U.S.
SECURITIES AND EXCHANGE COMMISSION


Washington,
D.C.  20549




FORM
40-F










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




For the fiscal year
endedDecember 31, 2008




Commission file
number333-148909




OPTI
CANADA INC.


(Exact
name of registrant as specified in its charter)




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




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




(403)
249-9425




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




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




(212)
894-8940




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




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






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


Securities
      registered or to be registered pursuant to Section 12(b) of the
    Act.
              NoneSecurities
      registered or to be registered pursuant to Section 12(g) of the
      Act
              NoneSecurities
      for which there is a reporting obligation pursuant to Section 15(d) of the
      Act.
              Debt
  Securities


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




x Annual
      Information Form
            x Audited
      Annual Financial Statements


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




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




Yes o                               No
x




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




Yes x                                No
o














EXHIBIT
INDEX
  Exhibit
                            
                            Description99.1
                            
                            Certification
      of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the
      Securities Exchange Act of 193499.2
                            
                            Certification
      of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the
      Securities Exchange Act of 193499.3
                            
                            Certification
      of Chief Executive Officer pursuant to 18 U.S.C. Section
    135099.4
                            
                            Certification
      of Chief Financial Officer pursuant to 18 U.S.C. Section
    135099.5
                            
                            Consent
      of PricewaterhouseCoopers LLP99.6
                            
                            Consent
      of McDaniel & Associates Consultants Ltd.







FORM
40-F






Principal
Documents





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




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




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




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






40
-F1




Annual
Information Form
  
  For
the Year Ended
  
  December
31, 2008
  
  
  
  March
24, 2009
  
 TABLE
OF CONTENTS
  
  PAGEEINTRODUCTORY
      INFORMATION
                      
                      
                      2FORWARD
      LOOKING INFORMATION
                      
                      
                      2CORPORATE
      STRUCTURE
                      
                      
                      4GENERAL
      DEVELOPMENT OF THE BUSINESS
                      
                      
                      5Competitive
      Strengths and Operating Strategies
                      
                      
                      6Our
      Industry
                      
                      
                      9Our
      Principal Assets
                      
                      
                      10The
      Long Lake Project and Future Phase Development
                      
                      
                      10Marketing
                      
                      
                      18Infrastructure
                      
                      
                      18Our
      Lands and Leases
                      
                      
                      19Material
      Agreements Related to the Joint Venture
                      
                      
                      21Royalties
                      
                      
                      27Regulatory
      Approvals and Environmental Considerations
                      
                      
                      28Insurance
                      
                      
                      31RESERVES
      AND RESOURCES SUMMARY
                      
                      
                      32DESCRIPTION
      OF CAPITAL STRUCTURE
                      
                      
                      34CREDIT
      RATINGS
                      
                      
                      38MARKET
      FOR SECURITIES
                      
                      
                      39DIVIDENDS
                      
                      
                      39DIRECTORS
      AND OFFICERS
                      
                      
                      39Board
      of Directors
                      
                      
                      41Officers
                      
                      
                      45Audit
      Committee
                      
                      
                      47Auditor
      Service Fees
                      
                      
                      48CONFLICTS
      OF INTEREST
                      
                      
                      48RISKS
      AND UNCERTAINTIES
                      
                      
                      49Risks
      Relating to the Project and to Future Phases of
Development
                      
                      
                      49Risks
      Relating to Reserves and Resources
                      
                      
                      54Risks
      Relating to Commodity and Currency Pricing
                      
                      
                      56Risks
      Relating to Technology
                      
                      
                      57Risks
      Relating to Third Parties
                      
                      
                      58Risks
      Relating to Financing and Our Indebtedness
                      
                      
                      61MATERIAL
      CONTRACTS.
                      
                      
                      63LEGAL
      PROCEEDINGS AND REGULATORY ACTIONS
                      
                      
                      63TRANSFER
      AGENTS AND REGISTRAR
                      
                      
                      64INTEREST
      OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
                      
                      
                      63INTERESTS
      OF EXPERTS..
                      
                      
                      64ADDITIONAL
      INFORMATION
                      
                      
                      64GLOSSARY
                      
                      
                      65
 
 APPENDIX
      A -
                RESERVES
      DATA AND OTHER OIL AND GAS INFORMATIONAPPENDIX
      B -
                REPORT
      ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES
    EVALUATOR
 APPENDIX
      C -
              REPORT
      OF MANAGEMENT ON RESERVES DATA AND OTHER
  INFORMATION
 APPENDIX
      D -
              AUDIT
      COMMITTEE CHARTER
   
 INTRODUCTORY
INFORMATION
  Except
as otherwise indicated, or unless the context otherwise requires, the terms
"OPTI," "we," "our" and "us," refer to OPTI Canada Inc. capitalized terms used
herein and not otherwise defined have the meanings ascribed thereto in the
Glossary located on page 66.
  Unless
otherwise indicated, all financial information included and incorporated by
reference in this AIF is determined using Canadian Generally Accepted Accounting
Principles ("Canadian GAAP") which differs in some respects from generally
accepted accounting principles in the United States.
  Unless
otherwise specified, all dollar amounts are expressed in Canadian dollars, all
references to "dollars'' or "$'' are to Canadian dollars and all references to
"US$'' are to United States dollars.
  FORWARD
LOOKING INFORMATION
  This
AIF contains forward looking statements and forward looking information within
the meaning of the applicable U.S. federal and state securities laws and
Canadian securities laws. These statements are subject to certain risks and
uncertainties that could cause actual results to differ materially from those
included in the forward looking statements and forward looking information. The
words "believe," "expect," "intend," "estimate," "anticipate," "project,"
"scheduled" and similar expressions, as well as future or conditional verbs such
as "will," "should," "would" and "could" often identify forward looking
statements and forward looking information. These statements and information are
only predictions. Actual events or results may differ materially. In addition,
this AIF may contain forward looking statements and forward looking information
attributed to third party industry sources. Undue reliance should not be placed
on these forward looking statements and forward looking information, as there
can be no assurance that the plans, intentions or expectations upon which they
are based will occur. By their nature, forward looking statements and forward
looking information involve numerous assumptions, known and unknown risks and
uncertainties, both general and specific, that contribute to the possibility
that the predictions, forecasts, projections and other forward looking
statements and forward looking information will not occur.
  2
 Specific
forward looking statements and forward looking information contained in this AIF
include, among others, statements regarding:
  •
                the level of production
      expected;
  •
                the operation of our facilities,
      including the SOR of the SAGD Operation and the PSCTM yield of the Long
      Lake Upgrader;
  •
                our estimated financial
      performance in future
periods;
  •
                our reserve and resource estimates
      and our estimates of the present value of our future net cash
      flow;
  •
                our expansion plans for our
      properties and our expected increases in revenues attributable to our
      expansions;
  •
                the impact of governmental
      controls and regulations on our
  operations;
  •
                our competitive advantages and
      ability to compete successfully;
and
  •
                our expectations regarding the
      development and production potential of our
    properties.
 With
respect to forward looking statements and forward looking information contained
in this AIF, we have made assumptions regarding, among other
things:
  •
                future natural gas and crude oil
      prices;
  •
                the ability for the operator to
      obtain qualified staff and equipment for the Long Lake Project in a timely
      and cost-efficient manner to meet our
  requirements;
  •
                the regulatory framework
      representing royalties, taxes and environmental matters in which we
      conduct our business;
  •
                the ability to market PSCTM
      successfully to customers and our ability to achieve product pricing
      expectations;
  •
                the impact of changing
      competition; and
  •
                our ability to obtain financing on
      acceptable terms.
  Some
of the risks that could affect our future results and could cause results to
differ materially from those expressed in our forward looking statements and
forward looking information include:
  •
                slower than expected ramp-up of
      bitumen production;
  •
                slower than expected ramp-up of
      the Upgrader;
  •
                equipment
      downtime;
  •
                equipment product
      yields;
  •
                our ability to source process
      inputs including water, contract bitumen, and natural
      gas;
  •
                costs associated with producing
      and upgrading bitumen;
  •
                the impact of
      competition;
  •
                the need to obtain required
      approvals and permits from regulatory
  authorities;
 3
 
  •
                  liabilities as a result of
      accidental damage to the
environment;
  •
                  compliance with and liabilities
      under environmental laws and
regulations;
  •
                  the uncertainty of estimates by
      our independent consultants with respect to our bitumen and synthetic
      crude oil reserves and
resources;
  •
                  the volatility of crude oil and
      natural gas prices and of the differential between heavy and light crude
      oil prices;
  •
                  changes in the foreign exchange
      rate between the Canadian and U.S.
  dollar;
  •
                  risks that our financial
      counterparties may not fulfill financial obligations to
      us;
  •
                  difficulties encountered in
      delivering PSCTM to commercial
markets;
  •
                  difficulties in and/or costs of
      disposing of process by-products or wastes including liquid sulphur and
      gasifier ash;
  •
                  we are a non-operator and as such
      we rely on the operator to generate cash flow from the Project and to
      provide information on the status and results of
      operations;
  •
                  we may be unable to sufficiently
      protect our proprietary technology or may be the subject of technology
      infringement claims from third
parties;
  •
                  general economic conditions in
      Canada and the United
States,
  •
                  failure to obtain industry partner
      and other third party consents and approvals, when
      required;
  •
                  royalties payable in respect of
      our production;
  •
                  the impact of amendments to theIncome Tax
      Act(Canada);
  •
                  changes in or the introduction of
      new government regulations, in particular related to carbon dioxide
      ("CO2"), relating to our business;
      and
  •
                  our ability to attract capital and
      the cost of that
capital.
  The
information contained in this AIF, including the information provided under the
heading "Risks and Uncertainties", identifies additional factors that could
affect our operating results and performance. We urge you to carefully consider
those factors and the other information contained in this AIF.
  Our
forward looking statements and forward looking information are expressly
qualified in their entirety by this cautionary statement. Our forward looking
statements and forward looking information are only made as of the date of this
AIF. We undertake no obligation to update these forward looking statements and
forward looking information to reflect new information, subsequent events or
otherwise, except as required by law.
  CORPORATE
STRUCTURE
  OPTI
Canada Inc. was incorporated under the laws of New Brunswick on January 15, 1999
and was continued under the Canada Business Corporations
Act on May 30, 2002.Effective October 1,
2004, we assigned substantially all of our interests in the Project to OPTI Long
Lake L.P. ("OPTI LP"), an Alberta limited partnership. The partners of the OPTI
LP were OPTI Canada Inc., as limited partner, and OPTI G.P. Inc., a wholly-owned
subsidiary of OPTI Canada Inc., as the general partner. Effective January 1,
2008, the limited partnership was dissolved and OPTI Canada Inc. was amalgamated
with OPTI G.P. Inc. OPTI has no subsidiaries at December 31, 2008.
  Our
head office is located at Suite 2100, 555 - 4th Avenue S.W., Calgary, AB, T2P
3E7 and our registered office is located at 3700, 400 - 3rd Avenue S.W.,
Calgary, Alberta, T2P 4H2
  
 4
  GENERAL
DEVELOPMENT OF THE BUSINESS
  We
are a Calgary, Alberta-based company, established in 1999 to develop major
integrated bitumen and heavy oil projects in Canada using our proprietary,
next-generation OrCrudeTM process. Our first project, the Long Lake Project,
includes the Long Lake SAGD Operation and the Long Lake Upgrader, each with
expected through-put rates of approximately 72,000 bbl/d of bitumen. We
expect that the Project, located near Fort McMurray, AB, will produce
58,500 barrels per day ("bbl/d") of products, primarily 39° API PSCTM with low
sulphur content, a highly desirable refinery feedstock. We expect PSCTM to sell
at a price similar to West Texas Intermediate ("WTI") crude oil.
  The
Project is the first to utilize OPTI’s OrCrudeTM process, integrated with proven
gasification and hydrocracking processes. Through this configuration, we
substantially reduce our exposure to and the need to purchase natural gas while
producing one of the highest quality synthetic crude oils from the Canadian oil
sands.
  The
SAGD portion of the Project was completed in advance of the Upgrader in order to
ramp-up bitumen production prior to Upgrader start-up. We began producing
bitumen in 2008 and we announced first production of PSCTM in January 2009. We
expect that SAGD volumes will reach full design rates of approximately 72,000
bbl/d of bitumen in 12 to 18 months and that the increasing capacity of the Long
Lake Upgrader during ramp-up will enable us to process the forecasted SAGD
Operation volumes.
  From
the commencement of our joint venture with Nexen Inc. (Nexen) in 2001 until
December 31, 2008, each company had a 50 percent interest in the Project; OPTI
was the operator of the Long Lake Upgrader and Nexen was the operator of the
Long Lake SAGD Operation. In December 2008, OPTI announced that it had entered
into a definitive agreement to sell a 15 percent working interest in all its
joint venture assets to Nexen for $735 million. The deal closed in January 2009.
Effective January 1, 2009, OPTI has a 35 percent working interest in all joint
venture assets, including the Project, all future phase reserves and resources,
and future phases of development. Nexen has a 65 percent working interest in all
joint venture assets and is now the operator of both the SAGD operation and the
Upgrader for Phase 1 and future phases. For further details on the Nexen
Transaction see “The Purchase and Sale Agreement” on page 28.
  The
leases that support our development plans are located in the Athabasca region of
north-eastern Alberta. The Project is being developed on a portion of the Long
Lake leases that are dedicated to the Project. Additional portions of the Long
Lake leases and other leases in areas commonly referred to as Cottonwood and
Leismer will be used for possible future expansion phases.
 
 At December 31, 2008, OPTI had
approximately 385 employees. Upon Nexen assuming operating responsibility of the
Long Lake Upgrader in early 2009, it is anticipated that Nexen will make
employment offers to many of OPTI's operating and Project staff. We expect that
after this transition OPTI will have approximately 25 employees.
 
 5
 Competitive
Strengths and Operating Strategies
  Our
plan is to optimize the economic recovery of reserves and resources from our
lands. We plan to achieve this objective by using a combination of proven
operating technologies, employing a multi-staged approach to future expansions
when economic conditions permit, and maintaining an integrated approach using
SAGD combined with the Integrated OrCrudeTM Upgrader.
  Our
competitive strengths are as:
  Operating
Project Employing Previously Demonstrated Technologies
  The
Project began producing bitumen in 2008. We announced first production of PSCTM
in January 2009, marking the start-up of only the fourth integrated oil sands
project in Canada. We expect SAGD production volumes to ramp-up through 2009 and
reach design volumes of 72,000 bbl/d of bitumen in 2010. We anticipate that the
increasing capacity of the Upgrader during ramp-up will enable OPTI to process
all of the forecasted SAGD volumes. We expect the Upgrader to produce
57,700 bbl/d of PSCTM and 800 bbl/d of butane at full capacity.
  Until
recently, most oil sands were extracted via mining. However, 80 percent of the
Athabasca oil sands are too deep to mine economically. Where bitumen is too deep
to mine, SAGD technology, first used in 1978, has become a common recovery
method. The majority of existing or planned in-situ oil sands
developments use SAGD. The Project includes SAGD in conjunction with on-site
bitumen upgrading. The Upgrader utilizes OrCrudeTM
technology along with commercially available hydro cracking and gasification
technologies that have been used in many applications around the world to
process heavy oil into refinery and petrochemical feedstocks.
 
 Both
the SAGD and OrCrudeTMtechnologies have been demonstrated by the JV Participants in the form of
the SAGD Pilot and the OrCrudeTMdemonstration plant. The SAGD Pilot consisted of three horizontal well
pairs and associated facilities. The SAGD Pilot operated from mid 2003 to mid
2006 and provided important design and operating information that has been
incorporated into the Project. The OrCrudeTM
demonstration plant had a capacity of 500 bbl/d, was in operation from the
second quarter of 2001 to the fourth quarter of 2003 and processed over 250,000
bbls of bitumen from various sources, including the SAGD Pilot. The OrCrudeTM
demonstration plant provided design and operating parameters that have been
incorporated into the Project. OPTI has the exclusive rights to the use of the
OrCrudeTM process in Canada, including the right to sub-license the
technology.
 
  Large,
Exploitable Resource Base with Low Geological Risk
  Our
working interest share of reserves and resources on current leases are estimated
to be approximately 2.2 billion barrels of bitumen, comprised of 738 million
barrels of proved and possible reserves and 1,424 million barrels of best
estimate contingent resources. These reserves and resources are estimated to be
sufficient to support production for Long Lake Phase 1, and for up to five
additional phases of a similar size as Phase 1, for approximately 40 years. We
believe that the approval of future phases by our board of directors, when
economic conditions permit, and by regulatory authorities in Alberta will allow
us to convert our substantial resource base into additional proved reserves. See
"Reserves and Resources Summary."
  The
timing of future phases is subject to many factors including initial performance
of Phase 1, receiving clarity on proposed climate change regulations, developing
cost estimates and an improved economic environment. We do not expect to
consider sanctioning Phase 2 until mid-2010 at the earliest.
  6
 When
compared to a conventional exploration and production operation, we believe that
an oil sands operation, like our Project, generally has lower geological risk.
Unlike conventional oil exploration and production, we expect that the Project
will have a constant non-declining rate of production during the life of the
Project and therefore would not require ongoing exploration risk to maintain its
production rate once operational. To maintain this rate of production, future
maintenance and sustaining capital expenditures will be required.
  Once
the Project is complete, including construction of the steam expansion plant
(expected in 2009) and the ash processing unit (expected in 2010), we expect
future capital expenditures in connection with the Project will include
maintenance and sustaining capital costs, which we define as those capital costs
necessary to maintain production at the anticipated level over the anticipated
life of the Project. These costs relate to the drilling of new well pairs to
sustain production and regular maintenance capital spending on plant and
facilities.
  Strong
Margins
  We
expect that the sale of PSCTM, a high quality sweet synthetic crude, combined
with lower operating costs, primarily due to lower natural gas needs, will
result in strong margins.
 
 To
illustrate these expected margins, we provide a financial outlook of our
estimated netback for the Project. Netback costs are updated annually as a
result of the JV’s budgeting process. The netback calculation shown below is
consistent with this most recent update and includes our estimates of revenue,
royalties, operating costs and G&A expenses per barrel of product sold when
the Project is at full capacity.
 
 This
financial outlook is intended to provide investors with a measure of the ability
of our Project to generate cash flow assuming full production capacity. We
believe that the ability of the Project to generate cash to fund interest
payments and future phases of development is a key advantage of our Project and
important to our investors. The netback measure is an appropriate financial
gauge to demonstrate this ability as corporate costs, interest, and other non
cash items are excluded from the calculation. The financial outlook may not be
suitable for other purposes. Netbacks generated by the Project are expected to
be lower than shown in this outlook in the years immediately following start-up
due to the lower production volumes during ramp-up and an initially higher SOR.
The netback calculation as presented is a non-GAAP measure. The closest Canadian
GAAP measure to the netback calculation is cash flow from operations. However,
cash flow from operations includes many other corporate items that affect cash
and are independent of the operations of the Project.
 
 The
actual netbacks achieved by the Project could differ materially from these
estimates. The material risk factors that OPTI has identified toward achieving
these netbacks are as outlined in the Forward Looking Information section of
this document. In particular; the SAGD Operation and Upgrader may not operate as
planned; the operating costs of the Project may vary considerably during the
operating period; our financial results of operations will depend upon the
prevailing prices of oil and natural gas in the worldwide market and those
prices can fluctuate substantially; we will be subject to foreign currency
exchange fluctuation exposure; and our operating cash flows will be directly
affected by the applicable royaltyregime
relating to our business. The key assumptions relating to the netback estimate
are set out in the notes beneath the table. Assumptions are considered
reasonable by OPTI as at the date of this AIF.
 
 7
 Estimated
Future Project Netbacks(1)
  In
      CDN$/bbl
                    
                    Post-payout
                    
                    
                    Pre-payout$/bbl
                    
                    
                    $/bblRevenue(1,2)
                    
                    $
                    86.33
                    
                    
                    $
                    86.33Royalties
      and G&A(3)
                    
                    
                    (8.43
                    )
                    
                    
                    (3.84
                    )Operating
      costs(4)Natural
      gas(5)
                    
                    
                    (3.90
                    )
                    
                    
                    (3.90
                    )Other
      variable(6)
                    
                    
                    (2.76
                    )
                    
                    
                    (2.76
                    )Fixed
                    
                    
                    (12.82
                    )
                    
                    
                    (12.82
                    )Property
      taxes and insurance(7)
                    
                    
                    (3.55
                    )
                    
                    
                    (3.55
                    )Netback
                    
                    $
                    54.87
                    
                    
                    $
                    59.46
 
 
 Notes:
 (1)
              The
      per barrel amounts are based on the expected yield for the Project of
      57,700 bbl/d of PSCTM and 800 bbl/d of butane, and assume that the Upgrader
      will have an on-stream factor of 96 percent. These numbers are cash costs
      only and do not reflect non-cash charges. See “Forward Looking
      Statements.”
 (2)
              For
      purposes of this projection, OPTI assumes a WTI price of US$75/bbl,
      foreign exchange rates of CDN$1.00=US$0.85 and an electricity sales price
      of $106 per megawatt hour. Revenue includes sale of PSCtm,
      bitumen, butane and electricity.
 (3)
              Royaltiesare calculated
      based on a light/heavy differential of 30 percent of WTI. OPTI anticipates
      payout for royalty purposes to occur in approximately 2022 based on the
      assumptions noted.
 (4)
              Costs
      are in 2009 dollars.
 (5)
              Natural
      gas costs are based on our long term estimate for a SOR of
      3.0.
 (6)
              Includes
      approximately $1.00/bbl for greenhouse gas mitigation costs based on an
      approximate average 20 percent reduction of CO2
      emissions at a cost of $20 per tonne of CO2.
 (7)
              Property
      taxes are based on expected mill rates for
2009.
 
