Exhibit 99.1









Annual Information Form




For the Year Ended




December 31, 2010






March 15, 2011











TABLE OF CONTENTS





PageINTRODUCTORY INFORMATION
3FORWARD-LOOKING INFORMATION
3CORPORATE STRUCTURE
6GENERAL DEVELOPMENT OF THE BUSINESS
6Competitive Strengths and Operating Strategies
7Our Industry
12Our Principal Assets
13The Long Lake Project and Future Expansion Developments
13The OrCrudeTMProcess
19Marketing
20Infrastructure
21Our Lands and Leases
21Material Agreements Related to the Joint Venture
24Royalties
30Regulatory Approvals and Environmental Considerations
30Insurance
33RESERVES AND RESOURCES SUMMARY
34Reserves Data
34Resources Data
36DESCRIPTION OF CAPITAL STRUCTURE
37Description of Share Capital
37Rights Plan
37Description of Debt Capital
38Description of Hedging Contracts
40CREDIT RATINGS
41MARKET FOR SECURITIES
42DIVIDENDS
42DIRECTORS AND OFFICERS
43Board of Directors
44Officers
46
 Audit Committee
47Auditor Service Fees
47
 
  CONFLICTS OF INTEREST
47RISKS AND UNCERTAINTIES
48Risks Relating to the Project, Operations and to Future Expansions
48Risks Relating to Financing and Our Indebtedness
54Risks Relating to Reserves and Resources
56Risks Relating to Economic Conditions, Commodity Pricing, and Exchange Rate Fluctuations and Other Risks
57Risks Relating to Technology
60Risks Relating to Third Parties
61Risks Relating to the Strategic Alternatives Review Undertaken by OPTI
64MATERIAL CONTRACTS
65LEGAL PROCEEDINGS AND REGULATORY ACTIONS
65TRANSFER AGENTS AND REGISTRAR
65INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
65INTERESTS OF EXPERTS
65ADDITIONAL INFORMATION
65GLOSSARY
66





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


APPENDIX E -
NOTICE OF FILING OF 51-101FI INFORMATION







- 2 -





INTRODUCTORY INFORMATION





Except as otherwise indicated, or unless the context otherwise requires, the terms "OPTI," "we," "our" and "us," refer to OPTI Canada Inc. Capitalized terms used herein and not otherwise defined have the meanings ascribed thereto in the Glossary located on page 66.





Unless otherwise indicated, all financial information included and incorporated by reference in this 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 applicable Canadian securities and U.S. federal securities laws. These statements and information 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:





•
our expectation that our financial resources will provide sufficient liquidity;





•
the level of bitumen production expected from the Long Lake Project (the "Long Lake Project" or the "Project");





•
the impact of heating high water saturation zones (or lean zones) and the result of maintaining steam injection on these zones;





•
the operation of our facilities, including the steam-to-oil ratio (the "SOR") of the Long Lake steam assisted gravity drainage ("SAGD") operation (the "Long Lake SAGD Operation" or the "SAGD Operation") and the Premium Sweet Crude (the "PSCTM") yield of the Long Lake Upgrader ( the "Long Lake Upgrader" or the "Upgrader");





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





•
our liquidity, financial resources, continued availability of our credit facilities and potential financing alternatives;





•
the prices we receive for the PSCTM and other products produced from the Project;





- 3 -





•
our estimates of reserve and resource volumes and of the present value of the Project’s future net cash flow;





•
our expansion plans for our properties and the expected increases in revenues attributable to OPTI’s expansions;





•
the impact of governmental controls and regulations on our operations;





•
our competitive advantages and ability to compete successfully;





•
our expectations regarding the development and production potential of our properties;





•
our ability to increase steam production;





•
our ability to fund our future development and expansion developments;





•
any strategic alternatives we are pursuing;





•
the expectation that the Upgrader will produce 57,700 barrels per day ("bbl/d") of PSCTM and 800 bbl/d of butane;





•
our estimated gravity of approximately 39° ("API") for the PSCTM;





•
our estimated capital cost to maintain full production;





•
our estimated financial performance, including estimated per barrel and annual netbacks and estimated free cash flows, in future periods; and





•
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.





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 and costs with respect to the Project;





•
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;





•
foreign exchange rates;





•
the ability to market PSCTM and other products successfully to customers and our ability to achieve product pricing expectations;





•
the impact of changing competition;





•
our ability to obtain financing on acceptable terms and to maintain the availability of our current financing arrangements; 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;





- 4 -





•
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;





•
risks that our financial counterparties may not fulfill financial obligations to OPTI;





•
risks that we may not be able to satisfy the covenants and conditions in our credit facilities and the potential accelerated required prepayment of such credit facilities and our senior secured notes;





•
risks that we may not be able to repay our indebtedness when we are required to do so;





•
difficulties encountered in delivering PSCTM and other products to commercial markets;





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





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





•
we may be unable to sufficiently protect our proprietary technology or may be the subject of technology infringement claims from third parties;





•
general economic conditions in Canada and the United States;





•
failure to obtain industry partner and other third party consents and approvals, when required;





•
royalties payable in respect of our production;





•
the impact of amendments to the Income Tax Act (Canada), or the Tax Act;





•
changes in or the introduction of new government regulations, in particular related to carbon dioxide emissions, relating to our business;





•
our ability to attract 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.





- 5 -





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, 2010.





Our head office is located at Suite 1600, 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





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 a joint venture ("JV") with our partner, Nexen Inc. ("Nexen"). OPTI holds a 35 percent working interest in all JV assets including all reserves and resources, current and future expansion developments, with Nexen as the sole operator and 65 percent working interest owner. Our first project, the Long Lake Project, is located near Fort McMurray, Alberta, and 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 will produce 58,500 bbl/d of products, primarily 39° API PSCTM. PSCTM is a highly desirable refinery feedstock with low sulphur content. We expect PSCTM to sell at a price similar to West Texas Intermediate ("WTI") crude oil.





The Project was the first to utilize OPTI’s proprietary OrCrudeTM Process (see glossary), integrated with proven gasification and hydrocracking processes. Through this configuration, we reduce our exposure to and the need to purchase natural gas while producing a high quality synthetic crude oils from the Canadian oil sands.





The leases that support our development plans are located in the Athabasca region of north-eastern Alberta. The Project is on the Long Lake lease. Other leases in areas commonly referred to as Kinosis, Leismer and Cottonwood will be used for possible future expansion developments.





We began producing bitumen at the Project in 2008 and we announced first production of PSCTM in January 2009.





In 2009, OPTI completed a transaction with Nexen (the "Nexen Transaction") to sell a portion of its JV working interest. See "Description of the Business – Material Agreements Related to the Joint Venture – The Purchase and Sale Agreement."





During 2009, OPTI amended its $190 million Senior Secured Revolving Credit Facility (the "Credit Facility"). We also 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 $150 million. In the same year, we 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. See "Description of Capital Structure."





- 6 -





In November 2009, our Board of Directors initiated a review of strategic alternatives. Scotia Waterous Inc. and TD Securities Inc. were engaged as financial advisors to assist in this review. Strategic alternatives included capital market opportunities, asset divestitures, and/or a corporate sale, merger or other business combination.





In August 2010, OPTI completed two issuances of First Lien Senior Secured Notes. We issued US$100 million of First Lien Senior Secured Notes, which bear interest at 9 percent per annum and mature on December 15, 2012, and US$300 million of First Lien Senior Secured Notes, which bear interest at 9.75 percent per annum and mature on August 15, 2013. The US$100 million First Lien Notes were offered as additional notes under OPTI’s existing US$425 million First Lien Notes (combined, the "US$525 million First Lien Notes"). See "Description of Capital Structure – Description of Debt Capital."





At December 31, 2010, OPTI had approximately 20 employees primarily focused on finance, accounting and JV management.





In early 2011, OPTI expanded its strategic alternatives review to include seeking advice on capital structure adjustments. Lazard Frères & Co. LLC was retained to work in a coordinated manner with Scotia Waterous Inc. and TD Securities Inc. to review the full range of strategic options available to the Company.





In February 2011, bitumen production was approximately 23,100 bbl/d (8,100 bbl/d net to OPTI) and the Upgrader was in operation. We expect production to increase in 2011.





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 PSCTM in January 2009, marking the start-up of the fourth integrated oil sands project in Canada. We anticipate that the Upgrader will be able to process all SAGD production from the Project. We expect the Upgrader to produce 57,700 bbl/d of PSCTM and 800 bbl/d of butane at full capacity.





Until recently, most oil sands were extracted via mining. However, about 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 (see glossary) 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.


In 2009, both the SAGD and OrCrudeTMtechnologies were demonstrated by successful integration of Upgrader and SAGD operations, as well as by the production and sale of first PSCTM. We also completed the SAGD debottleneck project, resulting in total expected steam generation capacity of approximately 230,000 bbl/d. We expect that approximately 224,000 bbl/d of this generated steam will be available for well injection.





- 7 -





The Upgrader is producing a synthetic fuel gas ("syngas") that is used in our SAGD operations and the solvent deasphalter and thermal cracker are operating effectively. In 2010, we achieved PSCTM yields as high as 72 percent. We expect PSCTM yields to reach 80 percent as Upgrader operations are optimized. We anticipate that all 90 well pairs to be capable of production in the second quarter of 2011. We will also continue to develop pads 12 and 13 this year, adding 18 additional well pairs that are expected to be in operation in 2012. We are considering approval of a steam expansion project consisting of two new once through boilers, which would increase existing steam capacity by 10 to 15 percent by late 2012.





As at the end of February 2011, the Project has produced over 10 million barrels of PSCTM (3.5 million barrels net to OPTI).





Large, Exploitable Resource Base





Our working interest share of reserves and resources on our leases are estimated to be 729 million barrels of proved and probable reserves, 1,100 million barrels of best estimate contingent resources, and 335 million barrels of best estimate prospective resources. These reserves and resources are estimated to be sufficient to support approximately 430,000 bbl/d (150,000 bbl/d net to OPTI) of SAGD production. We believe that the approval of future expansion developments 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."





The timing of future expansion developments is subject to many factors including Project operating performance; improvement in our financial position; finalization of cost estimates; the commodity price environment; supportive financial markets; and regulatory approvals.





Our next near-term development is Kinosis, located directly south of the Long Lake Project. OPTI and Nexen have regulatory approval for Kinosis SAGD development for up to 140,000 bbl/d of bitumen production and continue to evaluate developing the SAGD projects in approximately 40,000 bbl/d bitumen stages. OPTI’s sanctioning of the first stage may occur in 2012, dependent on the factors listed above and additional stages of Kinosis SAGD would proceed thereafter. Upgrading facilities could be built once sufficient bitumen rates from the Kinosis area have been reached and economic conditions support the development of upgrading. The JV Participants have regulatory approval for upgrading facilities to support 70,000 bbl/d of bitumen production capacity at Kinosis.





We expect that the Project will have sustained production rates during the life of the Project, which is expected to be over 40 years.





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, major plant turnarounds and regular maintenance capital spending on plant and facilities.




