interest income	$	6		$	13		$	10
Impairment related to asset sale		392			-			-
General and administrative		18			14			10
Amortization and accretion		6			2			22
Financing charges		1			12			-
Realized loss (gain) on commodity contracts		(2	)		-			-
Unrealized loss (gain) on commodity contracts		(67	)		4			-
Future tax expense (recovery)		(85	)		(9	)		(12	)

* Interest Income

For the year ended December 31, 2008 interest income decreased to $6 million from $13 million in 2007. The decrease was due to a decline in average cash and cash equivalent balances as well as lower interest rates on investments.

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Expenses, gains and losses

* Impairment Related to Asset Sale

To consider impairment as of December 31, 2008, assets were grouped into categories of depreciable assets, resource assets and unproved properties based on the nature of the asset and an assessment of its depreciation basis. Each asset type was assessed individually for impairment.

We allocated the sales proceeds to each asset type based on an estimate of fair value. The sales proceeds allocated to depreciable assets were lower than the book value of the asset; as a result, an impairment before taxes of $392 million was recorded in 2008. The sales proceeds allocated to resource assets did not alter the depletion rate by greater than 20 percent and, as a result, no gain or loss was recorded. The sales proceeds for resource assets will be recorded as a reduction to book value as of completion of the sale in 2009. The sales proceeds for unproved properties will be recorded as a reduction to book value as of completion of the sale in 2009. All of the Company’s remaining assets were subject to a ceiling test and cost recovery test which concluded no further impairment existed.   The ceiling test is described in Note 2 of the financial statements.

With respect to the assets sold and the related impairment, there were a number of business conditions which led to the sale and the impairment. These factors include: restricted access to capital for OPTI as well as potential purchasers of our assets; relatively low and declining commodity prices during the second half of 2008; relatively low SAGD production volumes and delayed start-up of the Upgrader. We expect that as these conditions improve, the fair value of our assets will also increase.

* General and Administrative

For the year ended December 31, 2008, G&A expenses increased to $18 million from $14 million in 2007. The increase for 2008 is due to higher levels of corporate staffing.

* Amortization and Accretion

For the year ended December 31, 2008, amortization and accretion expenses were $6 million compared to $2 million in 2007. For 2008, the expense was primarily related to an increase in the amortization of corporate assets.

* Financing Charges

For the year ended December 31, 2008 financing charges were $1 million compared to $12 million in 2007. Financing charges relate to the new $150 million revolving debt facility established in June 2008 and to the issuance of US$750 million in senior secured notes in 2007.  Our policy is to expense financing costs as incurred.

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* Realized Gain on Commodity Contracts

For the year ended December 31, 2008, we had a realized gain of $2 million related to our US$50/bbl commodity puts.

* Unrealized Loss (Gain) on Commodity Contracts

For the year ended December 31, 2008, we had a gain of $67 million compared to a loss of $4 million in 2007. The gain in 2008 was due to an increase in the fair value of our commodity contracts put in place for 2009 production. During 2008, spot prices for WTI decreased from approximately US$92/bbl at the beginning of the year to approximately US$41/bbl at year-end.

* Future Tax Expense (Recovery)

Future tax expense for the year ended December 31, 2008 is a recovery of $85 million compared with $9 million in the corresponding period of 2007. The recovery of future taxes in 2008 was primarily due to a reduction in book value associated with the impairment of assets and the realized cross currency swap gains, offset by future tax implications of foreign exchange movements and flow-through share renunciations.

* Foreign Exchange Hedging Instruments

OPTI is exposed to foreign exchange rate risk on our U.S.-dollar-denominated debt. To partially mitigate this exposure, we have entered into US$875 million of foreign exchange forwards to manage our exposure to repayment risk on our U.S.-dollar-denominated long-term debt. The forward contracts provide for the purchase of U.S. dollars and the sale of Canadian dollars at a rate of approximately CDN$1.17 to US$1.00 with an expiry in April 2010.  With respect to our U.S.-dollar-denominated debt, we believe that these forward contracts provide protection against a decline in the value of the Canadian dollar below CDN$1.17 to US$1.00 on a portion of our debt. The period-end value of the forwards is an asset of $32 million. As noted under “Liquidity”, the value of these derivatives affects our debt covenants as the value of these contracts is included in the measurement of our debt for covenant purposes.

During 2008, the fair value adjustment for each of these contracts at the end of each contract period is capitalized to property plant and equipment as the underlying debt instrument was used to fund development of our Project. The value of the currency derivatives increased from the inception of the contractsdue to a weakening Canadian dollar as compared to the U.S. dollar. During the year ended December 31, 2008, we had a realized gain of $114 million

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SELECTED ANNUAL INFORMATION

In millions (except per share amounts)	2008			2007			2006
Interest income	$	6		$	13		$	10
Net loss		(257	)		(9	)		(10	)
Net loss per share, basic and diluted		(1.31	)		(0.05	)		(0.06	)
Total assets		4,558			3,837			3,374
Total long-term liabilities		2,656			1,831			1,773

The amount of interest income in each year is primarily the result of cash and cash equivalents available for investment. The amount of cash in each year is influenced by the size and timing of financing activities, as well as capital expenditures related to project development. The net loss has been influenced by increasing general and administrative expenses as well as fluctuations in future tax recoveries. Amortization expense increased significantly in 2007 as a result of the expensing of pre-financing costs associated with the cancellation of various credit facilities, thereby increasing the net loss for the year. During 2008, we recorded a before tax impairment of assets as a result of our working interest sale of $392 million and a total future tax recovery of $85 million. Our total assets have been increasing continuously as a result of expenditures on the Project and future phase development, offset by the asset impairment at December 31, 2008.  Increases in long-term financial liabilities are a result of a weaker Canadian dollar increasing the measurement amount of our U.S.-dollar-denominated debt and borrowings under our revolving credit facilities.

SUMMARY FINANCIAL INFORMATION

	2008											2007
In millions (except per share amounts)		Q4			Q3		Q2			Q1			Q4		Q3			Q2			Q1
Interest income	$	2		$	1	$	1		$	2		$	3	$	3		$	2		$	5
Net earnings (loss)		(250	)		3		(8	)		(2	)		6		(13	)		(2	)		-
Earnings (loss) per share, basic and diluted		(1.27	)		0.02		(0.04	)		(0.01	)		0.03		(0.07	)		(0.01	)		-

Quarterly variations in interest income are primarily the result of the amount of cash and cash equivalents available for investment during the applicable period. The amount of cash and cash equivalents is influenced by the size and nature of financing activities and the level of investing activities during the period. Earnings have been influenced by fluctuating interest income, increasing levels of G&A expenses and fluctuating future tax expense.  In the third quarter of 2007, we expensed financing charges of $11 million, which increased our loss during the period. During the fourth quarter of 2007, we had a $9 million recovery of future taxes primarily as a result of a reduction in the applicable federal tax rate that increased our earnings.  During the second quarter of 2008, we had a $6 million loss on commodity contracts that increased our loss during the period.  During the fourth quarter of 2008, we had a pre-tax asset impairment for accounting purposes related to our working interest sale of $392 million and a future tax expense recovery, primarily related to this impairment, of $85 million.

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SHARE CAPITAL

At January 31, 2009, OPTI had 195,929,526 common shares and 7,150,116 common share options outstanding. The common share options have a weighted average exercise price of $13.14 per share.  At January 31, 2009, OPTI’s fully diluted shares outstanding were 203,079,642.

Effective November 2008, 5,991,000 common share warrants with an exercise price of $14.75 per share expired without being exercised. Effective June 2008, $202 million of call obligations with an exercise price of $2.20 per share expired without being exercised.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

For the year ended December 31, 2008, cash used by operating activities was $7 million, cash provided by financing activities was $651 million and cash used in investing activities was $747 million. These changes, combined with a gain on our U.S.-dollar-denominated cash of $9 million, resulted in a decrease in cash and cash equivalents during the year of $93 million.

During 2008 we funded our capital expenditures and ongoing start-up activities from existing working capital and borrowings under our credit facilities. In 2009, sales proceeds from the working interest sale to Nexen, operating cash flow and availability under our revolving credit facilities are expected to fund our capital expenditures.

After completion of the working interest sale to Nexen, the Company will have cash and unused credit facilities of approximately $450 million. In order to continue to access the revolving credit facility, we are required to meet a first lien to EBITDA covenant commencing in the third quarter of 2009.  The most significant risk to us not achieving this covenant is lower than expected bitumen production and associated PSC™ sales. Commodity pricing is a less significant risk in 2009 as a substantial portion of our production is hedged.  We have hedged 6,000 bbl/d at a net price of approximately US$76/bbl, which is a substantial portion of our expected 2009 PSC™ sales volume.  An additional 500 bbl/d of 2009 production is hedged with a US$77/bbl swap (risks associated with our hedging instruments are discussed in more detail under “Financial Instruments”, below). If we have lower than expected SAGD production or lower PSC™ sales, we may have to repay amounts outstanding under the revolving credit facility or may be prevented from further borrowings. The majority of our operating costs and interest costs are fixed. Aside from changes in the price of natural gas, our costs will neither decrease nor increase significantly as a result of fluctuations in WTI prices other than with respect to royalties, which increase at WTI prices higher than $55/bbl.

We have semi-annual interest payments of US$71 million in June and December of each year until maturity of the Notes in 2014. Also, we estimate our share of capital expenditures required to sustain production of Phase 1 at or near planned capacity for the Project will be approximately $60 million per year for the next five years. We expect to fund these payments from operating cash flow and from existing financial resources.

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A significant portion of our capital budget for 2009 has been pre-funded.  As part of the working interest sale to Nexen, we provided $85 million to Nexen in January to be applied against our working interest share of the 2009 joint venture capital budget of $114 million net to OPTI.  On a gross basis, the budget is $325 million of which approximately $200 million relates to sustaining capital including the completion of an additional well pad, $100 million relates to Phase 2 engineering and $25 million relates to future phases and resource development.

Recent developments in capital markets have restricted our access to new debt and equity. Although our current financial resources are considered sufficient for the next 12 to 24 months, further deterioration of commodity prices, delays in ramp-up of SAGD production, or operating issues with the SAGD or Upgrader operations could result in additional funding requirements earlier than we have estimated.  Should the Company require such funding, it may be difficult to obtain such financing on reasonable

terms.

If Phase 2 is sanctioned, which is not currently scheduled for consideration prior to mid-2010, we expect possible future capital requirements in excess of operating cash flows.  Unless we have stable operations at or near capacity for the Project and high commodity prices, such external financing requirements would be significant.  We expect that these financing requirements will come at a higher cost and contain more restrictions than the financings completed to date by OPTI.  Current market conditions would not support such a financing requirement so some improvement will be required in order to support such development.  In addition, our joint venture partner may evaluate the economics of future phases differently than we do and will likely have a different evaluation of the ability to fund this development.  As a result, Nexen may decide to proceed with development of future phases, which may result in OPTI having to reduce our working interest in such future phases.

Our debt facilities contain a number of provisions that serve to limit the amount of debt we may incur. With respect to our revolving credit facility, the key maintenance covenants are with respect to debt to capitalization and the ratio of debt outstanding under the revolving credit facility to EBITDA. Maintenance covenants are important as they are ongoing conditions that must be satisfied to provide continued access to the revolving credit facility.

The first lien to EBITDA covenant, as amended in January 2009, is measured quarterly and requires that this ratio is lower than 2.5:1 commencing for the quarter ended September 30, 2009. The first three measurements of EBITDA for this covenant will annualize EBITDA as measured from July 1, 2009, to the end of the applicable covenant period. Thereafter, EBITDA will be based on a trailing four quarters. Realized cash gains on commodity contracts, such as our existing puts and forwards, are included in EBITDA for the purposes of the covenant. If we are unable to generate sufficient EBITDA, we may be required to repay all or a portion of amounts outstanding under that facility or be unable to make additional borrowings under the revolving credit facility prior to the end of a covenant quarter or will be required to request and obtain approval for a waiver from our lenders under the facility.

The covenant as amended in January 2009 for debt to capitalization requires that we do not exceed a ratio of 70 percent as calculated on a quarterly basis.  The covenant is calculated based on the book value of debt and equity. The book value of debt is adjusted for the effect of any foreign exchange derivatives issued in connection with the debt that may be outstanding. At December 31, 2008, this means that our debt would be reduced by the value of our foreign exchange forward in the amount of $32 million. With respect to U.S.-dollar-denominated debt, for purposes of the debt to capitalization ratio, the debt is translated to Canadian dollars based on the average exchange rate for the quarter. The debt to capitalization is therefore influenced by the variability in the measurement of the foreign exchange forward, which is subject to mark to market variability and average foreign exchange rate changes during the quarter.

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In respect of new borrowings under the $350 million revolving credit facility prior to reaching completion of the Project, we are required to have sufficient funds (including cash and undrawn revolver) to fund our share of remaining Project

costs.