 Sustaining
capital costs required to maintain production at design rates of capacity are
estimated to be approximately $8.00 to $9.00 per barrel of PSCTM, assuming full
design rate production adjusted for long-term on-stream expectations. The
netbacks as shown are prior to abandonment and reclamation costs. We do not
include these costs due to the long-term nature of our assets. The estimates do
not include any expenditures related to future phases.
 
  8
 Lower
Cash Flow Volatility
  The
majority of in-situ bitumen projects currently being developed in Alberta are
intending to use SAGD without on-site upgrading. OPTI believes that the use of
the Integrated OrCrudeTM Upgrader offers several advantages over these other
projects in that we expect the Integrated OrCrudeTM Upgrader to provide
a solution to the three traditional challenges of stand alone 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
      differentialsExposure
      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
  Strong
Joint Venture Sponsorship and Technical Expertise
  OPTI
benefits from the participation, sponsorship and execution capabilities of
Nexen, one of Canada’s largest independent oil and natural gas producers with
reported production of over 249,000 boe/d, prior to royalties, in the third
quarter of 2008. Nexen has extensive holdings of heavy oil and bitumen
resources, including its 7.23 percent interest in the Syncrude Project, and
employs a team of geologists, engineers and other technical personnel to support
these interests. Nexen Marketing is currently responsible for marketing all of
the output from the Project.
  Experienced
Management Team
  The
members of our senior management team have substantial industry experience.
Technical teams have been established for the construction and operation of the
Project comprised of individuals with extensive previous experience in a number
of oil sands operations and construction projects. Based on experience in
development of the Project, these teams have unique knowledge that will provide
important expertise to future phases.
  Our
Industry
  Oil
sands operators produce and process bitumen, which is the heavy oil trapped in
the sands. According to the EUB, Canada’s oil sands are estimated to hold 175
billion barrels of bitumen at the end of 2007, second only to Saudi Arabia and
significantly more than the recoverable reserves in the United States. According
to the Canadian Association of Petroleum Producers (CAPP), in 2007 oil sands
production reached over 1.1 million bbl/d. CAPP currently estimates that oil
sands production will reach 2.4 million bbl/d by 2015.
  9
 Of
the 315 billion barrels of potentially recoverable bitumen estimated to be
contained in Canada’s oil sands only about 20 percent are shallow enough to be
mined economically, leaving the remainder of the resource to be recovered using
in-situ techniques. The in-situ techniques currently in use employ steam to heat
the bitumen, allowing it to flow into a well and be produced. The two most
common methods of in-situ production are Cyclic Steam Stimulation ("CSS") and
SAGD. The steam used in both processes is normally generated using natural gas,
and natural gas is the primary input cost of both methods. SAGD typically has
higher recovery rates and is a more energy efficient process than CSS in bitumen
deposits such as OPTI’s.
  Bitumen
is currently sold in two principal forms: either as a bitumen blend, in which
the bitumen is mixed with a lighter crude oil (to create synbit) or a very light
condensate (to create dilbit) so that it will flow in pipelines; or, after
upgrading, as a synthetic crude oil. Bitumen blend has many characteristics
similar to, and is generally priced like, conventional heavy oil. Synthetic
crude oil, depending on the level of upgrading it has undergone, has many
characteristics similar to, and is generally priced like, conventional medium or
light oil.
  Upgrading
is the process that changes bitumen into synthetic crude oil. Bitumen, like
crude oil, is a complex mixture of hydrocarbon components with a relatively high
content of carbon in relation to hydrogen compared to conventional light crude
oil. Some upgrading processes remove carbon, while others add hydrogen or change
molecular structures. The main product of upgrading is synthetic crude oil that
can be later refined like conventional oil into a range of hydrocarbon
products.
  Our
Principal Assets
  Our
principal assets include:
  •
                35 percent interest in an
      operating project, the Long Lake Project, as of January 1,
      2009;
  •
                $3.2 billion investment to the end
      of 2008;
  •
                proved plus probable plus possible
      bitumen reserves associated with a portion of the Long Lake Leases of 803
      million bbls. See “Reserves and Resources
  Summary”;
  •
                contingent and prospective bitumen
      resources of an estimated 1.424 billion bbls contained in the remainder of
      the Long Lake, Leismer and Cottonwood Leases. See "Reserves and Resources
      Summary"; and
  •
                the exclusive right to the use of
      the OrCrudeTM Process technology in
  Canada.
  The
Long Lake Project and Future Phase Development
  The
Long Lake Project
  In
2001, OPTI formed a joint venture with Nexen to develop integrated oil sands
projects in Canada. The first such project is Phase 1 of the Project, located on
our Long Lake lease 42 km south east of Fort McMurray, Alberta.
See:  “Our Lands and Leases.”
  Effective
January 1, 2009, OPTI owns a 35 percent undivided interest in the Project,
which, among other assets, includes the SAGD Operation and the Upgrader, each
with expected capacities of approximately 72,000 bbl/d of bitumen. The yield
from bitumen produced from the SAGD Operation is expected to be 57,700 bbl/d of
PSCtm
and approximately 800 bbl/d of butane. OPTI expects PSCtm
to sell at a price similar to WTI crude oil
  10
 The
Project is the first commercial application of the Integrated OrCrudetm
Process. The Project involves two major components, being the recovery of
bitumen and the upgrading of bitumen into PSCtm
and other petroleum products. Included in the Project is a cogeneration facility
that generates steam for the SAGD wells and electricity for use by the Project
or sales to the Alberta interconnected electric system in the event of surplus.
The cogeneration facility has a capacity of 170 megawatts.
  From
commencement of the Project until January 1, 2009, OPTI was the operator of the
Upgrader and had primary responsibility for all matters relating to the
Upgrader, subject to certain approvals of the management committee of the joint
venture. OPTI was responsible for overseeing the construction, commissioning and
start-up and operation of the Upgrader. During this period, Nexen was the
operator of the SAGD Operation and had primary responsibility for all matters
relating to such lands, plants and operations, subject to certain approvals of
the management committee of the joint venture. Nexen has been responsible for
overseeing the operation of the SAGD Pilot, as well as the construction and
operations of the SAGD Operation. Upon closing the Nexen Transaction, Nexen
became the operator of both the Upgrader and the SAGD Operation for Phase 1 and
future phases.
  There
are organizations in place for the management of ongoing operations. These
organizations include personnel experienced in the operation and maintenance of
oil and gas, petrochemical, and other industrial facilities both locally and
internationally. Facility operations are managed locally from an on-site
operations administration and maintenance complex. An emphasis is placed on
having operations personnel live locally in the region and be part of the local
communities.
  The
Project is being governed pursuant to the terms and conditions of the COJO
Agreement and the Technology Agreement. These agreements are reviewed in the
"Material Agreements Related to the Joint Venture" section of this
document.
  Project
Status
  Major
on-site construction of the Project began in mid-2005. The SAGD facilities were
completed and steam injection commenced in 2007. SAGD production ramped up in
2008 to approximately 20,000 bbl/d in November. However, SAGD ramp-up has been
affected by a variety of surface issues that have limited the amount of steam
available to inject into the reservoir over the past few months due to power
disruptions, extreme cold weather, and water temperature and treating issues.
Since steam injection rates directly impact bitumen production rates, and the
ability to generate steam is currently limited, bitumen production is lower than
we previously expected. Solutions are being implemented to place more heat into
the front-end of the water treatment process to supplement the heat returns from
the reservoir and improve the water processing ramp-up capability. Given
steaming constraints, only 32 of 81 well pairs are presently in production.
Bitumen production in January 2009 averaged approximately 13,000 bbl/d (gross).
As steam capacity increases the remaining wells will be brought on stream. The
reservoir continues to perform as expected given the amount of steam
injected.
 
 Construction of the Upgrader, which
intentionally lagged SAGD to ensure sufficient bitumen production at start-up,
was completed in early 2008. Turnover of the Upgrader from construction to
operations, and Upgrader commissioning and start-up activities, were the main
focus in 2008. With all main process units operating, first production of PSCTM
from the Project was achieved in January 2009. Preparation is underway to
transition gasifier feed from vacuum residue to asphaltenes, the final step in
Upgrader commissioning. Synthesis gas from the Upgrader is being used in SAGD
operations, decreasing operating costs by reducing the requirement for purchased
third-party natural gas. During the initial operating period, we expect periods
of Upgrader down time but anticipate that the stability of operations will
continue to improve. The Upgrader is currently gasifying and producing
PSCTM.
 11
 During the final commissioning phase,
prior to the operation of the solvent deasphalting and thermal cracking units,
there is a high percentage of diluent that feeds the Upgrader and continues to
the hydrocracker, forming part of the PSCTM stream. The Project has produced over
20,000 bbl/d (gross) of on-spec PSCTM, with between 10,000 and 12,000 bbl/d
(gross) of this representing upgraded bitumen. The remainder represents diluent
processed through the Upgrader. The percentage of diluent in the Upgrader feed
will decrease as bitumen production increases.
 
 Based on industry experience, we
expect the Upgrader to reach full production more quickly than SAGD operations.
Therefore, during the SAGD ramp-up period, we expect that up to 10,000
bbl/d of externally sourced bitumen will be imported and processed. We expect
the Project to reach full capacity of approximately 72,000 bbl/d of internally
produced bitumen, upgraded into 58,500 bbl/d of PSCTM and other products, in 12
to 18 months.
 
 The
final cost of the Project is expected to be approximately $6.5 billion of which
$3.25 billion will be net to OPTI. As of December 31, 2008, $6.4 billion or $3.2
billion net to OPTI had been incurred on the Project. As the Project is
essentially complete as of December 31, 2008, nearly all expenditures were
completed when OPTI retained a 50 percent working interest in the
Project.  The remaining capital costs relate to the completion of the
steam expansion project, expected in 2009, and the ash processing unit in the
following year. The cost to complete these two projects is estimated at
approximately $45 million net to OPTI’s current 35 percent working
interest.
  
  The
SAGD Process
  
  SAGD
is an in-situ process that removes bitumen from the oil sand reservoir without
removing the sand. The bitumen recovery component of the Project will use the
SAGD process, as depicted above, which involves drilling multiple pairs of
horizontal wells in the oil sands. Steam is injected into the upper well and
released in the oil sands reservoir where it heats the bitumen. The heated
bitumen becomes mobile and flows with condensed water from the steam to the
lower horizontal well and then flows or is pumped to the surface.
  12
 The
SAGD recovery process used by the Project causes considerably less surface
disturbance than mining operations that extracts both the sand and bitumen from
the ground, separates the bitumen from the sand and returns the sand to tailings
ponds. The SAGD process was first used in 1978 and is being employed as the
recovery process in most new or developing in-situ projects.
  SAGD
Commercial Project
  To
achieve approximately 72,000 bbl/d of bitumen production, we
expect that the Project will require 81 SAGD well pairs. Additional wells
will be drilled as required in future years to maintain an annual average
production profile of approximately 72,000 bbl/d.
  The
facilities associated with the SAGD Operation are typical of in-situ projects
and consist of bitumen, gas and water processing, steam generation and
cogeneration facilities and the infrastructure, such as storage tanks, to
support these facilities.
  The
bitumen is processed to remove water and solids, making it suitable for use in
the Upgrader. Until start-up of the Upgrader, the bitumen was blended with
diluent and shipped to markets. In the event that the Upgrader is unavailable,
the JV Participants will continue to market the bitumen directly. Gas produced
with the bitumen is sweetened and used as fuel for the steam generators. Over 90
percent of the water produced with the bitumen will be recycled and converted
into steam for injection into SAGD wells. Impurities in the water are removed to
allow the water to be used as a feed to the steam generators. The majority of
the Project’s initial steam for injection is generated using two cogeneration
facilities, each of which consist of a gas turbine and heat recovery steam
generator, while the remainder is produced by four once-through boilers.
Approximately 170megawatts of electricity
are produced by the combined cogeneration facilities when at full
capacity.
  The
Project was originally designed for steam capacity to support a SOR of
approximately 2.4 at a production rate of 72,000 bbl/d of bitumen. If the
reservoir performance of the initial well pairs requires operation at a higher
SOR, there would not have been adequate steam capacity to allow for the full
production rate of 72,000 bbl/d based on the initial design. In order to
mitigate this risk, the JV Participants have installed additional water
treatment and steam generation facilities to allow for a SOR of up to 3.3, while
maintaining the 72,000 bbl/d production rate. The capital cost of these
additional facilities is approximately $615million, or $300million net to OPTI. The
steam generation facilities are mechanically complete and are expected to become
operational in the first half of 2009. We expect the long-term average
SOR for the Project to be approximately 3.0.
  SAGD
Pilot Facility
  The
SAGD Pilot operated from the second quarter of 2003 to the third quarter of
2006. The purpose of the SAGD Pilot was to confirm reservoir performance
assumptions and the response of the Long Lake reservoir to the SAGD process as
well as to gain site specific operational experience on the drilling, start-up
and operation of SAGD well pairs at the Project. The SAGD Pilot consisted
primarily of a steam generator and bitumen processing facilities, wellsite
facilities and three horizontal well pairs. The initial phase of the SAGD Pilot,
consisting of circulating steam into all producer and injector wells, commenced
in the second quarter of 2003. In the third quarter of 2003, the wells were
switched over to SAGD production mode.
  13
 The
performance of the three well pairs varied widely, as would be expected in a
large scale commercial development. Individual well performance may be
influenced by geological factors, including the presence of low bitumen
saturation lean zones. Specifically, lean zones were present at the SAGD Pilot
and believed to have caused the lower than expected performance of the pilot
wells. It is expected that similar lean zones may occur over a portion of the
Project area. The SAGD commercial well pairs that have been drilled for the
Project are in areas where we expect these zones to occur less frequently than
in other areas of the Long Lake leases. In the 156 horizontal commercial wells
drilled for the Project, only four wells have encountered lean
zones.
  The
SAGD Pilot operations have provided several important lessons that have been
applied to the Project well pairs, including start-up and operating strategies,
well bore optimization, stimulation techniques and improvement to reservoir
simulation models. Based on the absence of any sand production at the SAGD
Pilot, the size of the slotted liners utilized in the Project wells was
increased, which is anticipated to allow for enhanced productivity.
  During
2006, operation of the SAGD Pilot wells and facility was suspended in order to
allow for the tie-in of the wells and portions of the facility to the SAGD
Operation. The pilot facility was then tied in with the main SAGD facilities and
the SAGD Pilot wells have been re-activated coincident with the SAGD start-up in
the spring of 2008.
  Long
Lake Upgrader
  Upgrading
of Bitumen
  The
bitumen recovered by the SAGD Operation is upgraded in the Upgrader. Once the
Upgrader ramps up to full production, it will have the capacity to upgrade
approximately 72,000 bbl/d of bitumen, yielding approximately 57,700 bbl/d of
PSCTMand approximately 800 bbl/d of butane. The JV Participants have sold
bitumen blend in the period prior to Upgrader start-up and will continue to do
so in periods of Upgrader downtime including periods of major maintenance at the
Upgrader. Electricity not consumed by the Project is also sold.
  Integrated
OrCrudeTM
Upgrader
  A
complete upgrading process has been developed which combines the OrCrudeTMProcess
with proven hydrocracking and gasification processes to produce PSCTM, a
premium sweet crude oil, and syngas, a synthesis fuel gas. 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 will only need to purchase
limited amounts of third party natural gas and therefore will have significantly
reduced the exposure to fluctuations in natural gas prices. The ultimate
exposure to natural gas prices and cost will depend on the SOR achieved. We
expect that the integration of the Integrated OrCrudeTMUpgrader and the SAGD facility will create operating cost advantages for
the Project over other SAGD projects.
  14
 The
PSCTMto be produced by the Long Lake Upgrader is expected to have a gravity of
approximately 39°API. Therefore, the Project will not be exposed to fluctuating
heavy oil differentials during regular operations. The Integrated OrCrudeTMUpgrader produces a light synthetic crude oil which will eliminate the
requirement to add diluent to assist in bitumen transportation. There will be no
need to purchase diluent for normal operations and no exposure to fluctuations
in diluent prices or supply will be present when the Upgrader is fully
operational. The Project will only need to purchase diluent for periods when the
Upgrader is not operating.
  OrCrudeTM
Unit
  The
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
fluctuations in diluent prices while the Upgrader is operational.
  The
OrCrudeTM unit
first desalts the diluted bitumen in a conventional desalter. The diluted
bitumen is then fed to a single train atmospheric distillation column that
recovers the diluent stream, an atmospheric gas oil distillate stream, an
atmospheric bottoms stream, and some fuel gas. The atmospheric bottoms stream is
fed into a vacuum distillation unit where vacuum gas oil distillate is recovered
and a vacuum bottoms stream results, which is in turn fed to the solvent
deasphalter. There, the vacuum bottoms are deasphalted using a pentane solvent,
producing asphaltenes and a deasphalted oil.
  The
asphaltenes are fed to the gasifier as a liquid stream for the production of
syngas. The deasphalted oil is fed to two thermal crackers where it is cracked
and recycled back to the distillation section where the converted material is
recovered as additional distillate. This cycle continues until 100 percent of
the original bitumen is converted to either distillate or asphaltenes.
Distillates from both the atmospheric and vacuum units are combined and form the
OrCrudeTM Product
stream which is fed to the hydrocracker.
  ORMAT
energy converters will be used to recover thermal energy that would otherwise be
wasted in the 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
today.
  The
Long Lake asphaltene gasification unit consists of four liquid-feed gasification
trains and a common syngas processing train. The gasifier receives the liquid
asphaltenes from the OrCrudeTM Process
and produces syngas consisting of mostly hydrogen and carbon
monoxide.
  The
oxygen required as part of the gasification process is produced in an air
separation unit. This unit consists of large compressors to compress filtered
outside air, cool it, and then expand the air to produce a low enough
temperature to liquefy the air. The liquid air is then distilled to produce high
purity oxygen and nitrogen. The single train air separation unit includes liquid
oxygen storage for increased reliability.
  15
 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 will be separated from the syngas by contacting it with
water, producing a soot water slurry. The water is recycled back to the
gasification unit.
  Initially
the soot water slurry is processed to remove a portion of the water which is
recycled back to the gasification unit, and the resultant product will be
transported by rail or truck for sale to a metal reclaimer or disposed in an
approved landfill. However, the JV Participants have developed a method to
further process the gasifier soot waste through use of wet oxidation technology.
By adding a soot processing facility, the soot solid waste stream is eliminated
by further processing the stream into a metals rich product with about 10
percent of the original volume. The resulting product, ash, can be marketed to
vanadium processors. This ash processing facility is expected to reduce Project
operating costs, provide additional product revenue, and reduce the
environmental impact of the plant. Final construction completion of the ash
processing unit has been deferred to 2010.
 
 Hydrocracker
 
 The
hydrocracker unit contains the facilities to process OrCrudeTMProduct
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 PSC product, and the remainder is sold as an end
product.
 
 Sulphur
Facilities
 
 The
sulphur recovery unit treats all of the sour gas and water streams to remove the
sulphur as a liquid product for sale. The sulphur recovery unit is licensed by
Fluor Intercontinental Inc. and consists of two oxygen enriched sulphur plant
trains and a common hydrogenation/amine tail gas treating train to remove
virtually all of the total sulphur fed to the Upgrader, including the sulphur
from the SAGD wells.
 
 Liquid
sulphur is loaded directly onto rail cars for transportation to markets which
are primarily in the United States.
 
 16
 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 an exclusive
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.
 
 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
OrCrudeTMProcess 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 is paid a one-time royalty based on the installed cost to the end user
      of any facility using the OrCrudeTMProcess. The estimate of the royalty payable to OPTI BV for the
      Project is approximately $12 million, of which OPTI’s share is 50 percent
      as the OrCrudeTM unit was completed in 2008 at which time OPTI held a 50
      percent interest in the JV;
  •
                OPTI
      BV and its affiliates have the right, but not the obligation, to engineer,
      procure, construct
      and fabricate the solvent deasphalting units for projects using the
      OrCrudeTMProcess.
 
