Exhibit 99.1

Annual Information Form

For the Year Ended

December 31, 2009

March 15, 2010

TABLE OF CONTENTS

	PAGE
INTRODUCTORY INFORMATION		3
FORWARD LOOKING INFORMATION		3
CORPORATE STRUCTURE		5
GENERAL DEVELOPMENT OF THE BUSINESS		6
Competitive Strengths and Operating Strategies		7
Our Industry		10
Our Principal Assets		11
The Long Lake Project and Future Phase Development		11
The OrCrudeTM Process		17
Marketing		18
Infrastructure		18
Our Lands and Leases		19
Material Agreements Related to the Joint Venture		21
Background		21
COJO Agreements and the Technology Agreement		22
The Future Phases COJO Agreements		26
The Purchase and Sale Agreement		27
Royalties		28
Regulatory Approvals and Environmental Considerations		28
Insurance		31
RESERVES AND RESOURCES SUMMARY		32
Reserves Data		32
Resources Data		33
DESCRIPTION OF CAPITAL STRUCTURE		34
Description of Share Capital		34
Rights Plan		35
Description of Debt Capital		35
Amended and Restated $190 million Senior Secured Revolving Credit Facility dated November 20, 2009 (the "Credit Facility")		35
US$425 million 9% First Lien Notes dated November 20, 2009		36
US$750 million 7.875% Senior Secured Notes dated July 5, 2007		36
US$1 billion 8.25% Senior Secured Notes dated December 15, 2006		36

Description of Hedging Contracts	37
CREDIT RATINGS	37
MARKET FOR SECURITIES	38
DIVIDENDS	39
DIRECTORS AND OFFICERS	39
Board of Directors	40
Officers	42
Audit Committee	43
Auditor Service Fees	43
CONFLICTS OF INTEREST	44
RISKS AND UNCERTAINTIES	44
Risks Relating to the Project, Operations and to Future Phases of Development	44
Risks Relating to Financing and Our Indebtedness	50
Risks Relating to Reserves and Resources	51
Risks Relating to Economic Conditions, Commodity Pricing, and Exchange Rate Fluctuations and Other Risks	52
Risks Relating to Technology	55
Risks Relating to Third Parties	56
Risks Relating to the Strategic Alternatives Process	59
MATERIAL CONTRACTS	60
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	60
TRANSFER AGENTS AND REGISTRAR	60
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	60
INTERESTS OF EXPERTS	60
ADDITIONAL INFORMATION	61
GLOSSARY	62

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

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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 62.

Unless otherwise indicated, all financial information included and incorporated by reference in this annual information form ("AIF") is determined using Canadian Generally Accepted Accounting Principles ("GAAP" or "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.

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

• the expectation that the Upgrader will produce 57,7000 bbl/d of PSC™ and 800 bbl/d of butane;

• the operation of our facilities, including both the long-term and short-term SOR of the SAGD Operation and the PSC™ yield of the Long Lake Upgrader;

• our estimated gravity of approximately 39°API for the PSC™;

• the impact of improvements made to the SAGD facility in 2009;

• our estimated final development cost of the Long Lake project (the "Project" or "Long Lake Project") of $6.5 billion (gross);

• our estimated capital cost to maintain full production;

•           our estimated financial performance, including estimated netbacks, in future periods;

• our reserve and resource estimates and our estimates of the present value of our future net cash flow;

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• our expectation that the Project will have a constant non-declining rate of production during the life of the Project and therefore, the Project will not require ongoing exploration risk to maintain its production rate once operational;

• 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 of the operator to obtain qualified staff and equipment for the 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;

• 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;

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• 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 obtain qualified staff and equipment for the Project, 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;

• our ability to raise new capital and the cost of that capital; and

• any potential transaction(s) as a result of the ongoing strategic alternatives process.

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 had no subsidiaries as at December 31, 2009.

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 at full production. We expect that the Project, located near Fort McMurray, Alberta, will produce 58,500 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 was 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.

We began producing bitumen in 2008 and we announced first production of PSC™ in January 2009. The Project is currently in the ramp-up stage, early February 2010 bitumen production was approximately 18,000 bbl/d and the Upgrader is in operation. We expect production to increase throughout 2010.

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 Inc. ("Nexen") has a 65 percent working interest in all joint venture assets and is the operator of both the SAGD operation and the Upgrader for Phase 1 and future phases.

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.

On July 14, 2009, OPTI completed the issuance of 82,720,000 common shares ("Common Shares") at a price of $1.75 per Common Share for aggregate gross proceeds of approximately $150 million.

On November 20, 2009, OPTI completed the issuance of US$425 million of First Lien Senior Secured Notes which bear interest at 9.0 percent per annum and mature on December 15, 2012 (the "9% Notes"). These notes are collateralized by a first priority security interest on substantially all of OPTI’s existing and future property, subject to certain exemptions and permitted liens. See "Description of Capital Structure - Description of Debt Capital".

In November 2009, we announced that our Board of Directors had initiated a process to explore strategic alternatives for enhancing shareholder value due to the belief that the trading price of our common shares does not reflect the value of our assets. The improving economic environment, continuing operational improvements, strengthening merger and acquisition valuations for oil sands assets and the future potential of our assets support our current strategy. OPTI’s management team and its Board of Directors are assessing a range of strategic alternatives that may include capital markets opportunities, asset divestitures, and/or a corporate sale, merger or other business combination. The ultimate objective of carrying out this review is to determine which alternative(s) might result in superior value for our shareholders. Our advisors, Scotia Waterous Inc., and TD Securities Inc. are assisting in these activities which involve contacting third parties. There is no assurance that any transaction will occur.

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At December 31, 2009, OPTI had approximately 20 employees primarily focused on finance, accounting and joint venture management.

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 and employing a multi-staged approach to future expansions when economic conditions permit.

Our competitive strengths are as follows:

Operating Project

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 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.

Significant operational milestones were achieved for the Project in 2009. Both the SAGD and OrCrudeTM technologies have been demonstrated by successful integration of Upgrader and SAGD operations, as well as by the production and sale of first PSC™. The Upgrader has produced syngas and we have utilized it in SAGD operation. The solvent deasphalter and thermal cracker are operating effectively. We have achieved a PSCTM yield of approximately 70 percent and expect to reach 80 percent as throughput increases. The SAGD debottleneck project has been completed with a resulting total steam capacity of 230,000 bbl/d. We have completed the development of 10 well pairs as part of the completion of pad 11 which brings the total number of well pairs to 91 for the Project and increases bitumen production potential. Electric submersible pumps ("ESPs") have been added to 43 well pairs, which allows for production at reduced operating pressures.

Large, Exploitable Resource Base with Low Geological Risk

Our working interest share of reserves and resources on current leases are estimated to be 711 million barrels of proved and probable reserves, 1,114 million barrels of best estimate contingent resources, and 314 million barrels of best estimate prospective resources. These reserves and resources are estimated to be sufficient to support production for the Project, and for up to five additional phases of similar size as the Project, for approximately 40 years per phase. We believe that the approval of future phases by our Board of Directors, when economic and regulatory conditions permit, will allow us to convert our substantial resource base into additional proved reserves. See "Reserves and Resources Summary".

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The timing of future phases is subject to many factors including Phase 1 performance, further clarity on proposed climate change regulations and the finalization of cost estimates. We have regulatory approval for Phases 2 and 3 SAGD as well as for Phase 2 upgrading facilities. We do not expect to consider sanctioning Phase 2 until late 2011.

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.

To maintain this rate of production, future maintenance and sustaining capital expenditures will be required. We define sustaining capital costs 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 purchases, will result in strong margins as the Project reaches higher production rates.

We provided an update to our estimated netback for the Project in the management’s discussion and analysis for the year ended December 31, 2009 filed on SEDAR and EDGAR on February 9 and February 10, 2010, respectively. Management approved this netback calculation on February 1, 2010.

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 invest in capital expenditures is a key advantage of our Project and important to our investors. We believe the netback measure is the most appropriate financial gauge to demonstrate this ability as corporate costs (other than corporate general and administrative ("G&A") expenses), interest, and other non-cash items are excluded from the calculation. The financial outlook may not be suitable for other purposes. We expect netbacks generated by our Project to be lower than shown in this outlook in the initial years 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 financial measure. The closest GAAP financial 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 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 which can fluctuate substantially; we will be subject to foreign currency exchange rate fluctuation; and our netback will be directly affected by applicable royalties. Assumptions relating to the netback estimate are set out in the notes beneath the table. These assumptions are considered reasonable by OPTI as at the date of this AIF.