- 8 -





Netbacks at Full Production and Annual Free Cash Flows Based on SOR Assumptions





As the project reaches higher production rates, operating costs will be reduced on a per barrel basis, primarily due to increased syngas production and resultant lower natural gas purchases.





We provided an update to our estimated netbacks and free cash flows for the Project in the management’s discussion and analysis for the year ended December 31, 2010 filed on "SEDAR" at www.sedar.com and "EDGAR" www.sec.gov/edgar.shtml on February 10, 2011. Management approved this netback calculation on February 9, 2011. The netback calculation at each WTI price reflects higher operating costs and has been updated for lower natural gas prices, a stronger Canadian dollar relative to the U.S. dollar, a lower heavy/light crude oil price differential and lower electricity sale prices. The estimated annual free cash flows are based on a range of SORs. The long-term performance of our reservoir and respective SOR will be demonstrated over a number of years. Our rationale for providing this sensitivity is to provide a range of outcomes based on SOR, a key variable to our per barrel and annual netbacks. With additional knowledge of our reservoir gained through our ramp-up to date, we have updated our estimate for SOR for the Project to between 3.0 and 4.0 and have therefore evaluated the impact of SOR within this range. This range captures our current SOR expectations for our existing well pairs at full production. We do not expect to reach full production, or this SOR range, until 2012 or later. The SOR for our original 90 well pairs is expected to be in the high end of the range. We show netbacks and resultant free cash flows at full production due to the expected long-term life of our assets. We expect that the netbacks and annual free cash flows generated by our Project to be lower in the initial years following start-up than shown in this outlook due to the lower production volumes during ramp-up and an initially higher SOR. Management approved these netback and annual free cash flow calculations on February 9, 2011. For the per barrel and annual netbacks and annual free cash flows at a SOR of 3.0, we have assumed no additional steam capacity. In the annual netbacks and free cash flows for the SOR cases at 3.5 and 4.0, we have assumed that our planned steam expansion project has been approved and constructed





This financial outlook is intended to provide investors with a measure of the ability of our Project to generate netbacks and free cash flows assuming full production capacity. This outlook also intends to provide investors with an estimate of how our annual netbacks and resultant free cash flows at full production capacity could be impacted by the specified SOR range. We believe that the per barrel and annual netbacks and resultant free cash flows are the most appropriate financial measures to evaluate future Project performance. Corporate costs (other than corporate G&A expenses), interest, and other non-cash items are excluded from the estimates. The financial outlook may not be suitable for other purposes. The per barrel and annual netback and resultant annual free cash flow calculations as presented are non-GAAP financial measures. The closest GAAP financial measure to the calculations 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 per barrel and annual netback and resultant free cash flows achieved by the Project could differ materially from these estimates. The material risk factors that we have identified toward achieving these netbacks and free cash flows are outlined under "Forward-looking Information" in this document. In particular, long-term SOR may be higher than we assumed, bitumen production may not reach our design rate of 72,000 bbl/d (25,200 bbl/d net to OPTI) or may require significantly more capital to be achieved, 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 fluctuation exposure; and our netback will be directly affected by the applicable royaltyregime relating to our business. The key assumptions relating to the netback and free cash flow estimates are set out in the notes beneath the tables.





- 9 -





Estimated Future Project Pre-Payout Netbacks at Full Production(1)





WTI - US$75(2)


WTI - US$100(3)Per Barrel of Products Sold


Annual

in millions


Per Barrel of Products Sold


Annual

in millions$/bbl


$CDN/year


$/bbl


$CDN/yearRevenue(1)

$
76.26


$
547


$
98.14


$
704Royalties and corporate G&A


(3.88
)


(28
)


(6.83
)


(49
)Operating costs(4)Natural gas(5)


(3.73
)


(27
)


(5.12
)


(37
)Other variable(6)


(2.38
)


(17
)


(2.38
)


(17
)Fixed


(18.02
)


(129
)


(18.02
)


(129
)Property taxes and insurance(7)


(2.65
)


(19
)


(2.65
)


(19
)Total operating costs


(26.78
)


(192
)


(28.17
)


(202
)Netback

$
45.60


$
327


$
63.14


$
453





Our estimate for SOR for the Project is between 3.0 and 4.0 and we have therefore evaluated the impact of SOR within this range. This range captures SOR expectations for our existing well pairs at full production. The SOR for our original 90 well pairs is expected to be in the high end of range. The net backs above are at an SOR of 3.0, for sensitivity to SOR, we evaluate the financial impact for our estimated SOR range on page 11.





Notes:


(1)
The annual and per barrel amounts are based on the expected yield for the Project of 57,700 bbl/d of PSCTM and 800 bbl/d of butane (20,100 bbl/d of PSCTM and 280 bbl/d of butane net to OPTI), and assume the Upgrader will have an on-stream factor of 96 percent. These numbers are cash costs only and do not reflect non-cash charges. See "Forward-Looking Statements."


(2)
For purposes of these calculations, with regard to the WTI price scenario of US$75, we have assumed natural gas costs of US$3.75/mmbtu (millions of British thermal units), foreign exchange rates of $1.00 = US$0.96, heavy/light crude oil price differentials of 24 percent of WTI and electricity sales prices of $40.00 per MegaWatt hour (MWh). Revenue includes sales of PSCTM, bitumen, butane and electricity.


(3)
For purposes of these calculations, with regard to the WTI price scenario of US$100, we have assumed natural gas costs of US$5.00/mmbtu, foreign exchange rates of $1.00 = US$1.00, heavy/light crude oil price differentials of 22 percent of WTI and electricity sales prices of $52.00 per MWh. Revenue includes sales of PSCTM, bitumen, butane and electricity.


(4)
Costs are in 2010 dollars.


(5)
Natural gas costs are based on the low end of our SOR range of 3.0 to 4.0.


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


(7)
Property taxes are based on expected mill rates for 2011.





On a long-term basis, we estimate sustaining capital costs required to maintain production at design rates of capacity to be approximately $80 million per year (net to OPTI). The one-time development cost of the steam expansion project was not considered in the annual netback and free cash flow calculations as the capital expenditure impact is not significant over the life of the Project and is not a sustaining capital cost. The increase from the prior estimate of approximately $60 million per year (net to OPTI) is due to an increase in the average annual turnaround sustaining capital costs and an increase in the average annual number of new wells to be drilled throughout the life of the Project. The netbacks as shown are prior to abandonment and reclamation costs.





- 10 -





Estimated Future Project Pre-Payout Free Cash Flows at a Range of Potential SOR at Full Production





WTI - US$75


WTI - US$100In millions ($CDN)

SOR 3.0 (3)


SOR 3.5 (4)


SOR 4.0(5)


SOR 3.0 (3)


SOR 3.5 (4)


SOR 4.0(5)Netback per barrel

$
45.60


$
44.81


$
39.02


$
63.14


$
62.05


$
54.35Annual Netback (1)

$
327


$
321


$
280


$
453


$
445


$
390Annual MaintenanceCapital (2)


(80
)


(80
)


(80
)


(80
)


(80
)


(80
)Free Cash Flow

$
247


$
241


$
200


$
373


$
365


$
310





Notes:


(1)
Annual netback amounts are based on the expected yield for the Project of 57,700 bbl/d of PSCTM and 800 bbl/d of butane (20,100 bbl/d of PSCTM and 280 bbl/d of butane net to OPTI), and assumes that the Upgrader will have an on-stream factor of 96 percent. Notes (2), (3), (4), (6) and (7) in the Estimated Future Project Pre-Payout Netbacks at Full Production table above apply to each of these Annual Netbacks. These numbers are cash amounts for OPTI’s working interest share only and do not reflect non-cash charges. See “Forward-Looking Statements.”


(2)
Annualized Maintenance Capital, based on estimated sustaining capital costs required to maintain production at design rates of capacity, is expected to be approximately $80 million per year. For the SOR cases at 3.5 and 4.0, the long-term annual maintenance capital is not adjusted for the long-term maintenance capital expense or the initial capital expenditure (of approximately $200 million gross) for the potential steam expansion project, as these costs are not significant over the life of the Project. Please refer to notes (4) and (5) below for further information.


(3)
For purposes of this calculation, we have assumed an SOR of 3.0 with no additional expenditures for the steam expansion project; all other assumptions are the same as noted under Estimated Future Project Pre-Payout Netbacks.


(4)
For purposes of this calculation, we have assumed an SOR of 3.5 with completion of the steam expansion project, where current steam capacity would be increased in order to reach design capacity bitumen production rates. Higher operating costs of approximately $6 million at US$75 WTI and approximately $8 million at US$100WTI would result from incremental natural gas costs.


(5)
For purposes of this calculation, we have assumed an SOR of 4.0 with completion of the steam expansion project. With an SOR of 4.0 and the inclusion of additional steam capacity bitumen, production is projected to reach rates of approximately 64,500 bbl/d (versus the Project’s design capacity of 72,000 bbl/d) on a gross basis. In this case, the annual netback is decreased by approximately $47 million at US$75 WTI and approximately $63 million at US$100 WTI primarily due to approximately 5,000 bbl/d of feedstock purchases to supplement lower bitumen production levels and incremental natural gas costs.





After the one-time investment for the potential steam expansion project, the reduction in annual free cash flow of $6 to $8 million at an SOR of 3.5, relative to the SOR of 3.0 case, is primarily attributable to higher expenses for natural gas. After the same one-time investment for the potential steam expansion project, the reduction in annual free cash flow of $47 to $63 million at an SOR of 4.0, relative to the SOR of 3.0 case, is primarily attributable to the reduction in bitumen production and royalties, and higher feedstock purchases, as well as higher natural gas expenses.





- 11 -





Lower Cash Flow Volatility





The use of the Integrated OrCrudeTM Upgrader offers several advantages in that the Upgrader provides a solution to the three traditional challenges of conventional SAGD Operations:





Challenge
Integrated OrCrudeTM Upgrader SolutionExposure to fluctuating natural gas prices
Operating costs and the volatility of netbacks are reduced since the Integrated OrCrudeTMUpgrader produces synthesis gas to supply fuel for steam generation and hydrogen for hydrocracking, thereby significantly reducing the need to purchase natural gasExposure to heavy oil differentials
The Integrated OrCrudeTM Upgrader produces a high quality 39° API synthetic crude oil thereby significantly reducing exposure to heavy oil differentials (the difference in value between light and heavy oil)Exposure to rising diluent prices and potential diluent shortages
The Integrated OrCrudeTM Upgrader produces a synthetic crude oil that does not require diluent to assist in its transportation, thereby limiting the Project’s exposure to diluent pricing and availability





Experienced 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 246,000 boe/d (see glossary), before royalties, in the fourth quarter of 2010. 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 by the Project.





Our Industry





Oil sands operators produce and process bitumen, which is the heavy oil trapped in the sands. According to the Energy Resources Conservation Board ("ERCB"), Canada’s oil sands are estimated to hold as much as 175 billion barrels of bitumen. Including the oil sands, Alberta has the second largest petroleum reserves in the world, second only to Saudi Arabia. The ERCB reports that oil sands bitumen production is currently around 1.5 million bbl/d and expects that oil sands production will reach 2.7 million bbl/d by 2015.





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.