 
 17
 OPTI
BV may terminate the OPTI License if OPTI were to be wound-up or become
insolvent or materially breach the terms of the OPTI License. Notwithstanding
the foregoing, OPTI BV may not terminate the OPTI License in respect of a
particular facility if the royalty described above has been paid by OPTI. If
OPTI BV’s license from ORMAT is terminated, the OPTI License will convert into a
direct license with ORMAT on substantially the same terms and conditions
provided for in the OPTI License.
  Marketing
  We
currently use Nexen Marketing to market the products on behalf of the joint
venture. These products include Premium Synthetic Heavy ("PSH"), PSCTM,
surplus electricity from our Cogeneration Facility and sulphur, and bitumen in
the event that the Upgrader is unavailable. OPTI has the right to take such
production in kind in certain circumstances. We expect PSCTM to sell at a price
similar to West Texas Intermediate (WTI) crude oil. The price OPTI receives is
generally the price actually received by Nexen Marketing, subject to certain
exceptions. No marketing fees are to be charged by Nexen Marketing. Payment from
Nexen Marketing is due within 25 days of the month end following the date of
delivery of products to Nexen Marketing.
  During
SAGD start-up and other periods where the Upgrader is not operational, including
during the Upgrader start-up period, diluent is purchased to blend with the
bitumen to produce a bitumen blend marketed as PSH. This product is being
primarily marketed in the Midwest region of the U.S. to refiners capable of
processing heavier crude types.  PSH has a gravity of approximately
20° API.
  While
some PSCTM is
expected to be sold in Canada, most volumes are expected to be exported to
various refineries in the U.S. Great Lakes and Midwest region with some volumes
sold as diluent to other bitumen producers in Canada. PSCTM has a
low density (39° API) and low sulphur (<10 parts per million). We believe
these characteristics make it attractive to other bitumen producers for use as a
diluent which could improve OPTI’s netbacks.
  The
main crude products, PSH and PSCTM, are
transported to market via the Enbridge Athabasca Pipeline.
  Infrastructure
  The
Project is located 42 kilometres southeast of Fort McMurray with connections to
existing infrastructure including road access (highways 881 and 63), a natural
gas supply pipeline, the electric power transmission grid to allow for both the
import and export of electricity and rail. The JV Participants have a long term
traffic guarantee agreement with Canadian National Railway Company ("CN") under
which traffic is moved to and from the Project site by rail and CN invests in
upgrades to the rail line north of Boyle, Alberta. The rail line will move,
amongst other commodities, sulphur, catalysts, and construction materials to and
from the Project site.
  The
JV Participants have an agreement with Enbridge to provide lateral facilities
and transportation services on the Enbridge Athabasca Pipeline. This pipeline
will transport PSH and PSCTM
produced by the Project to Hardisty, Alberta. The products are then pipeline
transported to markets in Canada and the United States. In addition, the JV
Participants also have an agreement with Pembina Oil Sands Pipeline L.P. for the
transportation of purchased diluent from the Athabasca Oil Sands Project
pipeline system to the Project.
  18
 Our
Lands and Leases
  
  The
following table sets forth our gross and net acreage in respect of the leases
comprising our lands as well as the delineation wells the JV Participants have
drilled on these lands to December 31, 2008.
  Gross
      Acres
                  
                  
                  Net
      Acres
                  
                  
                  Delineation
      WellsLong
      Lake
                  
                  
                  62,720
                  
                  
                  
                  21,952
                  
                  
                  
                  608Leismer
                  
                  
                  93,440
                  
                  
                  
                  32,704
                  
                  
                  
                  160Cottonwood
                  
                  
                  90,240
                  
                  
                  
                  31,584
                  
                  
                  
                  75Other
                  
                  
                  12,800
                  
                  
                  
                  4,480
                  
                  
                  
                  -Total
                  
                  
                  259,200
                  
                  
                  
                  90,720
                  
                  
                  
                  843
 
 We
own a 35 percent interest in the rights to recover bitumen found in the oil
sands deposits within the Long Lake, Leismer and Cottonwood leases.
  19
 Long
Lake Leases
  These
lands are located in the Athabasca oil sands region of Alberta approximately 40
kilometres south of Fort McMurray. The Long Lake leases cover an area of 98
sections (approximately 62,000 acres) and are estimated by McDaniel to contain
approximately 738 million barrels of proved and probable reserves and 254
million barrels of best estimate contingent resources for our 35 percent working
interest share. See "Appendix A - Reserves Data and Other Oil and Gas
Information."
  OPTI’s
capital program for 2009 includes funds allocated for additional core hole
drilling to further delineate our nearer-term development leases at Long Lake.
The 2008/2009 winter program is expected to include the drilling of 21wells and 47 square
kilometres of 3D seismic.
  According
to the Oil Sands Tenure Regulation (AR 50/2000), the lease on which the Project
is located is a deemed primary lease and can be continued beyond its term,
whether it is a producing or non-producing lease, if minimum production levels
or minimum levels of evaluation, respectively, have been achieved. The JV
Participants conducted in excess of the minimum levels of evaluation, and Lease
27 was continued in May 2002 pursuant to section 13 of the Oil Sands Tenure
Regulation. The other oil sands leases that govern the Long Lake leases are
within their primary terms expiring in 2017 or 2018 unless otherwise
continued.
  Leismer
Leases
  The
Leismer leases, located approximately 64 kilometres southwest of the Project,
are comprised of 146 sections of landand are estimated by
McDaniel to contain 668 million barrels of best estimate contingent resources
for our 35 percent working interest share. See "Reserves and Resources Summary -
Resources Data".
  At
Leismer, there have been 190 delineation wells drilled by the JV Participants
along with 52 square kilometres of 3D seismic gathered. In order to concentrate
capital expenditures in 2009 on Phase 1 and nearer-term development projects on
the Long Lake lease, nodelineation wells or
seismic are planned on these leases during the 2008/2009 winter
season.
  Cottonwood
Leases
  The
Cottonwood Leases, located approximately 32 kilometres southwest of the Project,
are comprised of 141 sections of land and are estimated by McDaniel to contain
502 million barrels of best estimate contingent and prospective resources for
our 35 percent working interest share. See "Reserves and Resources Summary -
Resources Data."
  There
are over 75 wells drilled on these lands, including 44 drilled by the JV
Participants, 25 of which were drilled in 2008. In order to concentrate capital
expenditures in 2009 on Phase 1 and nearer-term development projects on the Long
Lake lease, nodelineation wells or
seismic are planned on these leases during the 2008/2009 winter
season.
  Development
of Future Phases
  The
JV Participants believe thatthe landswill support
approximately 360,000 bbl/d of PSCTMproduction (126,000 bbl/d net to OPTI) from six phases, including Long
Lake Phase 1. Based on reserve and resource estimates, OPTI believes there is
potential for three phases at Long Lake. In addition, we believe we have
sufficient resources to support two phases at Leismer and one at Cottonwood.
From inception, the JV Participants have spent over $800million on the expansion
activities beyond Phase 1 and OPTI expects to continue to invest in engineering
and planning for future phases of development.
  20
 The
sanctioning of Phase 2 will depend on multiple factors including the initial
performance of Phase 1, receiving regulatory approval for Phase 2 SAGD
operations, receiving clarity on proposed climate change regulations, finalizing
cost estimates and an improved economic environment. OPTI therefore does not
expect to consider sanctioning of Phase 2 until mid 2010 at the earliest. In
addition, the Alberta government announced significant changes to the oil sands
royalty regime in late 2007. Increases in royalties will impact the economics of
our business and may impact the timing of future investment
decisions.
  In
2009, the JV partners plan to advance detailed engineering on the SAGD and
upgrader facilities for Phase 2 of Long Lake and conduct core hole drilling to
further delineate the leases. Regulatory approval has been obtained for the
Phase 2 upgrader, which is expected to be constructed adjacent to Phase 1 of the
Long Lake Upgrader. The SAGD portion of Phase 2 is planned to be located in the
southern portion of the Long Lake lease (Long Lake South). Planning and
delineation for the Phase 2 SAGD project is ongoing. In late 2006, a regulatory
application for the Long Lake South project was filed, comprising two SAGD
phases totalling 140,000 bbl/d of bitumen production in addition to Phase 1. The
regulatory approval for this project was obtained in February 2009.
  Lease
delineation and preliminary environmental evaluations are underway for phases
beyond Phase 2. Each future phase is planned to be of a similar size and design
to the Project and anticipated to consist of integrated SAGD and OrCrudeTMUpgrader projects. The specific design of these phases will be dependent
upon a number of factors including key learnings from Phase 1 and our strategy
to address CO2 and other
greenhouse gas emissions. Alternatives to facilitate CO2 capture
are being evaluated.
  Material
Agreements Related to the Joint Venture
  Background
  Prior
to March 12, 2004, the Project was being developed by the JV Participants
pursuant to the terms and conditions of a MOU dated October 29, 2001. The
Project is now governed by the COJO Agreement and, with regard to the associated
upgrading technology rights, by a technology agreement between the JV
Participants (the "Technology Agreement").
  Development
of those Long Lake lands not subject to the COJO Agreement and certain other
Leismer and Cottonwood area lands is governed by additional construction,
ownership and joint operation agreements with Nexen that contain substantially
the same terms as the COJO Agreement subject to those material differences as
summarized on page 26 and are referred to as the New COJO Agreements. The
Technology Agreement will govern these projects as well.
  While
the MOU was superceded by the COJO Agreement, the New COJO Agreements, and the
Technology Agreement with respect to the Project and certain additional lands,
the MOU continues to otherwise govern the joint venture relationship between
OPTI and Nexen.
  The
MOU provides for an Area of Mutual Interest respecting Townships 60 to 100
inclusive, and Ranges 1 to 24 inclusive, W4M, excepting certain specific areas.
The MOU will govern any new oil sands leases or petroleum and natural gas rights
overlying owned oil sands leases jointly acquired by OPTI and Nexen within the
Area of Mutual Interest and projects thereon, unless the parties agree
otherwise.
  21
  COJO
Agreement and the Technology Agreement
  On
March 12, 2004, OPTI and Nexen entered into an interim joint venture agreement
whereby it was agreed the COJO Agreement and the Technology Agreement superseded
the MOU in respect of the subject matter of those agreements.
  The
COJO Agreement
  General
  The
COJO Agreement is based on the MOU and relevant provisions of industry standard
agreements, and provides for the development, construction, ownership and
operation of the Project. The purpose of the COJO Agreement is to document the
terms upon which:
  •
                the Project will be constructed,
      owned and operated;
  •
                each JV Participant shall be
      responsible and pay for its respective share of joint Project costs;
      and
  •
                the share of the SAGD production
      volumes, Upgrader products and the surplus Project electricity will be
      allocated and distributed to each of the JV
      Participants.
  Subject
to available Upgrader capacity, each JV Participant has agreed to process at the
Upgrader its entire share of the SAGD production volumes produced from the
Project.
  Management
Committee
  The
COJO Agreement provides for the establishment of a Management Committee composed
of representatives of each JV Participant. The Management Committee exercises
supervision and control of each operator and all matters relating to the joint
operation of the Project, excluding matters specifically designated to be within
the exclusive jurisdiction of an operator, any unresolved audit claims, and the
interpretation of the COJO Agreement. Each JV Participant has appointed one
representative and one alternate representative to serve on the Management
Committee. If there are only two parties to the COJO Agreement, all decisions of
the Management Committee are required to be unanimous.
  If
there are more than two parties, different Management Committee approval
thresholds are specified. In such an event, a matter being voted on by the
Management Committee will generally be approved only upon the affirmative vote
of two or more JV Participants having a combined Project interest of more than
75 percent. However, there are certain exceptions to these voting requirements
and, among other things, the COJO Agreement provides that the following matters
will be approved by the Management Committee only upon the unanimous approval of
all JV Participants with regards to:
  •
                the approval of any design or
      scope change to a construction plan such that the facility or joint
      operation in question is or will be substantially different than what was
      provided for previously;
  •
                the processing at the Long Lake
      Upgrader of production from lands other than the
      Project;
  •
                any matter which significantly
      affects the integration of the Long Lake Upgrader and the SAGD
      Operation;
  •
                any enlargement work plan and
      budget, and any amendments thereto;
or
  •
                the termination of the COJO
      Agreement.
  22
 Operators
  Under
the original COJO Agreement, OPTI was the operator of the Upgrader and Nexen was
the operator of the SAGD facilities. In January 2009, Nexen became the operator
of both the SAGD facilities and the Upgrader of Phase 1 and all future phases as
per the Nexen Transaction.
  An
operator may be removed by the vote of two or more JV Participants having a
combined Project interest of 55 percent or more under certain
conditions.
  In
addition, after one year from the Upgrader or SAGD operational date, as the case
may be, a JV Participant may challenge for operatorship by proposing terms
which, if not matched by the existing operator, establish the proposing JV
Participant’s operatorship terms.
  Operators
are required by the COJO Agreement to conduct or cause to be conducted all joint
operations for which it is responsible diligently, in a good and workmanlike
manner and in accordance with good petroleum industry, construction and
environmental practices and principles. Each operator is to conduct or cause to
be conducted all joint operations as would a prudent operator under the same or
similar circumstances. An operator may sub-contract all or substantially all of
its duties and responsibilities to a reliable and competent third party
subcontractor or an affiliate of that operator with the approval of and on the
terms approved by the Management Committee, provided that such operator retains
full control and supervision of such subcontract and that any third party
subcontractor is retained on a general arm’s length basis.
  Contracts, Agreements and
Commitments
  A
contracting policy and procedure establishes limits on each operator’s authority
to enter into agreements on behalf of the JV Participants for Project
purposes.
  Force
Majeure
  If
prior to an operational date an event or series of events of force majeure
suspends a JV Participant’s obligations for longer than one year, any JV
Participant is entitled, in certain circumstances, to terminate the COJO
Agreement.
  Default
  Under
the terms of the COJO Agreement, each JV Participant has a first priority fixed
and specific lien, charge and security interest in and on the right, title,
estate and interest of each other JV Participant in the Project (including,
without limitation, that JV Participant’s Project interest) to secure payment
and performance of each other JV Participant’s Project obligations.
  23
 If
a JV Participant fails to pay an amount within the time period prescribed in the
COJO Agreement or is otherwise in material default under the COJO Agreement,
each non-defaulting JV Participant will be entitled to exercise the lien and
thereafter enforce the rights and remedies set out in the COJO Agreement that
include:
  •
              for
      the period prior to the expenditure by the JV Participants of 80 percent
      of the aggregate of all costs expended and to be expended in respect of
      the Project, treat non-payment of amounts as a sale, assignment, transfer
      and conveyance to the non-defaulting JV Participant of the defaulting JV
      Participant’s entire Project interest in and to the Project, subject to
      certain exclusions, provided that such sale, assignment, transfer and
      conveyance shall not be effective unless and until the non-defaulting JV
      Participant pays to the defaulting JV Participant as consideration for
      such sale, assignment, transfer and conveyance 80 percent of the total
      joint account Project costs paid by the defaulting JV Participant. If this
      remedy is exercised, the defaulting JV Participant shall have no further
      obligations thereafter arising in connection with the assigned Project
      interest;
  •
              for
      the non-payment of amounts occurring after the expenditure by a JV
      Participant of 80 percent of such Project costs but before commercial
      operation of the Project, the JV Participant exercising the lien, upon a
      default in payment by the other JV Participant, can acquire from the other
      JV Participant a portion of that JV Participant’s Project interest
      (subject to certain exclusions) which is determined by multiplying the
      defaulting JV Participant’s Project interest by the quotient obtained by
      taking 125 percent of the default amount in question, and dividing that
      product by the joint account expenditure amount spent in respect of the
      Project by the defaulting JV Participant as of the default date. If this
      remedy is exercised, the defaulting JV Participant will have no further
      obligations thereafter arising in connection with the assigned Project
      interest;
  •
              withhold
      from the defaulting JV Participant any further information and privileges
      with respect to the ongoing operations of the Project, including the right
      to participate in decisions of the Management Committee, and in such event
      the non-defaulting JV Participants will be entitled to, subject to certain
      limitations, vote the defaulting JV Participant’s
  interest;
  •
              treat
      the non-payment of an amount as an assignment to the non-defaulting JV
      Participant of the proceeds of the sale of the defaulting JV Participant’s
      share of production that has been produced from the Project or has been
      processed at the Long Lake Upgrader;
and
  •
              if
      the default occurs after commercial production is achieved, the JV
      Participant exercising the lien may sell the defending JV Participant’s
      interest in the Project.
  The
foregoing and certain other rights can only be exercised after notice from a
non-defaulting JV Participant and the expiry of certain cure
periods.
  Additionally,
if material physical damage occurs to Project property prior to the last
occurring operational date, each JV Participant shall have the right to
nonetheless commence reconstruction efforts. If in certain circumstances
reconstruction is not commenced by a JV Participant, we have the right (but not
the obligation) to terminate the COJO Agreement and the Technology
Agreement.
  Technology
  Technology
developed by the JV Participants in connection with the Project will be jointly
owned by the JV Participants, provided that upgrading technology included in the
Technology Agreement is expressly not subject to the COJO Agreement but rather
is governed by the Technology Agreement.
  24
 Marketing
  Pursuant
to the COJO Agreement all SAGD production volumes, Upgrader products, surplus
Project electricity, any sulphur production or any other by-product that is
produced from or processed at the SAGD Operation or the Upgrader, as the case
may be, shall be marketed by Nexen Marketing on behalf of the JV Participants,
subject to each JV Participant’s right to take in kind its share of such
committed production in certain circumstances. The price to which each JV
Participant shall be entitled for its committed production purchased by Nexen
Marketing shall be equivalent to the price actually received by Nexen, subject
to certain exceptions. No marketing fees are to be charged by Nexen
Marketing.
  Right of First
Offer
  If
after the project sanction date a JV Participant wishes to solicit bids or has
received an unsolicited bid it is favourably considering in respect of all or
any of its interest in the Project, it will by notice (a "ROFO Notice") advise
the other JV Participants of its desire to make the disposition. In addition, if
a JV Participant executes a binding agreement respecting the sale of all or any
of its interests, it will by notice (a "ROFR Notice") advise each other JV
Participant, by providing notice of the formal sale agreement. However, a
disposing JV Participant is not required to issue a ROFR Notice if that JV
Participant had issued a ROFO Notice within the previous 180 days and the
consideration set forth in the binding agreement which forms part of the ROFR
Notice is at least 95 percent of the consideration set forth in that ROFO
Notice.
  Nomination
Process
  The
Agreement allows either party to elect to reduce its participation in the
project in question. If a party reduces its participation, the other party is
obligated to purchase this reduced participation for an amount equal to OPTI’s
sunk costs related to the reduced participation. If the other party elects not
to purchase the reduced participation, then the project will stop.
 
 The Technology
Agreement
 
 The
Technology Agreement grants two sets of licensed rights, the AMI License
relating to the lands within the Area of Mutual Interest, and the Territory
License relating to Canada, excluding the Area of Mutual Interest (the
"Territory").
 
 License
Rights
 
 Under
the AMI License, we have granted to Nexen, for a term commencing on October 31,
2001 and ending October 31, 2026 an exclusive license (with the exception of the
license to Suncor) to use the technology to process and upgrade hydrocarbons,
including bitumen, oil sands and crude oil (the "Upgrading Technology")
associated patents (while they are in force), and information, knowledge and
experience of a technical, operating or commercial nature of OPTI, referred to
as the Licensor Information, to design, engineer, construct, operate and
maintain any facility using the Upgrading Technology, including the right to
sub-license the rights to third parties and affiliates.
 