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Estimated Future Project Pre-Payout Netbacks(1)

	WTI - US$60(2)			WTI - US$75(3)			WTI - US$90(4)
	$/bbl			$/bbl			$/bbl
Revenue(1)	$	69.43		$	82.27		$	93.75
Royalties and Corporate G&A		(2.86	)		(4.10	)		(5.65	)
Operating costs(5)
Natural gas(6)		(2.67	)		(3.15	)		(3.58	)
Other variable(7)		(2.00	)		(2.00	)		(2.00	)
Fixed		(15.46	)		(15.46	)		(15.46	)
Property taxes and insurance(8)		(2.81	)		(2.81	)		(2.81	)
Total operating costs		(22.94	)		(23.42	)		(23.85	)
Netback	$	43.63		$	54.75		$	64.25

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. Our netbacks include cash costs only and do not include non-cash expenses. See "Forward-Looking Information."

(2) For purposes of this calculation, with regard to the WTI price scenario of US$60, we have assumed natural gas costs of US$5.00/mcf, foreign exchange rates of CDN$1.00 = US$0.85, heavy/light crude oil price differentials of 30 percent of WTI and electricity sales prices of $70.40 per MegaWatt hour (MWh). Revenue includes sale of PSC™, bitumen, butane and electricity.

(3) For purposes of this calculation, with regard to the WTI price scenario of US$75, we have assumed natural gas costs of US$6.25/mcf, foreign exchange rates of CDN$1.00 = US$0.90, heavy/light crude oil price differentials of 27 percent of WTI and electricity sales prices of $83.12 per MWh. Revenue includes sale of PSC™, bitumen, butane and electricity.

(4) For purposes of this calculation, with regard to the WTI price scenario of US$90, we have assumed natural gas costs of US$7.50/mcf, foreign exchange rates of CDN$1.00 = US$0.95, heavy/light crude oil price differentials of 24 percent of WTI and electricity sales prices of $94.49 per MWh. Revenue includes sale of PSC™, bitumen, butane and electricity.

(5) Costs are in 2009 dollars.

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

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

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

We estimate sustaining capital costs required to maintain production at full design rates to be approximately $8.00 to $9.00 per barrel of products sold, assuming full design rate production and long-term on-stream expectations. The netbacks as shown are prior to abandonment and reclamation costs. We do not include any of the foregoing costs in our netback estimates due to the long-term nature of our assets.

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Based on US$60WTI and the other assumptions set out in the notes above, we expect our operating costs at full production plus royalties and corporate G&A expenses to be $25.80 per barrel of products sold. Using a foreign exchange rate of CDN$1.00 = US$0.85, the annual interest on our Senior Notes is approximately $30.00 per barrel of products sold. Based on this, at full production volumes, our revenue will exceed our estimated operating costs, royalties, corporate G&A expenses and interest on our Senior Notes at approximately $56.00 per barrel (US$48.00 per barrel) of products sold.

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. The use of the Integrated OrCrude™ Upgrader offers several advantages over these other projects in that the Integrated OrCrude™ Upgrader provides a solution to the three traditional challenges of 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 relies on the participation, sponsorship and execution capabilities of Nexen, one of Canada’s largest independent oil and natural gas producers with reported production averaging 265,000 boe/d, before royalties, in the fourth quarter of 2009. 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 products sold from the Project.

Our Industry

Oil sands operators produce and process bitumen, which is the heavy oil trapped in the sands. According to the ERCB, Canada’s oil sands are estimated to hold as much as 173 billion barrels of bitumen, second only to Saudi Arabia and significantly more than the recoverable reserves in the United States. The ERCB reports that in 2008, oil sands production reached over 1.3 million bbl/d and estimates that oil sands production will reach nearly 4 million bbl/d by 2020.

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Of potentially recoverable bitumen estimated to be contained in Canada’s oil sands only about 20 percent is 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:

•           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

•           as a synthetic crude oil, after upgrading.

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 the Long Lake Project, an operating, integrated plant that extracts low-value bitumen and upgrades it into one of the highest quality synthetic crude oils produced from Canada’s oil sands;

• proved plus probable bitumen reserves associated with a portion of the Long Lake leases of 711 million bbls. See "Reserves and Resources Summary";

• contingent bitumen resources of 1,114 million bbls and prospective bitumen resources of 314 million bbls contained in the remainder of the Long Lake and in the Leismer and Cottonwood Leases. See "Reserves and Resources Summary";

• the right to the use of the OrCrude™ Process technology in Canada; and

• at December 31, 2009, we had approximately $358 million of cash and a $190 million undrawn revolving credit facility.

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 kilometres ("km") south east of Fort McMurray, Alberta. See: "Our Lands and Leases".

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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. PSC™ is a high quality, 39° API, product that sells at a price similar to WTI crude oil. The Project is the first commercial application of the Integrated OrCrudetm Process. The Project involves two major components, the first being the recovery of bitumen and the second being the upgrading of bitumen into PSCtm and other petroleum products. Included in the Project is the 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 and 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 (the "Management Committee"). 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. 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.

The Project is being governed pursuant to the terms and conditions of the COJO Agreement and the Technology Agreement. These agreements are described under "Material Agreements Related to the Joint Venture".

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 began in 2008, however in late 2008 and through 2009, the ramp-up of bitumen production was limited by the inability to produce sufficient amounts of steam consistently and over a sustained period due to issues with the surface facilities. Several initiatives were completed in 2009 to optimize steam production and enhance long-term production capacity, including:

• the addition of supplementary heat to the hot lime softeners in the water treatment plant; and

• the completion of a turnaround in the third quarter, that resulted in the completion of the replacement of over 400 valves in the SAGD plant and to conduct maintenance on the water treatment plant.

After these initiatives were completed, with improved water treatment, steam injection rose to an average of approximately 92,000 bbl/d for the months of November and December 2009. In early February 2010, steam injection was approximately 105,000 bbl/d. The Project has been generating steam on a consistent basis since late October. In early February 2010, we had 75 well pairs receiving steam, of which 57 wells were producing.

As of early February 2010. the all-in SOR was approximately 6.0 including steam to wells that are in the steam circulation stage and not yet producing bitumen. This range of SOR is expected at this stage of bitumen ramp-up and our long-term estimate of SOR remains at approximately 3.0. A number of our wells have recently been converted to production status from circulation status which would be expected to result in an initially higher SOR. We expect SOR to decline later in 2010 assuming we are able to maintain our reliability in delivering steam to wells.

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With the reservoir in the early stages of warm-up post-turnaround, bitumen production for November and December 2009 averaged 15,800 bbl/d (5,530 bbl/d net to OPTI). As of early February 2010, bitumen production was approximately 18,000 bbl/d (6,300 bbl/d net to OPTI).

ESPs continue to be installed in a number of SAGD wells, which will allow us to have better pressure control and ultimately reduce the overall SOR. We currently have 43 well pairs with ESPs.

We expect that the improvements made to the SAGD facility in 2009 will result in a significant increase in bitumen production through 2010 and position the Project to achieve full design rates. Once the Project reaches full design rates, it is expected to produce 20,000 bbl/d of PSCTM net to OPTI for over 40 years.

Construction of the Upgrader, which intentionally lagged SAGD to ensure sufficient bitumen production at start-up, was completed in early 2008. First production of PSC™ from the Project was achieved in January 2009. Synthesis gas from the Upgrader has been used in SAGD operations, decreasing operating costs by reducing the requirement for purchased third-party natural gas.

In the third quarter of 2009, a significant milestone was achieved with the successful testing of the solvent deasphalter and thermal cracking units in the Upgrader. These units allow the Upgrader to transition from gasifying vacuum residue, which contains some lighter parts of the barrel, to gasifying the heaviest part of the barrel called asphaltenes. As a result, PSC™ yields have increased to approximately 70 percent. Yields are expected to continue to increase to the design rate of 80 percent once the Project reaches higher bitumen volumes. Upgrader on-stream time increased significantly in 2009, averaging 79 percent in November and December. Improved reliability allowed the Project to process over 90 percent of produced and purchased bitumen after the Upgrader start up in the fourth quarter. During the SAGD ramp-up period, we expect to purchase approximately 10,000 bbl/d of externally sourced bitumen.