With respect to our senior secured notes, the covenants are in place primarily to limit the total amount of debt that OPTI may incur at any time. This limit is most affected by the present value of our total proven reserves using forecast prices discounted at 10 percent.  Based on our 2008 reserve report, as adjusted for our new working interest in the joint venture, we have sufficient capacity under this test to incur additional debt beyond our existing $350 million revolving credit facility and existing senior secured notes. Other leverage factors, such as debt to capitalization and total debt to EBITDA, are expected to be more constraining than this limitation.

Capital Resources

Our long-term debt currently consists of US$1,750 million of senior secured notes and a $350 million revolving credit facility.  At February 17, 2009, we have approximately $280 million of cash on hand and have drawn $87 million on our $350 million revolving credit facility.

At December 31, 2008, our cash resources included cash of $217 million. Our cash and cash equivalents are invested exclusively in money market instruments issued by major Canadian banks. At December 31, 2008, $486 million had been drawn on the $500 million revolving credit facility and $146 million had been drawn on the $150 million revolving credit facility. As of February 17, 2009, after using proceeds from the working interest sale to Nexen to fund a partial pay-down, $87 million remained outstanding on the $350 million revolving credit facility and our $150 million revolving credit facility had been repaid and cancelled.  We eliminated the working capital deficiency that existed at December 31, 2008 as a result of the completion of the working interest sale to Nexen on January 27, 2009.

CREDIT RATINGS

OPTI, OPTI's revolving credit facility and OPTI’s Notes are currently rated by Moody’s Investor Service (Moody’s) and Standard and Poors (S&P).  Please refer to the table below for the respective ratings.

Type of Security	Moody's	S&P
OPTI Corporate Rating	B1	B+
Revolving Credit Facility	Ba3	BB
8.25% Notes	B2	BB
7.875% Notes	B2	BB

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The Moody’s ratings have been under review for potential downgrade by Moody’s since November 2008.  The S&P ratings have been on credit watch with negative implications since November 2008.

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.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

Commitments for contracts and purchase orders at December 31, 2008, related to project development are $22 million based on a working interest of 50 percent.

During the 12 months ended December 31, 2008, our long-term debt increased by $486 million due to borrowings under our $500 million revolving credit facility and the short-term portion increased by $146 million due to borrowings on our $150 million revolving credit facility.

The following table shows our contractual obligations and commitments related to financial liabilities at December 31, 2008. This table is prior to the January 2009 working interest sale to Nexen, which would reduce payments under our capital leases, operating leases and contracts and purchase orders by 30 percent.

In millions	Total	< 181 days	181- 365 days	2010-2011	2012-2013	2014 or later
Accounts payable and accrued liabilities	$       200	$   195	$        5	$         -	$          -	$           -
Short-term debt(1)	146	146	-	-	-	-
Long-term debt (Notes)(2)	3,166	86	86	345	345	2,304
Long-term debt (Revolving)(3)	486	136	-	350	-	-
Capital leases(4)	106	2	3	9	8	84
Operating leases and other commitments(5)	115	6	7	28	29	45
Contracts and purchase orders(6)	22	22	-	-	-	-
Total commitments	$  4,241	$  593	$   101	$     732	$  382	$  2,433

Notes:

(1) Consists of CDN$146 million of borrowings on our short-term revolving debt facility. This facility was repaid and cancelled in January 2009.

(2) Consists of US$1,000 million and US$750 million under our Notes.  Amounts represent scheduled principal and interest payments.

(3) Consists of $486 million drawn on the revolving credit facility. The repayment represents only the required reduction to reduce the facility to $350 million in January 2009 and the final repayment of the facility at its scheduled maturity in 2011. In addition, we are contractually obligated for interest payments on borrowings and standby charges in respect to undrawn amounts under the revolving credit facility, which are not reflected in the above table as amounts cannot be estimated due to the revolving nature of the facility and variable interest rates. See “Liquidity” section for repayments completed as part of working interest sale.

(4) Consists of our share of future payments under our product transportation agreements with respect to future tolls during the initial contract term at a working interest of 50 percent.

(5) Consists of our share of payments under our product transportation agreements with respect to future tolls during the initial contract term at a working interest of 50 percent. This amount also includes our share of future commitments with respect to rail traffic transportation assuming a 50 percent working interest.

(6) Consists of our share of commitments associated with contracts and purchase orders in connection with the Project and our other oil sands activities.

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OFF-BALANCE-SHEET ARRANGEMENTS

We have no off-balance-sheet arrangements.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining disclosure controls and procedures (DC&P), as such term is defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, for OPTI. They have, as at the financial year ended December 31, 2008, designed such DC&P, or caused them to be designed under their supervision, to provide reasonable assurance that information required to be disclosed by OPTI in its annual filings, interim filings or other reports filed or submitted by OPTI under applicable securities legislation is recorded, processed, summarized and reported within the time periods specified in applicable securities legislation and that all material information relating to OPTI is made known to them by others, particularly during the periods in which OPTI's annual and interim filings are being prepared.

Under the supervision of the Chief Executive Officer and the Chief Financial Officer, OPTI conducted an evaluation of the effectiveness of our DC&P as at December 31, 2008. Based on this evaluation, the officers concluded that as of December 31, 2008, OPTI's disclosure controls and procedures provide reasonable assurance that information required to be disclosed by OPTI in its annual filings, interim filings or other reports that we file or submit under applicable securities legislation is recorded, processed, summarized and reported within the time periods specified in such legislation and that these controls and procedures also provide reasonable assurance that material information relating to OPTI is made known to our Chief Executive Officer and Chief Financial Officer by others.

It should be noted that while our officers believe that OPTI’s disclosure controls and procedures provide a reasonable level of assurance with regard to their effectiveness, they do not expect that the disclosure controls and procedures or internal controls over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system are met.

Internal Controls over Financial Reporting

The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining internal control over financial reporting (ICFR), as such term is defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, for OPTI. They have, as at the financial year ended December 31, 2008, designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.  The control framework our officers used to design OPTI's ICFR is the Internal Control -- Integrated Framework (COSO Framework) published by The Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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Under the supervision of the Chief Executive Officer and the Chief Financial Officer, OPTI conducted an evaluation of the effectiveness of our ICFR as at December 31, 2008 based on the COSO Framework. Based on this evaluation, the officers concluded that as of December 31, 2008, OPTI's ICFR provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.

There were no changes in our internal control over financial reporting during the year ended December 31, 2008 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES

Capital Assets

We capitalize costs in connection with the development of oil sands projects. The measurement of these costs at each financial statement date requires estimates to be made with respect to construction progress, materials procurement and drilling progress. An increase in the measurement amount of these items would increase our property, plant and equipment and accrued liabilities accordingly.

Capital assets are reviewed for impairment whenever events or conditions indicate that the net carrying amount may not be recoverable from estimated future cash flows.  We have evaluated the book value of our assets in connection with the working interest sale to Nexen.  We have determined that the related assets sold were impaired as of December 31, 2008 and as a result recorded a loss of $392 million.  We have also evaluated the remaining assets and determined that these costs are recoverable based on our ceiling test as described in our accounting policies.

The quantity of reserves is subject to a number of estimates and projections, including assessment of engineering data, projected future rates of production, characteristics of bitumen reservoirs, commodity prices, foreign exchange rates, operating costs and sustaining capital expenditures. These estimates and projections are uncertain as we do not have any commercial production history to assist in the development of these forward-looking estimates. However, all reserve and associated financial information is evaluated and reported on by a firm of qualified independent reserve evaluators in accordance with the standards prescribed by applicable securities regulators.

The calculation of future cash flows based on these reserves is dependent on a number of estimates, production volumes, facility performance, commodity prices, royalties, operating costs, sustaining capital and foreign exchange rates. The price used in our assessment of future cash flows is based on our independent evaluators’ estimate of future prices and evaluated for reasonability by OPTI against other available information.  Although the future prices used are significantly higher than current prices, we believe these prices are reasonable estimates for a long-term outlook.  In addition, lower prices could be used without resulting in any additional impairment.  Different or significantly lower price assumptions could result in a ceiling test impairment.  Impairment and a corresponding loss would be recognized in earnings in the period in which capitalized costs exceeded estimated future cash flows.

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Asset Retirement Obligations

We measure asset retirement obligations at each financial statement date. The estimate is based on our share of costs to reclaim the resource assets and certain facilities related to the Project as well as other resource assets associated with future phases. The liability is primarily related to reclamation of the SAGD facility and drilling assets. To determine the future value of the liability, we estimate the amount, timing and inflation of the associated abandonment costs.  We then calculate the present value of the cost to record the current asset retirement obligation using a credit-adjusted risk-free rate. In some cases, due to the long-lived nature of the asset, the timing of future abandonment cannot be made and no asset retirement obligation is recorded. Due to the long-term nature of current and future project developments, abandonment costs will be incurred over many years in the future. As a result of these factors, different estimates could be used for such abandonment costs and the associated timing. Assumptions of higher future abandonment costs, higher inflation, higher credit-adjusted risk-free rates or an assumption of earlier or specified timing of abandonment would cause the asset retirement obligation and corresponding asset to increase. These changes would also cause future accretion expenses to increase and future earnings to decrease.

Future Taxes

We measure our future tax asset or liability based on estimates of temporary differences between our book and tax assets. In addition, an estimate is required for both the timing and tax rate of this reversal. Should these estimates change, it could impact the measurement amount of our asset or liability as well as future tax recovery or expense and earnings. These estimates would not impact cash flow from operations.  At December 31, 2008, we have recorded a future tax asset.  The recognition of a future tax asset requires further estimates that these taxes will be recoverable in the future.  We have estimated future cash flow based on reports from our independent engineers and concluded that, more likely than not, we will be able to earn taxable earnings in excess of the future tax asset that we have recorded.

ACCOUNTING POLICIES

On January 1, 2008, we adopted the following Canadian Institute of Chartered Accountants (CICA) standards: Section 1535 “Capital Disclosures,” Section 3862 “Financial Instruments – Disclosures,” and Section 3863 “Financial Instruments – Presentation.”

Section 1535 requires the disclosure of OPTI’s objectives, policies and processes for managing capital. This includes qualitative information regarding OPTI’s objectives, policies and processes for managing capital and quantitative data about what OPTI manages as capital. These disclosures are based on information that is used internally by our management.

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Sections 3862 and 3863 replace Section 3861 “Financial Instruments – Disclosure and Presentation,” which revises financial instruments disclosure requirements and leaves unchanged the presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how OPTI manages those risks.

There is no impact on our financial position or results of operations as a result of the adoption of these sections.

NEW ACCOUNTING PRONOUNCEMENTS

The CICA issued a new accounting standard Section 3064 “Goodwill and Intangible Assets” which OPTI will adopt for the reporting period beginning January 1, 2009. This standard replaces Section 3062 “Goodwill and Other Intangible Assets” and Section 3450 “Research and Development Costs.” The new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets are equivalent to the corresponding provisions of International Financial Reporting Standard (IFRS) IAS 38, “Intangible Assets.” Emerging Issues Committee (EIC) 27 “Revenues and Expenditures During the Pre-Operating Period” is no longer applicable for OPTI as we have adopted CICA 3064. Accounting Guidelines (AcG) 11 “Enterprises in the Development Stage” is amended to delete references to deferred costs and to provide guidance on development costs as intangible assets under Section 3064.

As a result of these changes and the adoption of these new standards, OPTI will expense certain previously capitalized costs with retroactive effect on January 1, 2009 with a corresponding increase to opening deficit. The opening deficit will be increased by approximately $75 million.  This increase will be comprised of deferred costs related to SAGD start-up activities, translation of OPTI’s U.S.-dollar debt, offset by gains related to financial derivatives associated with OPTI’s debt and by a recovery of future tax expense.

IFRS

The Canadian Accounting Standards Board has announced that Canadian Generally Accepted Accounting Principles (GAAP) no longer apply for all publically accountable enterprises as of January 1, 2011. From that date forward, OPTI will be required to report under International Financial Reporting Standards (IFRS) as set out by the International Accounting Standards Board (IASB). Any adjustments resulting from a change in policy are applied retroactively with corresponding adjustment to opening retained earnings.

OPTI is currently in the initial stages of planning for the IFRS transition. A formal changeover plan has not been approved by management. We are currently evaluating potential areas impacted by the new standards including adoption criteria as prescribed under IFRS1 – First-Time Adoption of International Financial Reporting Standards.

Business Impact of IFRS

OPTI has recorded a pre-tax asset impairment for accounting purposes of $392 million with respect to the working interest sale to Nexen.  Under IFRS this loss would have been significantly higher as all of OPTI’s assets would have been considered impaired based on the implied valuation. IFRS permits subsequent recovery of such write downs in future periods to the extent that fair value increases. Therefore, the cumulative effect of the Nexen working interest sale at the date of adoption on January 1, 2011 will depend on a fair value assessment of the assets as of December 31, 2010.