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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 bitumen and upgrades it into high quality synthetic crude oil;





•
proved plus probable bitumen reserves, associated with the Long Lake and Kinosis leases, of 729 million barrels. See "Reserves and Resources Summary";





•
contingent bitumen resources of 1,100 million barrels and prospective bitumen resources of 335 million barrels contained in the Long Lake, Kinosis, Leismer and Cottonwood leases. See "Reserves and Resources Summary";





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





•
approximately 840 delineation wells drilled and approximately 227 square kilometres of three dimensional seismic gathered at the Kinosis, Leismer and Cottonwood leases.





The Long Lake Project and Future Expansion Developments





The Long Lake Project





In 2001, OPTI formed a JV with Nexen to develop integrated oil sands projects in Canada. The first such project is the Long Lake Project, located on our Long Lake lease 42 kilometres ("km") southeast of Fort McMurray, Alberta. See: "Our Lands and Leases."





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. PSCTM 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 (see glossary) that generates steam for the SAGD wells and electricity for use by the Project. The Cogeneration Facility has a capacity of 170 megawatts, approximately 40 megawatts of which is available for sale into the Alberta interconnected electric system. The Project is being governed pursuant to the terms and conditions of the construction, ownership and joint operation agreement (the"COJO Agreement") and the technology agreement (the "Technology Agreement"). These agreements are described under "Material Agreements Related to the Joint Venture."





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Project Status





Major on-site construction of the Project began in mid-2005. The SAGD facilities were completed and steam injection commenced in 2007. Construction of the Upgrader, which intentionally lagged SAGD to ensure sufficient bitumen production at start-up, was completed in early 2008. First production of PSCTM from the Project was achieved in January 2009.





While SAGD production began in 2008, 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. As a result, in 2009 several initiatives were completed to optimize steam production and enhance long-term production capacity including: addition of supplementary heat to hot lime softeners in the water treatment plant; and the completion of a turnaround in September 2009 for replacement of over 400 valves in the SAGD plant and maintenance on the water treatment plant. After these initiatives were completed, and with improved water treatment, steam injection rates began to steadily increase. The construction development cost of the Project through to March 31, 2009 was approximately $7 billion (gross).





In 2010, steam injection rates rose from an average of approximately 114,000 bbl/d in the first quarter, to approximately 157,900 bbl/d in the fourth quarter. The bitumen production in 2010 increased from an average of approximately 18,700 bbl/d (6,545 bbl/d net to OPTI) in the first quarter, to approximately 28,100 bbl/d (9,800 bbl/d net to OPTI) in the fourth quarter.





Steam injection rates in December 2010 averaged approximately 172,300 bbl/d. While these rates were at record levels in December 2010, we did not see a corresponding improvement in our bitumen production levels. We expected bitumen production to be higher than the December 2010 monthly average of approximately 29,100 bbl/d (10,200 bbl/d net to OPTI) in response to the increased steam injection. Although a short term lag in bitumen production can occur, consistently high steam rates without a corresponding increase in bitumen production could indicate greater reservoir complexity. This complexity could indicate the prevalence of high water saturation zones (or lean zones). Steam contact with lean zones can result in cross-flow between steam chambers, heat losses and temporarily suppressed well performance. Some of our wells that exhibited this behaviour have also shown some recovery over time. Once the lean zones are heated and the water is displaced, bitumen production and SOR typically improve. Through our experience, we have learned that when we encounter these high water saturation zones it is important to maintain consistent steam injection and lift all the produced fluid from the wells. The magnitude of the steam losses into each lean zone is somewhat proportional to the pressure difference between the steam chamber and the lean zone. Geologic data and analysis indicates that higher water saturation zones make up only 3 to 5 percent of our reservoir by volume. The operator continues to adjust operational strategies in an effort to ensure optimal SAGD bitumen production.





In January and February 2011, steam injection rates decreased to average approximately 155,700 bbl/d and 130,300 bbl/d respectively and bitumen production rates also decreased to average approximately 27,000 bbl/d (9,450 bbl/d net to OPTI) and 23,100 bbl/d (8,100 bbl/d net to OPTI) respectively. Our production and steam levels decreased primarily due to a number of electric submersible pump ("ESP") failures in the field and some water treatment issues at the plant. These factors resulted in lower steam injection levels, making it difficult to evaluate whether bitumen production will respond to increased steam in the near term. The ESP replacements for the January failures were completed in February and the water treatment issues were addressed. We anticipate that steam injection and bitumen production rates will continue to ramp up throughout 2011.





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Our February 2011 all-in SOR average was approximately 5.6. The all-in SOR average included steam to wells that are currently in steam circulation mode and wells early in the ramp-up cycle. We expect the SOR to decrease as bitumen production levels rise in response to higher steam injection levels. We expect our all-in SOR to decline over time as we convert circulating wells to production mode, maintain stable operations, work through any high water saturation zones, add further well pairs, and allow our producing wells to mature. While we expect SOR to decline over time, the rate of decline is also affected by surface operations. A lack of surface operations reliability will negatively impact this expected improvement. With additional knowledge of our reservoir gained throughout ramp- up to date, we expect that our long-term SOR will range between 3.0 and 4.0. This range captures our current SOR expectations for our existing well pairs at full production. We do not expect to reach full production, or this long-term SOR range until 2012 or later. The SOR for our original 90 well pairs is expected to be in the high end of this range.





In 2010, we achieved PSCTM yields as high as 72 percent. We expect PSCTM yields to reach 80 percent as Upgrader operations are optimized. The Upgrader is producing syngas that is used in our SAGD operations and the solvent deasphalter and thermal cracker are operating effectively. Upgrader on-stream time increased significantly in 2010 from a first quarter average of approximately 78 percent to a fourth quarter average of approximately 90 percent. Improved reliability allowed the Project to process essentially all of the produced and purchased bitumen over the period from December 2010 through February 2011.





We have a total of 11 well pads with 90 well pairs available for the Project. We anticipate that all 90 well pairs will be capable of production in the second quarter of 2011. We will also continue to develop pads 12 and 13 this year, adding 18 additional well pairs that are expected to be in operation in 2012. 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. As at the end of February 2011, we have 75 well pairs with ESPs and we expect to install additional ESPs this year.





In 2011, we will increase the natural gas inlet capacity to allow us to maintain full steam production rates during period of Upgrader downtime when no syngas is produced, thereby further increasing the operating independence between our SAGD facilities and the Upgrader while maintaining the benefits of integration.





OPTI has a $150 million capital program for 2011, with approved spending of $122 million at the Project. One of the key initiatives is the continued development of pads 12 and 13 at Long Lake. The JV Participants also approved engineering costs to evaluate additional steam capacity and a Diluent Recovery Unit ("DRU"). The steam expansion project, if approved, is expected to increase existing steam capacity by 10 to 15 percent by late 2012. The DRU, if approved, is expected to enable improved operating flexibility during periods of Upgrader downtime by allowing us to switch between streams of PSCTM and PSH more effectively. Further capital spending to develop these projects requires approval by OPTI’s board of directors.





As at the end of February 2011, the Project has produced over 10 million barrels of PSCTM (3.5 million barrels net to OPTI). Once the Project reaches full design rates, it is expected to produce approximately 20,000 bbl/d of PSCTM net to OPTI for over 40 years.





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The SAGD Process









SAGD is an in-situ process that removes bitumen from the oil sand reservoir without removing the sand. The bitumen recovery component of the Project uses 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 bitumen mining operations that extract both the sand and bitumen from the ground, separate the bitumen from the sand and return the sand to tailings ponds. The SAGD process was first used in 1978 and is being employed as the recovery process in most new or developing in-situ projects.





SAGD Commercial Project





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 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 six 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.





We have 90 SAGD well pairs with 18 more pairs expected to be in operation in 2012. Additional sustaining well pairs will be drilled as required in future years to maintain production. In addition to the 90 wells pairs already drilled and completed, we anticipate that another 526 well pairs will be drilled during the life of the Project. This assumption is based on the McDaniel & Associates Consultants Ltd. ("McDaniel") total proved plus probable reserve case for the Project at December 31, 2010.





- 16 -





Water treatment and steam generation facilities are expected to support a SAGD steam generation capacity of approximately 230,000 bbl/d. We expect that approximately 224,000 bbl/d of this generated steam will be available for well injection in consideration of plant usage. We expect the long-term average SOR for the Project to be between 3 and 4.





Long Lake Upgrader





Upgrading of Bitumen





The bitumen recovered by the SAGD Operation is upgraded in the Upgrader. The Upgrader has an expected capacity of approximately 72,000 bbl/d of bitumen, yielding approximately 57,700 bbl/d of PSCTMand 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.





Integrated OrCrudeTM Upgrader





A complete upgrading process has been developed which combines the OrCrudeTMProcess with proven hydrocracking and gasification processes to produce PSCTM, a premium sweet crude oil, and syngas, a synthesis fuel gas. The gasification of the heaviest part of the bitumen barrel, in addition to producing syngas, also produces hydrogen for use in the hydrocracker.





The OrCrudeTMProcess, when combined with these hydrocracking and gasification processes, is referred to as an "Integrated OrCrudeTMUpgrader." ORMATIndustries Ltd.("ORMAT")has been granted patents respecting the Integrated OrCrudeTMUpgrader 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 OrCrudeTMProcess in Canada.





The syngas produced by an Integrated OrCrudeTMUpgrader is used as clean fuel in the Integrated OrCrudeTMUpgrader, 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 OrCrudeTMUpgrader is integrated with a SAGD facility) and a fuel source for a cogeneration facility. As a result, the Project’s requirement to purchase third party natural gas, and its exposure to fluctuations in natural gas prices, are reduced. The ultimate exposure to natural gas prices and cost will depend on the SOR achieved. We expect that the integration of the Integrated OrCrudeTMUpgrader and the SAGD facility will create operating cost advantages for the Project over other SAGD projects.





The PSCTMproduced 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 OrCrudeTMUpgrader produces a light synthetic crude oil which eliminates the requirement to add diluent to assist in bitumen transportation. There is 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 only needs to purchase diluent for periods when the Upgrader is not operating.





OrCrudeTM Unit





The OrCrudeTMunit 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 OrCrudeTMunit and recycled back to the SAGD Operation, the Project is not exposed to diluent costs while the Upgrader is operational.





- 17 -





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 OrCrudeTMProcess. ORMAT energy converters generate power by using the waste heat to vaporize pentane, expanding it across a turbine to generate power and then condensing it with an air cooler.





Gasifier





The gasification technology used in the Integrated OrCrudeTMUpgrader 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 SelexolTMsolvent 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.





- 18 -





Based on design specification, at full production, we expect to self-supply 60 percent of the fuel required by the Project. Total syngas production is expected to be approximately 90,000 gigajoules per day ("GJ/d") and the total fuel requirement for the Project is expected to be approximately 150,000 GJ/d.





Hydrocracker





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





Within the hydrocracker unit, the OrCrudeTMProduct is fed to a single hydrotreating reactor, where hydrogen is added over a catalyst to remove sulphur and nitrogen compounds in the OrCrudeTMProduct 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 PSCTM product, and the remainder can be 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 from 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 OrCrudeTMProcess





Background





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





The OrCrudeTMProcess 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 OrCrudeTMProcess is the manner in which the process is integrated to upgrade the deasphalted vacuum residue stream and recycle it to extinction.