 The
Territory License is a perpetual, non-exclusive license, which grants the same
rights to Nexen in the Territory as long as that use is for an upgrader used to
develop hydrocarbons, including bitumen, oil sands and crude oil in which Nexen
has an ownership interest and OPTI has been offered the right to participate.
Nexen is able to grant sub-licenses to its affiliates without our permission.
For Nexen to grant a sub-license to a non-affiliate for use in an upgrading
facility, Nexen must have an interest in the facility, the sub-license must
contain terms consistent with the Technology Agreement, including the payment of
royalties to us, and we must consent to the issuance of such
sub-license.
  25
 For
the purposes of each of the AMI License and the Territory License, improvements
made by us and our affiliates (which includes OPTI BV and ORMAT) are included in
the rights licensed to Nexen. In granting the AMI License and Territory License
rights, we retain all of its rights and entitlements, including use, associated
with the Upgrading Technology. Neither the AMI License rights nor the Territory
License rights include the right to design or manufacture any other proprietary
products of ORMAT, OPTI BV or ourselves. OPTI and our affiliates’ rights under
the Technology Agreement include the right to engineer, procure, construct or
fabricate solvent deasphalter units and the right to use the improvements made
by Nexen. Our right to use improvements made by Nexen, its affiliates or
sub-licensees survives the termination of the Technology Agreement.
  Royalty
Provisions
  The
Technology Agreement contains a royalty structure, which depends on the
ownership interest of the parties in the applicable facility and is calculated
based on barrels of capacity of the applicable upgrader. If Nexen, or an
affiliate of Nexen to which it issues a sub-license, has an interest in an
upgrader which is greater than 50 percent, Nexen must pay royalties to us based
on the daily volumetric raw bitumen handling capacity (both design capacity and
actual throughput) of the upgrader. If capacity is increased, there are
provisions for corresponding increases in royalties. The calculation of such
capacity royalties differs depending on our interest in the upgrader. There are
also provisions to ensure payment of royalties from third party assignees of
Nexen.  We are obligated to pay the full amount of this royalty to
OPTI BV under the terms of the OPTI License.
  Nexen
will pay to us a royalty based on the installed cost proportionate to its
working interest of any facility using the OrCrudeTMProcess. We estimate the royalty payable to us from Nexen in the first
phase of the Project will be approximately $6 million.
  Assignment and
Termination
  Nexen
may not assign the Technology Agreement without our consent, unless such
assignment is to a successor in interest, a party acquiring all or substantially
all of Nexen’s assets or a lender for the purposes of securing financing for a
project other than the Project. OPTI may assign the Technology Agreement at its
discretion without Nexen’s consent. Either party may terminate the agreement for
breach with notice, if the breach is not cured within 30 days. Additionally,
either party may terminate upon an Event of Insolvency, as such term is defined
in the Technology Agreement. Acts or omissions of a sub-licensee of Nexen, which
would have constituted a breach of the Technology Agreement by Nexen, had they
been the acts or omissions of Nexen, are considered breaches of the Technology
Agreement. Upon termination for payment default by Nexen, use of the Upgrading
Technology and Licensor Information must cease. In other instances of default,
Nexen maintains limited rights to use the Upgrading Technology based partially
on the royalties paid prior to termination.
  The
New COJO Agreements
  As
indicated above, the New COJO Agreements are in substantially the same form as
the COJO Agreement. There are only a few material differences,
namely:
  •
              The
      New COJO Agreements contain provisions permitting one party to propose and
      conduct delineation and lease-saving operations, and to propose and
      prepare a development plan (in contemplation of a construction plan). If
      the other party does not wish to participate in those operations or
      activities it will be subject to a penalty. The penalty for
      non-participation in a delineation operation or the preparation of a
      development plan is a before tax return of capital of 1.5309 percent
      calculated and compounded monthly on the costs incurred to conduct the
      applicable operations and activities. The penalty for non-participation in
      a lease-saving operation is the forfeiture of that party’s interest in the
      applicable lease.
   26
  •
              A
      party is required to pay for its share of costs associated with
      delineation operations and development plans, plus all associated
      penalties, prior to either the date the Management Committee approves the
      project construction plans or the project sanction date, as applicable,
      before it is entitled to participate in the
  project.
  As
was the case under the COJO Agreement, each party to each New COJO Agreement has
the right, until the construction plans are approved by the Management
Committee, to elect to participate in the project as to less than its current
interest therein. If a party exercises such right and the other party elects to
acquire the available interest, the acquiring party shall be required to pay the
disposing party various amounts, including a technology royalty, a production
royalty, and reimbursement of prior expenses incurred for the joint account in
connection with the acquired interest. If a party elects to reduce its interest
but no other party elects to acquire such interest, the project in question will
be postponed.
  Similarly,
if a party previously elected to participate as to a reduced interest, that
party has the right until the project sanction date under each New COJO
Agreement to elect to participate in the applicable project up to the interest
it owns as of the date hereof, if the scope of the project changes. If a party
exercises such right it shall be required to pay various amounts, including a
technology royalty, a production royalty, and reimbursement of prior expenses
incurred for the joint account in connection with the acquired interest together
with interest thereon.
  The
Purchase and Sale Agreement
  On December 16, 2008, OPTI and Nexen
entered into a Purchase and Sale Agreement wherein OPTI agreed to sell a 15
percent working interest in Phase 1 of the Long Lake Project, all future phase
reserves and resources, and future phases of development to Nexen for $735
million. Under the terms of the agreement, Nexen also assumed operatorship of
the Long Lake Upgrader and all future phases. The transaction closed January 26,
2009. Effective January 1, 2009, OPTI has a 35 percent working interest in all
joint venture assets, including Phase 1 of the Long Lake Project, all future
phase reserves and resources, and future phases of development. Nexen has a 65
percent working interest in all joint venture assets and is now the operator of
both the SAGD and upgrader facilities for Phase 1 and future phases. Pursuant to
the Nexen transaction, OPTI pre-funded $85 million of its portion of the 2009
joint venture capital expenditure program.  Any additional capital
expenditures allocable to our working interest share in 2009 will be funded by
OPTI.
 
  Royalties
  The
Government of Alberta receives royalties on production of natural resources from
lands in which it owns the mineral rights. On October 25, 2007, the Government
of Alberta unveiled a new royalty regime. The new royalties for conventional
oil, natural gas and bitumen became effective January 1, 2009 and are linked to
commodity prices and production levels, and will apply to both new and existing
oil sands projects as well as conventional oil and gas activities.
  Prior
to January 1, 2009, in respect of oil sands projects having regulatory approval,
a royalty of one percent of gross bitumen revenue was payable prior to the
payout of specified allowed costs, including certain exploration and development
costs, operating costs and a return allowance. Once such allowed costs were
recovered, a royalty of the greater of: (a) one percent of gross bitumen
revenue; and (b) 25 percent of net bitumen revenue (calculated as being gross
bitumen revenue less operating costs and additional capital expenditures
incurred since payout (net royalty)) was levied.
  27
 Under
the new regime, the Government of Alberta will increase its royalty share from
oil sands production by introducing price-sensitive formulas which will be
applied both before and after specified allowed costs have been recovered. The
gross royalty will start at one percent of gross bitumen revenue and will
increase for every dollar that world oil price, as reflected by the WTI crude
oil price, is above $55 per barrel, to a maximum of nine percent when the WTI
crude oil price is $120 per barrel or higher. The net royalty on oil sands will
start at 25 percent of net bitumen revenue and will increase for every dollar
the WTI crude oil price is above $55 per barrel to 40 percent when the WTI crude
oil price is $120 per barrel or higher. Prior to the payout of specified allowed
costs, including certain exploration and development costs, operating costs and
a return allowance, the gross royalty is payable. Once such allowed costs have
been recovered, a royalty of the greater of: (a) the gross royalty and (b) the
net royalty is payable. The Government of Alberta has announced that it intends
to review and, if necessary, revise current rules and enforcement procedures
with a view to clearly defining what expenditures will qualify as specified
allowed costs.
  The
implementation of the proposed changes to the royalty regime in Alberta is
subject to certain risks and uncertainties. The significant changes to the
royalty regime require new legislation, changes to existing legislation and
regulation and development of proprietary software to support the calculation
and collection of royalties. Additionally, certain proposed changes contemplate
further public and/or industry consultation. There may be modifications
introduced to the proposed royalty structure prior to the implementation
thereof.
  Our
initial evaluation based on the information available to date, assuming a $65
per barrel WTI crude oil price, is that the increase in the pre-payout royalty
would be approximately $1.00 per barrel of product sold when Phase 1 of the Long
Lake Project is fully operational.
  In
contemplation of the new royalty regime, a Government of Alberta appointed
royalty review panel recommended a tradable royalty credit of 5 percent of
eligible capital expenditures as an incentive for industry to increase upgrading
and refining capacity in Alberta. The Government of Alberta has rejected the
recommendation for an upgrader credit at this time. The Government indicated
that the recommendation related to a tradable upgrader credit will be studied
further in the context of the province’s overall value-added strategy and that
they would consider other options such as taking bitumen in kind rather than
cash for royalty amounts and directing that bitumen to Alberta upgraders and
refineries. The Government indicated that it would also consider adjusting
pipeline toll differentials to avoid subsidization of bitumen exports, requiring
value-added components in future oil sands development approvals, and government
investment in regional infrastructure that would support value-added initiatives
within Alberta.
  Regulatory
Approvals and Environmental Considerations
  Regulatory
Approvals
  We
have regulatory approval for SAGD and upgrading facilities for Phases 1 and 2,
as well as regulatory approval for SAGD facilities for Phase 3.
  The
Project received approval from the ERCB (formerly the EUB) and AE for up to
70,000 bbl/d of SAGD operation and up to 140,000 bbl/d of upgrading capacity in
2003. In September 2006, approval was received for routine amendments to these
approvals. It is possible that additional amendments to these approvals will be
as operations proceed, as is typical with projects of this nature.
  28
 In
July 2005, we made an application to AE for a Terms of Reference ("TOR") for a
proposed expansion to the Project. After a public notice period and input from
local stakeholders AE released the final TOR for the SAGD expansion which
contained no unanticipated requests. An application for an additional 140,000
bbl/d of SAGD production from the Long Lake lease was filed in late 2006 known
as the Long Lake South Project. Regulatory approval for the Long Lake South
Project was received in February 2009.
  In
January 2005, an application was filed to EUB and AE for approval of the Long
Lake Power Project (the "Power Project"). The Power Project consists of a
cogeneration facility comprised of two units, a main substation, a cogeneration
substation, associated transmission lines, two OrCrudeTM energy
converters and a power grid connection. The Power Project was approved by the
EUB in June 2005 and AE in December 2005.
  Throughout
the operational life of the Project additional regulatory approvals and permits
will be required. It is anticipated that such additional approvals and permits
required for the Project will be received in the ordinary course.
  Safety,
Environment and Social Considerations
 
 Many
stakeholders will play a role in the ultimate success of Long Lake and our
future developments - our employees, contractors and suppliers, area residents
including First Nations people, government and regulatory authorities,
non-government organizations, investors and others.
  Recognizing
the diverse needs of these stakeholders, OPTI and Nexen have adopted a Safety,
Environment & Social Responsibility ("SESR") Policy that helps guide
business decisions in an integrated manner and embraces the concept of
sustainable development - an approach that considers environmental protection,
economic growth and social responsibility.
   This
comprehensive policy assists OPTI and Nexen in identifying and achieving
sustainability as we strive for 100 percent safe performance in all of our
joint-venture operations and activities, for our employees, contractors and
management.
  The
key environmental issues and stakeholder concerns to be managed by the JV
Participants in the development of the Project encompass human health, surface
disturbance, effects on historical and traditional resources, air quality, water
quality and water use, noise and cumulative effects on ecosystems. The JV
Participants have committed to monitoring programs that will track the effects
of the Project and the cumulative effects of regional development on
environmental components and ecosystems. OPTI has participated at the executive
level in the Cumulative Environmental Management Association, the Regional
Aquatics Monitoring Program, the Wood Buffalo Environmental Association, the
Regional Infrastructure Participating Group and other multi-stakeholder regional
programs that address cumulative environmental and socio-economic project
impacts.
  The
JV Participants have designed the Project to meet or exceed existing standards
for control of air emissions, water emissions, water use and territorial
disturbance. As with all new industrial development, we expect regional air
emissions to increase slightly as a result of the Project. Air emission
modelling results show that emission concentrations should remain under existing
AE standards for ground level concentrations in all modelled communities in the
region; however, environmental regulations are becoming increasingly stringent,
and we cannot be certain that the Project will meet future standards that might
be imposed.
 
 29
 To
ensure we remain continuously improve our SESR performance, science-based risk
assessments, cost-benefit analyses and measurable targets are some of the tools
applied to our decision-making processes.
 
 Greenhouse
Gases and Industrial Air Pollutants
 
 Canada
is a signatory to the United Nations Framework Convention on Climate Change (the
"Convention") and has ratified the Kyoto Protocol established thereunder to set
legally binding targets to reduce nation-wide emissions of carbon dioxide,
methane, nitrous oxide and other GHGs. The Project will be a significant
producer of some GHGs covered by the Convention. We intend that the Project will
comply with applicable Canadian requirements implementing the Kyoto
Protocol.
  The
Long Lake Upgrader will produce more CO2 on site
per barrel than other integrated projects that stockpile petroleum coke. The
OrCrudeTM Process
uses virtually all of the bitumen resource and therefore produces more CO2 per
barrel. While this results in higher local CO2 emissions,
PSCTM’s
higher product quality results in lower CO2 emissions
when it is ultimately processed by a refinery.
  On
April 26, 2007 the Canadian Federal Government released the Regulatory Framework for Air
Emissions (the "Framework") which outlines proposed new requirements
governing emission of GHGs and other industrial air pollutants in accordance
with the Government’s Notice of Intent to Develop and Implement Regulations and
Other Measures to Reduce Air Emissions released on October 19, 2006. The
Framework introduces further, but not full, detail on new GHG and other
industrial air pollutant limits and compliance mechanisms that will apply to
various industrial sectors, including the oil sands extraction, upgrading and
electricity production industries starting in 2010. On March 10, 2008, the
Canadian Federal Government elaborated on the Framework with the release of its
Turning the Corner
document. It is contemplated that new regulations will take effect January 1,
2010. Draft regulations were expected to be available for public comment in the
Fall of 2008 and are now expected in mid-2009.
  The
proposed regulatory framework provides that existing oil sands facilities in
operation by 2004 will be subject to an 18 percent emission intensity reduction
targets requirement commencing in 2010, with 2 percent additional annual
reductions thereafter until 2020.  Emission intensity is the amount of
GHG emissions per unit of production or output. Facilities commissioned between
2004 to 2011 or facilities existing prior to 2004 which are between 2004 and
2011 have had a major expansion resulting in an increase of 25 percent or more
in physical capacity or which undergo a significant change to processes will be
exempt from the 2010 emissions intensity reduction target of 18 percent but will
have to report their emissions each year and after their third year of operation
will be required to reduce their emissions intensity by 2 percent annually from
a baseline emissions standard which is to be determined by reference to a
sector-specific cleaner-fuel standard. For oil sands facilities, it is
contemplated to form the basis of new draft regulations scheduled to be released
in early 2008 that there will be specific cleaner-fuel standards based on the
use of natural gas for each of mining, in situ and upgrading. However, an
incentive to deploy carbon capture and storage ("CCS") has been
included.  CCS is where carbon dioxide is separated from a facility's
process or exhaust gas emissions before they are emitted, transferred from the
facility to a suitable storage location, and injected into underground
geological formations and monitored to ensure they do not escape into the
atmosphere. If a facility commissioned between 2004 and 2011 is built such that
it is able or ready to undertake CCS, then it will be exempt from the
cleaner-fuel standard until 2018 and it will only be required to reduce it's
emission-intensity by 2 percent per year from its actual emissions. In situ oil
sands projects and oil sands upgraders built after 2011 must have their GHG
emissions profiles by 2018 equivalent to that of facilities employing CCS
technology. The proposed regulatory framework further encourages widespread use
of CCS by 2018 by crediting emitters that make use of CCS technology for
investments in pre-certified CCS projects up to 100 percent of their regulatory
obligations through 2017.
  30
 The
proposed compliance mechanisms include paying into a technology fund, fixed
emission caps and an emissions credit trading system for GHGs and certain
industrial air pollutants, and several options for companies to choose among to
meet GHG emission intensity reduction targets and encourage the development of
new emission reduction technologies., including the option of making payments
into a technology fund, an emissions and offset trading system, limited credits
for emission reductions created between 1992 and 2006, and international
emission credits under the clean development mechanism under the Kyoto Protocol
for up to 10 percent of each firm's regulatory obligation.
  On
January 7, 2008, the National Round Table on the Environment and the Economy
("NRTEE") released a report entitled: Getting to 2050: Canada's Transition to a
Low-emission Future ("Getting to 2050"). The NRTEE is an independent advisory
body to the Canadian Federal Government comprised of representatives from
business, labour, universities, environmental organizations, Aboriginal
communities and municipalities. Getting to 2050 was prepared in response to a
request from the federal Minister of the Environment in November 2006 requesting
NRTEE's advice on scenarios for achieving a 45 to 65 percent reduction in GHG
emissions by 2050. In Getting to 2050, the NRTEE recommended the implementation
of a GHG emission price signal as soon as possible in the form of a GHG emission
tax or a cap-and-trade system or both. NRTEE also recommended complementary
regulatory policies such as regulatory standards, subsidies and infrastructure
investments in parts of the economy that may not respond to price signals.
Initial reaction from the Government indicated that the Government will continue
to implement the Regulatory Framework for Air Emissions and that it was unlikely
to implement an additional GHG emission tax in the near future.
  We
will also be subject to the Alberta Climate Change and Emissions
Management 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.
  Insurance
  The
JV Participants have jointly insured the Project to provide comprehensive
coverage. The joint program comprises course of construction and delay in
start-up coverage for a combined single limit of $1.2 billion for each
occurrence.
  •
              Course
      of Construction for Physical Damage - The policy covers work in progress
      and during inland transportation, construction, installation and start-up.
      A deductible has been selected that is cost effective and within the
      financial capabilities of the JV Participants. Contractors,
      sub-contractors, suppliers and Project lenders are included as additional
      insured parties to control Project costs and potential
    claims.
  •
              Delay
      in Start-up - Delay in start-up coverage provides financial protection to
      the Project in the event a physical damage loss results in a production
      delay.
  •
              Liability
      - Liability considers the potential exposure to third parties, including
      limited coverage for accidental releases of pollution (subject to a $2
      million cap) arising out of the construction activities and includes
      damage to the SAGD Pilot as a result of construction activity.
      Contractors, sub-contractors, suppliers and Project lenders are additional
      insureds. Liability exposures are insured separately under each JV
      Participant’s corporate insurance
program.
   31
  •
              Drilling
      - All wells and drilling operations are being insured under each JV
      Participant’s corporate control of well insurance
  programs.
  •
              Existing
      Facilities - Physical damage (other than damage caused by construction
      activities) are insured under each JV Participant’s corporate insurance
      program.
  This
insurance program will be in place until March 31, 2009, at which time we expect
to transition to a post-construction operating insurance program. We are
currently working with Nexen on the placement of a joint operating insurance
program. The program is expected to include physical damage and business
interruption insurances.
  RESERVES
AND RESOURCES SUMMARY
  The
oil sands reservoir pertaining to the Long Lake, Leismer and Cottonwood Leases
is contained within the McMurray Formation of the basal unit of the Lower
Cretaceous Mannville Group. The McMurray Formation directly overlies the
sub-Cretaceous unconformity that is developed on the Palaeozoic carbonates of
the Beaverhill Lake Group. Directly overlying the McMurray Formation are the
Wabiskaw, Clearwater and Grand Rapids formations of the Mannville Group. At
surface is the Quaternary zone which overlies the Grand Rapids Formation and
also exists as a deep incising channel which cuts through the McMurray Formation
on the eastern side of the Long Lake Lease.
  The
average depth to the top of the McMurray Formation varies from 500 feet at the
northern part of the Long Lake Lease to more than 1,400 feet on the Cottonwood
Leases.
  Over
the leases, the reservoir has impairments including top water, top gas
(overlying the bitumen pay zones) and bottom water (underlying the oil
sands).  In addition, there are some areas that contain intervals of
low bitumen and high water saturation.  These intervals are
interpreted to be generally small and discontinuous, but in some areas reach
thicknesses of 8 to 10 meters, particularly in the area of the SAGD
Pilot.
  Over
the Long Lake Leases, gross pay in the McMurray Formation ranges from 150 feet
in areas of abandoned channel sequences to over 400 feet in areas of channelled
sand sequences. Within this thickness, the McMurray Formation net pay can range
from several feet to more than 200 feet.
  Based
on core analyses, the density of the bitumen varies both aerially and with
depth; at Long Lake, ranging from 6.5 to 8.5oAPI, with an expected volume
weighted average of 7.3oAPI. The bitumen in the lower portion of the McMurray
Formation has a higher density, viscosity and asphaltene content than the
bitumen in the upper portion of the formation.
  Reserves
Data
  McDaniel,
established in 1955, is an independent petroleum consulting firm headquartered
in Calgary, Alberta. McDaniel provides specialized services to the petroleum
industry in such areas as reservoir engineering, reserve estimation, geological
studies, reservoir simulation and all related economic evaluations.
  McDaniel
has prepared a report dated February 11, 2009, evaluating the bitumen reserves
and synthetic oil reserves of the Long Lake Leases effective as of December 31,
2008 (the "McDaniel Report"). Reserves have been recognized at Long Lake in the
Phase 1 area as proved, probable and possible reserves, and in the Phase 2 area
as probable and possible reserves.  The recognition of probable and
possible reserves in the Phase 2 area reflects the greater certainty of their
development than in prior years and the advancement of the regulatory approval
process. No reserves have been assigned to either Leismer or Cottonwood because
near term development is not sufficiently certain.
  32
 The
McDaniel Report has been prepared in compliance with the requirements of NI
51-101, issued by the Canadian Securities Administrators. See Appendix A for
additional reserves data and other oil and gas information presented in
accordance with NI 51-101.
  The
McDaniel Report recognizes the inclusion of upgrading in our reserves. Most of
the raw bitumen will be upgraded and sold as PSCTM and butane, and is shown as
synthetic crude oil or butane reserves. Bitumen will be sold upon start-up of
the SAGD Operation prior to Upgrader start-up, and thereafter during periods of
Upgrader downtime, and is shown as bitumen reserves.
  The
McDaniel Report, as summarized in Appendix A, reflects our reserves and
resources with a 50 percent working interest in the joint venture and prior to
the effect of our sale to Nexen of a 15 percent working interest in the Long
Lake Project and all future phase reserves and resources.  Effective
January 1, 2009, we own a 35 percent working interest in the JV Participants’
reserves and resources. The following table shows our 35 percent working
interest in the raw bitumen reserves and the corresponding sales volumes before
deducting royalties and using forecast prices and costs.
  Summary
of Raw Bitumen Reserves and Sales Volumes
  December
31, 2008
 (MMbbl)
  Raw
                Sales
      VolumesBitumen
                PSCTM
                Bitumen
                ButaneProved
                194
                147
                11
                6Proved
      plus probable
                738
                579
                15
                22Proved
      plus probable plus possible(1)
                804
                632
                15
                24
 