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FINANCIAL INSTRUMENTS

The Company considers its risks in relation to financial instruments in the following categories:

Credit Risk

Credit risk is the risk that counterparty to a financial instrument will not discharge its obligations, resulting in a financial loss to the Company. The Company has policies and procedures in place that govern the credit risk it will assume. We evaluate credit risk on an ongoing basis including an evaluation of counterparty credit rating and counterparty concentrations measured by amount and percentage. Our objective is to have no credit losses.

The primary sources of credit risk for the Company arise from the following financial assets: (1) cash and cash equivalents; (2) accounts receivable; and (3) derivatives contracts. The Company has not had any credit losses in the past and the risk of financial loss is considered to be low given the counterparties used by the Company. As at December 31, 2008, the Company has no financial assets that are past due or impaired due to credit-risk-related defaults.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet obligations associated with financial liabilities. Our financial liabilities are comprised of accounts payable and accrued liabilities, long-term debt and obligations under capital leases. The Company frequently assesses its liquidity position and obligations under its financial liabilities by preparing regular financial forecasts. We mitigate liquidity risk by maintaining a sufficient cash balance as well as maintaining sufficient current and projected liquidity to meet expected future payments. Our financial liabilities arose primarily from the development of the Project. As at December 31, 2008, the Company has met all of the obligations associated with its financial liabilities.  As noted under “Liquidity,” continued access to our revolving credit facility is a key liquidity risk.

Market Risk

Market risk is the risk that the fair value (for assets or liabilities considered to be held for trading and available for sale) or future cash flows (for assets or liabilities considered to be held-to-maturity, other financial liabilities, and loans and receivables) of a financial instrument will fluctuate because of changes in market prices. We evaluate market risk on an ongoing basis. We assess the impact of variability in identified market risks on our medium-term cash requirements and impact with respect to covenants on our credit facilities. At December 31, 2008, we had mitigation programs to reduce market risk related to foreign exchange and commodity price changes. Changes in these market risks related to foreign exchange would not have had an impact on our earnings as translation gains and losses on our U.S.-dollar debt and related hedging activities were capitalized. The primary market risks related to our commodity contracts relates to future estimated prices for WTI. A $5 change in estimated future WTI prices would change our unrealized loss by approximately $10 million in U.S. dollars at December 31, 2008 as a result of an estimated change in the value of our commodity contracts.

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The following sections describe these risks in relation to the Company’s key financial instruments.

* Cash and Cash Equivalents

The Company has cash deposits with Canadian banks and has money market investments. Counterparty selection is governed by the Company’s Treasury Policy, which limits concentration of investments and requires that all instruments be rated as investment grade by at least one rating agency. As at December 31, 2008 the amount in cash and cash equivalents was $217 million and the maximum exposure to a single counterparty was $51 million which is guaranteed by a Canadian bank.

At December 31, 2008, the remaining terms on investments made by the Company are less than 90 days with interest fixed over the period of investment. Maturity dates for investments are established to ensure cash availability for project development and interest payments. Investments are held to maturity and the maturity value does not deviate with changes in market interest rates.

Our cash balances are currently invested almost exclusively in money market instruments with major Canadian banks in the form of banker’s acceptances or term deposits. These instruments are widely offered by banks we deal with and are considered direct obligations of the banks that offer them. We manage our exposure to these banks in two primary ways: by limiting the amount invested with a single issuer or guarantor and by investing for relatively short periods of time. We do not expect any investment losses based on these money market investments.

* Accounts Receivable

Our accounts receivable includes amounts due from Nexen Inc. related to project development and Nexen Marketing related to marketing activities, interest earned but not received on money market investments, and amounts due from the Canada Revenue Agency in relation to GST refunds. The amounts due from Nexen increased significantly subsequent to year-end as a result of the completion of the working interest sale.  The agreement included $85 million as a pre-funded amount for 2009 development activities. These funds will be released as work is completed on the 2009 joint venture capital program. OPTI is entitled to a refund of such dollars or contribution of further dollars in the event that OPTI’s working interest share of 2009 joint venture capital expenditures is less than or exceeds $85 million. The Company’s credit risk in regard to accounts receivable therefore relates primarily to the risk of default by Nexen, which has an investment-grade corporate rating from Moody’s Investor Service, and by financial institutions with an investment grade rating. Therefore, we estimate the risk of credit loss as low.

* Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities are comprised primarily of amounts due in respect of development of the Project and certain other corporate expenses. Payment terms on these amounts are typically 30 to 60 days from receipt of invoice and generally do not bear interest. The Company has met its obligations in respect of these liabilities. As at December 31, 2008 accounts payable and accrued liabilities were $200 million.

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* Debt and Obligations under Capital Lease

The terms of the Company’s debt and obligations under capital lease are described in the notes to our audited financial statements as at December 31, 2008. The Company has met its obligations in respect of these liabilities. The Company accounts for its borrowings under all of its long-term debt and obligations under capital lease on an amortized cost basis. As at December 31, 2008 long-term debt was $2,618 million, short-term debt was $146 million and obligations under capital leases were $30 million.

The revolving credit facilities are variable interest rate facilities with borrowing rates and duration established at the time of the initial borrowing or subsequent extension. Our current borrowings have an approximate initial term of 90 days and therefore fluctuations in the value of such borrowings are not material during the term they are outstanding. The Company is exposed to interest rate changes if and when it extends each borrowing. The extent of the exposure to interest rate risk depends on the amount outstanding under the facility. As at December 31, 2008, there was $486 million drawn under the $500 million revolving credit facility and $146 million drawn under the $150 million revolving credit facility.  As described under ”Capital Resources,” these amounts were reduced in early 2009.  During 2008, a 1 percent change in interest rates would not have had a material impact on the interest expense due to the fixed nature of our senior notes and relatively low average balance of our revolving credit facilities.

Our senior secured notes are comprised of US$1,750 million of debt which has fixed U.S. dollar semi-annual interest payments. Changes in the exchange rate between the Canadian dollar and U.S. dollar impact the carrying value of the senior secured notes. A US$0.01 change in the exchange rate will impact the carrying value of the senior secured notes by approximately US$18 million. A US$0.01 change in the exchange rate will change our interest costs by approximately US$1.4 million. The exposure to exchange rate fluctuations has been partially mitigated by the forward contracts described under “Foreign Exchange Hedging Instruments.” These changes also influence our compliance with debt covenants as described under ”Liquidity.”

* Derivative Contracts

The Company periodically uses derivative contracts to hedge certain of the Company’s projected operational or financial risks. In the past, such instruments have involved the use of interest rate swaps, cross-currency interest swaps, currency-forward contracts and crude oil put options. Derivative contracts outstanding at December 31, 2008 are described in the notes to our audited financial statements as at December 31, 2008. These instruments are designated as held-for-trading and are measured at fair value at each financial statement date.

As at December 31, 2008, we had US$875 million of foreign currency forwards to manage a portion of the exposure to the foreign exchange variations on the Company’s long-term debt. Changes in the exchange rate between Canadian and U.S. dollars change the value of these instruments. The foreign currency forwards at December 31, 2008 had a fair value of $32 million. The foreign exchange forwards are measured by the present value of the difference between the settlement amounts of the foreign currency forwards as measured in Canadian dollars. The counterparties to the foreign currency forwards are major Canadian and international banks. Our exposure to non-payment from any single institution is less than 25 percent of the value of the forwards.

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The fair value of the foreign currency forwards is determined by calculating the present value of the existing contract as measured in Canadian dollars in reference to established market rates, primarily foreign exchange rates at the end of the year and discounted at market interest rates. The foreign currency forwards were valued primarily using a period-end foreign exchange rate of 1.22. Based on the active market for the underlying market variables used in the valuation, we do not believe other market assumptions with respect to these variables could result in a materially different valuation than the one we have determined. This conclusion is supported by an internal comparison completed by OPTI to compare the valuation provided by each counterparty to the forwards. The value of the foreign currency forwards would change by approximately $8 million for each $0.01 change in the foreign exchange rate between U.S. and Canadian dollars.  This change would have a corresponding impact on capitalized costs in 2008 and on our earnings before taxes in 2009.

We have established commodity hedging contracts to mitigate the Company’s exposure of future operations to decreases in the price of its synthetic crude oil. The Company has chosen to use put options and commodity price swaps to mitigate a portion of the exposure. As at December 31, 2008 the Company had deferred premium put options covering 2.2 million barrels of 2009 production at a price of US$80/bbl (deferred premiums to be paid on the expiration of the option are $4/bbl); and commodity price swaps covering 0.2 million barrels of 2009 production at a price of US$77/bbl. The value of these financial instruments as at December 31, 2008 was an asset of $78 million. The counterparties to the commodity hedges are major Canadian and international banks. Our exposure to non-payment from any single institution is approximately 60 percent of the value of the commodity hedge, which is due from a major Canadian bank.

The fair value of the commodity hedges is determined by calculating the present value of the existing contract as measured in Canadian dollars in reference to established market rates, primarily future estimated prices for WTI and period-end foreign exchange rates. Based on the active market for the underlying market variables used in the evaluation, we do not believe other market assumptions with respect to these variables could result in a materially different valuation than the one we have determined. This conclusion is supported by an internal comparison completed by OPTI to compare the valuation provided by each counterparty to the contract. The value of the commodity hedges would change by approximately US$2 million for each US$1/bbl change in future estimated prices for WTI. This change would have a corresponding impact on our earnings before taxes for the year.

We view the credit risk of these counterparties as low due to the diversification of the instrument with a number of banks.

26

RISK FACTORS

Readers should be aware that the list of assumptions, risks and uncertainties set forth herein are not exhaustive. Readers should refer to OPTI's current Annual Information Form (AIF), which is available at www.sedar.com, for a detailed discussion of these assumptions, risks and uncertainties.

Market Risks

We are involved in a capital intensive industry.  Oil sands development requires significant investment prior to any cash being returned to the business in the form of operating cash flow. Our development cycle for each phase can be greater than five years. This means significant external capital may be required. In addition, a combination of poor operating results, requirement for major repairs or improvements to our facilities and low commodity prices could require us to seek additional capital during 2009. Recent developments in the banking sector and the economy as a whole have meant such capital may be restricted in terms of size, extremely expensive in historical terms, or not available at all. Although the recent asset sale to Nexen has improved our short-term financial position, there is no assurance that, should we require additional capital in the future, we will be able to obtain such financing on a timeline suitable for OPTI.

Risk Factors During Operations

* Oil Prices and Foreign Exchange

Our financial results will be dependent upon the future price of crude oil. Oil prices fluctuate significantly in response to regional, national and global supply and demand factors beyond our control. Political and economic developments around the world can affect world oil supply and oil prices.

The Long Lake Upgrader will ultimately produce a fully upgraded product called PSCTM. The price we will receive for PSC™ will be dependent on the demand for it and will primarily be influenced by changes in the market price for WTI, which is influenced by global market factors. To a lesser extent, the price we receive for PSCtm will be affected by regional factors such as supply of other synthetic and conventional crude oils. Although we expect PSCtm to trade at a price similar to WTI, PSCtm will be a new synthetic crude oil product and no assurance can be given as to its price and marketability. We have engaged Nexen Marketing, which has extensive experience in marketing synthetic crude, to sell all of our production from the Long Lake Project.

After the Long Lake Upgrader start-up and during periods when the Upgrader is not operating, including planned and unplanned maintenance and repair, we may be unable to upgrade the bitumen produced by the Project. During these periods, bitumen would be mixed with diluent and sold as a bitumen blend. The blend would be priced significantly lower than conventional light oil or PSCtm.

Our future results of operations will be impacted by certain factors outside of our control, such as the gravity and quality of the bitumen produced from the Long Lake leases, which can ultimately determine the amount of syngas and PSCtm produced from the Long Lake Upgrader.

Crude oil prices are generally based on a U.S.-dollar market price, while most of our operating and capital costs are denominated in Canadian dollars. Fluctuations in exchange rates between the U.S. and Canadian dollars result in foreign currency exchange exposure. Therefore, changes in the exchange rate will affect the price we receive for PSCtm. We have protected a portion of this exposure to oil price fluctuation from our commodity contracts and have no protection from foreign exchange rates fluctuations related to the sale of our products.

27

* Operating Risk

The performance of the SAGD operation, the Long Lake Upgrader, or both may differ from our expectations. There are many factors related to the characteristics of the reservoir and SAGD operating facilities that could cause bitumen production to be lower than anticipated.

The Long Lake Upgrader is comprised of a number of facilities that upgrade bitumen, in part using high pressure and temperature. There are inherent risks in the initial and ongoing operation of our facility. The processing of hydrocarbons requires intensive planning and execution expertise. Problems during this process could result in increases to cost, reduced production or damage to facilities. All of these factors could negatively affect our results from operations.

* Non-operator

Nexen is the operator of the Long Lake Project. We rely on Nexen’s operating expertise to generate cash flow from the Project and to provide information on the status and results of operations. There are no assurances that Nexen will be able to generate financial results from the Project or that Nexen will be able to provide adequate financial and operational information on a timely basis.