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The OrCrudeTMProcess 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 OrCrudeTMportion of the Long Lake Upgrader, with nearly the same number of equipment components, process streams and control system elements.





OrCrudeTM Process License





The OrCrudeTTMProcess 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 OrCrudeTMProcess 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 OrCrudeTMProcess technology for an unlimited period of time anywhere in Canada, with the right to sub-license the technology to third parties. We refer to this sub-license as the OPTI License.





The key terms of the OPTI License are as follows:





•
Improvements made by OPTI BV or ORMAT in the OrCrudeTMProcess 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 OrCrudeTMProcess 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 OrCrudeTMProcess.





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 JV. These products include PSCTM, surplus electricity from our Cogeneration Facility and sulphur, and blended bitumen which we call Premium Synthetic Heavy ("PSH"), in the event that the Upgrader is unavailable. OPTI has the right to take such production in kind in certain circumstances. We expect PSCTM 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.





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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 under which traffic is moved to and from the Project site by rail. The rail line will move, amongst other commodities, sulphur, catalysts and construction materials to and from the Project site.





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





Our Lands and Leases










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Gross Acres


Net Acres


Delineation WellsLong Lake


30,080



10,528



428Kinosis


40,960



14,336



387Leismer


85,760



30,016



331Cottonwood


90,240



31,584



128Other


12,800



4,480



1Total


259,840



90,944



1,275





The above 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, 2010. We own a 35 percent interest in the rights to recover bitumen found in the oil sands deposits within the Long Lake, Kinosis, Leismer and Cottonwood leases.





Long Lake Lease





These lands are located in the Athabasca oil sands region of Alberta approximately 42 km south of Fort McMurray.





The Long Lake lease covers an area of 47 sections (approximately 30,000 acres). This lease is estimated by McDaniel to contain approximately 339 million barrels of proved and probable reserves and 150 million barrels of best estimate contingent resources for our 35 percent working interest share. See "Appendix A - Reserves Data and Other Oil and Gas Information."





OPTI’s capital program for 2011 includes funds allocated for additional core hole drilling to further delineate our nearer-term development lease at Long Lake. The 2010/2011 winter program is expected to include the drilling of 25 wells and a four dimensional seismic program in the Long Lake 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.





Future Expansion Developments





OPTI believes thatthe landswill support approximately 430,000 bbl/d of bitumenproduction (150,000 bbl/d net to OPTI) from all lease areas, including the Long Lake Project. Based on reserve and resource estimates, OPTI believes there is potential for approximately 144,000 bbl/d of SAGD bitumen production at Kinosis. In addition, we believe we have sufficient resources to support developments of approximately 144,000 bbl/d of SAGD bitumen production at Leismer, and approximately 72,000 bbl/d of SAGD bitumen production at Cottonwood. From inception, the JV Participants have spent approximately $985million on the expansion activities beyond the Project.





Kinosis Lease





The Kinosis lease covers an area of 64 sections (approximately 41,000 acres) and is located directly south of the Project. This lease is estimated by McDaniel to contain approximately 390 million barrels of proved and probable reserves and 152 million barrels of best estimate contingent resources for our 35 percent working interest share. See "Appendix A - Reserves Data and Other Oil and Gas Information."





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At Kinosis, over 300 delineation wells have been drilled and approximately 125 square km of three-dimensional ("3D") seismic has been gathered. We plan to drill 100 delineation wells at Kinosis during the 2010/2011 winter season.





The oil sands lease that governs the Kinosis area is within its primary terms expiring in 2017 or 2018 unless otherwise continued. OPTI has spent approximately $228 million on expansion activities for development at Kinosis.





In late 2006, a regulatory application for Kinosis (also called the Long Lake South project) was filed, comprising two SAGD stages totalling 140,000 bbl/d of bitumen production in addition to the Project. The regulatory approval for this project was obtained in February 2009. Regulatory approval was previously obtained for a second Upgrader.





OPTI and Nexen continue to evaluate developing SAGD projects in approximately 40,000 bbl/d stages at Kinosis, the next development. A second Upgrader could be built once sufficient bitumen rates from the Kinosis area have been reached and economic conditions support the development of upgrading. In 2011, the JV participants plan to advance detailed engineering and complete delineation work on the SAGD development at Kinosis. The sanctioning of Kinosis by OPTI will depend on multiple factors including improvement in our financial position; operational performance at Long Lake; the cost estimate to develop Kinosis; the commodity price environment; and supportive financial markets.





Leismer Lease





The Leismer lease is located approximately 64 km southwest of the Project. This lease is comprised of 134 sections of landand is 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 approximately 52 square km of 3D seismic gathered. In order to concentrate capital expenditures in 2011 on the Project and nearer-term development projects in Kinosis, nodelineation wells or seismic are planned on the Leismer lease during the 2010/2011 winter season.





OPTI has spent approximately $76 million on expansion activities for development at Leismer.





Cottonwood Lease





The Cottonwood lease is located approximately 32 km southwest of the Project. This lease is comprised of 141 sections of land and is estimated by McDaniel to contain 207 million barrels of best estimate contingent resources and 335 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 2011 on the Long Lake Project and nearer-term development projects at Kinosis, nodelineation wells or seismic are planned on the Cottonwood lease during the 2010/2011 winter season.





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OPTI has spent approximately $41 million on expansion activities for development at Cottonwood.





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.





Development of Kinosis 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 Expansion Developments COJO Agreements. The Technology Agreement governs these projects as well.





While the MOU was superseded by the COJO Agreement, the Future Expansion Developments COJO Agreements, and the Technology Agreement with respect to the Project and certain additional lands, the MOU continues to otherwise govern the JV relationship between OPTI and Nexen.





The MOU provides for an Area of Mutual Interest (see glossary), 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 JV 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.





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Management Committee





Pursuant to the COJO Agreement, we have established a management committee ("Management Committee") composed of representatives of each JV Participant. The Management Committee exercises supervision and control of the operator and all matters relating to the joint operation of the Project, excluding matters specifically designated to be within the exclusive jurisdiction of the operator, any unresolved audit claims, and the interpretation of the COJO Agreement. Each JV Participant has appointed one representative and one alternate representative to serve on the Management Committee. If there are only two parties to the COJO Agreement, all decisions of the Management Committee are required to be unanimous.





If there are more than two parties, different Management Committee approval thresholds are specified. In such an event, a matter being voted on by the Management Committee will generally be approved only upon the affirmative vote of two or more JV Participants having a combined Project interest of more than 75 percent. However, there are certain exceptions to these voting requirements and, among other things, the COJO Agreement provides that the following matters will be approved by the Management Committee only upon the unanimous approval of all JV Participants with regards to:





•
the approval of any design or scope change to a construction plan such that the facility or joint operation in question is or will be substantially different than what was provided for previously;





•
the processing at the Long Lake Upgrader of production from lands other than the Project;





•
any matter which significantly affects the integration of the Long Lake Upgrader and the SAGD Operation;





•
any enlargement work plan and budget, and any amendments thereto; or





•
the termination of the COJO Agreement.





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 the Project and all future expansion developments 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,  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.





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Contracts, Agreements and Commitments





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





Force Majeure





If 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 the last occurring operational date (the "Last Occurring Operational Date") 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. The Last Occurring Operational Date has not yet occurred;





•
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;





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•
treat the non-payment of an amount as an assignment to the non-defaulting JV Participant of the proceeds of the sale of the defaulting JV Participant’s share of production that has been produced from the Project or has been processed at the Long Lake Upgrader; and





•
if the default occurs after the Last Occurring Operational Date is achieved, the JV Participant exercising the lien may sell the defaulting 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.





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Nomination Process





The Agreement allows either party to elect to reduce its participation in the project in question. If a party reduces its participation, and the other party elects to purchase this reduced participation, then the purchasing party must pay an amount equal to the sunk costs related to the reduced participation. If the other party elects not to purchase the reduced participation, then the project will stop.





The Future Expansion Developments COJO Agreements





As indicated above, the Future Expansion Developments COJO Agreements (see glossary) are in substantially the same form as the COJO Agreement. There are only a few material differences, namely:





•
The Future Expansion Developments 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 Expansion Development COJO Agreement has the right, until the project sanction date, 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 Expansion Development 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 (see glossary) 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 65 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.





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The Purchase and Sale Agreement





On December 16, 2008, OPTI and Nexen entered into a Purchase and Sale Agreement wherein OPTI agreed to sell a 15 percent working interest in the Long Lake Project, all future expansion reserves and resources, and future expansion developments to Nexen for $735 million. Under the terms of the agreement, Nexen also assumed operatorship of the Long Lake Upgrader and all future expansions. The transaction closed January 26, 2009. Effective January 1, 2009, OPTI has a 35 percent working interest in all JV assets, including the Project, all future expansion reserves and resources, and future expansion developments. Nexen has a 65 percent working interest in all JV assets and is now the operator of both the SAGD and upgrader facilities for the Project and future expansions.





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 up to 70,000 bbl/d of SAGD bitumen production at the Project and up to 140,000 bbl/d of SAGD production at Kinosis. We also have regulatory approval for upgrading facilities for up to 70,000 bbl/d of SAGD production at the Project, and for a second 70,000 bbl/d Upgrader.





The Project received approval from the ERCB and Alberta Environment ("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 Kinosis was filed in late 2006. Regulatory approval for Kinosis 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 the Project 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 the JV Participants strive for 100 percent safe performance in all joint-venture operations and activities for 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 and federal standards for ground level concentrations in all modelled communities in the region; however, environmental regulations are becoming increasingly stringent, and we cannot be certain that the Project will meet future standards that might be imposed.





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





Greenhouse Gases and Industrial Air Pollutants





Canada is a signatory to the United Nations Framework Convention on Climate Change (the "Convention") and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other 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 outlined 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 and 2011 or facilities existing prior to 2004 which between 2004 and 2011 have had a major expansion resulting in an increase of 25 percent or more in physical capacity or which undergo a significant change to processes will be exempt from the 2010 emissions intensity reduction target of 18 percent, but will have to report their emissions each year and after their third year of operation will be required to reduce their emissions intensity by 2 percent annually from a baseline emissions standard, which is to be determined by reference to a sector-specific cleaner-fuel standard. For oil sands facilities, it was contemplated that new draft regulations which were scheduled to be released in early 2008 would set 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") was 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, 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.





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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 Federal 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 are also be subject to the Alberta Climate Change and Emissions Management Actand 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 10).





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, 2011. The renewal program is expected to be placed for a further one year term.





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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, Kinosis, 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 lease.





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 (or lean zones). 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 (see glossary). Steam contact with lean zones can result in cross-flow between steam chambers, heat losses and temporarily suppressed well performance. Once the lean zones are heated and the water is displaced, bitumen production and SOR typically improve. The magnitude of the steam losses into each lean zone is somewhat proportional to the pressure difference between the steam chamber and the lean zone.





Over the Long Lake and Kinosis 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.