 
 Note:
 (1)
                  Proved reserves are those reserves
      that can be estimated with a high degree of certainty to be
      recoverable.  It is likely that the actual remaining quantities
      recovered will exceed the estimated proven
  reserves.
 (2)
                  Probable reserves are those
      additional reserves that are less certain to be recovered than proven
      reserves. It is equally likely that the actual remaining quantities
      recovered will be greater or less than the sum of the estimated proven
      plus probable reserves.
 (3)
                  Possible reserves are those
      additional reserves that are less certain to be recovered than probable
      reserves. There is a 10 percent probability that the remaining quantities
      actually recovered will be greater than the sum of proven plus probable
      plus possible
reserves.
  33
 Resources
Data
  In
addition to estimating the reserves, McDaniel has estimated bitumen resources
associated with the remainder of the Long Lake, the Leismer and the Cottonwood
Leases. A summary of our 35 percent working interest in the additional resource
estimates is shown below:
 
 Summary
of Bitumen Resources (1)
 December
31, 2008
 (MMbbl)
  
 Raw BitumenRemainder
      of Long Lake leases(2)
                  
                  
                  254Leismer(2)
                  
                  
                  668Cottonwood(3)
                  
                  
                  502Total
                  
                  
                  1,424
 
 
 Notes:
 (1)
              These
      estimates represent the "best estimate" of our resources, are not
      classified or recognized as reserves, and are in addition to our disclosed
      reserve volumes. These resource estimates are categorized primarily as
      Contingent resources, with some categorized as prospective resources. See
      Notes 2 and 3 below.
 Contingent
      resources are those quantities of petroleum estimated, as of a given date,
      to be potentially recoverable from known accumulations using established
      technology or technology under development, but which are not currently
      considered to be commercially recoverable due to one or more
      contingencies. Contingencies may include factors such as economic, legal,
      environmental, political, and regulatory matters, or a lack of markets. It
      is also appropriate to classify as contingent resources the estimated
      discovered recoverable quantities associated with a project in the early
      evaluation stage. There is no certainty that it will be commercially
      viable to produce any portion of the contingent
  resources.
 Prospective
      resources are those quantities of petroleum estimated, as of a given date,
      to be potentially recoverable from undiscovered accumulations by
      application of future development projects. Prospective resources have
      both an associated chance of discovery and a chance of development. There
      is no certainty that any portion of the prospective resources will be
      discovered. If discovered, there is no certainty that it will be
      commercially viable to produce any portion of the
    resources.
 (2)
              The
      resource estimates for Leismer and Long Lake are categorized as contingent
      resources. These volumes are classified as resources rather than reserves
      primarily due to less delineation and the absence of regulatory approvals,
      detailed design estimates and near-term development
  plans.
 (3)
              The
      resource estimate for Cottonwood is categorized as both contingent and
      prospective resources. The estimate of 717 million barrels prior to the
      sale of the 15 percent working interest would be comprised of 274 MMbbl of
      contingent resources and 443 MMbbl of prospective resources. After taking
      account for the sale of the 15 percent working interest, the estimate of
      502 million barrels is comprised of 192 MMbbl of contingent resources and
      310 MMbbl of prospective resources. These contingent Resource volumes are
      classified as resources rather than reserves primarily due to less
      delineation; the absence of regulatory approvals, detailed design
      estimates and near-term development plans; and less certainty of the
      economic viability of their recovery. In addition to those factors that
      result in contingent resources being classified as such, prospective
      resources are classified as such due to the absence of proximate
      delineation drilling.
 
 
 DESCRIPTION
OF CAPITAL STRUCTURE
  Description
of Share Capital
  We
were reorganized and continued under the Canada Business Corporations
Act on May 30, 2002 and our share capital was reorganized under the Canada Business Corporations
Act on April 14, 2004 pursuant to which all of our outstanding shares
became Common Shares, such that the Common Shares were the only issued and
outstanding shares in our capital.  Under our current articles, we are
authorized to issue an unlimited number of Common Shares without nominal or par
value, and an unlimited number of preferred shares, issuable in a series
("Preferred Shares"), of which the first authorized series of Preferred Shares
is an unlimited number of Series A Shares, the second authorized series of
Preferred Shares is an unlimited number of Series B Shares ("Series B Shares"
which together with Series A Shares shall been referred to collectively as the
"Voting Convertible Preferred Shares"), and the third authorized series of
Preferred Shares is an unlimited number of Series C Shares. As of June 1, 2006,
we amended our Articles of Incorporation to divide the issued and outstanding
common shares on a two-for-one basis. All references to share issuances and
stated capital in this AIF give effect to these reorganizations of
capital.
  34
 Holders
of Common and Voting Convertible Preferred Shares are entitled to receive notice
of, and to attend and vote at, all meetings of our shareholders, except class or
series meetings at which only holders of another class or series of our shares
are entitled to vote. Each Common and Voting Convertible Preferred Share will
entitle the holder to one vote.
 Holders
of Common and Voting Convertible Preferred Shares will be entitled to receive
equally, share for share, if, as and when declared by our board of directors,
such dividends as may be declared by the board of directors from time to
time.
  In
the event of our liquidation, dissolution or winding-up, or any other
distribution of our assets among our shareholders for the purpose of winding-up
our affairs, the Voting Convertible Preferred Shares will have the right to
receive the subscription price paid for each such share in priority to the
holders of any other class of shares. Holders of Common Shares shall then be
entitled to receive equally, share for share, an amount which will result in
holders of Common Shares receiving an amount per share equal to the subscription
price paid for each Voting Convertible Preferred Share. Thereafter, holders of
Common and Voting Convertible Preferred Shares shall be entitled to receive
equally, share for share, any remaining value of such distribution.
  At
December 31, 2008, OPTI had 195,929,526 common shares and 7,160,116 common share
options outstanding. The common share options have a weighted average exercise
price of $13.14 per share.  At December 31, 2008, OPTI’s fully diluted
shares outstanding were 203,079,642.   There are no Voting
Convertible Preferred Shares currently outstanding.
 
 Effective
November 2008, 5,991,000 common share warrants with an exercise price of $14.75
per share expired without being exercised. Effective June 2008, $202 million of
call obligations with an exercise price of $2.20 per share expired without being
exercised.
 
 Rights
Plan
  At
the Corporation's annual and special meeting of shareholders held on April 27,
2006, the shareholders of the Corporation adopted a shareholder rights plan (the
"Rights Plan"), all as described in the material change report of the
Corporation dated April 27, 2006. The objectives of the Rights Plan are to
ensure, to the extent possible, that all shareholders of the Corporation are
treated equally and fairly in connection with any takeover bid or similar offer
for all or a portion of the Common Shares of the Corporation. The Rights Plan
discourages discriminatory, coercive or unfair takeovers of the Corporation and
gives the board of directors time if, in the circumstances, the board of
directors determines it is appropriate to take such time, to pursue alternatives
to maximize shareholder value in the event an unsolicited takeover bid is made
for all or a portion of the outstanding Common Shares of the
Corporation.
  35
 Registration
Rights
  In
connection with prior issuances of equity securities, we have agreed with
certain shareholders that in the event we cause our shares to become listed on
the NASDAQ stock market or another national stock exchange in the United States
at any time prior to April 15, 2009, we will enter into a registration rights
agreement with such holders in a form reasonably acceptable to us, which will
include demand rights and piggyback rights, and will address certain other
matters typically addressed in a registration rights agreement.
  Description
of Debt Capital
  We
have a revolving credit facility in the maximum principal amount of $350 million
that expires on December 15, 2011. Prior to the closing of the Nexen Transaction
in January 2009, this facility was in the amount of $500 million. Upon closing
the sale of 15 percent working interest, the facility was permanently reduced to
$350 million. At February 17, 2009, after using proceeds from the Nexen
Transaction to fund a partial pay-down, $87 million remained outstanding on the
$350 million revolving credit facility.
  An
additional first lien revolving debt facility was established during the second
quarter of 2008 in the maximum principal amount of $150 million. Other than
maturity date and amount, the terms and conditions of this facility were the
same as the $500 million revolving credit facility. Upon closing the sale of the
15 percent working interest in January 2009, this debt facility was repaid and
cancelled.
  Our
$350 million revolving credit facility contains a number of provisions that
serve to limit the amount of debt we are permitted to incur. The key maintenance
covenants are with respect to debt to capitalization and the ratio of debt
outstanding under the revolving credit facility to EBITDA. Maintenance covenants
are ongoing conditions that must be satisfied to provide continued access to the
revolving credit facility.
 
 The
first lien to EBITDA covenant as amended in January 2009 is measured quarterly
and requires that this ratio must be lower than 2.5:1 commencing for the quarter
ended September 30, 2009. The first three measurements of EBITDA for this
covenant will annualize EBITDA as measured from July 1, 2009 to the end of the
applicable covenant period. Thereafter, EBITDA will be based on a trailing four
quarters. Realized cash gains on commodity contracts, such as our existing puts
and forwards, are included in EBITDA for the purposes of the covenant. If we are
unable to generate sufficient EBITDA, we may be required to repay all or a
portion of amounts outstanding under that facility, or we may be unable to make
additional borrowings under the revolving credit facility, or we may be required
to request and obtain approval for a waiver from our lenders under the
facility.
 
 The
debt to capitalization covenant, as amended in January 2009, requires that we do
not exceed a ratio of 70 percent as calculated on a quarterly
basis.  The covenant is calculated based on the book value of debt and
equity. The book value of debt is adjusted for the effect of any foreign
exchange derivatives issued in connection with the debt that may be outstanding.
At December 31, 2008, this means that our debt would be reduced by the value of
our foreign exchange forward in the amount of $32 million. With respect to US
dollar denominated debt, for purposes of the debt to capitalization ratio, the
debt is translated to Canadian dollars based on the average exchange rate for
the quarter. The debt to capitalization is therefore influenced by the
variability in the measurement of the foreign exchange forward which is subject
to mark to market variability and the average foreign exchange rate changes
during the quarter.
 
 36
 In
respect of new borrowings under the $350 million revolver facility prior to
reaching completion of the Project, we are required to have sufficient funds
(including cash and undrawn revolver availability) to fund our share of
remaining Project costs.
 
 On
December 15, 2006, we issued US$1,000,000,000 principal amount of senior secured
notes which bear interest at 8.25 percent per annum (the "8.25%
Notes").  Semi-annual interest payments are due June 15 and December
15 of each year, with the final payment due on December 15, 2014.  We
may redeem up to 35 percent of the aggregate principal amount of the notes prior
to December 15, 2009 with the net proceeds from certain equity
offerings.  At any time prior to December 15, 2010, we may redeem some
or all of the notes at their principal amount plus the applicable premium and
accrued interest.  After December 15, 2010, we may redeem some or all
of the notes at the specified redemption price plus accrued
interest.  We may also redeem the notes in certain other limited
circumstances, including upon a change of control and in the event of certain
tax law changes.  The notes are our general senior obligations and
rank equally in right of payment with all of our existing and future senior
indebtedness and rank senior to all of our future subordinated
indebtedness.  The notes are secured by a second ranking charge over
all of our assets and the assets of our present and future restricted
subsidiaries.
  On
July 5, 2007, we issued US$750,000,000 principal amount of senior secured notes
which bear interest at 7.875 percent per annum (the "7.875% Notes"). The terms
and conditions associated with the 7.875% Notes, with the exception of interest
payable, are substantially the same as those of the 8.25% Notes described
above.
  In
connection with the 8.25% Notes and the 7.875% Notes, we had pre-funded interest
until December 15, 2008 which was held in an interest reserve account. The
account was closed on December 15, 2008. On a go forward basis, interest
payments will be paid from working capital.
 
 With
respect to our senior secured notes, covenants are in place primarily to limit
the total amount of debt that OPTI may incur at any time. This limit is most
affected by the present value of our total proved reserves using forecast prices
discounted at 10 percent.  Based on our 2008 reserve report, we have
sufficient capacity under this test to incur additional debt beyond our existing
$350 million revolving credit facility and existing senior secured notes.
However other leverage factors, such as the debt to capitalization and the total
debt to EBITDA covenants, are expected to be more constraining than this
limitation.
 
 OPTI
is exposed to foreign exchange rate risk on our U.S. dollar denominated debt. To
partially mitigate this exposure, we have entered into US$875 million of foreign
exchange forwards to manage some of the exposure to repayment risk due to
decline in value of the Canadian dollar. The forward contracts provide for the
purchase of U.S. dollars and the sale of Canadian dollars at a rate of
approximately CDN$1.17 to US$1.00 with an expiry in April 2010. With respect to
our U.S. dollar denominated debt, we believe that these forward contracts
provide protection against a decline in the value of the Canadian dollar below
CDN$1.17 to US$1.00 on a portion of our debt. The value of these derivatives
affects our debt covenants as the value of these contracts is included in the
measurement of our debt for covenant purposes.
 
 37
  CREDIT
RATINGS
  OPTI's
notes are currently rated by two separate agencies, Moody’s Investor Service
("Moody’s") and Standard and Poors ("S&P").
  Type of Security
                Moody's
                S&P8.25%
      Notes
                B3
                B-7.875%
      Notes
                B3
                B-
 
  OPTI
and OPTI's Revolving Credit Facility are currently rated by Moody’s and
S&P.
  Moody's
                S&POPTI
      Corporate Rating
                B3
                B-Revolving
      Credit Facility
                Ba3
                B+
 
 On
February 26, 2009, Moody’s downgraded OPTI’s Corporate Rating and second secured
note ratings, and confirmed its first secured revolver
rating.  Moody’s rating outlook is negative.  According to
Moody’s, the downgrades reflect a reduced likelihood that OPTI and Nexen
(project operator) will have the Project adequately close to design
specifications in time for OPTI to demonstrate internal support of its debt
structure by year-end 2009.
 
 The
S&P ratings have been on credit watch with negative implications since
November 2008.
 
 Moody’s
Rating Definition - Moody's long-term obligation ratings are opinions of the
relative credit risk of fixed-income obligations with an original maturity of
one year or more. They address the possibility that a financial obligation will
not be honoured as promised. Such ratings reflect both the likelihood of default
and any financial loss suffered in the event of default. Obligations rated B are
judged to have speculative elements and are subject to substantial credit risk.
Moody's appends numerical modifiers 1, 2, and 3 to each generic rating
classification from Aa through Caa. The modifier 1 indicates that the obligation
ranks in the higher end of its generic rating category; the modifier 2 indicates
a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of
that generic rating category. Investment grade under the Moody’s rating system
would be Baa3 and higher.
  S&P
Rating Definitions - Obligations rated B are regarded as having significant
speculative characteristics. An obligation rated B is more vulnerable to
non-payment than obligations rated 'BB', but the obligor currently has the
capacity to meet its financial commitment on the obligation. Adverse business,
financial, or economic conditions will likely impair the obligor's capacity or
willingness to meet its financial commitment on the obligation.
 
 A
security rating is not a recommendation to buy, sell or hold securities and may
be subject to revision or withdrawal at any time by the rating
organization.
  38
 MARKET
FOR SECURITIES
  Our
Common Shares are listed for trading on the Toronto Stock Exchange under the
symbol "OPC".  The following table sets for the high, low and closing
trading prices and the volume of Common Shares traded on the Toronto Stock
Exchange for each month of 2008:
  Month
                  
                  High
                  
                  
                  Low
                  
                  
                  Closing
                  
                  
                  VolumeJanuary
                  
                  $
                  18.62
                  
                  
                  $
                  15.30
                  
                  
                  $
                  16.55
                  
                  
                  
                  30,574,366February
                  
                  $
                  18.29
                  
                  
                  $
                  16.35
                  
                  
                  $
                  17.30
                  
                  
                  
                  19,098,427March
                  
                  $
                  17.62
                  
                  
                  $
                  15.41
                  
                  
                  $
                  17.30
                  
                  
                  
                  24,882,322April
                  
                  $
                  21.70
                  
                  
                  $
                  17.01
                  
                  
                  $
                  21.32
                  
                  
                  
                  25,520,310May
                  
                  $
                  24.25
                  
                  
                  $
                  20.99
                  
                  
                  $
                  22.50
                  
                  
                  
                  26,204,798June
                  
                  $
                  25.40
                  
                  
                  $
                  21.40
                  
                  
                  $
                  23.10
                  
                  
                  
                  25,134,995July
                  
                  $
                  23.46
                  
                  
                  $
                  18.20
                  
                  
                  $
                  19.44
                  
                  
                  
                  16,008,917August
                  
                  $
                  19.93
                  
                  
                  $
                  16.08
                  
                  
                  $
                  19.25
                  
                  
                  
                  22,679,665September
                  
                  $
                  19.24
                  
                  
                  $
                  9.71
                  
                  
                  $
                  11.05
                  
                  
                  
                  39,145,403October
                  
                  $
                  11.05
                  
                  
                  $
                  2.47
                  
                  
                  $
                  3.21
                  
                  
                  
                  63,042,917November
                  
                  $
                  4.02
                  
                  
                  $
                  1.10
                  
                  
                  $
                  2.18
                  
                  
                  
                  75,925,746December
                  
                  $
                  3.05
                  
                  
                  $
                  1.56
                  
                  
                  $
                  1.80
                  
                  
                  
                  62,067,913
 
  DIVIDENDS
  We
have not paid any dividends on the Common Shares or any other class or series of
shares to date. The payment of dividends in the future will be dependent upon
our earnings and financial position and on such other factors as our board of
directors consider appropriate.
  The
payment of dividends may also be subject to certain restrictions pursuant to our
credit facilities.
  DIRECTORS
AND OFFICERS
  Set
forth below are the names, titles and certain other information about our
directors and executive officers.
  Name
      and
                    Residence
                  Present
      Position
                    and
      Office
                  Position
      Held Since(1)(2)
                  Principal
      OccupationDirectorsJames
      M. Stanford(6)
                    Alberta,
      Canada
                  Chairman
      and Director
                  May
      30, 2002
                  President
      of Stanford Resource Management Inc., a financial management
      companyYoram
      Bronicki(4)(7)
                    Nevada,
      USA
                  Director
                  December
      29, 2001
                  President
      and Chief Operating Officer of  ORMAT Technologies
      Inc.Ian
      W. Delaney(4)(6)
                    Ontario,
      Canada
                  Director
                  November
      16, 2005
                  Chairman
      and Chief Executive Officer, Sherritt International Corporation, a
      diversified resource companyCharles
      L. Dunlap(3)(7)
                    Texas,
      USA
                  Director
                  June
      29, 2006
                  Management
      Consultant    39
   Name
      and
                              Residence
                            Present
      Position
                              and
      Office
                            Position
      Held Since(1)(2)
                            Principal
      OccupationSid
      Dykstra[14]
                              Alberta,
      Canada
                            President,
      CEO and Director
                            December
      29, 2001
                            President
      and Chief Executive Officer of OPTIRandall
      Goldstein(4)
                              California,
      USA
                            Director
                            January
      18, 1999
                            Chief
      Executive Officer of OptiSolar Inc., a private solar power
      companyEdythe
      (Dee) A. Marcoux(5)(7)
                              Alberta,
      Canada
                            Director
                            July
      16, 2008
                            Retired
      oil executiveRobert
      G. Puchniak(3)(6)
                              Manitoba,
      Canada
                            Director
                            May
      30, 2002
                            Executive
      Vice President and Chief Financial Officer of James Richardson & Sons,
      Limited, an investment and holding companyChristopher
      P. Slubicki(5)(6)
      (15)
                              Alberta,
      Canada
                            Director
                            February
      1, 2007
                            Energy
      InvestorSamuel
      Spanglet(5)(7)
                              Alberta,
      Canada
                            Director
                            October
      26, 2007
                            Retired
      oil executiveJames
      van Hoften(3)(5)
                              California,
      USA
                            Director
                            July
      12, 2007
                            Retired
      executiveBruce
      Waterman(3)(4)
                              Alberta,
      Canada
                            Director
                            July
      16, 2008
                            Senior
      Vice President, Finance and Chief Financial Officer of Agrium Inc. , a
      public agricultural supply
company.
 OfficersSid
      Dykstra[14]
                Alberta,
      Canada
              President
      and CEO
              July
      6, 2001
              see
      aboveJames
      Arnold(8)
      (9)
                Alberta,
      Canada
              Chief
      Operating Officer
              October
      13, 2005
              Chief
      Operating OfficerDavid
      Halford [12]
                Alberta,
      Canada
              Chief
      Financial Officer
              April
      10, 2007
              Chief
      Financial OfficerTravis
      Beatty [12]
                Alberta,
      Canada
              Vice
      President, Finance and Chief Financial Officer
              March
      1, 2009
              Chief
      Financial OfficerJoe
      Bradford
                Alberta,
      Canada
              Vice
      President, Legal and Administration and Corporate Services
              October
      14, 2008
              General
      Counsel and Corporate SecretaryMary
      Bulmer (13)
                Alberta,
      Canada
              Vice
      President, Human Resources and Corporate Services
              April
      15, 2004
              Vice
      President, Human Resources and Corporate ServicesPeter
      Duda(10)
                Alberta,
      Canada
              Vice
      President, Operations
              October
      13, 2005
              Vice
      President, Operations William
      W.
      King
                  Alberta,
      Canada
                Vice
      President, Development
                August
      1, 2008
                Vice
      President, Major ProjectsAlan
      Smith(11)
                  Alberta,
      Canada
                Vice
      President, Marketing
                March
      1, 2009
                Vice
      President, Marketing
  40
 Notes:
 (1)
              All
      of the directors of OPTI have been elected or appointed to hold office
      until the next annual meeting of shareholders or until their successor is
      duly elected or appointed, unless their office is earlier
      vacated.
 (2)
              Indicates
      date of election or appointment as director or officer of
      OPTI.
 (3)
              Member
      of the Audit Committee.
 (4)
              Member
      of the Compensation Committee.
 (5)
              Member
      of the Environment, Health and Safety
Committee.
 (6)
              Member
      of the Governance and Nominating
Committee.
 (7)
              Member
      of the Technical Committee.
 (8)
              Formerly
      Vice President, Development from January 1, 2000 to October 13,
      2005.
 (9)
              On
      January 31, 2009, Mr. Arnold resigned from OPTI to accept a position at
      Nexen.  He continues to be involved in Long Lake operations and
      future development.
 (10)
              Effective
      February 28, 2009, Peter Duda left his employment at OPTI
  .
 (11)
              Alan
      Smith was appointed Vice President, Marketing effective March 1,
      2009.
 (12)
              Effective
      March 1, 2009, David Halford resigned from OPTI to pursue other business
      opportunities, at which time Travis Beatty was appointed Vice President,
      Finance and Chief Financial
Officer.
 (13)
              Effective
      March 31, 2009, Mary Bulmer will leave her employment at
    OPTI.
 (14)
              Effective
      April 28, 2009, Sid Dykstra will leave his employment at OPTI and cease to
      be a director of OPTI.
 (15)
              Effective
      April 28, 2009, Christopher Sublicki will become President and Chief
      Executive Officer of OPTI.
 