* Natural Gas

During commercial operations, we will require a significant amount of natural gas to provide energy to generate steam for SAGD operations. The integrated Project design has mitigated a large amount of the risk, as syngas is expected to be produced through the gasification process and will be used to provide energy to the steam generation facilities. The amount of third-party natural gas purchases required is largely determined by the SOR that is required for SAGD production. If the SOR is higher than anticipated, we may be required to purchase natural gas beyond existing forecasted levels at prevailing market rates. This would cause our operating costs to increase and reduce our earnings.

* Reserves and Resources

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 resources or recovery of bitumen will be realized. In general, estimates of resources and of economically recoverable bitumen reserves 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 that 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 are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of such reserves based on risk of recovery, prepared by different engineers or by the same engineers at different times, may vary substantially.

28

The estimates with respect to reserves and resources that may be developed and produced in the future have been based upon volumetric calculations and upon analogy to similar types of reserves and 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 and resources based upon production history will result in variations, which may be material, in the estimated reserves and 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 fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. Also, short-term factors relating to oil sands resources may impair the profitability of the Project in any particular period.

Should the reserve estimate change in future periods, there could be a material impact on the fair value of our securities, our results of operations and our ability to obtain financing.

* Commodities Risk

During regular operations, our exposure to natural gas prices is reduced as the Long Lake Upgrader is expected to generate syngas, which will be used instead of natural gas. In the long-term, we expect approximately two thirds of our natural gas requirements will be generated by syngas with approximately one third being supplied from purchased natural gas. Although we expect stable Upgrader operations, during periods of Upgrader downtime we have significant exposure to natural gas prices. During these periods, virtually all of the energy required to generate steam for the SAGD operations will be from the purchase of natural gas.

During periods when the Upgrader is not in operation, we will be producing raw bitumen from the SAGD process. These bitumen barrels will be blended with a purchased diluent and sold as a bitumen blend. The price per barrel of purchased diluent will approximate WTI. The price we receive for this bitumen blend may vary widely and may be at a significant discount to WTI. At low commodity prices and high differentials between light oil and heavy oil in Northern Alberta as experienced in late 2008, the revenue we receive for bitumen blend may approximate the cost of the diluent.

Project Development Risk

* Financing Risk

Continuing access to our revolving credit facility is critical to our financial position, as noted under “Liquidity,” and there are risks of failure to meet covenants that would impair this access. The development of oil sands projects in connection with the Project and our multi-stage expansion plan requires a significant amount of capital investment that occurs over a number of years. We currently do not have the capital or committed financing necessary to complete our future phases of development and we expect to need to complete additional debt or equity financing to obtain the funds necessary to complete future phases. The cost of additional financing may not make future projects economically feasible.

29

* Regulatory Risk

We are subject to extensive Canadian federal, provincial and local laws and regulations governing exploration, development, transportation, production, exports, occupational health, protection and reclamation of the environment, safety and other matters.

Completed phases of the Project will produce greenhouse gases (GHGs) and other industrial air pollutants. The Canadian federal government has released a framework that outlines proposed new requirements governing the emission of GHGs and other industrial pollutants. It is possible that new federal or provincial requirements with respect to GHGs and industrial air pollutants will be imposed. This may require additional funding or facilities to comply with such requirements.

* Risks to Future Phase Development

We have announced phased development for up to five additional phases of projects of a similar size to the Project. The development of these phases is subject to a number of risks, primarily in the areas of resource extent and quality, cost, execution, long-term commodity price expectation and regulatory approval. If the estimates of costs to complete these future phases are higher than anticipated, these future phases may be deferred or cancelled. The execution of these future phases requires specialized labour, module construction, engineering expertise and construction management. As oil sands development in Alberta has been and may be in the future at high levels of development activity, some or all of these resources may not be available to us on the schedule that we require, which could delay future development.  We have regulatory approval for the Phase 2 upgrader, but do not have regulatory approval for any future phase of SAGD development or upgraders. These regulatory approvals may delay or restrict our development of future phases.

* Infrastructure Risk

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

·   pipelines for the transportation of feedstocks and petroleum products to be sold ;

·   pipelines for the transportation of natural gas;

·   a railway spur for the transportation of products and byproducts including sulfur;

·   disposal facilities for by-products of the Project (e.g. sulphur); 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.

30

	PricewaterhouseCoopers LLP Chartered Accountants 111 5 Avenue SW, Suite 3100 Calgary, Alberta Canada T2P 5L3 Telephone +1 403 509 7500 Facsimile +1 403 781 1825

Auditors’ Report

To the Shareholders of OPTI Canada Inc.:

We have audited the balance sheets of OPTI Canada Inc. as at December 31, 2008 and 2007 and the statement of loss, comprehensive loss and deficit and cash flows for each of the years in the two year period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2008 and 2007 and the results of its operations and its cash flows for each of the years in the two year period ended December 31, 2008 in accordance with Canadian generally accepted accounting principles.

Chartered Accountants
Calgary, Alberta
Canada

February 24, 2009

“PricewaterhouseCoopers” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership, or, as the context requires, the PricewaterhouseCoopers global network or other member firms of the network, each of which is a separate and independent legal entity.

OPTI CANADA INC.

Balance Sheets

	AS AT DECEMBER 31
	2008			2007
	(Amounts in thousands of Canadian dollars)
ASSETS
Current
Cash and cash equivalents (note 2c)	$	217,145		$	310,504
Accounts and other receivables		22,807			13,495
Commodity contracts (note 3)		78,003			-
Future income taxes (note 6)		2,709			-
Interest reserve account (note 2j)		-			137,328
		320,664			461,327
Future income tax asset (note 6)		44,417			2,153
Other long term assets (note 9c)		31,679			-
Property, plant and equipment (note 4)		4,160,901			3,373,908
	$	4,557,661		$	3,837,388
LIABILITIES
Current
Accounts payable and accrued liabilities	$	199,907		$	190,723
Short term debt (note 5)		145,500			-
		345,407			190,723
Long-term debt (note 5)		2,618,000			1,734,775
Obligation under capital lease (note 11b)		30,195			29,600
Other long-term liabilities (note 7)		7,937			66,677
		3,001,539			2,021,775
SHAREHOLDERS’ EQUITY (note 8)
Capital stock		1,847,461			1,837,253
Warrants		-			15,686
Contributed surplus		31,080			11,897
Deficit		(322,419	)		(49,223	)
		1,556,122			1,815,613
	$	4,557,661		$	3,837,388

Commitments (note 11)

Subsequent events (note 14)

(signed) "Robert G. Puchniak" (signed) "Sid W. Dykstra"

See accompanying notes to the financial statements

1

OPTI CANADA INC.

Statements of Loss, Comprehensive Loss and Deficit

	Years Ended December 31
	2008			2007
	(Amounts in thousands of Canadian dollars, except per share amounts)
Interest income	$	5,985		$	13,303
Expenses
Impairment of assets (note 14)		391,686			-
General and administrative		17,616			14,206
Financing charges		893			11,927
Realized loss (gain) on commodity contracts		(1,653	)		-
Unrealized loss (gain) on commodity contracts		(66,973	)		3,779
Amortization and accretion		5,973			2,011
		(347,542	)		31,923
Loss before taxes		(341,557	)		(18,620	)
Income taxes
Capital taxes		-			-
Future tax recovery (note 6)		(85,025	)		(9,134	)
		(85,025	)		(9,134	)
Net loss and comprehensive loss		(256,532	)		(9,486	)
Deficit - beginning of year		(49,223	)		(12,453	)
Adoption of new accounting policy (note 2m)		-			(27,284	)
Deficit - beginning of year		(49,223	)		(39,737	)
Expiration of call options (note 8)		(16,664	)		-
Deficit - end of year	$	(322,419	)	$	(49,223	)
Loss per share, basic and diluted	$	(1.31	)	$	(0.05	)

See accompanying notes to the financial statements

2

OPTI CANADA INC.

Statement of Cash Flows

	Years Ended December 31
	2008			2007
	(Amounts in thousands of Canadian dollars)
Cash provided by (used in)
Operating activities
Net loss	$	(256,532	)	$	(9,486	)
Items not affecting cash
Amortization and accretion expense		5,973			2,011
Stock based compensation expense		1,895			1,356
Impairment of assets		391,686			-
Unrealized loss (gain) on commodity contracts		(66,973	)		3,779
Imputed interest on commodity contract liability		189			-
Unrealized foreign exchange gain		(317	)		-
Future tax expense (recovery)		(85,025	)		(9,134	)
		(9,104	)		(11,474	)
Asset retirement costs incurred		(9	)		(24	)
Financing charges		893			11,927
Net change in non-cash working capital		1,157			4,496
		(7,063	)		4,925
Financing activities Increase in long-term debt		632,000			930,700
Repayments of long-term debt		-			(612,820	)
Proceeds from share issuances		7,041			428,972
Deferred financing charges		-			-
Share issue costs		(71	)		(16,768	)
Financing charges		(893	)		(11,927	)
Decrease in principle portion of capital lease obligation		(305	)		-
Net change in non-cash working capital		13,241			(4,793	)
		651,013			713,364
Investing activities
Property, plant and equipment additions		(987,134	)		(1,108,367	)
Settlement of interest rate swap		113,762			(2,201	)
Decrease in short-term investments		-			37,097
Decrease (increase) in interest reserve account		158,398			102,626
Net change in non-cash working capital		(31,950	)		30,837
		(746,924	)		(940,008	)
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency		9,615			(4,443	)
Increase (decrease) in cash		(93,359	)		(226,162	)
Cash and cash equivalents - beginning of year		310,504			536,666
Cash and cash equivalents - end of year	$	217,145		$	310,504

See accompanying notes to the financial statements

3

OPTI CANADA INC.

Statements of Shareholders’ Equity

	Warrants			Call Obligations			Common and Preferred Shares			Contributed Surplus			Deficit			Total
	(Amounts in thousands of Canadian dollars)
Balance at December 31, 2006		15,686			(16,664	)		1,447,679			9,357			(12,453	)		1,443,605
Issued for cash		-			-			352,156			-			-			352,156
Issued for cash - flow-though		-			-			60,021			-			-			60,021
Share issue costs		-			-			(16,768	)		-			-			(16,768	)
Stock options exercised		-			-			16,795			(1,548	)		-			15,247
Stock based compensation		-			-			1,548			4,088			-			5,636
Tax effect on financing activities		-			-			(7,514	)		-			-			(7,514	)
Adoption of new accounting policy		-			-			-			-			(27,284	)		(27,284	)
Net loss		-			-			-			-			(9,486	)		(9,486	)
Balance at December 31, 2007	$	15,686		$	(16,664	)	$	1,853,917		$	11,897		$	(49,223	)	$	1,815,613
Share issue costs		-			-			(71	)		-			-			(71	)
Stock options exercised		-			-			4,870			(1,030	)		-			3,840
Stock based compensation		-			-			-			5,076			-			5,076
Expiration of call options		-			16,664			-			-			(16,664	)		-
Warrants exercised		(549	)		-			3,750			-			-			3,201
Reclassified expired warrants		(15,137	)		-			-			15,137			-			-
Tax effect on financing activities		-			-			(15,005	)		-			-			(15,005	)
Net loss		-			-			-			-			(256,532	)		(256,532	)
Balance at December 31, 2008	$	-		$	-		$	1,847,461		$	31,080		$	(322,419	)	$	1,556,122

See accompanying notes to the financial statements

4

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

1. SUMMARY OF OPERATIONS

OPTI Canada Inc. (OPTI) is a public Canadian company with its shares listed for trading on the Toronto Stock Exchange (Symbol: OPC).  OPTI’s primary activity is the Long Lake Project (the Project), in which OPTI has a 50 percent working interest as at December 31, 2008.  Effective January 1, 2009, OPTI has a 35 percent working interest in all the joint venture assets, including Phase 1 of the Long Lake Project, all future phase reserves and resources, and future phases of development. See note 14.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

a) Property, plant and equipment

(i) Consolidation

On January 1, 2008, OPTI Long Lake LP (Partnership) was dissolved by a distribution of assets to each of the partners, OPTI and OPTI GP Inc.  On January 1, 2008, OPTI GP Inc. was amalgamated with OPTI Canada Inc. Accordingly, the 2007 comparable financial results are consolidated.

(ii) Petroleum and natural gas properties

OPTI follows the full cost method of accounting for petroleum and natural gas properties, whereby all costs of exploring for and developing petroleum and natural gas reserves are capitalized. Costs include land acquisition costs, geological and geophysical costs, carrying charges on non-productive properties, costs of drilling both productive and non-productive wells, costs of testing the bitumen upgrading process, related overhead and pre-operating costs. The capitalized costs, less undeveloped land costs, are depleted using the unit-of-production method based upon estimated proved reserves before royalties.  To date, no depletion has been recorded as commercial operations have not commenced.