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McDaniel has prepared a report dated March 8, 2011, evaluating the bitumen reserves and synthetic oil reserves of the Long Lake and Kinosis leases effective as of December 31, 2010 (the "McDaniel Report"). Reserves have been recognized at Long Lake in the Project area as proved, probable and possible, and in the Kinosis area as probable and possible. The recognition of probable and possible reserves in the Kinosis area reflects the greater certainty of their development than in prior years and the advancement of the regulatory approval process.





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 at Long Lake. Most of the raw bitumen will be upgraded and sold as PSCTM and butane, and is shown as synthetic crude oil or butane reserves. Bitumen will be sold during periods of Upgrader downtime, and is shown as bitumen reserves.





The evaluation of reserves in the Kinosis area includes two 40,000 bbl/d SAGD Kinosis developments, as further SAGD developments and potential future upgrader developments are not within the timeframe to allow inclusion in the evaluation. As such, the resources are shown as bitumen reserves only. This is a change from 2009 when the reserves were evaluated on an integrated basis. Upon formal sanctioning of Kinosis by OPTI and its JV partner, some of the probable reserves could be categorized as proven 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 Reserve Volumes
 
 As at December 31, 2010
 
 (Volumes in millions of barrels)


Raw Bitumen


Sales VolumesPSCTM


Bitumen


ButaneProvedLong Lake(1)


195



150



7



3Proved plus probableLong Lake (2)


339



262



11



5Kinosis (2)


390



-



390



-Total proved plus probable


729



262



401



5Proved plus probable plus possibleLong Lake (3)


404



314



11



6Kinosis(3)


442



-



442



-Total proved plus probable plus possible(3)


846



314



453



6




Notes to reserve table:


(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 proved 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 proved 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 proved plus probable plus possible reserves.




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Resources Data





In addition to estimating the reserves, McDaniel has estimated bitumen resources associated with the Long Lake, Kinosis, Leismer and Cottonwood leases. A summary of our 35 percent working interest in the additional resource estimates is shown below:





Summary of Bitumen Resources (1)


December 31, 2009


(MMbbl)





Raw BitumenContingent Resources(2)


Prospective Resources(3)Long Lake (4)


150



-Kinosis (4)


152



-Leismer (4)


591



-Cottonwood (5)


207



335Total


1,100



335




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.





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DESCRIPTION OF CAPITAL STRUCTURE





Description of Share Capital





We were reorganized and continued under the Canada Business Corporations Act on May 30, 2002 and our share capital was reorganized under the Canada Business Corporations Act on April 14, 2004 pursuant to which all of our outstanding shares became Common Shares, such that the Common Shares were the only issued and outstanding shares in our capital. Under our current articles, we are authorized to issue an unlimited number of Common Shares without nominal or par value, and an unlimited number of preferred shares, issuable in a series ("Preferred Shares"), of which the first authorized series of Preferred Shares is an unlimited number of Series A Shares, the second authorized series of Preferred Shares is an unlimited number of Series B Shares (Series B Shares which together with Series A Shares shall be 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.





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. There are no Voting Convertible Preferred Shares currently outstanding.





At December 31, 2010, OPTI had 281,749,526 Common Shares and stock options to purchase 3,471,500 Common Shares outstanding. The stock options have a weighted average exercise price of $3.63 per share.





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





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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





Canadian Dollar Denominated Debt





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





The $190 million Credit Facility matures on December 15, 2011. Amounts borrowed through the Credit Facility bear interest at a floating rate based on bankers’ acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at December 31, 2010, the Credit Facility was undrawn. In early January 2011, OPTI borrowed $90 million under the Credit Facility.





Our ability to make further borrowings under the Credit Facility is conditional upon our ability to satisfy certain conditions precedent as set forth in the Credit Facility agreement. These conditions include confirmations that the representations and warranties in our loan documents are correct on the date of the new borrowing, that no default or event of default has occurred and that there has not been a change or development that would constitute a material adverse effect on our ability to perform our obligations under the loan documents. Certain payment related defaults on our Senior Notes (see glossary) and our joint venture agreements with Nexen are considered events of default under our Credit Facility. More generally, the determination of events that would constitute a material adverse effect is dependent under the facts in question. There may be individual or collective events whereby we determine that such an event has occurred and we are unable to make new borrowings on the Credit Facility. In addition, we have a total debt-to-capitalization covenant that requires us not to exceed a ratio of 75 percent, as calculated on a quarterly basis. This total debt-to-capitalization ratio was increased from 70 to 75 percent in connection with the August 2010 financings. This 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. Our book value of equity is adjusted to exclude the $369 million increase to our equity deficit as a result of the asset impairment associated with the working interest sale to Nexen and to exclude the $85 million increase to the January 1, 2009 opening deficit as a result of new accounting pronouncements effective on that date.





The Credit Facility is collateralized by a first priority security interest on substantially all of OPTI’s existing and future property and is effectively senior in priority in respect of this collateral to the 9% First Lien Notes, the 9.75% First Lien Notes, the 8.25% Senior Secured Notes and the 7.875% Senior Secured Notes.





U.S. Dollar Denominated Debt





OPTI currently has four note issuances. Issuances are discussed in order of security priority over collateral.





US$525 million 9% First Lien Notes





OPTI issued US$425 million of 9% First Lien Notes on November 20, 2009. On August 20, 2010, OPTI issued an additional US$100 million of 9% First Lien Notes under this existing series with an original issue discount of 0.5 percent for net proceeds of approximately US$97 million after the original issue discount and financing costs. Semi-annual interest payments are due June 15 and December 15 of each year with a final interest payment due on December 15, 2012. At any time prior to June 15, 2012, OPTI may redeem all or a part of the 9% First Lien Notes at a redemption price of 102 percent of the principal amount plus accrued and unpaid interest. This redemption price declines over time and these notes can be redeemed at par subsequent to June 15, 2012. The 9% First Lien 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. The 9% First Lien Notes are subordinated in respect of this collateral in favour of the Credit Facility lenders and certain hedge counterparties of the Company, but are senior in priority to the 9.75% First Lien Notes and are effectively senior in priority to the 7.785% and 8.25% Senior Secured Notes.





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US$300 million 9.75% First Lien Notes





On August 20, 2010, OPTI issued US$300 million of 9.75% First Lien Notes with an original issue discount of 3.5 percent for net proceeds of approximately US$282 million after the original issue discount and financing costs and which bear interest at a fixed 9.75 percent. Semi-annual interest payments are due February 15 and August 15 of each year with final payment due August 15, 2013. At any time prior to August 15, 2011, OPTI may redeem all or a part of these notes at a redemption price equal to between 106 percent and 102 percent of the principal amount, plus accrued and unpaid interest. After August 15, 2011 and prior to February 15, 2013, OPTI may redeem all or a part of these notes at a redemption price of 102 percent of the principal amount plus accrued and unpaid interest. After February 15, 2013, OPTI may redeem all or a part of these notes at par plus accrued and unpaid interest. Also, these notes have a special change of control provision of 105 percent of the principal amount. In connection with these notes, OPTI funded approximately US$87 million to an interest escrow account to fund interest payments until these notes mature on August 15, 2013. These notes are collateralized by a first priority security interest on substantially all of OPTI’s existing and future property and are effectively senior in priority to the 7.875% and 8.25% Senior Secured Notes, but are subordinate in priority to the Credit Facility lenders, certain hedge counterparties and the 9% First Lien Notes.





US$1 billion 8.25% Senior Secured Notes





On December 15, 2006, we issued US$1 billion principal amount of 8.25% Senior Secured Notes which bear interest at 8.25 percent per annum. Semi-annual interest payments are due June 15 and December 15 of each year, with the final interest payment due on December 15, 2014. At any time prior to December 15, 2012, OPTI may redeem all or a part of these notes at a redemption price equal to between 104 and 102 percent of the principal amount plus accrued and unpaid interest. This redemption price declines over time and these notes can be redeemed at par subsequent to December 15, 2012. 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 substantially all of our assets, rank pari passu in respect of the collateral with the 7.875% Senior Secured Notes, and are subordinated in respect of this collateral to the Credit Facility, certain hedge counterparties, the 9% First Lien Notes and the 9.75% First Lien Notes.





We have total semi-annual interest payments under our Senior Notes of US$109 million ($218 million per annum). This includes semi-annual interest payments of US$24 million until the maturities of the 9% First Lien Notes in 2012, the semi-annual interest payments of US$15 million until the maturities of the 9.75% First Lien Notes in 2013, and semi-annual interest payments of US$71 million until maturity of the 8.25% Senior Secured Notes and 7.875% Senior Secured Notes in 2014.





- 39 -





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 2010 reserve report, we have sufficient capacity under this test to incur additional debt beyond our existing Credit Facility and existing First Lien Notes. Other leverage considerations, such as debt restrictions under the First Lien Notes and the Credit Facility, are expected to be more constraining than this limitation.





US$750 million 7.875% Senior Secured Notes





On July 5, 2007, we issued US$750 million principal amount of 7.875% Senior Secured Notes which bear interest at 7.875 percent per annum. The terms and conditions associated with the 7.875% Senior Secured Notes, with the exception of interest payable, are substantially the same as those of the 8.25% Senior Secured Notes described above. The notes are secured by a second ranking charge over substantiallyall of our assets, rank pari passu in respect of the collateral with the 8.25% Senior Secured Notes, and are subordinated in respect of this collateral to the Credit Facility, certain hedge counterparties, the 9% First Lien Notes and the 9.75% First Lien Notes.





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, 2010, we had US$420 million of foreign exchange hedging instruments 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 instruments is approximately CDN$1.22 to US$1.00. Changes in the exchange rate between Canadian and U.S. dollars change the value of these instruments. At present, these foreign exchange hedging instruments settle in September 2011. With respect to our U.S. dollar-denominated debt, these instruments provide protection against a decline in the value of the Canadian dollar below CDN$1.22 to US$1.00 on a portion of our debt. The foreign exchange hedging instruments at December 31, 2010 provide a net liability of $89 million based upon exchanges rates at such date. The net value of our foreign exchange hedging instruments is approximately equivalent to the present value of the difference between the settlement amounts of the foreign exchange hedging instruments as measured in Canadian dollars. The counterparties to the foreign exchange hedging instruments are major Canadian and international banks. Our exposure to non-payment from any single institution at December 31, 2010 is approximately 37 percent of the value of these instruments.





Prior to the settlement of the foreign exchange hedging instruments in 2011, OPTI may agree to extend some or all of them to a later settlement date. In the event that any instrument is extended, there would be no cash settlement for that instrument until the new settlement date of the instrument. If we are unable or choose not to extend the term of any or all of these instruments, the net benefit or cost to us of each instrument at the time of its current settlement date in 2011 would be approximately equivalent to the net of the payments made and received by us under each instrument 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 exchange hedging instruments would change by approximately $4 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 2011.