The final development cost of the Project is expected to be approximately $6.5 billion (gross). As the Project was 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 ash processing unit in 2011. The cost to complete this unit is estimated at approximately $31 million net to OPTI.

The SAGD Process

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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.

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

We have 91 SAGD well pairs drilled. Additional sustaining well pairs 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, OPTI and Nexen (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 consists of a gas turbine and heat recovery steam generator, while the remainder is produced by four once-through boilers. Approximately 170 megawatts of electricity are produced by the combined cogeneration facilities when at full capacity. Electricity not consumed by the Project is sold.

Water treatment and steam generation facilities were completed in 2009, which increased the SAGD steam design capacity to over 230,000 bbl/d. The debottleneck train will start-up as needed to support SAGD ramp-up. We expect the long-term average SOR for the Project to be approximately 3.0.

Long Lake Upgrader

Upgrading of Bitumen

The bitumen recovered by the 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. During periods of Upgrader downtime, including periods of major maintenance at the Upgrader, the JV Participants plan to sell bitumen blend.

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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.

The PSCTM 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 diluent costs 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 are 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.

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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.

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.

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 is separated from the syngas by contacting it with water, producing a soot water slurry. 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 is transported by truck and 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 2011 in order for the operations team to focus on optimizing SAGD and Upgrader operations during the ramp-up period.

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.

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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.

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 a 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.

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

OPTI BV may terminate the OPTI License if 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 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 km southeast of Fort McMurray with connections to existing infrastructure including road access (highways 881 and 63), a natural gas supply pipeline, rail access and the electric power transmission grid to allow for both the import and export of electricity. 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.

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The JV Participants have an agreement with Enbridge to provide lateral facilities and transportation services on the Enbridge Athabasca Pipeline. This pipeline transports 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.

Our Lands and Leases

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The following table sets forth our gross and net acreage in respect of the leases comprising our lands as well as the delineation wells drilled on these lands to December 31, 2009.

	Gross Acres	Net Acres	Delineation Wells
Long Lake	71,040	24,864	797
Leismer	85,760	30,016	330
Cottonwood	90,240	31,584	128
Other	12,800	4,480	1
Total	259,840	90,944	1,256

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.

Long Lake Leases

These lands are located in the Athabasca oil sands region of Alberta approximately 40 km south of Fort McMurray. The Long Lake leases cover an area of 111 sections (approximately 71,000 acres) and are estimated by McDaniel to contain approximately 711 million barrels of proved and probable reserves and 319 million barrels of best estimate contingent resources for our 35 percent working interest share. The Long Lake leases comprise the Long Lake Phase 1 area (50 sections) and the Kinosis area (61 sections). See "Appendix A - Reserves Data and Other Oil and Gas Information".

OPTI’s capital program for 2010 includes funds allocated for additional core hole drilling to further delineate our nearer-term development leases at Long Lake. The 2009/2010 winter program is expected to include the drilling of 18wells and a four-dimensional seismic program in the commercial area.

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 km southwest of the Project, are comprised of 134 sections of landand are estimated by McDaniel to contain 591 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 over 300 delineation wells drilled, along with 52 square km of three-dimensional ("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 2009/2010 winter season.

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Cottonwood Leases

The Cottonwood Leases, located approximately 32 km southwest of the Project, are comprised of 141 sections of land and are estimated by McDaniel to contain 203 million barrels of best estimate contingent resources and 314 million barrels of prospective resources for our 35 percent working interest share. See "Reserves and Resources Summary - Resources Data".

There are over 120 wells drilled on these lands, including 41 drilled by the JV Participants, as well as over 50 square km of 3D seismic. In order to concentrate capital expenditures in 2010 on Phase 1 and nearer-term development projects on the Long Lake lease, nodelineation wells or seismic are planned on these leases during the 2009/2010 winter season.

Development of Future Phases

The JV Participants believe thatthe landswill support approximately 430,000 bbl/d of bitumenproduction (150,000 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 $900million on the expansion activities beyond Phase 1 and OPTI expects to continue to invest in engineering and planning for future phases of development.

The sanctioning of Phase 2 will depend on multiple factors including the initial performance of Phase 1, receiving clarity on proposed climate change regulations and finalizing cost estimates. OPTI therefore does not expect to consider sanctioning of Phase 2 until late 2011.

In 2010, the joint venture JV partners plan to advance detailed engineering on the SAGD and upgrader facilities for Phase 2 of Long Lake. 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 memorandum of understanding ("MOU") dated October 29, 2001. The Project is now governed by the COJO Agreement and, with regard to the associated upgrading technology rights, by the Technology Agreement.

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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 Future Phases COJO Agreements. The Technology Agreement governs these projects as well.

While the MOU was superseded by the COJO Agreement, the Future Phases 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.

COJO Agreements 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

Pursuant to the COJO Agreement, we have established 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.

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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.

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.

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Force Majeure

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

Default

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

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

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

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• if the default occurs after commercial production is achieved, the JV Participant exercising the lien may sell the defending JV Participant’s interest in the Project.

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

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

Technology

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

Marketing

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

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The Future Phases COJO Agreements

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

• The Future Phases COJO Agreements contain provisions permitting one party to propose and conduct delineation and lease-saving operations, and to propose and prepare a development plan (in contemplation of a construction plan). If the other party does not wish to participate in those operations or activities it will be subject to a penalty. The penalty for non-participation in a delineation operation or the preparation of a development plan is a before tax return of capital of 1.5309 percent calculated and compounded monthly on the costs incurred to conduct the applicable operations and activities. The penalty for non-participation in a lease-saving operation is the forfeiture of that party’s interest in the applicable lease.

• A party is required to pay for its share of costs associated with delineation operations and development plans, plus all associated penalties, prior to either the date the Management Committee approves the project construction plans or the project sanction date, as applicable, before it is entitled to participate in the project.

As was the case under the COJO Agreement, each party to each Future Phase 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 Future Phase 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 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

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.

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The Territory License is a perpetual, non-exclusive license, which grants the same rights to Nexen in the Territory License 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.

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.

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 Purchase and Sale Agreement

From the commencement of our joint venture with Nexen in 2001 until January 1, 2009, 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.

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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.

Royalties

The Government of Alberta receives royalties on production of natural resources from lands in which it owns the mineral rights. Effective January 1, 2009, the Government of Alberta introduced price-sensitive formulas which are applied both before and after specified allowed costs have been recovered. The gross royalty starts at one percent of gross bitumen revenue and increases for every dollar that the world oil price, as reflected by the WTI crude oil price, is above CDN$55 per barrel, to a maximum of nine percent when the WTI crude oil price is CDN$120 per barrel or higher. The net royalty on oil sands starts at 25 percent of net bitumen revenue and increases for every dollar the WTI crude oil price is above CDN$55 per barrel to 40 percent when the WTI crude oil price is CDN$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.

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 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 required 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, known as the Long Lake South Project, was filed in late 2006. Regulatory approval for the Long Lake South Project was received in February 2009.

In January 2005, an application was filed to ERCB 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 ERCB 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 - the operator, our employees, contractors, 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. The JV Participants have participated at the executive level in the Cumulative Environmental Management Association, the Regional Aquatics Monitoring Program, the Wood Buffalo Environmental Association, the Regional Infrastructure Participating Group and other multi-stakeholder regional programs that address cumulative environmental and socio-economic project impacts.

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

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.

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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 greenhouse gases ("GHGs"). The Project will be a significant producer of some GHGs covered by the Convention.

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.

In April 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 in October 2006. Draft regulations were expected to be available for public comment in the Fall of 2008 but have not yet been released, and it’s not known if or when they will be released or implemented.

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 its 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 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.

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In January 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.

On January 31, 2010, the Government of Canada submitted to the United Nations Framework on Climate Change a non-legally binding commitment under the Copenhagen Accord to reduce Canada’s emissions of GHGs by 17 percent from 2005 emission levels by 2020. This is a significant change from previous international commitments of a 20 percent reduction in emissions from 2006 levels by 2020. The Government of Canada signalled that the new national emission reduction target was to be aligned with emission reduction targets of the United States. It is unclear how the new proposed national emission reduction target is to be met and whether the previous announced proposed regulatory Framework will proceed or be replaced with a new regulatory framework. We believe that it is reasonably likely that the new federal legislation requiring emissions reductions similar to the Framework will be enacted in Canada around the same time as similar legislation is enacted in the United States. We also believe that such federal legislation could have a material effect on the development of our assets.