Impairment is recognized if the carrying amount of the property, plant and equipment (PP&E) exceeds the sum of the undiscounted cash flows expected to result from proved reserves (ceiling test). Cash flows are calculated based on an estimate of future prices. In circumstances of impairment, the impairment would be calculated as the amount by which carrying amounts of the PP&E exceed the net present value of future cash flows from proved plus risked probable reserves. The risk-free interest rate is used to arrive at the net present value of the future cash flows. Any excess carrying value above the net present value of OPTI’s future cash flows would be recorded as a permanent impairment. The costs of unproved properties are excluded from the ceiling test calculation and subject to a separate impairment test. In circumstances of impairment, the impairment would be calculated as the amount by which carrying amounts of unproved properties exceed the net present value of future cash flows. The impaired amount would be moved to the full cost amount subject to depletion. Effective January 1, 2009 operating costs net of revenue will be expensed with retroactive adjustment of prior costs (See note 2 l(iii)a)

Proceeds from the sale of oil and gas properties reduce PP&E, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion and depreciation.

(iii) Major facilities

Major facilities including the Upgrader and related equipment, and operating costs net of revenues in relation to major facilities that are considered to be in the development stage, are capitalized. Judgment is required to determine whether operations are in the development stage. The factors considered include whether commercially viable production levels have been achieved, whether the plant is producing a saleable product, whether the plant is operating at pre-determined operating levels in relation to commercial operations or other factors as circumstances warrant. Once the operations are no longer considered development stage, revenue is recognized and operating costs are recorded in earnings during the year.

An impairment loss is recognized on major facilities when the carrying amount is not recoverable and exceeds its fair value. The carrying amount is not recoverable if the carrying amount exceeded the sum of the undiscounted cash flows from expected use and eventual disposition. If the carrying amount is not recoverable, an impairment loss is measured as the amount by which the assets exceed the discounted future cash flows from the major facilities assets.

5

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

(iv) Asset retirement obligations

OPTI recognizes the fair value of the liability for asset retirement obligations in the period it is incurred with a corresponding increase to the carrying amount of the related asset. The initial obligation recognized is accreted over time until the future period in which the obligation is settled. The related asset will be amortized over its estimated useful life using straight line or the unit of production method once commercial operations commence.

(v) Corporate assets

Corporate office assets are recorded at cost less accumulated amortization which is calculated using the declining balance method at rates of 30 percent to 50 percent per annum.

(vi) Capitalized interest

Prior to the commencement of commercial operations, OPTI capitalizes interest costs in relation to its long-term debt for major development projects.

(vii) Foreign currency translation

Monetary assets and liabilities are translated at exchange rates in effect on the balance sheet date. Other assets and related depreciation, depletion and amortization, other liabilities and expenses are translated at rates in effect at the date of the transaction. Prior to the commencement of commercial operations, OPTI capitalizes foreign exchange gains or losses in relation to the revaluations of its U.S. dollar (US$) denominated cash and cash equivalents, related derivatives and long-term debt used for major development projects. Exchange gains and losses resulting from operating activities are included in earnings.

b) Joint venture

A significant portion of OPTI’s activities are conducted within a joint venture. The accounts reflect OPTI’s proportionate interest in such activities.

c) Cash and cash equivalents

Cash and cash equivalents include cash, bankers’ acceptances, term deposits and bankers’ deposit notes that carry terms less than 91 days at the date of purchase.

d) Leases

Leases that transfer substantially all the benefits, risks and rewards of ownership to OPTI are recorded as capital leases and classified as PP&E with a corresponding increase to obligations under capital leases.  Amortization is capitalized up until commencement of commercial operations.  All other leases are classified as operating leases under which leasing costs are expensed in the period incurred.  Prior to the commencement of commercial operations, OPTI is capitalizing operating lease payments.

e) Income taxes

OPTI uses the liability method of accounting for income taxes. Future tax assets and liabilities are recognized based on differences in the financial statement carrying amount for assets and liabilities and the associated tax balance.  Future taxes are measured based on substantially enacted tax rates in the period in which the temporary differences are expected to be realized or settled. The asset must be more likely than not to be realized, otherwise a valuation allowance reduces the tax asset.

f) Flow-through shares

Tax deductions for income tax purposes related to exploratory and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. Share capital is reduced, with a corresponding increase to the future tax liability, by the estimated cost of the tax deductions when such deductions are renounced to the investors.

6

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

g) Stock-based compensation plans

Stock options granted to directors, officers, employees and consultants are accounted for using the fair value method under which compensation expense is recorded based on the estimated fair value of the options at the grant date using the Black-Scholes option pricing model.  Compensation cost is either expensed or capitalized over the vesting period with a corresponding increase in contributed surplus.  When stock options are exercised, the cash proceeds along with the amount previously recorded as contributed surplus are recorded as share capital.

h) Loss per share

Loss per share is calculated using net earnings or loss and the weighted average number of common shares outstanding during the year. For the year ended December 31, 2008, the weighted average number of common shares of all classes outstanding is 195.7 million (December 31, 2007 - 177.4 million) and diluted is 195.7 million (December 31, 2007 - 181.6 million). OPTI uses the treasury stock method of calculating diluted earnings or loss per common share. There is no difference in basic or diluted loss per share.

i) Use of estimates

The preparation of the financial statements in accordance with Canadian generally accepted accounting principles (Canadian GAAP) requires management to make estimates and assumptions that affect reported amounts and presentation of assets, liabilities, revenues, expenses and disclosures of contingencies and commitments. Such estimates primarily relate to unsettled transactions and events at the balance sheet date which are based on information available to management at each financial statement date. Actual results could differ from those estimated.

The estimate of the percentage of completion of various projects at the financial statement date affects PP&E additions and the related accrued liability. Various estimates are required in consideration of impairment of capitalized costs. Consideration of impairment includes estimates relating to future cash flows, regulatory approval, and commodity prices.

For petroleum and natural gas properties, OPTI assesses impairment using management estimates of total proved oil and gas reserves, commodity prices and capital and operating costs required to develop those reserves. By their nature, these estimates and the related future net cash flows are subject to measurement uncertainty, and the impact of differences between actual and estimated amounts on the financial statements of future periods could be material. Our reserve estimates, which have been estimated by independent engineering firms, are subject to change as additional information becomes available or if different assumptions are used.

The estimate related to asset retirement obligations requires estimates of the amount and timing of future abandonment liabilities, inflation, and interest rates. The recognition of amounts in relation to stock-based compensation requires estimates related to valuation of stock options at the time of issuance.  Future taxes require estimates as to the realization of future tax assets and the timing of reversal of tax assets and liabilities. The fair value of the commodity contracts and foreign exchange hedging instruments are calculated using valuation models that require estimates as to future market prices.

By their nature, these estimates are subject to measurement uncertainty and the effect of changes in such estimates on the financial statements for current and future periods could be significant.

j) Interest reserve account

Cash is considered to be restricted when its availability is limited to a specified purpose.  At December 31, 2007, OPTI’s restricted cash balance was connected with the Senior Secured Notes.  The loan agreements required OPTI to maintain an account to fund anticipated interest payments through December 2008.

k) Capitalized foreign exchange hedging instruments gain or loss

Prior to the commencement of commercial operations, OPTI capitalizes to PP&E gains or losses in relation to the fair market valuation of its foreign exchange hedging instrumentswhich have not been designated for hedge accounting.

7

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

l) New standards

(i) Capital disclosures

On January 1, 2008, OPTI adopted the Canadian Institute of Chartered Accountants (CICA) handbook section 1535 “Capital Disclosures.” Section 1535 requires the disclosure of OPTI’s objectives, policies and processes for managing capital. This includes qualitative information regarding OPTI’s objectives, policies and processes for managing capital and quantitative data about what OPTI manages as capital. These disclosures are based on information used internally by OPTI’s management.  See note 10.

(ii) Financial instruments

On January 1, 2008, OPTI adopted the CICA handbook section 3862 “Financial Instruments - Disclosures,” and section 3863 “Financial Instruments - Presentation.”  Sections 3862 and 3863 replace section 3861 “Financial Instruments - Disclosure and Presentation” which revises financial instruments disclosure requirements and leaves unchanged its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how OPTI manages those risks. See discussion in OPTI’s 2008 annual Management’s Discussion and Analysis (“MD&A”) under the heading “Financial Instruments.”

(iii) Future accounting changes

a. The CICA issued a new accounting standard section 3064 “Goodwill and Intangible Assets” which is effective for OPTI on January 1, 2009.  This standard replaces section 3062 “Goodwill and Other Intangible Assets” and section 3450 “Research and Development Costs.”  The new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets.  The provisions relating to the definition and initial recognition of intangible assets are equivalent to the corresponding provisions of International Financial Reporting Standard IAS 38, “Intangible Assets.”  Emerging Issues Committee (EIC) abstract 27 “Revenues and Expenditures During the Pre-Operating Period” will no longer apply once section 3064 is adopted.  Accounting Guideline (AcG) 11 “Enterprises in the Development Stage” is amended to delete references to deferred costs and to provide guidance on development costs as intangible assets under section 3064.

In accordance with OPTI’s existing accounting policies, OPTI has capitalized gains and losses related to the translation of OPTI’s U.S. dollar debt, capitalized operations, as well as unrealized gains and losses related to certain financial derivatives associated with its long-term debt. As a result of the adoption of this new accounting standard, these capitalized amounts will no longer meet the criteria for capitalization. As such, OPTI will expense these items with retroactive effect on January 1, 2009 with a corresponding adjustment to opening deficit with restatement of comparative amounts as applicable.

The magnitude of these adjustments is expected to be approximately $92 million before tax increase to retained deficit. This is comprised primarily of the value of the foreign exchange hedging contracts at December 31, 2008 whose value reflects the then current and future value of foreign exchange and interest rates.

b. On February 13, 2008 the CICA Accounting Standards Board announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards (IFRS) in 2011. Prior to the adoption date, certain MD&A disclosures are required, beginning for the fourth quarter of 2008. OPTI is currently evaluating the impact of these new standards.

        m) Adoption of new accounting policies

On January 1, 2007, OPTI adopted the Canadian Institute of Chartered Accountants (CICA) handbook sections 1530 “Comprehensive Income,” section 3251 “Equity,” section 3855 “Financial Instruments - Recognition and Measurement” and section 3865 “Hedges.” These standards result in changes in the accounting for financial instruments and hedges as well as introduce comprehensive income as a separate component of shareholders’ equity. As required, these standards have been adopted prospectively and comparative amounts for the prior periods have not been restated.

8

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

(i) Comprehensive income

Comprehensive income is comprised of net earnings or loss and other comprehensive income (OCI). OCI represents the change in equity for a period that arises from unrealized gain and losses on available-for-sale securities and changes in the fair market value of derivative instruments designated as cash flow hedges. OPTI does not currently have any transactions that give rise to OCI, therefore OPTI’s net loss and comprehensive loss for the years ended December 31, 2007 and 2008 are the same amount.

(ii) Equity

This section establishes the standards for presentation of equity and changes in equity during the period. The section requires separate presentation of changes in equity for the period arising from net income, OCI, contributed surplus, retained earnings, share capital and reserves. Accumulated OCI is included in the balance sheet as a separate component of shareholders’ equity.

(iii) Financial instruments

This section establishes standards for the recognition and measurement of financial instruments, which is comprised of financial assets, financial liabilities, derivatives and non-financial derivatives.

A financial asset is cash or a contractual right to receive cash or another financial asset, including equity, from another party. A financial liability is the contractual obligation to deliver cash or another financial asset to another party.

A derivative is a financial instrument whose value changes in response to a specified variable, requires little or no net investment and is settled at a future date. An embedded derivative is a derivative that is a part of a non-derivative contract and not directly related to that contract. Under this standard, embedded derivatives must be accounted for as a separate financial instrument. A non-financial derivative is a contract that can be settled net in cash or another financial instrument.

Under this standard, all financial instruments are initially recorded at fair-value and are subsequently accounted for based on one of five classifications: held for trading, held-to-maturity, other financial liabilities, loans and receivables or available-for-sale. The classification of a financial instrument depends on its characteristics and the purpose for which it was acquired.

A) Held for trading

Held for trading financial instruments are financial assets or financial liabilities that are purchased with the intention of selling or repurchasing in the near term. Any financial instrument can be designated as held for trading as long as its fair value can be reliably measured. A derivative is classified as held for trading unless designated as and considered an effective hedge. Held for trading instruments are recorded at fair value with any subsequent gains or losses from changes in the fair value included in earnings.

OPTI’s commodity contracts and foreign exchange hedging instruments are derivatives and accounted for as held for trading financial instruments and are recorded at fair value.

B) Held-to-maturity

Held-to-maturity investments are non-derivative financial assets with fixed or determinable payments and a fixed maturity that OPTI has the intent and ability to hold to maturity. These financial assets are measured at amortized cost using the effective interest method. Any gains or losses arising from the sale of a held-to-maturity investment are included in earnings. All of OPTI’s cash equivalents and the interest reserve account are designated as held-to-maturity investments.

The fair values of cash equivalents, short-term investments and the interest reserve account approximate their carrying value due to their short-term nature.