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CREDIT RATINGS





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




S&P
Moody'sOPTI Corporate Rating
CCC-
Caa3Revolving Credit Facility
CCC+
B29% Notes - US$525 million
CCC+
B39.75% Notes - US$300 million
CCC+
Caa18.25% Notes - US$1,000 million
CCC
Ca7.875% Notes - US$750 million
CCC
Ca




On December 14, 2010, S&P lowered OPTI’s corporate rating from CCC+ to CCC-, lowered the rating on the revolving credit facility from B to CCC+, lowered the ratings on the US$525 million and US$300 million First-Lien Notes from B to CCC+, and lowered the ratings on the US$1,000 million and US$750 million Secured Notes from B- to CCC. S&P has also downgraded their ratings outlook from stable to negative.





On February 2, 2011, Moody’s lowered OPTI’s corporate rating from Caa2 to Caa3, lowered the rating on the revolving Credit Facility from B1 to B2, lowered the ratings on the US$525 million notes from B2 to B3, lowered the ratings on the US$300 million First-Lien Notes from B3 to Caa1, and lowered the ratings on the US$1,000 million and US$750 million Secured Notes from Caa3 to Ca. Moody’s negative rating outlook remains unchanged.





S&P Rating Definitions – Investment grade under Standard & Poor’s long-term rating scale would be BBB- and higher. Obligations rated below BBB- are judged as speculative grade where the issuer currently has the ability to repay but faces significant uncertainties, such as business or financial circumstances that could affect credit risk. The CCC rating is judged as speculative grade and are currently vulnerable and dependant on favourable business, financial and economic conditions to meet financial commitments. Ratings from AA to CCC may be modified by the addition of (+) plus or (-) minus sign to show relative standing within the major rating categories.





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 be speculative and are subject to high credit risk, obligations rated Caa are judged to be of poor standing and are subject to very high credit risk, and obligations rated Ca are judged to be highly speculative and are likely in, or very near, default, with some prospect of recovery of principle and interest. 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.





A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the rating organization.





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MARKET FOR SECURITIES





Our Common Shares are listed for trading on the Toronto Stock Exchange under the symbol "OPC." The following table sets for the high, low and closing trading prices and the volume of Common Shares traded on the Toronto Stock Exchange for each month of 2010.





Month

High


Low


Closing


VolumeJanuary

$
2.21


$
1.81


$
1.93



11,979,071February

$
2.04


$
1.71


$
1.89



9,209,362March

$
2.17


$
1.83


$
2.06



11,731,650April

$
2.47


$
2.09


$
2.29



26,642,696May

$
2.37


$
1.77


$
1.96



24,593,879June

$
1.95


$
1.65


$
1.79



11,623,712July

$
1.98


$
1.61


$
1.65



12,523,980August

$
1.69


$
0.97


$
1.03



37,417,505September

$
1.04


$
0.83


$
0.83



22,071,649October

$
0.90


$
0.68


$
0.70



19,880,175November

$
0.95


$
0.63


$
0.72



83,087,234December

$
0.78


$
0.48


$
0.67



89,908,776





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.





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DIRECTORS AND OFFICERS





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





Directors




Name andResidence

Present Positionand Office

Position Held Since (1) (2)

Principal OccupationDirectorsJames M. Stanford (4)

Alberta, Canada

Chairman and Director

May 30, 2002

President of Stanford Resource Management Inc., a financial management company; and formerly President, Chief Executive Officer and Director of Petro-Canada., an integrated oil and gas companyIan W. Delaney (3) (4)

Ontario, Canada

Director

November 16, 2005

Chairman and Chief Executive Officer, Sherritt International Corporation, a diversified resource companyCharles L. Dunlap (4)

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., a refining companyDavid Halford (3)

Alberta, Canada

Director

July 1, 2010

Executive Vice President, Finance and Chief Financial Officer of ENMAX Corporation, an electricity generation and distribution company; formerly Chief Financial Officer of OPTI Canada; and previously Chief Financial Officer of BA Energy, an oil sands companyEdythe (Dee) A. Marcoux (3)

British Columbia, Canada

Director

July 16, 2008

Retired oil executive; formerly a consultant to Ensyn Group In., a heavy oil upgrading technology companyChristopher P. Slubicki (5)

Alberta, Canada

President, CEO and Director

February 1, 2007

President and Chief Executive Officer, OPTI





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.





- 43 -





Officers





Name andResidence

Present Positionand Office

Position Held Since (1)

Principal OccupationOfficersChris Slubicki

Alberta, Canada

President and CEO

April 27, 2009

President and Chief Executive Officer, OPTITravis Beatty

Alberta, Canada

Vice President, Finance and Chief Financial Officer

March 1, 2009

Vice President, Finance and Chief Financial OfficerJoe Bradford

Alberta, Canada

Vice President, Legal and Administration and Corporate Secretary

October 14, 2008

Vice President, Legal & Administration, and Corporate SecretaryAlan 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, 2010, our directors and officers, as a group, beneficially own, or control or direct, 566,219 Common Shares or 0.20 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 has served 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 Chief Executive Officer, 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 Chief Executive Officer 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.





- 44 -





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.





David Halford





Mr. Halford is the Executive Vice President, Finance and Chief Financial Officer of ENMAX Corporation ("ENMAX"). He is responsible for all financial policy, planning and reporting, risk management, corporate finance, tax and treasury functions of ENMAX and its subsidiaries.





Prior to joining ENMAX, Mr. Halford held Chief Financial Officer roles at OPTI, BA Energy and Irving Oil. He also held a variety of senior level corporate finance and accounting roles, including partner in the corporate financial group of Deloitte and Touche, LLP.





Mr. Halford is a Chartered Accountant and holds a Bachelor of Arts degree from the University of Western Ontario.





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 effective 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.





- 45 -





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 Corporation 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.





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 & Administration and Corporate Secretary 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.





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.





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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. Delaney (Chairman), Halford and Ms. Marcoux. All three members are financially literate and two of the three are independent for the purposes of National Instrument 52-110 "Audit Committees." Mr. Halford was an employee at OPTI within the last three years and is therefore not deemed to be independent.





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 2010 and 2009 in thousands of dollars:





2010


2009Audit fees

$
382


$
344Audit-related fees


68



266Tax fees


31



50TOTAL

$
481


$
660





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 2010 is primarily attributed to preparation for the conversion to International Financial Reporting Standards. This was offset by a decrease due to the Dodd-Frank Wall Street Reform and Consumer Protection Act, signed into law on July 21, 2010, exempting non-accelerated filers from internal control audit requirements for fiscal years ended on or after June 15, 2010. Audit-related fees are exclusively related to compulsory services required to support financing activities, as well as translation of public documents. Tax fees were primarily related to the completion of our corporate tax returns.





As per the Audit Committee charter, all permissible categories of non-audit services require pre-approval from the Audit Committee.





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,





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•
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 theCanada 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 Expansions





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.





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;





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•
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, including high water saturation zones or lean zones;





•
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.





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.





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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 process large volumes of hydrocarbons at high pressure and at high temperatures in equipment with fine tolerances and 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 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 includes 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 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 $US10 million deductible ($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.





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.





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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 the Long Lake Project and future expansion developments. 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 expansion developments, we will forego our working interest in such expansions and the associated lands. If we fail to pay amounts when they are due or if we are subject to an event of insolvency, we may be found in default of our joint venture agreement. In any event, we may recover only those costs spent to date, which may be less than the fair market value of the foregone working interest.





Future expansion developments may not proceed on our expected timeline or at all.





We have announced a multistage expansion plan, including plans to increase total bitumen production by 360,000 bbl/d in our JV with Nexen (126,000 bbl/d net to OPTI). In order to proceed with such development, we will need to establish that the proposed development will satisfy our required conditions for development. Kinosis sanctioning by OPTI will be dependent on multiple factors including improvement in our financial position; operational performance at the Project; the cost estimate to develop Kinosis; the commodity price environment; and supportive financial markets. 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 Kinosis and future expansion developments.





We may not be able to efficiently manage or finance future expansion developments, 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 by 360,000 bbl/d in our JV with Nexen (126,000 bbl/d net to OPTI). In order to proceed with such development, we will require additional financing in order to fund a portion of our share of costs associated with such expansion. Our participation in any additional expansion developments related to the JV will be subject to substantially all of the same risks as those set forth in this AIF for the Project in general.





Oil sands development requires significant investment prior to any cash being returned to the business in the form of operating cash flow. Potential volatility in the financial sector and in the overall economy means that such capital may be restricted in terms of size, expensive in historical terms, or not available at all. The sanctioning of all future expansion developments has been deferred to 2012 and beyond. Participation in the expansion developments 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."





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If we are unable or choose not to participate in part or at all in future expansions, we will forego our working interest in such expansions 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 partner 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 Convention 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 Emissionsreleased 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.





We are also be subject to the Alberta Climate Change and Emissions Management Actand 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.





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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.





The emission reductions required under Alberta’s legislation and which may be required under future federal legislation 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 they could be included in the future regulatory approvals, 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 renewed 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.





Alberta’s Land-Use Framework, which is to be implemented under the Alberta Land Stewardship Act("ALSA"), sets out the Government of Alberta’s approach to managing Alberta’s land and natural resources to achieve long-term economic, environmental and social goals. ALSA contemplates the creation of regional plans which could amend or extinguish previously issued regulatory permits, licenses, approvals and authorizations in order to achieve or maintain an objective or policy resulting from the implementation of a regional plan The Government of Alberta is expected to develop a regional plan for each of seven regions in the province and has identified the Lower Athabasca Regional Plan ("LARP") as a priority. The LARP is intended to identify and set resource and environmental management outcomes for air, land, water and biodiversity, and guide future resource decisions while considering social and economic impacts. In August 2010, the Lower Athabasca Regional Advisory Council provided its vision document to the Government of Alberta regarding the LARP.





It is possible that the LARP may negatively impact our access to our properties or out ability to conduct operations on our properties or limit or prohibit development due to environmental limits and thresholds.





Any future expansions beyond the Project will be subject to the same issues applicable to the Project as described above.





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 GHG emissions of purchased fuel and which may negatively affect marketing of our products, or require the purchase of emissions or off-set credits in order to affect sales in such jurisdictions.





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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.





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% First Lien Notes is due in December 2012, the 9.75% First Lien Notes in August 2013, and the remainder of our Senior Notes in December 2014.





Global capital markets have recently 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 we are not able to meet our debt covenants, we may need to repay our debt or seek creditor protection.





Our Credit Facility contains certain covenants that serve to limit the amount of debt we are permitted to incur, including a requirement to remain solvent. 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. Alternatively, we may have to make an application for creditor protection. If such an application is made, it may result in a corporate restructuring that could detrimentally impact the value of OPTI’s common shares. At December 31, 2010, OPTI was in full compliance with its debt covenants relating to the Credit Facility. See "Description of Debt Capital."





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





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 Kinosis by OPTI, 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).





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 expansion developments of the Project. Nexen has the right, in certain circumstances, to acquire some or all of our interest in the expansion developments if we fail to meet all or some of our future expansion 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 Expansion Developments 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. See "Description of Material Indebtedness." 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. Fluctuations in exchange rates may significantly increase the amount of debt recorded in our financial statements and negatively impact our reported earnings.





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Risks Relating to Reserves and Resources





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





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





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





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





No assurance can be provided as to the quality of bitumen produced from the Long Lake lease. 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 lease. Although we conducted pilot tests on the Long Lake lease reservoir and now have limited data from ramp-up of the well pairs of the Project, 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. Should the actual long term SOR 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.