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.

Considering all of these factors, OPTI includes approximately $1.00/bbl for GHG mitigation costs in its estimated future netback calculation (see table on page 9).

Insurance

OPTI reduces exposure to some operational risks by maintaining appropriate levels of insurance, primarily business interruption ("BI") and property insurance. The JV has purchased total coverage of US$2.0 billion of BI and property insurance (combined) in case Long Lake experiences an event causing a loss or interruption of production, such as a fire or explosion at the operating facilities. The BI insurance is subject to a 90-day waiting period and the property insurance contains a US$10 million deductible (US$3.5 million net to OPTI). In the event of loss, the combined property and BI insurance claims payable to OPTI would be scaled to reflect OPTI’s project ownership. While such insurance assists in mitigating some operational upsets, insurance is unlikely to fully protect against catastrophic events or prolonged shutdowns. This insurance program will be in place until July 1, 2010. The renewal program is expected to be placed for a further one year term and may be placed separately under each JV participant insurance program.

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OPTI also carries Control of Well and Comprehensive General Liability insurance to insure against damage to third parties. Control of Well insurance protects against liability to third parties for damage resulting from sudden and accidental discharge from a well bore or underground blowout (these are coverages excluded under Comprehensive General Liability insurance).

RESERVES AND RESOURCES SUMMARY

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

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

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

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

Based on core analyses, the density of the bitumen varies both areally 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. Based on core hole data, the API is higher at Kinosis and Leismer.

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 26, 2010, evaluating the bitumen reserves and synthetic oil reserves of the Long Lake leases effective as of December 31, 2009 (the "McDaniel Report"). Reserves have been recognized at Long Lake in the Phase 1 area as proved, probable and possible, and in the Phase 2 area as probable and possible. 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.

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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 during periods of Upgrader downtime, and is shown as bitumen reserves.

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, 2009

(MMbbl)

	Raw	Sales Volumes
	Bitumen	PSC™	Bitumen	Butane
Proved (1)	194	149	8	3
Proved plus probable (2)	711	553	34	8
Proved plus probable plus possible (3)	780	608	35	9

Notes:

(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.

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:

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Summary of Bitumen Resources (1)

December 31, 2009

(MMbbl)

	Raw Bitumen
	Contingent Resources(2)	Prospective Resources(3)
Long Lake (4)	153	-
Kinosis (4)	167	-
Leismer (4)	591	-
Cottonwood (5)	203	314
Total	1,114	314

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.

(2) 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.

(3) 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.

(4) The resource estimates for Long Lake, Kinosis and Leismer 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.

(5) The resource estimate for Cottonwood is categorized as both Contingent and 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 ("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 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, 2009, OPTI had 281,749,526 Common Shares and stock options to purchase 5,512,216 Common Shares outstanding. The stock options have a weighted average exercise price of $6.90 per share. There are no Voting Convertible Preferred Shares currently outstanding.

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.

Approval by shareholders to extend the plan is required every three years by the Toronto Stock Exchange. OPTI obtained this approval at our Annual General and Special Meeting of Shareholders on April 28, 2009.

Description of Debt Capital

Amended and Restated $190 million Senior Secured Revolving Credit Facility dated November 20, 2009 (the "Credit Facility")

The $190 million Credit Facility expires on December 15, 2011. Amounts borrowed through this facility bear interest at a floating rate based on bankers’ acceptances plus a credit spread, while any unused amounts are subject to standby fees. Prior to the closing of the 9% Notes issuance in November 2009, the Credit Facility was in the amount of $350 million. Upon closing the 9% Notes issuance, the Credit Facility was reduced to $190 million. As at December 31, 2009, the Credit Facility was undrawn.

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In respect of each new borrowing under the Credit Facility, we must satisfy certain conditions precedent prior to making a new borrowing. These include a confirmation that the representations and warranties in our loan documents are correct on the date of the new borrowing, that no event of default has occurred and that there has not been a change or development that would constitute a material adverse effect. In addition, we have a total debt to total capitalization covenant that requires we do not exceed a ratio of 70 percent. The covenant is calculated based on the book value of debt and equity adjusted for the effect of any foreign exchange derivatives issued in connection with U.S. dollar denominated debt that may be outstanding, accounting impacts resulting from the sale of working interest to Nexen and the result of GAAP changes effective January 1, 2009.

US$425 million 9% First Lien Notes dated November 20, 2009

On November 20, 2009 OPTI issued US$425 million of 9% Notes. These notes were sold with an original issue discount of 3 percent for net proceeds of US$402 million after the original issue discount and financing costs. Semi-annual interest payments are due June 15 and December 15 of each year with final payment due on December 15, 2012. At any time prior to December 15, 2010, OPTI may redeem all or part of the 9% Notes at a redemption price equal between 108 percent and 102 percent of the principal amount, plus the applicable premium and accrued interest. At any time after December 15, 2010 and prior to June 15, 2012, OPTI may redeem all or a part of the 9% Notes at redemption price of 102 percent of the principal amount plus accrued and unpaid interest. The 9% Notes are, together with the Credit Facility and certain hedges of the Company, collateralized by a first priority security interest on substantially all of OPTI’s existing and future property (subject to certain prior liens). The 9% Notes are subordinated in respect of this collateral in favour of the Credit Facility lenders and certain hedge counterparties of the Company pursuant to a Sharing Agreement.

US$750 million 7.875% Senior Secured Notes dated July 5, 2007

On July 5, 2007, we issued US$750 million principal amount of 7.875% Notes which bear interest at 7.875 percent per annum. 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 below.

US$1 billion 8.25% Senior Secured Notes dated December 15, 2006

On December 15, 2006, we issued US$1 billion principal amount of 8.25% Notes which bear interest at 8.25 percent per annum and mature December 15, 2014. 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.

We have total semi-annual interest payments under our Senior Notes of US$90 million ($180 million per annum). This includes semi-annual interest payments of US$19 million until maturities of the 9% Notes in 2012 and semi-annual interest payments of US$71 million until maturity of the 8.25% Notes and 7.875% Notes in 2014.

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With respect to our Senior Notes, there are covenants 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 2009 reserve report, we have sufficient capacity under this test to incur additional debt beyond our existing Credit Facility and existing Senior Notes. Other leverage considerations, such as debt restrictions under the Senior Notes and the Credit Facility , are expected to be more constraining than this limitation.

Description of Hedging Contracts

OPTI is exposed to foreign exchange rate risk on our long-term U.S. dollar-denominated debt. As at December 31, 2009, we had US$875 million of foreign currency forwards primarily to hedge a portion of our exposure to fluctuations in the Canadian dollar-equivalent cost of the Company’s long-term U.S. dollar-denominated debt. The average fixed rate of exchange under these foreign currency forwards is approximately CDN$1.18 to US$1.00. Changes in the exchange rate between Canadian and U.S. dollars change the value of these instruments. At present, these forward contracts settle in April 2010 (US$330 million) and December 2010 (US$545 million). With respect to our U.S. dollar-denominated debt, these forward contracts provide protection against a decline in the value of the Canadian dollar below CDN$1.18 to US$1.00 on a portion of our debt. The foreign currency forwards at December 31, 2009 provide a net liability of $115 million based upon exchanges rates at such date. The net value of our foreign exchange forwards is approximately equivalent to 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.

Prior to the settlement of the foreign exchange forward in 2010, OPTI may agree to extend some or all of them to a later settlement date. In the event that any forward is extended, there would be no cash settlement for that forward until the new settlement date of the forward. If we are unable or choose not to extend the term of any or all of these forwards, the net benefit or cost to us of each forward contract at the time of its current settlement date in 2010 would be approximately equivalent to the net of the payments made and received by us under each forward on the relevant settlement date. Based on the active market for the underlying market variables used in the valuation, we do not believe other market assumptions could result in a materially different valuation than the one we have determined. This conclusion is supported by an internal evaluation. The value to us of the foreign currency forwards would change by approximately $9 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 earnings (loss) before taxes in 2010.