9

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

C) Other financial liabilities

Items classified as other financial liabilities, excluding asset retirement obligation, on OPTI’s financial statements are accounted for at amortized cost using the effective interest method. Any gains or losses in the realization of other financial liabilities are included in earnings.

D) Receivables

Items classified as receivables in OPTI’s financial statements are accounted for at amortized cost using the effective interest method. Any gains or losses on the realization of receivables are included in earnings.

The fair value of accounts and other receivables and accounts payable and accrued liabilities approximate their carrying values due to the short-term nature of these instruments. All costs related to debt issuance are expensed as incurred.

E) Available-for-sale

Available-for-sale assets are those financial assets that are not classified as held for trading, held-to-maturity or loans and receivables. Available-for-sale instruments are recorded at fair value. Any gains or losses arising from the change in fair value is recorded in OCI and upon the sale of the instrument or other-than-temporary impairment, the cumulative gain or loss is included in earnings.

OPTI has not designated any financial instruments as available-for-sale assets.

Fair values are based upon quoted market prices available from active markets or are otherwise determined using a variety of valuation techniques and models using quoted market prices.

Effective January 1, 2007, transaction costs relating to all financial instruments are expensed as incurred. As a result, $38 million of deferred financing costs, net of taxes of $11 million, have been charged to opening deficit.

3. COMMODITY CONTRACTS

OPTI has deferred premium West Texas Intermediate put options that provide a US$80 per barrel strike price for 6,000 bbl/d through 2009. At December 31, 2008 these instruments had an estimated value of $73 million. The cost of the put options are paid as the contracts expire and have been included in accounts payable and accrued liabilities. Additionally, OPTI has crude swaps at US$77 per barrel for 500 barrels a day through 2009, with an estimated value of $5 million at December 31, 2008.

4. PROPERTY, PLANT AND EQUIPMENT

	2008			2007
Long Lake Project	$	3,699,068		$	3,027,730
Other oil sands activities		422,728			294,319
Corporate assets		3,555			17,470
Asset retirement cost		7,763			7,454
Capital lease		30,195			29,600
		4,163,309			3,376,573
Accumulated amortization - corporate assets		(2,408	)		(2,665	)
	$	4,160,901		$	3,373,908

10

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

4.     PROPERTY, PLANT AND EQUIPMENT (CONTINUED)

During the year ended December 31, 2008, OPTI capitalized $3 million (2007 - $5 million) of general and administrative expenses, $177 million (2007 - $130 million) of interest and $372 million of net foreign exchange losses (2007 - $235 million gain).  With the exception of corporate assets, no depletion, depreciation or amortization has been recorded as commercial operations have not commenced. The cost of unproved property was $423 million (2007 - $289 million). As a result of the asset sale noted in note 14, subsequent events, an impairment loss before taxes of $392 million was recorded in 2008.

For the calculation of the December 31, 2008 ceiling test, the benchmark prices for West Texas Intermediate in US$/barrel were as follows: 2009 - $60.00; 2010 - $71.40; 2011 - $83.20; 2012 - $93.90; 2013 - $97.40; and thereafter annual increases of 2 percent. See note 2a(ii) for discussion of impairment policy.

OPTI is engaged in the development of oil sands projects. Since inception, OPTI has been developing the Long Lake Project and proceeding with the development of future phases. OPTI is considered to be in the development stage as the Upgrader has not commenced operations.

				Years ended
Amounts capitalized	Inception to 2008			2008			2007
Revenue	$	296,555		$	286,931		$	-
Operating costs		(498,563	)		(428,114	)		(36,995	)
Standby charges on debt		(33,210	)		(1,603	)		(3,491	)
Foreign exchange gain (loss)		(167,318	)		(372,625	)		235,164
Foreign exchange hedging instruments gain (loss)		145,241			207,049			(56,982	)
Interest		(368,179	)		(177,480	)		(130,109	)
General and administrative costs		(22,751	)		(2,636	)		(4,538	)
Future tax		(7,048	)		(25,047	)		13,109

5. DEBT FACILITIES

OPTI’s debt consists of the following:

	2008		2007
Senior secured notes (a)	$	2,131,500	$	1,734,775
$500 million revolving credit facility (b)		486,500		-
Long-term debt		2,618,000		1,734,775
Short-term debt: $150 million revolving credit facility (c)		145,500		-
Total debt	$	2,763,500	$	1,734,775

a) Senior secured notes

OPTI has US$1,000 million senior secured notes which bear interest at a fixed 8.25 percent and mature on December 15, 2014. These notes are collateralized by a second priority security interest on all OPTI’s existing and future property. OPTI may redeem up to 35 percent of these notes prior to December 15, 2009 with net proceeds from certain equity offerings. At any time prior to December 31, 2010, OPTI may redeem these notes at the principal amount, plus the applicable premium and accrued interest and at any time after December 31, 2010 at redemption prices between 104.13 percent and 100 percent of the principal amount.

OPTI also has US$750 million senior secured notes. These notes bear interest at a fixed 7.875 percent and mature December 15, 2014. The other terms and conditions associated with these notes are substantially the same as the notes described above.

See note 10 for discussion of the debt covenants.

11

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

5.     DEBT FACILITIES (CONTINUED)

b) $500 million revolving credit facility

OPTI has a $500 million revolving credit facility due December 15, 2011. Amounts drawn under this facility can take the form of prime rate based loans, bankers’ acceptances, LIBOR loans or letters of credit. The facility will bear interest at the prime rate, bankers’ acceptance rate or at LIBOR plus a spread above the reference rate between 1.0 percent and 2.5 percent per annum. This facility is collateralized by a first priority security interest on all present and after acquired property of OPTI. The revolving credit facility includes certain conditions precedent to all borrowings which include a sufficient funding test related to the Project.  At December 31, 2008, $486.5 million was outstanding under this facility. Subsequent to December 31, 2008, the $500 million revolving credit facility was reduced to $350 million. See note 14, Subsequent events.

c) $150 million revolving credit facility

On June 23, 2008, OPTI established a $150 million revolving credit facility due June 22, 2009. Borrowings under this facility can take the form of prime rate based loans, bankers’ acceptances, LIBOR loans or letters of credit. Borrowings will bear interest at the prime rate, bankers’ acceptance rate or at LIBOR plus a spread above the reference rate between 1.0 percent and 2.5 percent per annum. This facility is collateralized by a first priority security interest on all present and after acquired property of OPTI. This facility includes certain conditions precedent to all borrowings which include a sufficient funding test related to the Project. At December 31, 2008, $145.5 million was outstanding under this facility.  Subsequent to December 31, 2008, this $150 million revolving credit facility was repaid and cancelled. See note 14, Subsequent events.

6. FUTURE INCOME TAXES

The provision for income taxes reflects an effective tax rate of 25 percent (2007 - 49 percent) which differs from the statutory tax rate of 29.5 percent (2007 - 32.1 percent).  The reasons for the difference are discussed below.

	2008			2007
Recovery based on book earnings	$	(100,759	)	$	(5,981	)
Impact of future tax rate and timing changes		15,307			(3,588	)
Resource allowance		-			-
Stock-based compensation		559			435
Large corporation tax		-			-
Other		(132	)		-
Future tax recovery	$	(85,025	)	$	(9,134	)

Significant components of OPTI’s future tax liabilities (assets) are as follows:

	2008			2007
Book value in excess of tax value - capital assets	$	265,952		$	74,197
Book value in excess of tax value - long-term debt		(23,663	)		25,928
Asset retirement obligation		(1,984	)		(1,767	)
Benefit of share issuance costs		(9,198	)		(15,561	)
Losses for income tax purposes		(278,233	)		(84,950	)
Future tax asset		(47,126	)		(2,153	)
Short-term future tax asset		(2,709	)		-
Long-term future tax asset	$	(44,417	)	$	(2,153	)

At December 31, 2008, the expiry dates of losses for income tax purposes are $3 million in 2009, $10 million in 2010, $9 million in 2014, $16 million in 2015, $117 million in 2026, $685 million in 2027, and $278 million in 2028.

12

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

7.  OTHER LONG TERM LIABILITIES

OPTI’s other long term liabilities consists of the following:

	2008		2007
Foreign exchange hedging instruments (a)	$	-	$	59,607
Asset retirement obligation (b)		7,937		7,070
	$	7,937	$	66,677

a) Foreign exchange hedging instruments

In 2008, OPTI settled its existing foreign currency hedging instruments for a net realized gain of $114 million. These instruments consisted of a US$200 million foreign exchange forward contract and US$875 million of cross currency swaps. OPTI’s new foreign exchange hedging instruments are in other long-term assets and discussed in note 9c.

b) Asset retirement obligation

OPTI’s obligations with respect to asset retirement relate to reclamation of sites and facilities on which the Project operations are situated. The obligation is recognized in the period in which the obligation is created based on the estimated future reclamation cost using an average discount rate of 11.5 percent and estimated inflation of 3 percent annually. The total undiscounted future obligation is $151 million.

CONTINUITY OF ASSET RETIREMENT OBLIGATION
Present value of obligation at January 1, 2007	$	5,832
New obligations during the year		835
Asset retirement costs incurred		(24	)
Accretion expense		427
Present value of obligation at December 31, 2007		7,070
New obligations during the year		309
Asset retirement costs incurred		(9	)
Accretion expense		567
Present value of obligation at December 31, 2008	$	7,937

OPTI estimates its obligations related to drilling activities will be settled over approximately the next 20 years and obligations relating to resource assets will be settled in approximately 55 years. OPTI’s upgrading facilities related to the Project have retirement obligations with indeterminate settlement dates and for which present value cannot be reasonably determined because the asset currently has an indeterminable useful life. An asset retirement obligation for these assets will be recorded in the period in which the lives of the assets become reasonably determinable.

13

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

8. SHAREHOLDERS’ EQUITY

a)     Authorized

Unlimited number of common shares and preferred shares without nominal or par value.

b) Issued and outstanding

	NUMBER OF SHARES (thousands)		AMOUNT
Common shares - January 1, 2007		172,684	$	1,447,679
Issued for cash (c)		18,535		352,156
Issued for cash - flow-through (c)		2,430		60,021
Common share options exercised		1,707		18,343
Share issue costs				(16,768	)
Tax effect on flow-through shares and share issue costs				(7,514	)
Common shares - December 31, 2007		195,356		1,853,917
Common share options exercised		357		4,870
Warrants exercised		217		3,750
Share issue costs				(71	)
Tax effect on flow-through shares and share issue costs				(15,005	)
Common shares - December 31, 2008		195,930	$	1,847,461
Call obligations - December 31, 2007				(16,664	)
Expiration of call obligations (e)				16,664
Call obligations - December 31, 2008				-
Total capital stock - December 31, 2008		195,930	$	1,847,461

c)     2007 equity issuance

On November 21, 2007 OPTI issued 18,534,500 common shares at a price of $19.00 per common share and 2,430,000 flow-through common shares at a price of $24.70 per common share for aggregate gross proceeds of $412 million.

d)     Outstanding warrants

OPTI had common share warrants outstanding that entitled the holders to purchase a total of 5,991,000 common shares at a price of $14.75 each. These warrants expired in November 2008.

e)     Call obligations

On June 30, 2008, $202 million of outstanding call obligations expired unexercised by OPTI.  The call obligations consisted of unconditional and irrevocable call options whereby OPTI, at its option, could have required a subscription for either a convertible preferred share or a common share for the face amount of the call obligation.  The exercise price per share of the call obligations was $2.20 per share.  The amount of the expired call obligations has been recorded as an adjustment to Deficit.

14

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

8. SHAREHOLDERS’ EQUITY (CONTINUED)

f)      Outstanding stock options

OPTI may grant stock options to executives, certain employees, consultants, and directors as determined by the Board of Directors.  The exercise price of each option is determined by the Board based on the current market price of OPTI’s common shares at the date of the grant.  Vesting rights are determined at the discretion of the Board. Under OPTI’s plans, options vest at the time of grant or over a five-year period. The maximum number of options that are allowed to be issued under the stock option plan is approximately 15 million. Options outstanding expire at dates up to 2018.