 As
at December 31, 2008, our directors and officers, as a group, beneficially own,
directly or indirectly, or exercise control or direction over 674,093 of our
common shares or 0.34 percent of our issued and outstanding common
shares.
  Board
of Directors
  Brief
biographies for each member of our board of directors are set forth
below:
  James
M. Stanford
  Mr.
Stanford is the Chairman of OPTI's board of directors.  He is the
President of Stanford Resource Management Inc., and retired President, Chief
Executive Officer and a director of Petro-Canada, having held those positions
from 1993 to 2000. Mr. Stanford served as the President, Chief Operating Officer
and a director of Petro-Canada from 1990 to 1993. Prior to joining Petro-Canada
in 1978, Mr. Stanford worked with Mobil Oil Canada Ltd. for 19 years in numerous
engineering and managerial positions.
  Mr.
Stanford acts as Chairman of the board for Nova Chemicals Corporation, and sits
on the board of directors of EnCana Corporation. Mr. Stanford also serves on a
variety of other industry and community organizations.
  Mr.
Stanford holds an LL.D. (Hon.) and a B.Sc. in petroleum engineering from the
University of Alberta and an LL.D. (Hon.) and a B.Sc. in mining from Concordia
University. In 2004, he was appointed an Officer of the Order of
Canada.
  Yoram
Bronicki
  Mr.
Bronicki, President and Chief Operating Officer of ORMAT Technologies Inc. since
September 2007 and July 2004, respectively, was the Vice President, OrCrudeTM
Upgrading of OPTI from its inception until June, 30, 2004. Mr. Bronicki, a
co-inventor of the OrCrudeTM Process, was a project manager with ORMAT from 1996
to 2000. Mr. Bronicki oversaw and managed the development, design, construction,
operations and testing of the one bbl/d OrCrudeTM Process pilot plant in Israel
and the demonstration plant near Cold Lake, Alberta.
  Mr.
Bronicki holds a B.Sc. in mechanical engineering from the Tel Aviv University
and a certificate from the Technion Institute of Management Senior Executives
Program.
  41
 Ian
W. Delaney
  Mr.
Delaney is the Chairman and Chief Executive Officer of Sherritt International
Corporation of Toronto, Ontario. Since 1995, and prior to his appointment as
CEO, Mr. Delaney was the Executive Chairman of Sherritt. From 1990 to 1995, Mr.
Delaney was the Chairman and Chief Executive Officer of Viridian Inc., a
fertilizer company (formerly Sherritt Inc.) acquired by Agrium Inc. in 1996. He
was President and CEO of The Horsham Corporation, a holding company, from 1987
to 1990; and President and Chief Operating Officer of Merrill Lynch Canada, a
financial management and advisory company, from 1984 to 1987.
  Mr.
Delaney is a director of EnCana Corporation and Chairman of The Westaim
Corporation, a technology investment company. He has previously served on a
number of boards, including Co-Steel Inc., MacMillan Bloedel Ltd., and GoldCorp
Inc.
  Charles
Dunlap
  Prior
to his current role as a Management Consultant, Mr. Dunlap was most recently the
Chief Executive Officer and President of Pasadena Refining System Inc., operator
of a Houston, Texas-based refinery producing gasoline and diesel fuels with
revenues of $2.6 billion in 2008. Mr. Dunlap is currently a member of the board
of directors for Transmontaigne GP L.L.C., a publicly traded Master Limited
Partnership. In addition, Mr. Dunlap has served on the board of directors of
various publicly traded companies over the past 14 years.
  Prior
to joining Pasadena Refining, Mr. Dunlap’s career included over 30 years of
senior management experience, predominantly in the petroleum industry, including
executive positions with Crown Central Petroleum Corporation, Pacific Resources
Inc., ARCO Petroleum Products Company, and Clark Oil & Refining
Corporation.
  Mr.
Dunlap holds a juris doctor degree from the Saint Louis University School of Law
and an undergraduate degree from Rockhurst College.
  Sid
Dykstra
  Mr.
Dykstra has been the President and Chief Executive Officer of OPTI since June
2001. From June 2000 to March 2001, Mr. Dykstra was the President of Hunt Oil
Company of Canada Inc. Mr. Dykstra, a co-founder of Newport Petroleum
Corporation, was the President and Chief Operating Officer of Newport from 1997
to 2000, the Executive Vice President of Newport from 1994 to 1997 and the Vice
President, Engineering of Newport from 1992 to 1994. From 1980 to 1992, Mr.
Dykstra held various positions with Suncor, Inc., was the Manager of
Exploitation for Pancontinental Oil Ltd. and was an independent consultant with
Maranta Resources Ltd.
  42
 Mr.
Dykstra is currently a director of Cinch Energy Corp. and is a past Governor of
the Canadian Association of Petroleum Producers. Mr. Dykstra is a professional
engineer in Alberta and holds numerous professional affiliations and
memberships.
  He
holds a B.Sc. in chemical engineering from the University of Alberta and an
M.B.A. from Queen’s University.
  Mr.
Dykstra will leave his employment with OPTI effective April 28,
2009.
  Randall
Goldstein
  Mr.
Goldstein is currently Chief Executive Officer of OptiSolar, Inc. Previously, he
was the President of ORMAT Process Technologies, Inc. and was employed by the
ORMAT Group of Companies. He is a co-inventor of the OrCrudeTM
Process.
  Mr.
Goldstein was a co-founder of National Power Company and held the position of
Chief Financial Officer of that company from 1991 to 1994. National Power
Company is a developer of independent power projects using low value opportunity
fuels. Mr. Goldstein was employed by the Harbert Power Group from 1987 to 1991
as Manager of Project Finance. In that capacity he was responsible for business
development and financing of independent power projects, including a number of
projects fuelled by petroleum coke. Prior to that, Mr. Goldstein was employed by
ORMAT Energy Systems Inc. as Manager of Project Finance, responsible for the
financing of geothermal power plants.
  Mr.
Goldstein holds a B.A. in economics from the University of California, Berkeley
and a M.Sc. in energy management and policy from the University of
Pennsylvania.
  Edythe
(Dee) A. Marcoux
 
 Ms.
Marcoux is a retired executive from the oil industry with extensive experience
with several major oil and gas companies including Suncor Inc. She is currently
a director of Sherritt International Corporation and SNC-Lavalin. She was a
consultant to Ensyn Group Inc. a heavy oil upgrading technology company from
2002 to mid-2005 and was previously, from 2001 to 2002, Chairman and Chief
Executive Officer of Ensyn Energy, a subsidiary of Ensyn Group Inc. As well, Ms.
Marcoux worked as a consultant and served as a director of Southern Pacific
Petroleum NL (“SPP”), a company developing shale oil reserves in Australia from
1998 to 2003. During this time, SPP’s securities were suspended from quotation
on the Australian Stock Exchange prior to the commencement of trading on
November 23, 2003 for a period of more than 30 consecutive days, and in respect
of which receivers were appointed on December 2, 2003. SPP’s securities are not
currently traded. Ms. Marcoux resigned as a director of SPP with effect from
12:00 noon on December 5, 2003.
 
 Ms.
Marcoux holds an engineering degree, a Masters of Business Administration and an
honourary Ph.D., all from Queen’s University.
 
 Robert
G. Puchniak
  Mr.
Puchniak has been the Executive Vice President and Chief Financial Officer of
James Richardson & Sons, Limited, an investment and holding corporation,
since March 2001 and prior thereto, was Vice President, Finance and Investment
with James Richardson & Sons, Limited since November 1996.  Mr.
Puchniak was President and Chief Executive Officer of Tundra Oil & Gas
Limited, a private oil and gas corporation, from January 1989 to April
2003.
  43
 Mr.
Puchniak is a director of a number of public and private corporations including
Richardson International Limited, Tundra Oil & Gas Limited, Value Creation
Inc., Richardson Partners Financial Holdings Limited, OptiSolar, Inc., Strad
Energy Services Ltd. and Lombard Realty Limited.  His past
involvements include Director, Western Oil Sands Inc., Petrobank Energy and
Resources Ltd., Trident Resources Corp., Moffat Communications Limited and
Richland Petroleum Corporation; Chairman, Manitoba Teachers’ Retirement Fund;
Chairman, Council of Examiners, Institute of Chartered Financial Analysts; and
President, Winnipeg Society of Financial Analysts.
  Mr.
Puchniak holds a B.Comm. (Honours) from the University of Manitoba and was
awarded the University Gold Medal for his achievements.  He earned a
Chartered Financial Analyst designation in 1975.
  Christopher
P. Slubicki
  Mr.
Slubicki has been appointed President and Chief Executive Officer of OPTI
effective April 28, 2009. Mr. Slubicki was formerly the Vice Chairman of Scotia
Waterous. Mr. Slubicki was one of the founders of Waterous & Co., a private
global oil and gas investment banking firm, where he was involved in all aspects
of the firm's strategic development as Senior Managing Director and Principal.
Waterous & Co. was sold to The Bank of Nova Scotia in 2005. Prior to the
founding of Waterous, Mr. Slubicki held operations management and engineering
positions within the oil and gas industry including Placer CEGO Petroleum Ltd.
and Chevron Canada Resources Limited. Mr. Slubicki is a director of OptiSolar,
Inc., Bonavista Energy Trust and Insignia Energy Inc.
  Mr.
Slubicki holds a Masters of Business Administration from the University of
Calgary, a B.Sc. in Mechanical Engineering from Queen's University, and is a
professional engineer in Alberta.
  Samuel
Spanglet
  Mr.
Spanglet was most recently the Vice President Operations, Oil Sands and
President, Albian Sands Energy Inc. at Shell Canada. There, he oversaw all
oilsands operations, including the Scotford Complex and Albian Sands.
Previously, he was the general manager of the Scotford Complex, responsible for
managing Shell's manufacturing in Western Canada, as well as overseeing the
successful integration of a newly constructed upgrader. Mr. Spanglet also held
other managerial positions within Shell Canada during his 25 year
tenure.
  Mr.
Spanglet holds a Bachelor of Science in chemical engineering from the Technion
Institution of Technology in Haifa, Israel, and is currently a member of the
board of directors of ATCO Power.
  James
van Hoften
  Dr.
van Hoften was most recently a Senior Vice President and Partner at Bechtel
Corporation (Bechtel), one of the world's largest engineering, construction, and
project management companies. In his 20 years at Bechtel, he held responsibility
for some of the world's largest construction projects. Dr. van Hoften is also a
former NASA astronaut and flew two Space Shuttle missions. Prior to that, Dr.
van Hoften was an assistant professor of civil engineering at the University of
Houston.
  Dr.
van Hoften is currently a director of Flex LNG, a London based LNG shipping and
production company. Dr. van Hoften holds a Ph.D. in hydraulic engineering from
Colorado State University, and a B.Sc. in civil engineering from the University
of California at Berkeley.
  44
 Bruce
Waterman
  Mr.
Waterman is the Senior Vice President, Finance and Chief Financial Officer of
Agrium Inc. He joined Agrium in 2000 and has more than 30 years experience as a
financial executive. Prior to joining Agrium, Mr. Waterman was the Vice
President and Chief Financial Officer of Talisman Energy Inc.
 
 Mr.
Waterman holds a Bachelor of Commerce from Queen's University and is a Chartered
Accountant.
  Officers
  At
December 31, 2008, our management team was comprised of the following
individuals:  Sid Dykstra, Jim Arnold, David Halford, Joe Bradford,
Mary Bulmer, Peter Duda and William King.
 
 As
a result of the Nexen Transaction, there have been changes to OPTI’s management
team as reflected below.
 
 Jim
Arnold
 
 Prior
to his appointment to this position in October 2005, Mr. Arnold was our Vice
President, Development since January 2000. During 1999, Mr. Arnold was the
General Manager and Reservoir Engineering Manager of Canadian Occidental
Petroleum’s Heavy Oil Business Unit and during 1998 was the General Manager
Facilities (Domestic) of Canadian Occidental Petroleum. Mr. Arnold held various
positions with Wascana Energy Inc. (formerly Saskoil) from 1982 to 1997, ranging
from Development Engineer to General Manager, Deep/Medium Gas Business
Unit.
 
 Mr.
Arnold holds, and has held, numerous professional affiliations and memberships
with petroleum related organizations and associations.
 
 Mr.
Arnold is a professional engineer in Alberta. He holds a B.Sc. in mechanical
engineering from the University of Manitoba.
 
 Mr.
Arnold resigned from OPTI effective January 31, 2009, to accept a position at
Nexen.  He continues to be involved in Long Lake operations and future
development.
 
 Travis
Beatty
 
 Travis
Beatty was appointed Vice President, Finance and Chief Financial Officer of OPTI
effective March 1, 2009. Mr. Beatty joined OPTI in 2002 as Controller and since
then has also held the roles of Treasurer and Director, Planning. Prior to
joining OPTI, Mr. Beatty was the VP Finance and Chief Financial Officer of
International Datashare Corporation from 2000 to 2002,  Mr. Beatty also
worked for Hunt Oil Company of Canada (formerly Newport Petroleum Canada) and
KPMG LLP.
 
 Mr.
Beatty is a Chartered Accountant and a Chartered Financial Analyst, and holds a
Bachelor of Commerce from the University of Calgary.
 
 David
Halford
 
 Mr.
Halford joined OPTI in April 2007.  Most recently, Mr. Halford held the
position of Vice President and Chief Financial Officer at BA Energy in
Calgary.  Prior, Mr. Halford was the Chief Financial Officer of Irving Oil,
a New Brunswick-based refiner and marketer of petroleum products.  Before
joining Irving Oil, Mr. Halford was a Partner in the Corporate and Finance group
in the Toronto office of Deloitte and Touche LLP.
 
 45
 Mr.
Halford is a Chartered Accountant and holds a B.A. from the University of
Western Ontario.
 
 Mr.
Halford resigned to pursue other business opportunities effective March 1,
2009.
 
 Joseph
Bradford
 
 Mr.
Bradford joined OPTI in October 2008 in the newly created role of General
Counsel and Corporate Secretary.  Effective March 1, 2009, he was appointed
Vice President, Legal and Administration and Corporate
Services.  Prior to joining OPTI, he held a number of senior
management positions including Senior Vice President, Commercial and Legal with
Advanced Biodiesel Group and Vice President, Regulatory and Legal at Electricity
Supply Board International (Alberta), Alberta’s first independent electrical
transmission administrator.  Additionally, he was a board member of
Veridian Corporation, one of Ontario’s largest distributors of electricity and
has consulted to the United Horsemen of Alberta.
 
 Mr.
Bradford holds a L.L.B. from Queen’s University, a B.A. (Hons.) from St. Francis
Xavier University and a Queen’s Commission from the Canadian School of
Infantry.  He is a member of the Law Society of Alberta and the Law Society
of Upper Canada.
 
 Mary
Bulmer
 
 Ms.
Bulmer is our Vice President, Human Resources and Corporate Services. She joined
OPTI as a consultant in October 2003 and was promoted to her current position in
April 2004. From 2000 to 2002, Ms. Bulmer was the Vice President of Human
Resources and Corporate Services, Corporate Officer of Hunt Oil Company of
Canada Inc., and from 1992 to 2000, Ms. Bulmer was the Director of Human
Resources of Koch Petroleum Canada L.P.
 
 Ms.
Bulmer holds a M.Sc. in counselling psychology from the University of Calgary
and a B.A. (Honours) from the University of Western Ontario.
 
 Ms.
Bulmer’s employment with OPTI will end on March 31, 2009.
 
 Peter
Duda
 
 Mr.
Duda joined OPTI in 2003 as the General Manager, Upgrader Operations and was
promoted to Vice President, Operations, in October 2005. From December 2000 to
2003, Mr. Duda was the Venture Operations Manager of Petrola Hellas S.A.
(Greece) and, prior thereto, Mr. Duda held executive and managerial positions as
Vice- President Manufacturing and as a director of Chevron Canada Limited
concurrent with his position as a director of Alberta Envirofuels from 1997 to
2000. Mr. Duda was the General Manager of Alberta Envirofuels from 1992 to
1997.
 
 Mr.
Duda is a professional engineer in Alberta and British Columbia. Mr. Duda holds
a B.A.Sc. in mechanical engineering from the University of Alberta.
 
 Mr.
Duda currently serves as a member of the Keyano College board of Governors, and
has held positions in the past as vice chair of the Keyano College Foundation
and as a director for the Strathcona Industrial Association.
 
 Mr.
Duda’s employment with OPTI ended effective February 28, 2009.
 
 46
 William
King
 
 Mr.
King is currently Vice President, Development.  He joined OPTI in mid-2004
as Area Project Manager, OrCrude. Before being promoted to his current position,
Mr. King was Director, Phase 2 Upgrader and Vice President, Major Projects.
Prior to joining OPTI, he held project management positions with ConocoPhillips,
Gulf Indonesia and Gulf Canada.
 
 Mr.
King holds, and has held, numerous professional affiliations and memberships
with petroleum related organizations and associations, including the Project
Management Institute and the Canadian Gas Processors Association. He is
currently a member of APEGGA. Mr. King is a Professional Engineer in Alberta and
holds a B.Sc. in Chemical Engineering from the University of
Alberta.
 
 Alan
Smith
 
 Mr.
Smith is presently the Vice President, Marketing of OPTI. He joined OPTI in 2006
as Director of Marketing, and was appointed to his present position effective
March 1, 2009. Mr. Smith possesses over 27 years of petroleum industry
experience in disciplines including upstream heavy oil, upgrading and synthetic
production, midstream marketing, and downstream refining. From 2000 until his
time with OPTI, Mr. Smith was Manager of Market Development at Chevron Canada
Resources. He also worked as Business Coordinator and Supervisor for a Chevron
Products plant in California and held various positions with Chevron Canada’s
Burnaby plant. In addition, Mr. Smith held positions as operations manager at
Alberta Envirofuels and in project engineering at Turbo Resources.
 
 Mr.
Smith is a professional engineer in Alberta with membership in both APEGGA and
APEGBC. He holds a B.A.Sc. in Chemical Engineering from the University of
Waterloo.
 