CREDIT RATINGS

OPTI maintains a corporate rating and a rating for the Credit Facility and the Senior Notes with Moody’s Investor Service (Moody’s) and Standard and Poors (S&P). Please refer to the table below for the respective ratings.

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	Moody's	S&P
OPTI Corporate Rating	Caa2	B-
Revolving Credit Facility	B1	B+
The 9% Notes - US$425 million	B2	B+
The 8.25% Notes - US$1,000 million	Caa3	B
The 7.875% Notes - US$750 million	Caa3	B

Moody’s assigned a B2 rating to the 9% Notes and a B1 rating to the Credit Facility. Moody’s lowered the ratings on the 8.25% and 7.875% Notes from Caa1 to Caa3 and OPTI’s corporate rating from Caa1 to Caa2. The outlook remains negative according to Moody’s.

S&P assigned a B+ rating to the 9% Notes and a B+ rating to the Credit Facility. The ratings on the 8.25% and 7.875% Notes remain at B and OPTI’s corporate rating at B-. S&P removed ratings from Credit Watch with negative implications. The outlook remains negative according to S&P.

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.

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 2009.

Month	High	Low	Closing	Volume
January	$2.09	$1.32	$1.60	33,304,696
February	$1.71	$0.95	$1.00	27,863,351
March	$1.35	$0.61	$0.99	126,785,833
April	$2.51	$0.93	$1.93	212,922,055
May	$4.50	$1.88	$3.28	205,289,379
June	$3.60	$1.81	$1.95	98,992,226
July	$1.93	$1.37	$1.57	85,048,060
August	$1.74	$1.42	$1.69	42,695,727
September	$2.57	$1.59	$2.15	84,197,794
October	$2.71	$1.86	$1.90	45,169,262
November	$2.25	$1.77	$2.07	29,404,484
December	$2.15	$1.93	$2.03	15,119,508

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DIVIDENDS

We have not paid any dividends on the Common 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 (4)                                          Alberta, Canada	Chairman and Director	May 30, 2002	President of Stanford Resource Management Inc., a financial management company.
Ian W. Delaney (4) Ontario, Canada	Director	November 16, 2005	Chairman and Chief Executive Officer, Sherritt International Corporation, a diversified resource company.
Charles L. Dunlap (3) Texas, USA	Director	June 29, 2006	President and Chief Executive Officer of TransMontaigne Inc., a terminaling and transportation company; formerly Chief Executive Officer and President and Director of Pasadena Refining System Inc.
Edythe (Dee) A. Marcoux (3) British Columbia, Canada	Director	July 16, 2008	Retired oil executive; formerly a consultant to Ensyn Group Inc., a heavy oil upgrading technology company.
Christopher P. Slubicki (5) Alberta, Canada	President, CEO and Director	February 1, 2007	President and Chief Executive Officer, OPTI
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.

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 as director of OPTI.

(3) Member of the Audit Committee.

(4) Member of the Governance and Compensation Committee.

(5) Mr. Slubicki was appointed President and Chief Executive Officer of OPTI effective April 27, 2009.

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Name and Residence	Present Position and Office	Position Held Since (1)	Principal Occupation
Officers
Chris Slubicki                                          Alberta, Canada	President and CEO	April 27, 2009	President and Chief Executive Officer, OPTI
Travis Beatty                                          Alberta, Canada	Vice President, Finance and Chief Financial Officer	March 1, 2009	Vice President, Finance and Chief Financial Officer
Joe Bradford                                          Alberta, Canada	Vice President, Legal and Administration and Corporate Services	October 14, 2008	Legal, Administration and Corporate Services
Kiren Singh                                          Alberta, Canada	Vice President and Treasurer	April 16, 2009	Treasurer
Alan Smith                                          Alberta, Canada	Vice President, Marketing	March 1, 2009	Vice President, Marketing

Note:

(1) Indicates date of appointment as officer of OPTI.

As at December 31, 2009, our directors and officers, as a group, beneficially own, or control or direct, 523,727 Common Shares or 0.19 percent of the Common Shares outstanding.

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 serves on a variety of 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.

Ian W. Delaney

Mr. Delaney is the Chairman and Chief Executive Officer of Sherritt International Corporation ("Sherritt") 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.

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Mr. Delaney is a director of Cenovus Energy 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

Mr. Dunlap is Chief Executive Officer and President of TransMontaigne, a terminaling and transportation company, and Chief Executive Officer of TransMontaigne Partners L.P., a master limited partnership, both based in Denver, Colorado. Mr. Dunlap served as Chief Executive Officer and President of Pasadena Refining System, Inc., based in Houston, Texas from January 2005 to December 2008. From 2000 to 2004, Mr. Dunlap served as one of the founding partners of Strategic Advisors, L.L.C., a management consulting firm based in Baltimore, Maryland. Prior to that time, Mr. Dunlap served in various senior management and executive positions at various oil and gas companies including Crown Central Petroleum Corporation, Pacific Resources Inc., ARCO Petroleum Products Company and Clark Oil & Refining Corporation.

Mr. Dunlap is a graduate of Rockhurst University, holds a Juris Doctor degree from Saint Louis University Law School and is a graduate of the Harvard Business School Advanced Management Program.

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 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 is currently a director of Sherritt and SNC-Lavalin. Ms. Marcoux holds an engineering degree, a Masters of Business Administration and an honourary Ph.D., all from Queen’s University.

Christopher P. Slubicki

Mr. Slubicki was appointed President and Chief Executive Officer of OPTI in April 2009. Previously, he was 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.

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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

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.

Joseph Bradford

Mr. Bradford joined OPTI in October 2008 as General Counsel and Corporate Secretary and was appointed to his current role as Vice President, Legal and Administration and Corporate Services in March 2009. 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.

Kiren Singh

    Ms. Singh is the Vice President and Treasurer of OPTI. Ms. Singh joined OPTI in 2008 as Treasurer and was appointed to her present position in April 2009. Ms. Singh has over 22 years of experience in corporate and project finance and corporate insurance with Canadian and international energy leaders including Mobil (Calgary, AB and Fairfax, VA) and ExxonMobil (Houston, TX). Ms. Singh’s recent experience includes Chief Financial Officer of VCI (Calgary, AB). Ms. Singh has significant mega-project experience in Canada and internationally, leading various aspects of structuring, financing and insurance arrangements for Canadian oil sands and infrastructure projects, Australia/Papua New Guinea gas development and Venezuela heavy oil projects.

Ms. Singh holds a Masters of Business Administration and a Bachelor of Commerce from the University of Calgary and a Chartered Financial Analyst designation.

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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. Waterman (Chairman), Dunlap and Marcoux. All three members are financially literate and independent for the purposes of National Instrument 52-110 "Audit Committees".

Auditor Service Fees

PricewaterhouseCoopers LLP ("PWC") has served as the auditors of OPTI since its incorporation. The following table summarizes the total fees paid to PWC for the years ended 2009 and 2008 in thousands of dollars:

	2009		2008
Audit fees	$	344	$	187
Audit-related fees		266		49
Tax fees		50		68
Other		-		43
TOTAL	$	660	$	347

Audit fees are 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. The increase in Audit fees in 2009 are primarily related to additional work required in order for OPTI to comply with section 404 of the Sarbanes-Oxley Act of 2002. Audit-related fees are exclusively related to compulsory services required to support planned and actual financing activities as well as translation of public documents. Tax fees are primarily related to the completion of our corporate tax returns. "Other" fees in 2008 were 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.

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CONFLICTS OF INTEREST

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.

RISKS AND UNCERTAINTIES

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

Risks Relating to the Project, Operations and to Future Phases of Development

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.

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.

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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 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.

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

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

• amount and cost of labour to operate the Project;

• cost of catalyst and chemicals;

• actual SOR required to operate the SAGD well pairs;

• cost of natural gas and electricity;

• cost of complying with regulatory approvals;

• maintenance cost of the facilities;

• cost to transport sales products and the cost to dispose of certain by-products; and

• cost of insurance and taxes.

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

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

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

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

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

The SAGD Operation and 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.

OPTI reduces exposure to some operational risks by maintaining appropriate levels of insurance, primarily BI and property insurance. The JV has purchased total coverage of US$2.0 billion of BI and property insurance (combined) in case Long Lake experiences an event causing a loss or interruption of production, such as a fire or explosion at the operating facilities. The BI insurance is subject to a 90-day waiting period and the property insurance contains a $US10 million deductible ($US3.5 million net to OPTI). In the event of loss, the combined property and BI insurance claims payable to OPTI would be scaled to reflect OPTI’s project ownership. While such insurance assists in mitigating some operational upsets, insurance is unlikely to fully protect against catastrophic events or prolonged shutdowns.