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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.





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. The variability in commodity prices may 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.





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. 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 2010. 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;





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•
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.





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.





Volatility in the global financial market may impact our ability to obtain equity, debt or bank financing on terms commercially reasonable to us, if at all. This volatility, 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. Additionally, this volatility 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.





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





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





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





We will be subject to foreign currency exchange fluctuation exposure.





Crude oil prices are generally based on a U.S. dollar market price, while certain of our operating and capital costs will be primarily in Canadian dollars. Fluctuations in exchange rates between the U.S. and Canadian dollar will therefore give rise to foreign currency exchange exposure. A material increase in the value of the Canadian dollar relative to the U.S. dollar may negatively affect our revenue by decreasing the Canadian dollars we receive for a given U.S. dollar price. 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, future expansions or the U.S. dollar denominated debt by entering into currency hedges, but those hedges cannot fully mitigate our risks. Furthermore, the costs of the hedges could be substantial if foreign exchange rates change unfavourably.





- 58 -





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.





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





The nature of our operations will result in exposure to fluctuations in commodity prices. We may use financial instruments and may also use physical delivery contracts to hedge our exposure to these risks. If we engage in hedging, we will be exposed to credit-related losses in the event of non-performance by counterparties to the financial instruments. Additionally, if product prices increase above those levels specified in any future hedging agreements, we could lose the cost of floors or ceilings or a fixed price could prevent us from receiving the full benefit of commodity price increases. Any future hedging arrangements could cause us to suffer financial loss if we are unable to maintain 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.





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. Based on our evaluation to-date and existing IFRS, the areas that have the potential for the most significant financial impact to us are the methodology for impairment testing, the absence of a comparable standard to full-cost accounting, treatment of transaction costs attributable to the issuance of our long-term debt, the accounting for decommissioning obligations and the treatment of flow-through shares. Under IFRS, we may have an asset impairment loss. 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. See the section entitled "New Accounting Pronouncements" in our Management’s Discussion and Analysis for the period ended December 31, 2010 incorporated by reference to this AIF.





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Risks Relating to Technology





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





There can be no assurance that the Long Lake Upgrader will achieve the same performance results as the OrCrudeTM demonstration plant owned and operated by us from 2001 to 2003, nor that the Long Lake Upgrader will have the same level of success in upgrading the bitumen production from the Long Lake lease 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 developments.





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





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





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





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





- 60 -





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 expansion developments. Such default by Nexen may adversely affect the continuation of the Project or future expansions, the construction or operations of future expansion developments, or other facets of the Project or future expansions, any of which may adversely affect us. In addition, subject to certain conditions, Nexen may sell its interest in the JV and our new partner may not have the resources or experience that Nexen has.





The Project is being undertaken jointly by the JV Participants pursuant to the 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 expansion developments and/or decide to not engage in any future activities with us.





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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 water 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 or expansion developments requires regulatory 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 or upon renewal, could result in delays or restructuring of the Project and increased costs, all of which could have a material adverse effect on us. The Project is also subject to periodic inspections by regulatory authorities to ensure our compliance with the conditions of regulatory approvals. Negative inspection results may lead to the imposition of fines or penalties or the suspension or rescission of the Project’s regulatory approvals.





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





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





•
pipelines for the transportation of feedstocks to the Long Lake Upgrader and petroleum products to be sold from the Long Lake Upgrader;





•
pipelines for the transportation of 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.





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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 expansions.





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 expansions.There is also the risk that the provincial government could impose additional emission or emission-intensity reduction requirements, or that the federal and/or provincial governments could pass legislation which would tax such emissions.





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





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





We are one of only six Upgraders currently on stream in Alberta. 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.





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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.





Lands owned by the JV Participants are subject to Aboriginal claims which could have a significant adverse effect on the Project and future expansion developments.





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 OPTI is a JV Participant 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 future expansion developments.





Risks Relating to the Strategic Alternatives Review Undertaken by OPTI





We are engaged in a review of strategic alternatives and there can be no assurance that any transaction will occur, or if a transaction is undertaken, as to its terms or timing.





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. As we announced in early 2011, SAGD production continues to be below expectations. Our strategic alternatives review has been underway since November 2009. Lower than expected bitumen production over the last seven months has negatively impacted our liquidity and has made it more difficult to achieve a transaction under our review. As a result of this performance, our financial commitments and our limited financial resources, OPTI has expanded its strategic alternatives to include seeking advice on capital structure adjustments to address its overall leverage position. There can be no assurance that any transaction will occur or, if a transaction is undertaken, as to its terms or timing. The Company remains highly leveraged and a capital structure adjustment of the balance sheet may be required in order for the company to meet its obligations and to be able to participate in future development. If a capital structure adjustment is pursued, there is a risk that it could be executed on terms that could be highly detrimental to existing equity holders.





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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 Expansion Developments COJO Agreements between OPTI and Nexen as more particularly described under the heading "Material Agreements Related to the Joint Venture"; and





4.
the Technology Agreements among OPTI, ORMAT and Nexen as more particularly described under the heading "General Development of the Business."





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





ADDITIONAL INFORMATION





Additional information relating to 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. For additional copies of this AIF, please contact:





Investor Relations


OPTI Canada Inc.


1600, 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, 2011;





"AMI License" means the licensed rights relating to the land within the Area of Mutual Interest;





"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 Expansion Developments";





"Common Shares" means common shares of OPTI;





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





"Cottonwood lease" means our lands in the Cottonwood area;





"Credit Facility" means OPTI’s $190 million Senior Secured Revolving Credit Facility;





"EDGAR" means the Electronic Data Gathering, Analysis, and Retrieval system, which perform automated collection, validation, indexing, acceptance and forwarding of submissions by companies and others who are required by law to file forms with the U.S. Securities and Exchange Commission;





"ERCB" means the Energy Resources Conservation Board, an independent, quasi-judicial agency of the Government of Alberta that regulates the safe, responsible, and efficient development of Alberta's energy resources: oil, natural gas, oil sands, coal, and pipelines. Prior to January 1, 2008, the ERCB and the Alberta Utilities Commission were under one regulatory body called the Alberta Energy & Utilities Board;





"ESPs" means electric submersible pumps;





"Future Expansion Developments 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 Expansion Developments COJO Agreements";





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"GAAP" or "Canadian GAAP" means Canadian Generally Accepted Accounting Principles;





"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 OrCrudeTM Upgrader" means an upgrader which uses the OrCrudeTM Process combined with additional third party technology to upgrade bitumen and heavy oil to produce PSCTM and syngas, as further described under the heading "Long Lake Upgrader –  Integrated OrCrudeTM Upgrader";





"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;





"Kinosis" means our next expansion development in the Kinosis area and the related lands;





"Kinosis lease" means our lands in the Kinosis area;





"Last Occurring Operational Date" means:





(i)
the first date upon which the SAGD production volumes produced during the previous seven consecutive days exceeds an average of 37,000 barrels per day; or





(ii)
the first date upon which the production of upgraded products from SAGD production during the previous seven consecutive days exceeds an average of 30,000 barrels per day;





whichever date occurs last;





"Leismer lease" means our lands in the Leismer area;





"Long Lake lease" includes the Project land and our interest in the Long Lake areas;





"Long Lake Project" or the "Project" means the Long Lake SAGD Operation, the Long Lake Upgrader and the related lands. The Project consists of approximately 72,000 bbl/d of expected SAGD bitumen production capacity integrated with an uprading facility expected to produce58,500 bbl/d of products, primarily 39° API premium sweet crude;





"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 Expansion Developments – SAGD Commercial Project";





"Long Lake Upgrader" or "Upgrader" means the Integrated OrCrudeTM 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 Expansion Developments - Long Lake Upgrader";





"MM$" means millions of dollars





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





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





"McDaniel Report" means the report prepared by McDaniel, dated March 8, 2011, evaluating the bitumen reserves and synthetic oil reserves of the Long Lake and Kinosis leases and the resources of all of our lease areas, as of December 31, 2010;





"Mbbl" means thousands of barrels;





"MMbbl" means millions of barrels;





"mmbtu" means millions of British thermal units;





"MOU" means memorandum of understanding between the JV Participants, dated October 29, 2001;





"Nexen" means Nexen Inc.;





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


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





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





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





"PSH" means, blended bitumen which we call Premium Synthetic Heavy;





"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% First Lien Notes, the 9.75% First Lien Notes, the 8.25% Senior Secured Notes and the 7.875% Senior Secured Notes as described under the heading "Description of Debt Capital";





"SEDAR" means the System for Electronic Document Analysis and Retrieval, operated by the Canadian Securities Administrators, a mandatory document filing and retrieval system for Canadian public companies and investment funds;





"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;





- 68 -





"SOR" means steam-to-oil ratio;





"syngas" means synthesis fuel gas produced through gasification;





"Technology Agreement" means the Technology Licence for Upgrading Technology Agreement between the JV Participants; and





"WTI" means West Texas Intermediate crude oil.





- 69 -





APPENDIX A





RESERVES DATA AND OTHER OIL AND GAS INFORMATION





The McDaniel Report dated March 8, 2011, summarized below, reflects OPTI’s reserves and resources as of December 31, 2010.





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 845,734 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


ButaneGross(1)


Net(1)


Gross(1)


Net(1)


Gross(1)


Net(1)(Mbbl)


(Mbbl)


(Mbbl)


(Mbbl)


(Mbbl)


(Mbbl)Proved Developed Producing(2)(5)(6)


30,574



29,040



4,869



4,570



544



517Proved Developed Non-Producing(2)(7)


--



--



--



--



--



--Proved Undeveloped(2)(8)


119,406



101,914



2,081



1,293



2,087



1,781Total Proved


149,980



130,954



6,950



5,863



2,631



2,297Probable(3)


111,940



89,637



394,222



313,083



1,957



1,567Total Proved Plus Probable


261,920



220,591



401,172



318,946



4,588



3,864Possible (4)


52,314



39,535



51,522



32,854



915



691Total Proved Plus Probable Plus Possible


314,233



260,126



452,694



351,800



5,503



4,555





Net Present Values of Future Net Revenue

Based on Forecast Prices and Costs(9)Before Deducting Income Taxes


After Deducting Income TaxesDiscounted 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)


1,216



1,003



841



714



615



1,216



1,003



841



714



615Proved Developed Non-Producing(2)(7)


--



--



--



--



--



--



--



--



--



--Proved Undeveloped(2)(8)


5,760



2,921



1,589



910



536



5,033



2,615



1,454



847



506Total Proved


6,976



3,924



2,429



1,624



1,151



6,248



3,618



2,294



1,561



1,121Probable (3)


20,844



5,084



1,552



542



191



15,578



3,748



1,113



364



108Total Proved Plus Probable


27,819



9,008



3,981



2,166



1,343



21,827



7,367



3,407



1,926



1,229Possible (4)


8,304



1,632



544



288



197



6,164



1,231



430



241



173Total Proved Plus Probable Plus Possible


36,124



10,640



4,526



2,454



1,539



27,990



8,598



3,837



2,167



1,402





- 1 -





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)


17,976



2,280



6,956



1,744



20



6,976



728



6,248Total Proved Plus Probable(2)(3)


76,214



14,103



25,910



8,304



77



27,819



5,993



21,827Total Proved Plus Probable Plus Possible(2)(3)(4)


92,749



18,461



28,331



9,750



83



36,124



8,133



27,990





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


2,429


$
12.47Total Proved Plus Probable(2)(3)
Bitumen, synthetic crude oil, and butane


3,981


$
5.46Total Proved Plus Probable Plus Possible(2)(3)(4)
Bitumen, synthetic crude oil, and butane


4,526


$
5.35





Reserves Reconciliation





The following table sets forth the changes between the reserve volume estimates made as at December 31, 2010 and the corresponding estimates as at December 31, 2009, based on forecast prices, net of royalties.