 Audit
Committee
  Our
board of directors has adopted a charter for the Audit Committee which clearly
defines the committee's responsibilities in the areas of external audit,
internal controls, governance and financial reporting. Set out in
Appendix D is the text of the Audit Committee's charter.
  The
Audit Committee is comprised of Messrs. Puchniak (Chairman), Dunlap, van Hoften
and Waterman. All four members are financially literate and independent for the
purposes of Multilateral Instrument 52-110 "Audit Committees", by the Canadian
Securities Administrators.
  47
 Auditor
Service Fees
  PricewaterhouseCoopers
LLP has served as the auditors of OPTI since its incorporation. The following
table summarizes the total fees paid to PricewaterhouseCoopers LLP for the years
ended 2008 and 2007 in thousands of dollars:
  2008
                                
                                
                                
                                2007
                                **Audit
      fees
                                
                                $
                                187
                                
                                
                                $
                                158Audit-related
      fees
                                
                                
                                49
                                
                                
                                
                                249Tax
      fees
                                
                                
                                68
                                
                                
                                
                                66Other
                                
                                
                                37
                                
                                
                                
                                -TOTAL
                                
                                $
                                347
                                
                                
                                $
                                473
 
 **
2007 fees were adjusted for a fee credit that was received in 2008.
  Audit
fees were paid for professional services rendered by the auditors for the audit
of our annual financial statements, review of interim quarterly financial
statements and services provided for statutory and regulatory filings.
Audit-related fees are in connection with language translation of public
documents and services provided in connection with financing activities. Tax
fees were primarily related to the completion of our corporate tax returns.
Other fees in 2009 are related to environmental evaluation services
provided.  PricewaterhouseCoopers LLP was engaged, based on associated
expertise, to conduct a high level assessment of the readiness of OPTI’s
Environmental Compliance Systems in anticipation of the start-up of
operations.
  As
per the audit committee charter, all permissible categories of non-audit
services require pre-approval from the Audit Committee.
  CONFLICTS
OF INTEREST
  Our
right to utilize the OrCrudeTM Process technology is pursuant to an exclusive
license to us from OPTI BV, a wholly-owned subsidiary of ORMAT which is an
entity that constitutes part of the ORMAT Group of Companies. One member of our
board of directors is an officer of a separate entity that also constitutes part
of the ORMAT Group of Companies and one member of our board of directors is a
former officer of an entity which is a member of the ORMAT Group of Companies
and, as a result of such positions and shareholdings, such directors of OPTI may
become subject to conflicts of interest in the future. Additionally, certain of
the directors and officers of OPTI may engage in, or are engaged in, other
business activities on their own behalf or on behalf of other companies or are
directors of other companies and, as a result of such activities or positions,
such directors and officers of OPTI may become subject to conflicts of interest
in the future. The Canada
Business Corporations Act provides that a director or officer shall
disclose the nature and extent of any interest that he or she has in a material
contract or material transaction, whether made or proposed, if the director or
officer:
  •
              is
      a party to the contract or
transaction,
  •
              is
      a director or an officer, or an individual acting in a similar capacity,
      of a party to the contract or transaction,
or
  •
              has
      a material interest in a party to the contract or
    transaction,
  and
shall refrain from voting on any matter in respect of such contract or
transaction unless otherwise provided under the Canada Business Corporations
Act.
  To
the extent that conflicts of interest arise, such conflicts will be resolved in
accordance with the provisions of theCanada Business Corporations
Act.
  48
  RISKS
AND UNCERTAINTIES
  We
are exposed to a number of risks and uncertainties relating to our
operations.
  Risks
Relating to the Project and to Future Phases of Development
  The Project may
be subject to delays, interruptions or costs that may
materially adversely affect our results of operations.
 
 There
is a risk that the Project may have delays, interruption of operations or costs
due to many factors, including, without limitation:
  •
                labour disputes, disruptions or
      declines in productivity;
  •
                breakdown or failure of equipment
      or processes;
  •
                delays in obtaining, or conditions
      imposed by, regulatory
approvals;
  •
                challenges to our proprietary
      technology and/or that of our affiliates or suppliers or of our
      licensors;
  •
                transportation accidents,
      disruption or delays in availability of transportation services or adverse
      weather conditions affecting
  transportation;
  •
                unforeseen site surface or
      subsurface conditions;
  •
                disruption in the supply of
      energy; and
  •
                catastrophic events such as fires,
      storms or explosions.
  The
information contained in this AIF, including, without limitation, reserve and
economic evaluations, is conditional upon receipt and maintenance of all
regulatory approvals and no material delays, interruptions of operations or
unforeseen costs.
  Our
SAGD and Long Lake Upgrader facilities may not operate as planned.
  The
performance of either the SAGD Operation or the Upgrader may differ from our
expectations. The variances from expectation may include, without
limitation:
  •
              the
      ability to ramp-up bitumen production or the
  Upgrader;
  •
              the
      ability to operate at the expected design rates of throughput or
      production;
  •
              the
      percentage conversion of bitumen to PSCtm;
  •
              the
      quality and characteristics of the PSCTM;
      and
  •
              the
      reliability or availability of the
facilities.
  If
the facilities do not perform to our expectations or as required by regulatory
approvals, we may be required to invest additional capital to correct
deficiencies or we may not be able to produce the expected level of production
of either bitumen or PSCtm.
If these expectations are not met, our revenue, cash flows and earnings may be
reduced.
  49
 As
the Project is our only source of potential revenue for the next several years,
any significant deviation from our expectations in the operation or performance
of the SAGD Operation or the Upgrader could compromise our ability to meet our
obligations, including making debt repayments and interest
payments.
  There
are technology license agreements in place for some SAGD and Upgrader
facilities. If these facilities fail to perform as expected, we may not be able
to recover damages from the licensors, and if we do recover damages from the
licensors, they may not be sufficient to compensate us for our
losses.
  The operating
costs of the Project may vary considerably during the operating
period. If they increase,
our earnings may be reduced.
  The
operating costs of the Project are significant components of the cost of
production of the petroleum products produced by the Project. Those operating
costs may vary considerably during the operating period. The principal factors
which could affect operating costs include, without limitation;
  •
                amount and cost of labour to
      operate the Project;
  •
                cost of catalyst and
      chemicals;
  •
                actual SOR required to operate the
      SAGD well pairs;
  •
                cost of natural gas and
      electricity;
  •
                cost of complying with regulatory
      approvals;
  •
                maintenance cost of the
      facilities;
  •
                cost to transport sales products
      and the cost to dispose of certain
      by-products; and
  •
                cost of insurance and
      taxes.
  Our
earnings may be reduced if we experience increases in operating
costs.
  The Project is
subject to numerous operational hazards and other risks against
which we may not be
insured.
  The
operation of the Project will be subject to the customary hazards of recovering,
transporting and processing hydrocarbons, such as fires, explosions, gaseous
leaks, migration of harmful substances, blowouts and oil spills. A casualty
occurrence might result in the loss of equipment or life, as well as injury or
property damage. We do not and will not carry insurance with respect to all
potential casualty occurrences and disruptions. There can be no assurance that
our insurance will be sufficient to cover any casualty occurrences or
disruptions that may occur in the future. The Project could be interrupted by
natural disasters or other events beyond the control of the JV Participants.
Losses and liabilities arising from uninsured or under-insured occurrences could
have a material adverse effect on the Project and, accordingly, on our business,
financial condition and results of operations.
  Recovering
bitumen from oil sands and upgrading the recovered bitumen into synthetic crude
oil and other products involve particular risks and uncertainties. The Project
is susceptible to loss of production, slowdowns, or restrictions on its ability
to produce higher value products due to the interdependence of its component
systems. Severe climatic conditions can cause reduced production and in some
situations result in higher costs. SAGD bitumen recovery facilities and
development and expansion of production can entail significant capital outlays.
The costs associated with synthetic crude oil production are largely fixed and,
as a result, operating costs per unit are largely dependent on levels of
production.
  50
 The
bitumen upgrading facilities of the Project are subject to numerous risks
related to the operation of upgrading facilities and other distribution
facilities, including loss of product or disruptions and slowdowns due to
equipment failures or other accidents.
  The
SAGD Operation and Upgrader will process large volumes of hydrocarbons at high
pressure and at high temperatures in equipment with fine tolerances and will
handle large volumes of high pressure steam. Equipment failures could result in
damage to the Project’s facilities and liability to third parties and regulators
against which we may not be able to fully insure or may elect not to insure
because of high premium costs or for other reasons.
  Certain
components of the Project will produce sour gas, which is gas containing
hydrogen sulphide. Sour gas is a colourless, corrosive gas which is toxic at
relatively low levels to plants, animals and humans. The Project will include
integrated facilities for handling and treating the sour gas, including the use
of gas sweetening units, sulphur recovery systems and emergency flaring systems.
Failures or leaks from these systems or other exposure to sour gas produced as
part of the Project could result in damage to other equipment, liability to
third parties, adverse effect to humans, animals and the environment, or the
shut-down of operations.
  We
are currently in the process of putting operating insurance in
place.  There is no guarantee that we will secure insurance as
expected or at all.
  The pool of
project employees with the skills required for the Project is limited, so the
Project  may not be able to
hire all of the labour force required at the compensation
levels budgeted for or
at all.
  The
Project will require experienced employees with particular areas of expertise.
There can be no assurance that all of the required employees with the necessary
expertise will be available. The Project will compete with other projects for
experienced employees and such competition may impact the availability of
employees and/or may result in increases to compensation paid to such
employees.
  Our
business may suffer if we lose key personnel.
  We
face numerous risks due to the stage of development of our company, the recent
transaction with Nexen, and certain other factors. Our success will depend in
part on the ability, expertise, judgment, discretion and good faith of our
management and our ability to retain them. We do not maintain key-man life
insurance with respect to any of our employees. If we lose any key personnel, it
may have a material adverse effect on our business, financial condition or
results of operations.
  We
plan to expand the Project through development of future phases and these
expansions may not proceed on our expected timeline or at all.
  We
have announced a multistage expansion plan, including plans to increase total
production to 360,000 bbl/d in our joint venture with Nexen (126,000 bbl/d net
to OPTI). In order to proceed with such development, we will need to establish
that the development will exceed our required conditions for
development.  Phase 2 sanctioning will be dependent on multiple
factors including Phase 1 ramp-up performance, regulatory approval for the SAGD
portion of the project, the capital cost estimate, the commodity price
environment, stability in the financial markets and global economies, as well as
further clarity on CO2
regulations.  There is a risk that these factors in aggregate may not
be sufficient for our criteria to sanction Phase 2 or future
phases.
  51
 We plan to expand
the Project and we may not be able to efficiently manage or
finance such expansion,
which could have a material adverse effect on our business, financial
condition or results of operations.
  We
have announced a multistage expansion plan, including plans to increase total
production to 360,000 bbl/d in our joint venture with Nexen (126,000 bbl/d net
to OPTI). In order to proceed with such development, we will require additional
financing in order to fund a portion of our share of costs associated with such
expansion. Our participation in any additional phases of the Project will be
subject to substantially all of the same risks as those set forth in this AIF
for the Project in general.
  The
industry is currently in a period of significant retraction with low commodity
prices, volatility in financial markets and weakness in global economies. As a
result, Phase 2 and all future phases of the multistage expansion plan have been
deferred to 2010 and beyond. Participation in the expansion projects will
significantly increase the demands on our management and administrative
resources and require significant financing. We may not be able to effectively
manage or finance the expansions, and any failure to do so could have a material
adverse effect on our business, financial condition or results of operations.
See "Risks and Uncertainties  - Risks Related to Financing and Our
Indebtedness."
  The Project and
future expansions must obtain and maintain regulatory approvals under and comply
with stringent
environmental laws and regulations. The failure to attain such
approvals and comply with
any of these laws and regulations could, among other things,
prevent or limit our
operations or subject us to substantial liability, which, in turn,
could have a material
adverse effect on our business and financial condition.
  The
construction, operation and decommissioning of the Project and future
expansions, and reclamation of the associated lands, are conditional upon
various environmental and regulatory approvals issued by governmental
authorities. There is no assurance such approvals will be issued, or once
issued, not appealed, or renewed, or that they will not contain terms and
conditions which make the Project uneconomic or cause us and our partners to
significantly alter the Project. Further, the construction, operation and
decommissioning of the Project and reclamation of the Project’s lands are and
will be subject to approvals, laws and regulations relating to environmental
protection and operational safety. Risks of substantial costs and liabilities
are inherent in oil sands recovery and upgrading operations, as well as
operations associated with the cogeneration facility, and there can be no
assurance that substantial costs and liabilities will not be incurred or that
the Project will be permitted to carry on operations. Moreover, it is possible
that other developments, such as increasingly strict environmental and safety
laws, regulations and enforcement policies thereunder, and claims for damages to
property or persons resulting from the Project’s operations, could result in
substantial costs and liabilities to us or delays to, or abandonment of, the
Project.
  No
assurance can be given that future environmental approvals, processes, laws or
regulations will not adversely impact our ability to operate the Project or
increase or maintain production of the Project or will not increase our unit
costs of production. Canada is a signatory to the United Nations Framework
Convention on Climate Change and has ratified the Kyoto Protocol established
thereunder to set legally binding targets to reduce nation-wide emissions of
GHGs. The Project will be a significant producer of some GHGs covered by the
Convention. On April 26, 2007 the Canadian Federal Government releasedthe Framework which
outlines proposed new requirements governing the emission of GHGs and other
industrial air pollutants, including sulphur oxides, volatile organic compounds,
particulate matter, and possibly additional sector-specific pollutants, in
accordance with the Canadian Federal Government’s Notice of Intent to Develop
and Implement
Regulations and Other Measures to Reduce Air Emissionsreleased on
October 19, 2006. The Framework introduces further, but not full, detail on
new GHG and industrial air pollutant limits and compliance mechanisms that will
apply to various industrial sectors, including the oil sands extraction,
upgrading and electricity production industries starting in 2010. On March 10,
2008, the Canadian Federal Government elaborated on the Framework with the
release of its Turning the
Corner document.  It is contemplated that new regulations will
take effect January 1, 2010.  Draft regulations were expected to be
available for public comment in the Fall of 2008 and are now expected in
mid-2009.
  52
 The
proposed regulatory framework provides that existing oil sands facilities in
operation by 2004 will be subject to an 18 percent emission intensity reduction
requirement commencing in 2010, with 2% additional annual reductions thereafter
until 2020.  Emission intensity is the amount of GHG emissions per
unit of production or output.  Facilities commissioned between 2004 to
2011 or facilities existing prior to 2004 which between 2004 and 2011 have had a
major expansion resulting in an increase of 25 percent or more in physical
capacity or which undergo a significant change to processes will be exempt from
the 2010 emissions intensity reduction target of 18 percent but will have to
report their emissions each year and after their third year of operation will be
required to reduce their emissions intensity by 2 percent annually from a
baseline emissions standard which is to be determined by reference to a
sector-specific cleaner-fuel standard.  For oil sands facilities, it
is contemplated that there will be specific cleaner-fuel standards based on the
use of natural gas for each of mining, in situ and
upgrading.  However, an incentive to deploy carbon capture and storage
(CCS) has been included.  CCS is where carbon dioxide is separated
from a facility's process or exhaust gas emissions before they are emitted,
transferred from the facility to a suitable storage location, and injected into
underground geological formations and monitored to ensure they do not escape
into the atmosphere.  If a facility commissioned between 2004 and 2011
is built such that it is able or ready to undertake CCS, then it will be exempt
from the cleaner-fuel standard until 2018 and it will only be required to reduce
it's emission-intensity by 2 percent per year from its actual
emissions.  In situ oil sands projects and oil sands upgraders built
after 2011 must have their GHG emissions profiles by 2018 equivalent to that of
facilities employing CCS technology.  The proposed regulatory
framework further encourages widespread use of CCS by 2018 by crediting emitters
that make use of CCS technology for investments in pre-certified CCS projects up
to 100 percent of their regulatory obligations through 2017.
  The
proposed compliance mechanisms include an emissions credit trading system for
GHGs and certain industrial air pollutants, and several options for companies to
choose among to meet GHG emission intensity reduction targets and encourage the
development of new emission reduction technologies, including the option of
making payments into a technology fund, an emissions and offset trading system,
limited credits for emission reductions created between 1992 and 2006, and
international emission credits under the clean development mechanism under the
Kyoto Protocol for up to 10 percent of each firm's regulatory
obligation.
  These
future federal industrial air pollutant and GHG emission reduction targets,
together with provincial emission reduction requirements contemplated in
Alberta’s Climate Change and
Emissions Management Act,or emission reduction requirements in future
regulatory approvals, may require the reduction of emissions or emissions
intensity from our operations and facilities, payments to a technology fund or
purchase of emission reduction or off-set credits. The required emission
reductions may not be technically or economically feasible for the Project and
the failure to meet such emission reduction requirements or other compliance
mechanisms may materially adversely affect our business and result in fines,
penalties and the suspension of operations. As well, equipment from suppliers
which can meet future emission standards may not be available on an economic
basis and other compliance methods of reducing emissions or emission intensity
to required levels in the future may significantly increase our operating costs
or reduce output of the Project. Emission reduction or off-set credits may not
be available for acquisition by the Project or may not be available on an
economic basis. There is also the risk that the provincial government could
impose additional emission or emission-intensity reduction requirements, or that
the federal and/or provincial governments could pass legislation which would tax
such emissions.
  53
 To
operate the facilities, the Project relies on groundwater, which is obtained
under licenses from Alberta Environment ("AE"). There can be no assurance that
the licenses to withdraw groundwater will not be rescinded or that additional
conditions will be not be added to these licenses. There can be no assurance
that we will not have to pay a fee for the use of water in the future or that
any such fees will be reasonable. In addition, the expansion of the Project
relies on securing licenses for additional water withdrawal, and there can be no
assurance that these licenses will be granted on terms favourable to the company
or at all, or that such additional water will in fact be available to divert
under such licenses.
  American
climate change legislation could negatively affect markets for crude and
synthetic crude oil
  Environmental
legislation regulating carbon fuel standards in jurisdictions that import crude
and synthetic crude oil in the United States could result in increased costs
and/or reduced revenue.  For example, both California and the United
States federal government have passed legislation which, in some circumstances,
considers the lifecycle greenhouse gas emissions of purchased fuel and which may
negatively affect marketing of our products, or require the purchase of
emissions credits in order to affect sales in such jurisdictions.
  We will be
responsible for abandonment and reclamation costs which may be
substantial but which we
cannot currently estimate.
  We
will be responsible for compliance with terms and conditions of environmental
and regulatory approvals and all laws and regulations regarding the abandonment
of the Project and reclamation of the Project lands at the end of their economic
life.  Abandonment and reclamation costs may be substantial. A breach
of such legislation and/or regulations may result in the imposition of fines and
penalties, including an order for cessation of operations at the site until
satisfactory remedies are made. It is not possible to estimate reliably the
abandonment and reclamation costs since they will be a function of regulatory
requirements at the time and the value of the salvaged equipment may be more or
less than the abandonment and reclamation costs. In addition, in the future we
may determine it prudent or be required by applicable laws, regulations or
regulatory approvals to establish and fund one or more reclamation funds to
provide for payment of future abandonment and reclamation costs.
  Risks
Relating to Reserves and Resources
  Undue reliance
should not be placed on estimates of reserves and resources,
since these estimates
are subject to numerous uncertainties, and our actual reserves
could be lower than
such estimates.
  There
are numerous uncertainties inherent in estimating quantities of reserves and
resources, including many factors beyond our control, and no assurance can be
given that the indicated level of reserves or recovery of bitumen will be
realized. In general, estimates of economically recoverable bitumen reserves and
resources and the future net revenues therefrom are based upon a number of
factors and assumptions made as of the date on which the reserve and resource
estimates were determined, such as geological and engineering estimates which
have inherent uncertainties, the assumed effects of regulation by governmental
agencies and estimates of future commodity prices and operating costs, all of
which may vary considerably from actual results. All such estimates are, to some
degree, uncertain and classifications of reserves and resources are only
attempts to define the degree of uncertainty involved. For these reasons,
estimates of the economically recoverable bitumen, the classification of such
reserves and resources based on risk of recovery and estimates of future net
revenues expected therefrom, prepared by different engineers or by the same
engineers at different times, may vary substantially. References to "resources"
in this AIF should be distinguished from "reserves." See "Reserves and Resources
Summary" and Appendix A to this AIF for more information.
  54
 Estimates
with respect to reserves and resources that may be developed and produced in the
future are often based upon volumetric calculations, probabilistic methods and
upon analogy to similar types of reserves or resources, rather than upon actual
production history. Estimates based on these methods generally are less reliable
than those based on actual production history. Subsequent evaluation of the same
reserves or resources based upon production history will result in variations,
which may be material, in the estimated reserves or resources.
  Reserve
and resource estimates may require revision based on actual production
experience. Such figures have been determined based upon assumed oil prices and
operating costs. Market price fluctuations of oil prices may render uneconomic
the recovery of certain grades of bitumen. Moreover, short term factors relating
to oil sands resources may impair the profitability of the Project in any
particular period.
  No
assurance can be provided as to the quality of bitumen produced from the Long
Lake leases. The quality of the bitumen can ultimately determine the amount of
syngas and PSCtm
produced from the Long Lake Upgrader.
  The
SAGD bitumen recovery process is subject to uncertainty.
  The
recovery of bitumen using the SAGD process is subject to uncertainty. The SAGD
process has had limited operating history in commercial projects and has only
had one year of production ramp-up on the Long Lake leases. Although we
conducted pilot tests on the Long Lake leases reservoir and now have almost 12
months of data from ramp-up of the well pairs of Phase 1, there can be no
assurance that the Long Lake SAGD Operation will produce bitumen at the expected
levels or on schedule.
  We
have a limited operating history with respect to the SOR for the Project.
However, based on early reservoir results, we believe our current estimates of
SOR are reasonable. Should the actual SOR in commercial operations be higher
than these estimates, it may result in some or all of the
following:
  •           an
increase in operating costs;
  •           lower
bitumen production; or
  •           the
requirement for additional facilities.
  Any
of these could have a significant adverse impact on the future activities and
economic performance of the Project.
  Full
use of the upgrading capacity of the Long Lake Upgrader may depend on the supply
of third party bitumen, which may not be available at all or at commercially
acceptable prices. We may enter into long-term agreements with others for the
supply of such bitumen but there is no guarantee that such suppliers will be
able to meet their commitments to us under such agreements.
  55
 Risks
Relating to Commodity and Currency Pricing
  Our results of
operations will depend upon the prevailing prices of oil and
natural gas in the
worldwide markets, and those prices can fluctuate
substantially.
  Our
revenues, cash flows, earnings, cost of capital, asset values, results of
operations and financial condition will be dependent upon the prevailing price
of crude oil and natural gas among other things. Oil prices have historically
been extremely volatile and fluctuate significantly in response to regional,
national and global supply and demand factors beyond our control. Among the
factors that can cause oil price and natural gas price fluctuation
are:
  •
                the level of consumer product
      demand;
  •
                the domestic and foreign supply of
      natural gas and crude oil, including the decisions of the Organization of
      Petroleum Exporting Countries relating to export quotas and their
      compliance or non-compliance with such self-imposed
      quotas;
  •
                weather conditions, including
      hurricanes, floods and other natural
  disasters;
  •
                domestic and foreign governmental
      regulations;
  •
                the effect of worldwide
      conservation of resources;
  •
                the price and availability of
      alternative fuels, including liquefied natural
  gas;
  •
                political conditions in crude oil
      and natural gas producing regions, including wars, terrorist activities
      and other hostilities;
  •
                the proximity of reserves to, and
      capacity of, transportation
facilities;
  •
                the price of foreign imports of
      crude oil and natural gas;
  •
                overall global and domestic
      economic
conditions; and
  •
                concern over climate change or GHG
      emissions.
  Any
material decline in oil prices could result in a material reduction of our
operating results, production revenue, reserves and overall value. In addition,
any prolonged period of low oil prices could result in a decision by us and/or
Nexen to suspend or reduce production. Any such suspension or reduction of
production would result in a corresponding substantial decrease in our revenues
and earnings and could materially impact our ability to meet our debt servicing
obligations and could expose us to significant additional expense as a result of
any future long-term contracts. If production was not suspended or reduced
during such period, the sale of the petroleum products produced by the Project
at such reduced prices would lower our revenues.
  We
conduct an assessment of the carrying value of our assets to the extent required
by GAAP. If oil prices decline, the carrying value of our assets could be
subject to downward revision, and our earnings could be adversely affected.
  The price we
receive for PSCtmwill depend upon
the demand for it, which is not
currently proven.
  The
price we will receive for PSCtm
will be dependent on the demand for it. PSCtm
will compete against other synthetic crude oils and natural crude oils. As
PSCtm
will be a new synthetic crude oil product, no assurance can be given as to the
price and marketability of PSCtm.
  The
production of PSCTM may
generate GHG emissions that are higher than those generated during the
production of other synthetic or conventional oils, which could limit our
ability to sell PSCTM.
  We
will be subject to foreign currency exchange fluctuation exposure.
  Crude
oil prices are generally based on a U.S. dollar market price, while certain
of our operating and capital costs will be primarily in Canadian dollars.
Fluctuations in exchange rates between the U.S. and Canadian dollar will
therefore give rise to foreign currency exchange exposure. A material increase
in the value of the Canadian dollar relative to the U.S. dollar may
negatively affect our revenue by decreasing the Canadian dollars we receive for
a given U.S. dollar price. OPTI is also exposed to foreign exchange rate
risk on our U.S. dollar denominated debt. We may mitigate the impact of exchange
rate fluctuations on the revenue from the Project or the U.S. dollar denominated
debt by entering into currency hedges, but there is no assurance that any hedges
we may enter into will be successful and, if not successful, those hedges could
result in serious adverse effects on our financial condition and
business.
 