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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, including our current initiative to examine strategic alternatives that could include a corporate sale, 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 are a 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 operating or financial results from the Project or that Nexen will be able to provide adequate financial and operational information on a timely basis. In addition, these financial results require Nexen to make estimations in regards to progress on capital and operating activities.

Our joint-venture agreement is designed to promote development of Long Lake Project and future phases. Major capital decisions for new projects require support from both OPTI and Nexen while other matters require only the approval of the operator.  Historically, OPTI and Nexen have sought consensus on all significant matters however, there can be no assurance that future agreements will be reached with respect to future capital programs. The ability of either joint-venture partner to prevent future development is limited. If we are unable or choose not to participate in part or at all in future phases, we will forego our working interest in such phases and the associated lands. We may recover only those costs spent to date which may be less than the fair market value of the foregone working interest.

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

We have announced a multistage expansion plan, including plans to increase total bitumen production to 430,000 bbl/d in our joint venture with Nexen (150,000 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, 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, individually or in aggregate, may have an adverse effect on our ability to obtain the necessary sanctions for 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 bitumen production to 430,000 bbl/d in our joint venture with Nexen (150,000 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 volatility as are financial markets and global economies. As a result, Phase 2 and all future phases of the multistage expansion plan have been deferred to 2011 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".

If we are unable or choose not to participate in part or at all in future phases, we will forego our working interest in such phases and the associated lands. We may recover only those costs spent to date which may be less than fair market value of the foregone working interest.

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. In April 2007, the Canadian Federal Government releasedthe Framework which outlines proposed new requirements governing the emission of GHGs and other industrial air 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 in October 2006. Draft regulations were expected for public comment in the Fall of 2008 but have not yet been released, and it’s not known if or when they will be released or implemented.

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The required emission reductions may not be technically or economically feasible for the Project and the failure to meet such emission reduction requirements or other compliance mechanisms may materially adversely affect our business and result in fines, penalties and the suspension of operations. As well, equipment from suppliers which can meet future emission standards may not be available on an economic basis and other compliance methods of reducing emissions or emission intensity to required levels in the future may significantly increase our operating costs or reduce output of the Project. Emission reduction or off-set credits may not be available for acquisition by the Project or may not be available on an economic basis. There is also the risk that the provincial government could impose additional emission or emission-intensity reduction requirements, or that the federal and/or provincial governments could pass legislation which would tax such emissions.

To operate the facilities, the Project relies on groundwater, which is obtained under licenses from 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.

U.S. 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.

OPTI continues to assess the timing of and potential effects of United States climate change legislation.

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.

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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 Credit Facility, and full principal repayment of our Credit Facility is due in December 2011.

We also have semi-annual interest payments due each year on our Senior Notes. Full principal repayment of the 9% Notes is due in December 2012 and the remainder of our Senior Notes is due in December 2014.

During the period 2007 to 2009, global capital markets experienced a number of economic and financial crises, among other factors, which impacted financial markets within Canada. As a result, there has been a tightening of global credit markets characterized by higher borrowing costs. Deterioration of commodity prices and or operating issues with our SAGD or Upgrader operations could result in additional funding requirements. Should we 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 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, 2009, OPTI was in full compliance with its debt covenants relating to the 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.

While the Project has begun operations, we continue to have financial obligations relating to completion of the ash processing unit, as well as sustaining capital costs.

Subsequent to possible sanctioning of Phase 2, 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 and company conditions would not support such a financing requirement and therefore some improvement will be required 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.

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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 Future Phases COJO Agreements".

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

We must satisfy a number of conditions precedent prior to each borrowing under the Revolving Credit Facility, including that we have sufficient funding to complete the Project. There can be no assurance that we will be able to satisfy all of the conditions precedent, in which case we will not be able to access the Revolving Credit Facility to satisfy our financial 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 Hedging Contracts". Fluctuations in exchange rates may significantly increase the amount of debt recorded on our financial statements and negatively impact our reported earnings.

Risks Relating to Reserves and Resources

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

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

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

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

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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 short operating history in commercial projects and limited history on the Long Lake leases. Although we conducted pilot tests on the Long Lake leases reservoir and now have limited 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.

Risks Relating to Economic Conditions, Commodity Pricing, and Exchange Rate Fluctuations and Other Risks

Our results of operations depend upon the prevailing prices of oil and natural gas in the worldwide markets. Those prices have declined substantially and remain subject to further declines.

Our revenues, cash flows, earnings, cost of capital, asset values, results of operations and financial condition are dependent upon the prevailing price of crude oil and natural gas and heavy oil differentials. There has been a significant volatility in oil and natural gas prices due at least in part to the deteriorating global economy. The variability in commodity prices has adversely affected, and if it persists in the future will adversely affect, our financial condition and results of operations, cash flows, access to the capital markets and ability to grow. Our financial condition, operating results and future rate of growth depend upon the prices that we receive for our oil and natural gas. Such prices also affect the amount of our cash flow available for capital expenditures and our ability to access funds.

Sustained low prices or a further decline in such prices could result in a material reduction of our operating and financial results, production revenue, reserves and overall value. In addition, any prolonged period of low oil prices could result in a decision by us 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 us at such reduced prices would lower our revenues. There can be no assurance that the conditions in the oil and natural gas industries will improve and that the oil and natural gas prices will increase in the future.

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We conduct an assessment of the carrying value of our assets to the extent required by Canadian and U.S. GAAP. If crude oil and/or natural gas prices decline, the carrying value of our assets could be subject to downward revision and our earnings could be adversely affected. The substantial volatility in crude oil prices over the last two years has affected the profitability of our industry and our company. Under Canadian and U.S. GAAP, we did not incur any "ceiling test" write downs of our oil and gas assets or impairment charges to our other assets in 2009. There can be no assurance that declines in crude oil prices or other circumstances will not result in such "ceiling test" write downs or impairment charges at some future date.

The prevailing prices of oil and natural gas in the worldwide markets can fluctuate substantially, which may adversely affect our results of operations.

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 legislative response to 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.

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Global financial conditions have been subject to increased volatility. This may impact our ability to obtain equity, debt or bank financing in the future and may adversely impact our operations.

Current global financial conditions have been subject to increase volatility and numerous commercial and financial enterprises have either gone into bankruptcy or creditor protection or have had to be rescued by governmental authorities. Access to public financing has been negatively impacted by sub-prime mortgage defaults, the liquidity crisis affecting the asset-backed commercial paper and collateralized debt obligation markets, massive investment losses by banks with resultant recapitalization efforts and deterioration in the global economy. These factors may impact our ability to obtain equity, debt or bank financing on terms commercially reasonable to us, if at all. Additionally, these factors, as well as other related factors, may cause decreases in asset values that are deemed to be other than temporary, which may result in impairment losses. If these increased levels of volatility and market turmoil continue, our operations could be adversely impacted and the trading price of our securities could continue to be adversely affected.

Banks have been adversely affected by the worldwide economic crisis, increased pricing and tightened borrowing restrictions to corporate borrowers; this has resulted in limited access to new facilities or for new borrowers. These factors could negatively impact our ability to access liquidity needed for our business in the longer term. We may be unable to generate a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

In addition, certain of our customers could experience an inability to pay us, in the event they are unable to access the capital markets to fund their business operations.

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 those hedges cannot fully mitigate these risks to the Company. Further, the costs of the hedges, should foreign exchange rates move unfavourably, could be substantial. If we continue to engage in commodity price hedging, we will be exposed to credit-related losses in the event of non-performance by counterparties to the financial instruments. Additionally, if product prices increase above those levels specified in any future hedging agreements, we could lose the cost of floors or ceilings or a fixed price could prevent us from receiving the full benefit of commodity price increases. Our current and any future hedging arrangements could cause us to suffer financial loss if we are unable to commence operations on schedule, if we are unable to produce sufficient quantities of oil to fulfill our obligations, if we are required to pay a margin call on a hedge contract or if we are required to pay royalties based on a market or reference price that is higher than our fixed ceiling price.

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International Financial Reporting Standards.