Proved


Probable


Proved and ProbableBitumen


Synthetic Oil


Butane


Total


Bitumen


Synthetic Oil


Butane


Total


Bitumen


Synthetic Oil


Butane


TotalMbbl


Mbbl


Mbbl


Mbbl


Mbbl


Mbbl


Mbbl


Mbbl


Mbbl


Mbbl


Mbbl


MbblDec 31, 2009


7,569



149,300



2,609



159,478



26,312



403,493



5,473



435,278



33,881



552,793



8,082



594,756Extensions


-



-



-



-



-



-



-



-



-



-



-



-Improved Recovery


-



-



-



-



-



-



-



-



-



-



-



-Technical Revisions


107



3,141



22



3,270



367,910



(291,553
)


(3,516
)


72,841



368,017



(288,412
)


(3,494
)


76,111Acquisitions


-



-



-



-



-



-



-



-



-



-



-



-Dispositions


-



-



-



-



-



-



-



-



-



-



-



-Economic Factors


-



-



-



-



-



-



-



-



-



-



-



-Production (Estimate)


(726
)


(2,461
)


-



(3,187
)


-



-



-



-



(726
)


(2,461
)


-



(3,187
)Dec 31, 2010


6,950



149,980



2,631



159,561



394,222



111,940



1,957



508,119



401,172



261,920



4,588



667,680





- 2 -





Undeveloped Reserves





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





Synthetic Crude Oil (PSCTM)


Bitumen


Butane(Mbbl)


(Mbbl)


(Mbbl)First Attributed


Synthetic Cumulative


First Attributed


Bitumen Cumulative


First Attributed


Butane Cumulative2005


(158
)


175,060



(930
)


19,869



(2
)


2,4032006


(31,913
)


143,147



(17,484
)


2,385



(438
)


1,9652007


58,562



201,709



13,670



16,055



804



2,7692008


(42,075
)


159,634



(1,128
)


14,927



3,326



6,0952009


(47,599
)


112,035



(8,259
)


6,668



(4,137
)


1,9582010


7,371



119,406



(4,587
)


2,081



129



2,087





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





Synthetic Crude Oil (PSCTM)


Bitumen


Butane(Mbbl)


(Mbbl)


(Mbbl)First Attributed


Synthetic Cumulative


First Attributed


Bitumen Cumulative


First Attributed


Butane Cumulative2005


(2,627
)


172,591



(1,748
)


1,726



39



2,3692006


(6,540
)


166,051



3,554



5,280



(90
)


2,2792007


251,813



417,864



8,136



13,416



3,456



5,7352008


194,023



611,887



(7,639
)


5,777



17,629



23,3642009


(212,737
)


399,150



20,430



26,207



(17,966
)


5,3982010


(173,656
)


225,494



371,761



397,968



(1,457
)


3,941





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 Kinosis. OPTI’s sanction of the first stage of Kinosis may occur in 2012, dependent upon multiple factors including improvement in our financial position; operational performance at the Project; the cost estimate to develop Kinosis; the commodity price environment; and supportive financial markets. Subsequent to Kinosis 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 do not expect it to make the development of the property uneconomic.





- 3 -





Future Development Costs

Based on Forecast Prices and CostsTotal Proved(2)


Total Proved Plus Probable(2)(3)(MM$)


(MM$)2011


167.9



167.92012


84.3



93.62013


31.0



150.72014


20.4



171.32015


32.2



116.7Total for all years undiscounted


1,743.5



8,304.1Total for all years discounted at 10% per year


749.8



1,889.0





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 known 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.





- 4 -





Oil


Synthetic Oil


Condensate


Butane


Natural Gas


Bitumen


Inflation Rate


Exchange RateWTI Crude Oil Price $US/bbl


Edmonton Light Oil Price $CDN/bbl


WCS

Hardisty Oil Price $CDN/bbl


Edmonton Synthetic Oil Price $CDN/bbl


PSCTM 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


Long Lake Bitumen Netback CDN$/

bbl


Kinosis Bitumen Netback CDN$/

bbl


%/ year


$US/

$CDNForecast2011


85.00



84.20



71.10



85.70



84.55



88.20



64.32



4.25



71.10



56.57



56.41



2.0



0.9752012


87.70



88.40



73.20



89.40



88.23



90.40



67.55



4.90



73.20



58.49



58.32



2.0



0.9752013


90.50



91.80



73.30



92.82



91.62



93.90



70.28



5.40



73.30



56.86



56.82



2.0



0.9752014


93.40



94.80



75.60



95.84



94.62



96.90



72.60



5.90



75.60



58.69



58.66



2.0



0.9752015


96.30



97.70



78.00



98.76



97.52



99.90



74.82



6.35



78.00



60.67



60.65



2.0



0.9752016


99.40



100.90



80.50



101.98



100.71



103.10



77.35



6.75



80.50



62.70



62.69



2.0



0.9752017


101.40



102.90



82.10



104.00



102.71



105.20



78.87



7.10



82.10



63.93



63.91



2.0



0.9752018


103.40



104.90



83.70



106.03



104.71



107.20



80.39



7.40



83.70



65.19



65.18



2.0



0.9752019


105.40



107.00



85.40



108.15



106.80



109.30



82.01



7.60



85.40



66.55



66.54



2.0



0.9752020


107.60



109.20



87.10



110.37



109.00



111.60



83.72



7.75



87.10



67.82



67.81



2.0



0.9752021


109.70



111.30



88.80



112.50



111.09



113.70



85.34



7.85



88.80



69.18



69.16



2.0



0.9752022


111.90



113.60



90.60



114.82



113.39



116.10



87.05



8.05



90.60



70.54



70.52



2.0



0.9752023


114.10



115.80



92.40



117.04



115.58



118.30



88.76



8.20



92.40



71.99



71.97



2.0



0.9752024


116.40



118.10



94.30



119.37



117.88



120.70



90.57



8.40



94.30



73.49



73.47



2.0



0.9752025


118.80



120.60



96.20



121.89



120.38



123.20



92.48



8.50



96.20



74.94



74.92



2.0



0.9752026


121.10



122.90



98.10



124.22



122.67



125.60



94.18



8.70



98.10



76.43



76.41



2.0



0.9752027


123.60



125.40



100.10



126.75



125.17



128.10



96.19



8.90



100.10



78.02



78.00



2.0



0.9752028


126.00



127.90



102.00



129.27



127.66



130.70



98.09



9.10



102.00



79.41



79.40



2.0



0.9752029


128.50



130.40



104.10



131.80



130.16



133.30



99.99



9.20



104.10



81.10



81.08



2.0



0.9752030


131.10



133.10



106.20



134.53



132.85



136.00



102.08



9.40



106.20



82.73



82.71



2.0



0.9752031


133.70



135.70



108.30



137.16



135.45



138.70



104.08



9.60



108.30



84.36



84.34



2.0



0.9752032


136.40



138.40



110.50



139.89



138.14



141.40



106.07



9.80



110.50



86.13



86.11



2.0



0.9752033.


139.10



141.20



112.60



142.72



140.94



144.30



108.27



10.00



112.60



87.66



87.64



2.0



0.9752034.


141.90



144.00



114.90



145.55



143.73



147.20



110.35



10.20



114.90



89.47



89.46



2.0



0.9752035.


144.80



147.00



117.30



148.58



146.73



150.20



112.74



10.40



117.30



91.39



91.37



2.0



0.975Thereafter

+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%/yr



2.0



0.975





Pricing Assumptions:





The pricing forecasts in the above table were based on the McDaniel January 1, 2011 price forecast.   Transportation costs for bitumen, PSCTM and Butane were supplied by the JV Participants.





Oil Wells





As at December 31, 2010, we had an interest in 90 gross (31.5 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 and Kinosis leases comprise 71,000 acres. 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 2011. There are no work commitments associated with any of these lands.





- 5 -





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, 2010 is $7 million for our 35 percent working interest. The total undiscounted future amount of abandonment liabilities expected to be incurred is $125million based on measurement criteria under Canadian GAAP. These liabilities relate to facilities and wells completed or under construction at the end of 2010. At December 31, 2010, there are 90 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 case of the McDaniel report is $22 million net to us.





We incurred negligible abandonment costs in 2010 and do not expect to incur significant amounts in the next three years.





Tax Horizon





We did not pay any current income taxes in our fiscal year ended December 31, 2010. Considering the Long Lake Project only and our existing tax pools, we do not anticipate paying income taxes until approximately 2024, based on the Proved plus Probable case in the McDaniel Report using forecast prices. This estimate will be impacted by, among other factors, 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, 2010:





($ millions) Property Acquisition Costs (1)Proved Properties
Unproved Properties
Exploration Costs
Development Costs$0
$0
$4
$92





Notes:


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





- 6 -





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 36,000 bbl/d (12,600 bbl/d net to OPTI’s 35 percent working interest) of raw bitumen in 2011.





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 2011.





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 OrCrudeTM 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.





2010


Q1



Q2



Q3



Q4


YearBitumen production (bbl/d)(1)


6,500



8,700



9,200



9,800



8,600





- 7 -





Netback





In CDN$/bbl(2)


Q1



Q2



Q3



Q4


YearRevenue(3)

$
87.98


$
78.83


$
71.42


$
91.36


$
82.16Royalties


(2.45
)


(2.20
)


(2.19
)


(2.46
)


(2.32
)Operating expense


(88.68
)


(66.86
)


(63.72
)


(60.68
)


(68.34
)Diluent and feedstock purchases(4)


(40.00
)


(19.03
)


(24.70
)


(29.56
)


(27.55
)Transportation costs


(6.39
)


(5.49
)


(4.67
)


(2.84
)


(4.67
)Netback

$
(49.54
)

$
(14.75
)

$
(23.86
)

$
(4.18
)

$
(20.72
)





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.





- 8 -





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, 2010. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2010 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 presented 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, 2010, 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
TotalMarch 8, 2011
Canada
-
3,981
-
3,981





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, consistently applied. 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.











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





March 8, 2011





- 2 -





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, 2010, 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.











(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, 2011





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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 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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APPENDIX E






Form 51-101F4
 NOTICE OF
 FILING OF 51-101F1 INFORMATION
 
 This is the form referred to in section 2.3 of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).
 
 On March 16, 2011, OPTI Canada Inc. filed its report s under section2.1 of NI 51-101, which can be found in the company’s’ annual information form under the company’s profile on SEDAR at www.sedar.com.
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