OPTIONS OUTSTANDING	OPTIONS (thousands)			EXERCISE PRICE PER SHARE
Balance January 1, 2007		8,136		$	11.69
Granted		1,003			19.58
Forfeited		(224	)		15.77
Exercised		(1,707	)		9.82
Balance December 31, 2007		7,208		$	13.03
Granted		761			15.74
Forfeited		(452	)		17.80
Exercised		(357	)		10.76
Balance December 31, 2008		7,160		$	13.14

			OPTIONS OUTSTANDING				EXERCISABLE OPTIONS
EXERCISE PRICE RANGE	THOUSANDS OF OPTIONS		REMAINING CONTRACTUAL LIFE (YEARS)		WEIGHTED AVERAGE EXERCISE PRICE		THOUSANDS OF OPTIONS		WEIGHTED AVERAGE EXERCISE PRICE
$1.95 to $4.99		281		2.7	$	4.22		260	$	4.32
$5.00 to $9.99		2,890		1.7		9.06		2,834		9.12
$10.00 to $14.99		1,153		5.7		10.97		782		10.95
$15.00 to $19.99		2,009		8.5		18.14		465		18.54
$20.00 to $23.50		827		7.6		21.27		257		21.23
Balance December 31, 2008		7,160		5.0	$	13.14		4,598	$	10.79

g)    Stock-based compensation

During the year ended December 31, 2008, there were 760,500 (2007 - 1,002,500) common share options granted which had a total fair value of $4 million (2007 - $7 million). The fair value was calculated at the date of each grant using the following assumptions: a risk free interest rate of 3.5 percent (2007 - 4.0 percent), a term of ten years (2007 - ten years) and an average volatility of 45 percent (2007 - 36 percent). Stock-based compensation costs for the year ended December 31, 2008 are $5 million (2007 - $4 million), of which $2 million is included in general and administrative expenses (2007 - $1 million) and $3 million is included in PP&E (2007 - $3 million).

15

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

8. SHAREHOLDERS’ EQUITY (CONTINUED)

h)    Contributed surplus

The following outlines changes in contributed surplus:

Balance January 1, 2007		9,357
Capitalized stock-based compensation		2,732
Expensed stock-based compensation		1,356
Stock options exercised		(1,548	)
Balance December 31, 2007	$	11,897
Capitalized stock-based compensation		3,181
Expensed stock-based compensation		1,895
Reclassified expired warrants		15,137
Stock options exercised		(1,030	)
Balance December 31, 2008	$	31,080

9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

a) Fair values

OPTI’s financial instruments include cash equivalents, interest reserve account, accounts receivable and accounts payable and accrued liabilities. Due to the short-term nature of the instruments, the carrying values approximate the fair values. The commodity contracts, cross currency interest rate swaps and foreign exchange contracts are considered to be held-for-trading and are recorded at fair value. OPTI’s senior secured notes and the revolving credit facilities are recorded at cost. At December 31, 2008, the estimated fair value of the notes is US$934 million (CAD$1,137 million) and the carrying value of the revolving credit facilities approximates their fair value due to their variable rate, first priority security position and short-term duration of instruments outstanding under the facilities.

b) Risk management

OPTI provides a risk management discussion as required by the CICA handbook section 3862 “Financial Instruments - Disclosures” on its exposure to and management of credit risk, liquidity risk and market risk in the 2008 annual MD&A under the heading “Financial Instruments”.

c) Foreign exchange hedging instruments

At December 31, 2008, OPTI has foreign exchange forward contracts to provide for a fixed Canadian dollar (CAD) payment of $1,028 million in exchange for receipt of US$875 million on April 16, 2010 at a rate of approximately $1.17 Canadian dollars per U.S. dollar. Prior to the commencement of commercial operations, any gains or losses based on mark to market of the contract are capitalized to property, plant and equipment.

d) Commodity contracts

During 2008, OPTI purchased put options that provide a price floor for a portion of its anticipated 2009 production.  See note 3.

10. CAPITAL MANAGEMENT

OPTI’s objectives when managing its capital are:

• to manage capital in a manner that will maintain compliance with its financial covenants;

• to manage a strong capital base so as to maintain investor, creditor and market confidence and to sustain future development of the business;

• to maintain an appropriate balance between debt and equity sources of financing; and

• to maintain sufficient undrawn credit capacity to provide liquidity.

16

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

10. CAPITAL MANAGEMENT (CONTINUED)

OPTI defines its capital as follows:

• capital stock; and

• debt, including long and short-term portions.

As OPTI does not have commercial operations, virtually all of our capital to date has resulted from the issuance of debt and equity.  To date, OPTI has been funded with both long-term debt and equity. A description of debt and related changes in the period is described in note 5. Equity capital for OPTI is described in note 8. We expect to generate positive operating cash flows to support funding for interest costs and future expenditures once bitumen production rises and the Upgrader is operating stably. The sale of a portion of the Long Lake Project in January 2009 is expected to provide an additional financing for 2009.

OPTI is a public company and has established access in past transactions to both public and private debt and equity markets. OPTI anticipates continued long-term access to both the debt and equity markets to fund future growth of the business. In the short term, there may be times where access to debt and equity markets is restricted or unavailable.

All of OPTI’s debt facilities set certain limitations on its capital structure primarily through financial covenants. Measurement of the ratios for this purpose is defined in the relevant credit agreement. OPTI is presently in compliance with these financial maintenance covenants:

Financial Ratio	Covenant(1)	Calculated ratio at December 31,
		2008	2007
Debt to Capitalization (2)	Maximum 65%	64%	50%
First Lien to EBITDA (3)	Minimum 3.5:1	N/A(4)	N/A(4)

(1) Covenants noted are as of December 31, 2008. On January 27, 2009, the facilities were renegotiated and resulted in adjustments to the covenants. See note 14.

(2) "Debt to Capitalization” means, as at any date of determination, the ratio of Total Consolidated Debt to Total Capitalization (net of the effect of any currency Hedge Agreements relating to any Debt included therein). "Total Capitalization" means, as at any date of determination, the aggregate of Total Consolidated Debt, and Shareholders' Equity on such date.

(3) EBITDA (defined here as total revenue less direct costs and selling and administrative costs) is not a recognized measure under GAAP, does not have a standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers. First Lien for the purposes of this ratio includes the debt outstanding under the revolving credit facilities.

(4) Under the amended revolving credit facility, the first time this covenant is applicable is the third quarter of 2009, previously it was to be assessed for the first quarter of 2009.

With respect to our senior secured notes, the covenants are in place primarily to govern the total amount of debt that OPTI may incur at any time. This limit is most affected by the present value of our total proved reserves using forecast prices discounted at 10 percent. We have sufficient capacity under this test to incur additional debt beyond our existing $350 million revolving credit facility. Other leverage factors, such as debt to capitalization, interest coverage ratios and total debt to EBITDA are expected to be more constraining of future than this limitation. Under certain payment related defaults under our revolving credit facility, we may be required to offer to repay our senior secured notes.

OPTI sets internal targets for its financial ratios that are similar to the requirements in the debt agreements.  These internal targets support evaluation of the timing and amount of new debt and equity that balance creation of value for stakeholders with the management of risks associated with debt. Capital funding plans and targets are set annually based on expected growth programs and forecasted financial results for the business.

17

OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

10.  CAPITAL MANAGEMENT (CONTINUED)

In management’s opinion, OPTI has met its objectives as outlined and has available borrowing capacity under its debt facilities. Ongoing access to its revolving credit facility requires that production levels for the project continue to ramp up so that the company can meet its financial ratios described above.

11. COMMITMENTS

a) Project commitments

OPTI has commitments in connection with contracts and purchase orders of $22 million at December 31, 2008.   Commitment amounts are measured within contracts and purchase orders through letters of intent, scheduled work releases and forecast expenditures for labor and equipment utilization. These commitments will be realized in incurred expenditures over time as certain milestones are met, work is completed, or both.

b) Lease obligations and other commitments

OPTI has an agreement with Enbridge Pipelines (Athabasca) Inc. that provides for the storage, measurement and transportation of crude oil and other liquids between the Athabasca main line and the Long Lake site. This agreement is considered to be a capital lease for accounting purposes. This agreement has a primary term of 25 years and an option for renewal of five additional years. Capital lease payments on this agreement for the next five years and thereafter are as follows:

2009	$	4,646
2010		4,646
2011		4,647
2012		4,315
2013		4,149
Thereafter		79,517
Total including interest		101,920
Less imputed interest		(71,725	)
Capital lease obligation	$	30,195

The above table is based on OPTI’s 50 percent working interest in the Long Lake Project as of December 31, 2008. Capital lease obligation as at January 27, 2009 was $21.1 million based on a 35 percent working interest. See note 14.

OPTI has an agreement with Enbridge Pipelines (Athabasca) Inc. for transportation of oil products from Long Lake to Hardisty.  The initial term of this agreement extends to 2012. OPTI also has an agreement with Pembina Oil Sands Pipeline L.P. for a pipeline which transports synthetic crude oil, for use as a diluent, available to the Long Lake site. This agreement has an initial term of 25 years. These two pipeline agreements are considered to be operating leases for accounting purposes. During the fourth quarter, OPTI entered into 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 for periods up to 2032. Prior to the commencement of commercial operations, OPTI capitalizes operating lease payments.

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OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

11. COMMITMENTS (CONTINUED)

Operating lease payments on these agreements for the next five years and thereafter are as follows:

2009	13,418
2010	14,279
2011	13,725
2012	14,177
2013	14,414
Thereafter	44,728
Total	114,741

The above table is based on OPTI’s 50 percent working interest in the Long Lake Project. Actual commitments are $80 million based on a 35 percent working interest in the Long Lake Project. See note 14.

12. COMPARATIVE FIGURES

Certain of the comparative figures have been reclassified to conform to the presentation adopted in the current period.

13. SUPPLEMENTAL INFORMATION TO STATEMENT OF CASH FLOW

	2008			2007
Cash taxes paid	$	-		$	-
Cash interest received		5,909			23,281
Cash interest paid		173,511			142,049
Non-cash changes to property, plant and equipment		(73,734	)		(206,994	)
Non-cash changes to capital stock		(13,246	)		(5,966	)

	2008			2007
Change in non-cash working capital
Accounts and other receivables	$	(10,224	)	$	(6,014	)
Accounts payable and accrued liabilities		(7,328	)		36,554
Net change in non-cash working capital	$	(17,552	)	$	30,540
Operating activities	$	1,157		$	4,496
Financing activities		13,241			(4,793	)
Investing activities		(31,950	)		30,837
Net change in non-cash working capital	$	(17,552	)	$	30,540

14. SUBSEQUENT EVENTS

On January 27, 2009, OPTI completed a sale of a 15 percent working interest in its joint venture assets to Nexen Inc. (Nexen) for $735 million.  Effective January 1, 2009, OPTI has a remaining 35 percent working interest in all the joint venture assets, including Phase 1 of the Long Lake Project, all future phase reserves and resources, and future phases of development.  As part of the sale, Nexen retained $85 million of the proceeds to pre-fund OPTI’s share of 2009 joint venture capital requirements.  

To consider impairment as of December 31, 2008, assets were grouped to depreciable assets, resource assets and unproved properties based on the nature of the asset and an assessment of their depreciation basis. Each asset type was assessed individually for impairment.

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OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

14. SUBSEQUENT EVENTS (CONTINUED)

We allocated the sales proceeds to each asset type based on an estimate of fair value. The sales proceeds allocated to depreciable assets were lower than the book value of the asset, as a result a loss before taxes of $392 million was recorded in 2008. The sales proceeds allocated to resource assets did not alter the depletion rate by greater than 20 percent and as a result no gain or loss was recorded. The sales proceeds will be recorded as a reduction to book value as of completion of the sale in 2009. The sales proceeds for unproved properties and resource assets will be recorded as a reduction to book value as of completion of the sale in 2009. The remaining assets were subject to a ceiling test and cost recovery test which concluded no further impairment existed.

Additionally, as a result of the asset sale, the revolving debt facilities were amended on January 27, 2009. Significant changes include:

• $150 million revolving credit facility was repaid and cancelled;

• $500 million revolving credit facility was reduced to $350 million, $400 million was repaid through February 25, 2009 and applicable interest rates were increased by approximately 2 to 4 percent depending on our debt rating;

• First lien to EBITDA covenant commences in the third quarter of 2009 with a maximum ratio 2.5:1 as defined in Note 10 (previously the first quarter of 2009 and a ratio of 3.5:1);

• Debt to Capitalization ratio was  increased to 70 percent from 65 percent as defined in Note 10; and

• The Canadian measurement of our U.S. dollar denominated debt was changed from a period end exchange rate to the average rate for the preceding quarter for debt covenant calculation purposes.