The Accounting Standards Board of the Canadian Institute of Chartered Accountants has announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board, effective January 1, 2011. IFRS will require increased financial statement disclosure as compared to Canadian GAAP and accounting policy differences between Canadian GAAP and IFRS will need to be addressed by us. We are currently considering the impact a conversion to IFRS would have on our future financial reporting. No assurance can be provided that the adoption of IFRS will not adversely affect our reported financial results or our ability to satisfy the financial covenants in the Credit Facility and the Senior Notes.

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.

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.

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The Project is being undertaken jointly by the JV Participants pursuant to 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.

The development of future phases of the Project requires regulator approvals. 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 required to pay a royalty to the Government of the Province of Alberta on our bitumen production. The Province of Alberta implemented a new royalty regime effective January 1, 2009, and such regime has been and may in the future be amended from time to time. The new royalty regime is sensitive to commodity prices and the impact of such regime, or any amendment thereto, on OPTI cannot be accurately predicted.

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 the Strategic Alternatives Process

Our Board of Directors has decided to assess a range of strategic alternatives available to OPTI that may include capital market opportunities, asset divestures and/or a corporate sale, merger or other business combination. There can be no assurance that any transaction will occur.

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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 Future Phases 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

As at the date of this AIF, there are no material legal proceedings and regulatory actions against us.

TRANSFER AGENTS AND REGISTRAR

Transfer Agent for the Common and Preferred Shares is Valiant Trust at its principal offices in Calgary, Alberta and Toronto, Ontario.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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

INTERESTS OF EXPERTS

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

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ADDITIONAL INFORMATION

Additional information relating to OPTI may be found on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.shtml.

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 15, 2010;

"API" means degrees API, a measure of hydrocarbon density;

"Area of Mutual Interest" means the area of mutual interest with Nexen as described under the heading "Material Agreements Related to the Joint Venture - Background";

"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 constructed in connection with the Long Lake SAGD Operation, as further described under the heading "The Long Lake Project and Future Phase Development";

"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;

"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. Prior to January 1, 2008, the ERCB and the Alberta Utilities Commission were under one regulatory body called the Alberta Energy & Utilities Board;

"Future Phases COJO Agreements"means 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 further described under the heading "The Future Phases COJO Agreements";

"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 "Long Lake Upgrader - Integrated OrCrude™ Upgrader";

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"JV" means the joint venture between OPTI and Nexen;

"JV Participants" means OPTI and Nexen wherein OPTI holds 35 percent interest and Nexen holds 65 percent interest;

"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 and Kinosis areas;

"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 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 "The Long Lake Project and Future Phase Development - SAGD Commercial Project";

"Long Lake Upgrader" or "Upgrader" means the Integrated OrCrude™ Upgrader constructed for the purpose of upgrading bitumen produced from the Project lands, as further described under the heading "The Long Lake Project and Future Phase Development - Long Lake Upgrader";

"MM$" means millions of dollars

"Management Committee" means the committee comprised of representatives of each of OPTI and Nexen who pursuant to the COJO Agreement and the Future Phases 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;

"Mbbl" means thousands of barrels;

"MMbbl" means millions of barrels;

"mmbtu" means millions of British thermal units;

"Nexen Transaction" means the transaction, effective January 1, 2009, wherein OPTI sold a 15 percent working interest in its joint venture assets to Nexen, as further described under the heading "Material Agreements Related to the Joint Venture - The Purchase and Sale Agreement";

"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. 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;

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"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;

"Senior Notes" means collectively the 9% Notes, the 8.25% Notes and the 7.875% Notes as described under the heading "Description of Debt Capital";

"Sharing Agreement" means a sharing agreement dated November 20, 2009 between the Toronto Dominion Bank, as revolving debt representative, and the Bank of New York Mellon, as the trustee of the 9% Notes;

"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, 2009.

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 780,254 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)		37,265		34,022		901		823		651		595
Proved Developed Non-Producing(2)(7)		-		-		-		-		-		-
Proved Undeveloped(2)(8)		112,035		91,165		6,668		5,524		1,958		1,593
Total Proved		149,300		125,187		7,569		6,347		2,609		2,188
Probable(3)		403,493		320,217		26,312		20,899		5,473		4,331
Total Proved Plus Probable		552,793		445,404		33,881		27,246		8,083		6,519
Possible (4)		54,787		36,881		669		124		940		649
Total Proved Plus Probable Plus Possible		607,580		482,286		34,550		27,370		9,023		7,169

Net Present Values of Future Net Revenue Based on Forecast Prices and Costs(9)
	Before Deducting Income Taxes											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)		2,067		1,663		1,368		1,147		977			2,067		1,663		1,368		1,147			977
Proved Non-Producing		-		-		-		-		-			-		-		-		-			-
Proved Undeveloped(2)(8)		5,597		2,686		1,428		830		519			4,532		2,230		1,219		728			467
Total Proved		7,664		4,350		2,796		1,977		1,496			6,599		3,893		2,587		1,874			1,443
Probable (3)		28,383		5,925		1,324		142		(200	)		21,203		4,313		853		(27	)		(271	)
Total Proved Plus Probable		36,046		10,275		4,120		2,119		1,295			27,802		8,206		3,440		1,848			1,172
Possible (4)		6,016		1,138		408		247		191			4,484		868		332		215			174
Total Proved Plus Probable Plus Possible		42,062		11,413		4,528		2,366		1,486			32,286		9,074		3,772		2,063			1,346

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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)		18,208		2,363		6,529		1,631		22		7,664		1,065		6,599
Total Proved Plus Probable(2)(3)		88,507		13,340		28,517		10,490		113		36,046		8,245		27,802
Total Proved Plus Probable Plus Possible(2)(3)(4)		99,895		15,873		30,622		11,216		122		42,062		9,776		32,286

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		2,796	$	14.42
Total Proved Plus Probable(2)(3)	Bitumen, synthetic crude oil, and butane		4,120	$	5.79
Total Proved Plus Probable Plus Possible(2)(3)(4)	Bitumen, synthetic crude oil, and butane		4,528	$	5.80

Reserves Reconciliation

The following table sets forth the changes between the reserve volume estimates made as at December 31, 2009 and the corresponding estimates as at December 31, 2008, 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, 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
Extensions		-			-			-			-			-			-			-			-			-			-			-			-
Improved Recovery		-			-			-			-			-			-			-			-			-			-			-			-
Technical Revisions		(2,815	)		2,925			(2,993	)		(2,884	)		22,173			(28,968	)		(11,040	)		(17,835	)		19,358			(26,043	)		(14,033	)		(20,719	)
Acquisitions		-			-			-			-			-			-			-			-			-			-			-			-
Dispositions		(4,821	)		(62,888	)		(2,401	)		(70,110	)		(1,774	)		(185,341	)		(7,077	)		(194,191	)		(6,595	)		(248,228	)		(9,478	)		(264,302	)
Economic Factors		-			-			-			-			-			-			-			-			-			-			-			-
Production (Estimate)		(865	)		(363	)		-			(1,228	)		-			-			-			-			(865	)		(363	)		-			(1,228	)
Dec 31, 2009		7,569			149,300			2,609			159,479			26,312			403,493			5,473			435,278			33,881			552,793			8,083			594,757

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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		(158	)		175,060		(930	)		19,869		(2	)		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
2009		(47,599	)		112,035		(8,259	)		6,668		(4,137	)		1,958

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		(2,627	)		172,591		(1,748	)		1,726		39			2,369
2006		(6,540	)		166,051		3,554			5,280		(90	)		2,279
2007		251,813			417,864		8,136			13,416		3,456			5,735
2008		194,023			611,887		(7,639	)		5,777		17,629			23,364
2009		(212,737	)		399,150		20,430			26,207		(17,966	)		5,398

There are proved and probable undeveloped reserves associated with the 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 late-2011. 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.

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Future Development Costs Based on Forecast Prices and Costs
	Total Proved(2)		Total Proved Plus Probable(2)(3)
	(MM$)		(MM$)
2010		8.9		22.8
2011		154.8		131.3
2012		9.3		26.2
2013		9.5		383.3
2014		44.4		557.7
Total for all years undiscounted		1,630.5		10,489.9
Total for all years discounted at 10% per year		592.0		2,623.3

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 Hardisty 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
2010	80.00	83.20	70.60	84.70	84.19	85.20	60.35	6.05	70.60	59.32	2.0	0.950
2011	83.60	87.00	72.00	88.00	87.48	89.00	63.18	6.75	72.00	58.89	2.0	0.950
2012	87.40	91.00	72.60	91.50	90.97	93.10	66.20	7.15	72.60	57.12	2.0	0.950
2013	91.30	95.00	73.90	95.00	94.46	97.10	69.22	7.45	73.90	57.03	2.0	0.950
2014	95.30	99.20	77.20	98.70	98.15	101.40	72.35	7.80	77.20	59.74	2.0	0.950
2015	99.40	103.50	80.50	102.50	101.94	105.70	75.57	8.15	80.50	62.45	2.0	0.950
2016	101.40	105.60	82.10	104.10	103.53	107.90	77.09	8.40	82.10	63.64	2.0	0.950
2017	103.40	107.70	83.70	106.17	105.58	110.00	78.61	8.55	83.70	64.88	2.0	0.950
2018	105.40	109.80	85.40	108.24	107.64	112.10	80.22	8.70	85.40	66.26	2.0	0.950
2019	107.60	112.10	87.20	110.50	109.90	114.50	81.84	8.90	87.20	67.65	2.0	0.950
2020	109.70	114.30	88.90	112.68	112.05	116.70	83.45	9.05	88.90	68.98	2.0	0.950
2021	111.90	116.50	90.60	114.84	114.21	119.00	85.06	9.25	90.60	70.26	2.0	0.950
2022	114.10	118.80	92.40	117.11	116.46	121.30	86.77	9.45	92.40	71.68	2.0	0.950
2023	116.40	121.20	94.30	119.48	118.82	123.80	88.48	9.65	94.30	73.16	2.0	0.950
2024	118.80	123.70	96.20	121.94	121.27	126.30	90.38	9.85	96.20	74.63	2.0	0.950
2025	121.10	126.10	98.10	124.31	123.62	128.80	92.09	10.00	98.10	76.10	2.0	0.950
2026	123.60	128.70	100.10	126.87	126.17	131.40	93.99	10.20	100.10	77.67	2.0	0.950
2027	126.00	131.20	102.10	129.33	128.62	134.00	95.79	10.40	102.10	79.23	2.0	0.950
2028	128.50	133.80	104.10	131.90	131.17	136.70	97.68	10.65	104.10	80.74	2.0	0.950
2029	131.10	136.50	106.20	134.56	133.82	139.40	99.68	10.85	106.20	82.40	2.0	0.950
2030	133.70	139.30	108.30	137.32	136.56	142.30	101.77	11.05	108.30	83.96	2.0	0.950
2031	136.40	142.10	110.50	140.08	139.31	145.10	103.77	11.25	110.50	85.71	2.0	0.950
2032.	139.10	144.90	112.70	142.84	142.05	148.00	105.85	11.50	112.70	87.41	2.0	0.950
2033.	141.90	147.80	114.90	145.70	144.90	151.00	107.94	11.75	114.90	89.06	2.0	0.950
2034.	144.80	150.80	117.30	148.66	147.84	154.00	110.13	12.00	117.30	91.00	2.0	0.950
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	0.950

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, 2010 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, 2009, we had an interest in 91 gross (31.9 net) SAGD well pairs; each SAGD well pair is comprised of one injection well and one production well. These well pairs are contained within the Long Lake SAGD operation.

Properties with No Attributed Reserves

The Long Lake leases comprise 27,600 hectares. Proved, probable and possible reserves have been assigned, in whole and in part, on 70 sections of these lands and 41 sections have no reserves assigned. Resources have been assigned to some of these 41 sections. We have a 35 percent working interest in all of these lands.

We also have a 35 percent working interest in an additional295 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.

We do not expect any of the attributed reserves to expire within 2009. 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 financial statements at December 31, 2009 is $6 million for our 35 percent working interest. The total undiscounted future amount of abandonment liabilities expected to be incurred is $114million based on measurement criteria under Canadian GAAP. These liabilities relate to facilities and wells completed or under construction at the end of 2009. At December 31, 2009, there are 91 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. The undiscounted amount used in the constant dollar, proved plus probable plus case of the McDaniel report is $21 million net to us.

We incurred negligible abandonment costs in 2009 and expect to incur none in the next three years.

Tax Horizon

We did not pay any current income taxes in our fiscal year ended December 31, 2009. Considering Phase 1 only and our existing tax pools, we do not anticipate paying income taxes until approximately 2020, based on the Proved plus Probable case in the McDaniel Report using forecast prices. This estimate will be impacted by, among other factors, the final construction cost of the Project, commodity prices, foreign exchange rates, operating costs, interest rates, expansions of the Project and OPTI's other business activities. Changes in these factors from estimates used by us could result in us paying income taxes earlier or later than expected.

Costs Incurred

The following table sets forth costs incurred by us for oil and gas activities for the year ended December 31, 2009:

($ millions) Property Acquisition Costs (1)
Proved Properties	Unproved Properties	Exploration Costs	Development Costs
$8	$6	$10	$125

Notes:

(1) All of these costs were capitalized by OPTI.

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Exploration and Development Activities

During 2010, we completed the development of 10 gross (3.5 net) SAGD well pairs associated with pad 11.

Production Estimates

McDaniel estimates, based on the proved plus probable case, that the Project will produce on average approximately 35,100 bbl/d (12,285 bbl/d net to OPTI’s 35 percent working interest) of raw bitumen in 2010. 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 assumptions of well-pair productivity and well-pair drilling schedule. 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 continue to ramp-up through 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.

For an illustration of expected netbacks upon reaching full commercial production, see "Estimated Future Project Pre-Payout Netbacks" on page 9 of this document.

2009	Q1	Q2	Q3	Q4	Year
Bitumen production (bbl/d) (1)	4,705	4,992	2,977	4,762		4,359

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Netback

In CDN$/bbl(2)		Q1			Q2			Q3			Q4		Year
Revenue(3)	$	68.80		$	74.94		$	141.43		$	100.01		$	91.67
Royalties		(0.32	)		(0.91	)		(1.38	)		(2.23	)		(1.20	)
Operating expense		(67.00	)		(85.16	)		(161.95	)		(80.42	)		(92.24	)
Diluent and feedstock purchases(4)		(68.78	)		(44.79	)		(104.08	)		(55.26	)		(64.28	)
Transportation costs		(7.91	)		(6.20	)		(11.72	)		(8.58	)		(8.26	)
Netback	$	(75.20	)	$	(62.12	)	$	(137.70	)	$	(46.48	)	$	(74.31	)

Notes:

(1) Bitumen production is OPTI’s share only.

(2) These netbacks are not expected to be representative of future operations. All per barrel values are calculated based on bitumen production only. The significant cost of third party bitumen and diluent expenses have been included in dollar amounts only; we have not included the associated volumes in our per barrel calculations. As a result, these netbacks may not be suitable for other purposes and are not expected to be representative of future operations.

(3) Revenue includes revenue from all products: PSCTM, PSH, Bitumen, and power and is calculated by dividing Bitumen production only.

(4) Diluent and feedstock volumes are calculated by Bitumen production only and are not included in the volumes noted above.

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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 Company’s reserves data as at December 31, 2009. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2009 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, 2009, 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 MM$ (before income taxes, 10% discount rate)
Preparation Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated	Reviewed	Total
February 19, 2010	Canada	-	4,120	-	4,120

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

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

7. Because the reserves data are based on 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.

Executed as to our report referred to above:

McDANIEL & ASSOCIATES CONSULTANTS LTD.

"signed by P.A. Welch"

P.A. Welch, P.Eng.

President & Managing Director

Calgary, Alberta

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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") is 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, 2009, 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 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 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 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.

(signed) "Chris Slubicki"

President and Chief Executive Officer

(signed) "Al Smith"

Vice President, Development

(signed) "Charles Dunlap"

Director

(signed) "Edythe (Dee) Marcoux"

Director

Dated March 15, 2010

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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;

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

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

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

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

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

E.           STEWARDSHIP FUNCTIONS

Relationship with External Auditor

1. The Audit Committee shall:

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

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

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

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

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

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

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

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

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

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

(ii) adopt specific policies and procedures for the engagement of the external auditor for the purposes of the provision of non-audit services; and

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

Financial Statements and Financial Reporting

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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