15. RECONCILIATION TO US GAAP

The financial statements of OPTI have been prepared in accordance with generally accepted accounting principles (GAAP) in Canada. With respect to OPTI, these principles conform in all material respects to those in the United States for items of measurement except for the following:

STATEMENT OF LOSS RECONCILIATION (CAD $000)	Year-ended December 31
	2008			2007
Net loss in accordance with CDN GAAP	$	(256,532	)	$	(9,486	)
Revenue capitalized (a)		286,931		
Pre-operating expenses capitalized (a)		(388,118	)		(36,995	)
Depletion expense (a)		(11,875	)	
Standby charges capitalized (b)		(1,603	)		(3,491	)
Foreign exchange gain (loss) capitalized (b)		(372,625	)		235,164
Foreign currency hedging instruments capitalized (b)		207,049			(56,982	)
Reduction (increase) in future tax (a,b,d)		16,002			(9,426	)
Flow-through share premium (c)		13,778			8,959
Tax effect of flow-through shares (c)		(15,005	)		(11,706	)
Deferred financing charges expensed (d)		893			11,927
Deferred financing amortization (d)		(7,481	)		(6,144	)
Asset impairment under Canadian GAAP (e)		391,686		
Asset impairment under US GAAP (e)		(354,274	)	
Net earnings (loss) in accordance with US GAAP	$	(491,174	)	$	121,820
Earnings (loss) per share, basic and diluted	$	(2.51	)	$	0.69

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OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

15.  RECONCILATION TO US GAAP (CONTINUED)

BALANCE SHEET RECONCILIATION	AT DECEMBER 31, 2008						AT DECEMBER 31, 2007
(CAD $000)	CDN GAAP			US GAAP			CDN GAAP			US GAAP
Assets
Property, plant and equipment (a,b)	$	4,160,901		$	3,973,965		$	3,373,908		$	3,438,084
Accumulated depletion expense (a)		-			(15,358	)		-			(3,483	)
Deferred financing charges (d)		-			39,362			-			44,211
Liabilities
Liability relating to flow-through share premium (c)		-			-			-			13,778
Future income tax liability (asset) (a,b,d)		(47,126	)		(67,032	)		(2,153	)		4,259
Shareholders’ equity
Capital stock (c)		1,847,461			1,902,532			1,837,253			1,877,319
Deficit		(322,419	)		(512,409	)		(49,223	)		(4,570	)
Total Shareholders’ equity		1,556,122			1,421,203			1,815,613			1,900,332

a) Under Canadian GAAP, OPTI’s resource activities are considered to be in the pre-operating stage and are therefore capitalized under full cost accounting guidelines. There is no comparable standard for US GAAP which allows capitalization of pre-operating activities. These operations would be recorded as revenue and operating costs with a depletion provision calculated on a unit of production basis. The resulting decrease in the book value of PP&E reduces the related future tax liability.

b) Under Canadian GAAP during the pre-operating period, standby fees associated with borrowing facilities, foreign exchange gains or losses, unrealized gains or losses on the interest rate swap and unrealized gains or losses associated with the foreign currency hedging instruments associated with borrowing facilities and the related future tax impact can be capitalized. Under US GAAP, during the pre-operating period these costs would be expensed as incurred and any gains or losses on derivative instruments not designated as a hedging instrument are recognized into earnings.

c) Under Canadian GAAP, the proceeds from the issuance of flow-through shares are recorded in equity at their face value. Under US GAAP, the proceeds must be allocated between the sale of the shares and the sale of the tax benefit. A liability is created for the difference between the market price of the existing shares and the price the investor paid for the flow-through shares.  In November 2007, OPTI issued 2,430,000 flow-through common shares at a price of $24.70 per share for gross proceeds of $60 million which has resulted in a $14 million liability. When the tax benefits are renounced to shareholders, the difference between this liability and the value of the tax basis given up is recorded as tax expense. Under Canadian GAAP the value of the tax basis given up reduces the value of the flow-through shares issued. During March 2008, OPTI fully renounced the tax deductions to investors in relation to the flow-through shares issued in 2007 and recorded the related entries to future tax.

d) On January 1, 2007, OPTI adopted to Canadian Institute of Chartered Accountants section 3855 “Financial Instruments - Recognition and Measurement.” As a result of the adoption, all previously recorded deferred financing charges, net of future tax, are recorded as an adjustment to opening deficit. Under this new section, all transactions costs relating to financial instruments are to be expensed as incurred. Under US GAAP, debt transactions costs are deferred and amortized over the life of the associated debt.

e) OPTI recognized an impairment at December 31, 2008 related to the pending sale of assets under Canadian GAAP. The book value of assets sold under US GAAP is lower based on the capitalized pre-operating costs discussed in (d) above and results in a lower impairment. As such, the Canadian GAAP loss was reversed out of net income and the US GAAP loss was added.

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OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

15. RECONCILATION TO US GAAP (CONTINUED)

f) The statement of cash flows are prepared in accordance with Canadian GAAP and conform in all material respects to US GAAP except that Canadian GAAP allows for the presentation of operating cash flow before changes in non-cash working capital in the statement of cash flows. This total cannot be presented under US GAAP.

g) Under Canadian full cost accounting rules, impairment is recognized if the carrying amount of the PP&E exceeds the sum of the undiscounted cash flows expected to result from proved reserves using estimated future prices and costs (the “ceiling test”). Under the full cost method of accounting as set forth by the US Securities and Exchange Commission, the ceiling test differs from Canadian GAAP in that future net revenues from proved reserves are based on prices and costs as at the balance sheet date (“constant dollar pricing”) and are discounted at 10 percent. Management has reviewed the valuation of the Long Lake Project and other oil sands properties and estimates that the fair market value of these properties exceeds their carrying amount.

h) The components of accounts payable and accrued liabilities are as follows:

	December 31, 2008		December 31, 2007
CAD $000’s
Accounts payable	$	19,686	$	14,242
Accrued liabilities		180,221		176,481
Total	$	199,907	$	190,723

i) For US GAAP purposes, OPTI is considered to be a development stage company and the financial statements should be labeled as such. In the statement of shareholders’ equity, OPTI’s deficit should be labeled as deficit accumulated during the development stage. Additional disclosure required for a development stage company are as follows:

	December 31, 2008			December 31, 2007
CAD $000’s
Property, plant and equipment under Canadian GAAP	$	4,160,901		$	3,373,908
Revenue capitalized (a)		296,555			9,624
Pre-operating expenses capitalized (a)		(458,568	)		(70,449	)
Standby charges capitalized (b)		(33,210	)		(31,607	)
Foreign exchange gain (loss) capitalized (b)		(167,318	)		205,307
Foreign exchange hedging instruments capitalized (b)		145,241			(61,808	)
Impairment difference (e)		37,412			-
Capitalized future tax (b)		(7,048	)		13,109
Property, plant, and equipment under US GAAP	$	3,973,965		$	3,438,084

        J) Recent Accounting Pronouncements

The Company has assessed new and revised accounting pronouncements that have been issued that are not yet effective:

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” This standard became effective November 15, 2008 following the SEC’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section, 411 “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” The statement is intended to improve financial reporting by identifying a consistent hierarchy for selecting accounting principles to be used in preparing financial statements that are presented in conformity with U.S. GAAP. The adoption of this standard did not have a material impact on OPTI’s Financial Statements.

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OPTI CANADA INC.

Notes to the Financial Statements

(Tabular amounts are in thousands of Canadian dollars, unless otherwise stated)

As of January 1, 2009, SFAS 141(R), “Business Combinations,” replaces SFAS 141. This revised standard requires assets and liabilities acquired in a business combination, contingent consideration, and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination. This new standard will only impact acquisitions occurring on or after January 1, 2009

As of January 1, 2009, SFAS No. 160, “Noncontrolling Interests in Financial Statements, an Amendment of ARB No. 51” will come into effect. This standard requires a noncontrolling interest in a subsidiary to be classified as a separate component of equity. The standard also changes the way the U.S. GAAP Statement of Earnings is presented by requiring net earnings to include the amounts attributable to both the parent and the noncontrolling interest and to disclose these respective amounts. The adoption of this standard will not have any impact on OPTI’s Financial Statements.

As of December 31, 2009, OPTI will be required to prospectively adopt the new reserves requirements that arise from the completion of the SEC’s project, Modernization of Oil and Gas Reporting. The new rules include provisions that permit the use of new technologies to establish proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. Additionally, oil and gas reserves will be reported using an average price based upon the prior 12-month period rather than year-end prices. The new rules will affect the reserve estimate used in the calculation of DD&A and the ceiling test for U.S. GAAP purposes. The Company is assessing the impact these new rules will have on its Financial Statements

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ADDITIONAL DISCLOSURE

Certifications and Disclosure Regarding Controls and Procedures.

(a) Certifications.  See Exhibits 99.1, 99.2. 99.3 and 99.4 to this Annual Report on Form 40-F.

(b) Disclosure Controls and Procedures.  As of the end of the registrant’s fiscal year ended December 31, 2008, an evaluation of the effectiveness of the registrant’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was carried out by the registrant’s management with the participation of the principal executive officer and principal financial officer.  Based upon that evaluation, the registrant’s principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, the registrant’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits to the Securities and Exchange Commission (the “Commission”) under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Commission’s rules and forms and (ii) accumulated and communicated to the registrant’s management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

It should be noted that while the registrant’s principal executive officer and principal financial officer believe that the registrant’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the registrant’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud.  A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

(c) and (d) Management’s Report on Internal Control Over Financial Reporting and Attestation Report of the Registered Public Accounting Firm.  This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s independent registered public accounting firm due to a transition period established by the rules of the Commission for newly reporting companies.

(e) Changes in Internal Control Over Financial Reporting.  During the fiscal year ended December 31, 2008, there were no changes in the registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.

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Notices Pursuant to Regulation BTR.

None.

Identification of the Audit Committee.

The registrant has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act.  The members of the audit committee are:  Charles Dunlap, Robert G. Puchniak, James van Hoften, and Bruce Waterman.

Audit Committee Financial Expert.

The registrant’s board of directors has determined that Robert Puchniak, a member of the registrant’s audit committee, qualifies as an “audit committee financial expert” (as such term is defined in Form 40-F), and is “independent” as that term is defined in the rules of the New York Stock Exchange.

Code of Ethics.

The registrant has adopted a “code of ethics” (as that term is defined in Form 40-F) (the “Code of Ethics”) that applies to its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions.

OPTI will arrange for a copy of the Code of Ethics to be mailed to an interested party.  Requests for copies of the Code of Ethics should be made by contacting: Chief Financial Officer, OPTI Canada Inc., 2100, 555-4th Avenue S.W., Calgary, Alberta, Canada  T2P 4H2, (403) 249-9425 (Fax: (403) 225-2606).

Since the adoption of the Code of Ethics, there have not been any amendments to the Code of Ethics or waivers, including implicit waivers, from any provision of the Code of Ethics.

Principal Accountant Fees and Services.

The required disclosure is included under the heading “Auditor Service Fees” in the registrant’s Annual Information Form for the fiscal year ended December 31, 2008, filed as part of this Annual Report on Form 40-F.

Pre-Approval Policies and Procedures.

The required disclosure is included under the heading “Auditor Service Fees” in the registrant’s Annual Information Form for the fiscal year ended December 31, 2008, filed as part of this Annual Report on Form 40-F.

40-F3

Off-Balance Sheet Arrangements.

OPTI does not have any off-balance sheet financing arrangements that have or are reasonably likely to have an effect on its results of operations or financial condition.

Tabular Disclosure of Contractual Obligations.

Commitments for contracts and purchase orders at December 31, 2008, related to project development are $22 million based on a working interest of 50 percent.

During the 12 months ended December 31, 2008, our long-term debt increased by $486 million due to borrowings under our $500 million revolving credit facility and the short-term portion increased by $146 million due to borrowings on our $150 million revolving credit facility.

The following table shows our contractual obligations and commitments related to financial liabilities at December 31, 2008. This table is prior to the January 2009 working interest sale to Nexen, which would reduce payments under our capital leases, operating leases and contracts and purchase orders by 30 percent.

$ million	Total		Less than 1 year		1 - 3 years		3 - 5 years		5 years onward
Accounts payable and accrued liabilities	$	200	$	200	$	-	$	-	$	-
Short-term debt(1)		146	$	146		-		-		-
Long-term debt (Notes)(2)		3,166	$	172		345		345		2,304
Long-term debt (Revolving)(3)		486	$	136		350		-		-
Capital leases(4)		106	$	5		9		8		84
Operating leases and other commitments(5)		115	$	13		28		29		45
Contracts and purchase orders(6)		22	$	22		-		-		-
Total commitments	$	4,241	$	694	$	732	$	382	$	2,433

Notes:

 (1) Consists of CDN$146 million of borrowings on our short-term revolving debt facility. This facility was repaid and cancelled in January 2009.

(2) Consists of US$1,000 million and US$750 million under our Notes.  Amounts represent scheduled principal and interest payments.

(3) Consists of $486 million drawn on the revolving credit facility. The repayment represents only the required reduction to reduce the facility to $350 million in January 2009 and the final repayment of the facility at its scheduled maturity in 2011. In addition, we are contractually obligated for interest payments on borrowings and standby charges in respect to undrawn amounts under the revolving credit facility, which are not reflected in the above table as amounts cannot be estimated due to the revolving nature of the facility and variable interest rates. See “Liquidity” section for repayments completed as part of working interest sale.

 (4) Consists of our share of future payments under our product transportation agreements with respect to future tolls during the initial contract term at a working interest of 50 percent.

(5) Consists of our share of payments under our product transportation agreements with respect to future tolls during the initial contract term at a working interest of 50 percent. This amount also includes our share of future commitments with respect to rail traffic transportation assuming a 50 percent working interest.

(6) Consists of our share of commitments associated with contracts and purchase orders in connection with the Project and our other oil sands activities.

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UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A.           Undertaking.

The registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

B. Consent to Service of Process.

The registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

Any change to the name or address of the agent for service of process of the registrant shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 24, 2009.

OPTI Canada Inc.

By: ___________________________                                                     

Name:

Title: 

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