  56
 We enter into
commodity price hedging arrangements, which may subject us to additional
risks.
  The
nature of our operations will result in exposure to fluctuations in commodity
prices. We use financial instruments and may also use physical delivery
contracts to hedge our exposure to these risks. If we continue to engage in
hedging, we will be exposed to credit-related losses in the event of
non-performance by counterparties to the financial instruments. Additionally, if
product prices increase above those levels specified in any future hedging
agreements, we could lose the cost of floors or ceilings or a fixed price could
prevent us from receiving the full benefit of commodity price increases. Our
current and any future hedging arrangements could cause us to suffer financial
loss if we are unable to commence operations on schedule, if we are unable to
produce sufficient quantities of oil to fulfill our obligations, if we are
required to pay a margin call on a hedge contract or if we are required to pay
royalties based on a market or reference price that is higher than our fixed
ceiling price.
  Risks
Relating to Technology
  The Integrated
OrCrudetmUpgrading Process
may not be successful, which could have
a significant adverse impact on our financial condition of the Project.
  There
can be no assurance that the Long Lake Upgrader will achieve the same
performance results as the OrCrudetm
demonstration plant owned and operated by us from 2001 to 2003, nor that the
Long Lake Upgrader will have the same level of success in upgrading the bitumen
production from the Long Lake leases and other lands owned by the JV
Participants to the desired product specifications, at the expected levels, on
schedule or at all. If we are unable to upgrade the bitumen for any reason, we
may decide to, or may be forced to, sell it as bitumen without upgrading it.
Bitumen blend is not as readily marketable as conventional light oil and market
prices are lower for bitumen blend on a comparable basis. This could have a
significant adverse impact on our financial performance and future activities of
the Project and expansion projects.
  Our results of
operations, business and financial condition are dependent in
large part on our
ability to protect our proprietary technology.
  Our
future results of operations depend to a significant extent on our proprietary
technology, the proprietary technology of third parties that has been, or is
required to be, licensed by us, and our ability, and that of such third parties,
to prevent others from copying or infringing upon such proprietary technologies.
We currently rely on intellectual property rights and other contractual or
proprietary rights, including (without limitation) copyright, trademark, trade
secrets, confidentiality procedures, contractual provisions, licenses and
patents, to protect our proprietary technology, and on third parties, from whom
licenses have been received, to protect their proprietary technology. From time
to time, we may have to engage in litigation in order to protect patents or
other intellectual property rights, or to determine the validity or scope of the
proprietary rights of others. This kind of litigation can be time-consuming and
expensive, regardless of whether or not we are successful. The process of
seeking patent protection can itself be long and expensive, and there can be no
assurance that any currently pending or future patent applications by us, or by
such third parties will actually result in issued patents, or that, even if
patents are issued, they will be of sufficient scope or strength to provide
meaningful protection or any commercial advantage to us. Even if patents are
issued, our licensors may fail to maintain these patents or may determine not to
pursue litigation against other companies that are infringing these patents.
Such failures or determinations could adversely affect the intellectual property
we license, and our competitive position could be harmed.
  57
 Despite
our efforts, or those of such third parties, our intellectual property rights,
particularly in existing or future patents, may be invalidated, circumvented,
challenged, infringed or required to be licensed to others. There can be no
assurance that any steps we, or such third parties, may take to protect our and
their intellectual property rights and other rights to such proprietary
technologies that are central to our operations will prevent misappropriation or
infringement. One or more of our licensors may allege that we have breached our
license agreement with them and, accordingly, may seek to terminate our license.
If successful, this could result in our loss of the right to use the licensed
intellectual property, which could adversely affect our ability to operate the
Project and/or to commercialize these technologies or services, as well as harm
our competitive business position and business prospects.
  With
respect to proprietary know-how that is not patentable, we rely on trade secret
protection and confidentiality agreements. We require all employees, consultants
and collaborators who are involved in the development of our technology to enter
into confidentiality agreements. There can be no assurance, however, that these
agreements will provide adequate protection or remedies for any breach, or that
our trade secrets will not otherwise become known or independently discovered by
our competitors.
  There
is also a risk that we may not be able to enter into licensing arrangements with
third parties for the hydrocracking, gasification and other technologies
required for the expansion plans as announced by us or for future Integrated
OrCrudetm
Upgraders that we may desire to build.
  We may be the
subject of claims by third parties that we, or our licensors,
have infringed their
intellectual property rights.
  A
third party may claim that we or our licensors have infringed such third party’s
rights or may challenge our right in that third party’s intellectual property.
In such event, we will undertake a review to determine what, if any, actions we
should take with respect to such claim. Any claim, whether or not with merit,
could be time-consuming to evaluate, result in costly litigation, cause delays
or interruptions in our operations or the Project or require us to enter into
licensing agreements that may require the payment of a license fee or royalties
to the owner of the intellectual property. Such royalty or licensing agreements,
if required, may not be available on terms that are commercially reasonable or
acceptable to us, if at all. In addition, if we were to lose an intellectual
property infringement litigation, we may be required to cease operations or pay
significant monetary damages and to redesign our technology to avoid future
infringement. Our agreements with our licensors generally include exclusions of
indirect or consequential damages and limits on the recovery of direct damages.
Accordingly, if an infringement claim relates to a licensed technology, we may
not be able to claim reimbursement and/or damages from our
licensors.
  Risks
Relating to Third Parties
  The
success of the Project is dependent upon our joint venture partner
Nexen.
  Nexen
is the operator of the Long Lake Project. We rely on Nexen’s operating expertise
to generate cash flow from the Project and to provide information on the status
and results of operations.
 There
are no assurances that Nexen will be able to generate forecasted SAGD volumes,
which could compromise OPTI’s financial results.  Furthermore, there
is no assurance that Nexen will be able to provide adequate financial and
operational information on a timely basis.
 
 58
 We
will be subject to the risk of default by Nexen in meeting its financial
commitments and/or other obligations to us, the Project, or future phases of
project development. Such default by Nexen may adversely affect the continuation
of the Project or future phases, the construction or operations of future
phases, or other facets of the Project or future phases, any of which may
adversely affect us. In addition, subject to certain conditions, Nexen may sell
its interest in the joint venture and our new partner may not have the resources
or experience that Nexen has.
  The
Project is being undertaken jointly by the JV Participants pursuant to the
Construction, Ownership and Joint Operation of the Project Agreement (the "COJO
Agreement"). The COJO Agreement provides for the creation of a management
committee which is responsible for the supervision and direction of the
management and operation of the Project, the supervision and control of the
operators and all other matters relating to the development of the Project. If
our interest in the Project falls below 25 percent as a result of a sale of our
working interest or is reduced due to failure to maintain financial commitments,
Nexen may be able to make decisions respecting the Project without input from
us, which may adversely affect us or our operations.
  Our
business, and the Project in particular, is also subject to the risk that Nexen
may change its business strategies and future phases of project development
and/or decide to not engage in any future activities with us.
  We are subject to
extensive government regulation. We may have to expend
substantial amounts for
compliance with regulations or we may become liable for failure to
comply with
regulations.
  The
oil and gas industry in Canada, including the oil sands industry, operates under
Canadian federal, provincial and municipal legislation and regulation governing
such matters as land tenure, prices, royalties, production rates, environmental
protection controls, income, the exportation of crude oil, natural gas and other
products, the use of groundwater in our operations, as well as other matters.
The industry is also subject to regulation by federal, provincial and municipal
governments in such matters as the awarding or acquisition of exploration and
production rights, oil sands or other interests, the imposition of specific
drilling obligations, environmental protection controls, control over the
development and abandonment of fields and mine sites (including restrictions on
production) and possibly expropriation or cancellation of contract
rights.
  Government
regulations may be changed from time to time in response to economic or
political conditions. The exercise of discretion by governmental authorities
under existing regulations, the implementation of new regulations or the
modification of existing regulations affecting the crude oil and natural gas
industry could reduce demand for crude oil and natural gas, increase our costs
and have a material adverse impact on us.
  Before
proceeding with the Project, the JV Participants must obtain all required
regulatory approvals. To date, we believe the Project has received substantially
all of the approvals currently required. The regulatory approval process can
involve stakeholder consultation, environmental impact assessments, public
hearings and appeals to tribunals and courts, among other things. In addition,
regulatory approvals may be subject to conditions including security deposit
obligations and other commitments. Failure to obtain regulatory approvals, or
failure to obtain them on a timely basis, could result in delays or
restructuring of the Project and increased costs, all of which could have a
material adverse affect on us. The Project is also subject to periodic
inspections by regulatory authorities to ensure our compliance with the
conditions of regulatory approvals. Negative inspection results may lead to the
imposition of fines or penalties or the suspension or rescission of the
Project’s regulatory approvals.
  59
 The Project will
depend on utility infrastructure owned and operated by third parties, and the
failure by those third parties to provide services required by
the Project could
have a material adverse effect on our business and results of operations.
  The
Project will depend on successful operation of certain infrastructure owned and
operated by others, including, without limitation:
  •
                pipelines for the transportation
      of feedstocks to the Long Lake Upgrader and petroleum products to be sold
      from the Long Lake Upgrader;
 •
                pipelines for the transportation
      of externally supplied natural
gas;
 •
                a railway spur for the
      transportation of Long Lake Upgrader products and by-products including
      sulphur disposal; and
 •
                electricity transmission systems
      for the provision and/or sale of
  electricity.
  The
failure of any or all of these utilities to supply service will negatively
impact the operation of the Project which, in turn, may have a material adverse
effect on our business or results of operations.
  The
inability of counterparties to fulfill their obligations to us could adversely
impact us.
  Our
oil revenue and associated accounts receivable will be concentrated among a
limited number of counterparties.  There is a risk that theses
counterparties will not pay amounts owing to us on a timely basis or at
all.  Derivative instruments expose us to certain risks, including the
risk of loss from fluctuating commodity prices, credit risks if a counterparty
is unable to meet its contractual obligations and the risk of margin calls from
third-parties. The inability to close out options, futures and forward positions
could have an adverse impact on the use of derivative instruments to effectively
hedge our position.
  Our
banks could encounter financial difficulties.
  We maintain significant cash balances
and undrawn revolving credit facilities, primarily with large Canadian
banks.  These banks could encounter financial difficulties that could
prevent us from accessing these funds.
  Our
operating cash flows will be directly affected by the applicable royalty
regime.
  We
are currently required to pay a royalty to the Government of the Province of
Alberta on our bitumen production. The implementation of the new royalty regime
in Alberta, effective January 1, 2009, is subject to certain risks and
uncertainties. The significant changes to the royalty regime require new
legislation, changes to existing legislation and regulation and development of
proprietary software to support the calculation and collection of
royalties.
  Changes
in tax laws may adversely affect us, the Project and future expansion
phases.
  Income
tax laws or government incentive programs relating to the oil and gas industry
and in particular the oil sands sector may in the future be changed or
interpreted in a manner that adversely affects us, the Project and future
expansion phases.There is also the risk
that the provincial government could impose additional emission or
emission-intensity reduction requirements, or that the federal and/or provincial
governments could pass legislation which would tax such emissions.
  60
 Our industry is
highly competitive and many of our competitors have greater
resources than we
do.
  The
Canadian and international petroleum industry is highly competitive in all
aspects, including the exploration for, and the development of, new sources of
supply, the acquisition of oil interests and the distribution and marketing of
petroleum products. The Project will compete with other producers of synthetic
crude oil blends and other producers of conventional crude oil. Some of the
conventional producers have lower operating costs than we are anticipated to
have, and many of them have greater resources then we have. The petroleum
industry also competes with other industries in supplying energy, fuel and
related products to consumers.
  A
number of companies other than our company had announced plans to enter the oil
sands business and begin production of synthetic crude oil, or expand existing
operations. However similar to our announcement to delay the sanctioning of
Phase 2 of our Project, these companies have also delayed or cancelled their
expansion plans given the current economic climate. Consequently we are one of
only two new Upgraders currently going on stream and there might not be any new
Upgraders or refineries constructed for at least a few years. In the short term,
this could be to our advantage. However, development of the Canadian oil sands
region will continue in the future and could materially increase the supply of
synthetic crude oil and other competing crude oil products in the marketplace.
Depending on the levels of future demand, increased supplies could have a
negative impact on prices of synthetic crude oil and, accordingly our results of
operations and cash flows.
  Unforeseen title
defects may result in a loss of entitlement to production and reserves.
  We
have not obtained title opinions in respect of the leases that we intend to
develop and, accordingly, our ownership of the leases could be subject to prior
unregistered agreements or interests or undetected claims or interests. If such
were the case, our entitlement to the production and reserves associated with
such leases could be jeopardized, which could have a material adverse effect on
our financial condition, results of operations and our ability to execute our
business plan in a timely manner or at all.
  The land on which
the Project is located is subject to Aboriginal claims which,
if determined
adversely to us, could have a significant adverse effect on the
Project and on
us.
  Aboriginal
peoples have claimed aboriginal title and rights to a substantial portion of
western Canada. Certain aboriginal peoples have filed a claim against the
Government of Canada, the Province of Alberta, certain governmental entities and
the regional municipality of Wood Buffalo (which includes the City of
Fort McMurray, Alberta) claiming, among other things, aboriginal title to
large areas of lands surrounding Fort McMurray, including the lands on
which the Project and most of the other oil sands operations in Alberta are
located. Such claims, if successful, could have a significant adverse effect on
the Project and on us.
  Risks
Relating to Financing and Our Indebtedness
  We
are subject to liquidity risk.
  Liquidity
risk is the risk that we are not able to meet our financial obligations as they
fall due.  We incur monthly interest and standby payments relating to
our Revolving Credit Facility, and full principal repayment of our Revolving
Credit Facility is due in 2011.
  We
also have semi-annual interest payments due each year on our senior secured
notes and full principal repayment of these notes is due in December
2014.
  61
 During
2007 and 2008, global capital markets experienced a number of economic crises
related to subprime lending and structured finance products, among other
factors, which also impacted financial markets within Canada.  As a
result, there has been a tightening of global credit markets characterized by a
decline in liquidity and higher borrowing costs.  Although our current
financial resources are considered sufficient for Phase 1, further deterioration
of commodity prices and or operating issues with our SAGD or Upgrader operations
could result in additional funding requirements.  Should the company
require such funding, it may be difficult to obtain such financing on terms
attractive to the company or at all.
 
 If
are not able to meet our debt covenants, we may need to repay our
debt
  Our Revolving Credit Facility contains
certain covenants that serve to limit the amount of debt we are permitted to
incur .  These maintenance covenants are ongoing conditions that must
be satisfied to provide continued access to the Revolving Credit
Facility.  If we are unable to meet the conditions of the debt
covenants, we may be obligated to repay principal on the debt in advance of its
maturity date.  At December 31, 2008, OPTI was in full compliance with
its debt covenants relating to the Revolving Credit Facility.  (see:
Description of Debt Capital)
  If we are unable
to obtain sufficient funding, we may lose our ownership interest
in the Project and
future phases.
  Significant
amounts of financing are required to develop the Project.  While the
Project has begun operations, we continue to have financial obligations relating
to completion of the steam debottlenecking plant and the ash processing unit, as
well as sustaining capital costs.  If our current cost estimates were
to increase, it is not certain that we would be able to finance our portion of
the increased capital cost.
 
 Subsequent
to possible sanctioning of Phase 2, which is currently scheduled for
consideration in 2010, we expect capital requirements in excess of operating
cash flows. Unless we have stable operations at or near capacity for the Project
and relatively high commodity prices, such external financing requirements will
be significant.  We expect that these financing requirements will come
at a higher cost and contain more restrictions than the prior financings
completed by OPTI.  Current market conditions would not support such a
financing requirement and therefore some improvement will be required between
now and 2010 in order to support such development.
  Nexen
has a first priority fixed lien, charge and security interest in our ownership
interest in the Project to secure payment and performance of our Project
obligations. Should we fail to meet all or some part of our Project obligations,
Nexen has the right, in certain circumstances, to acquire some or all of our
interest in the Project (excluding our rights to the OrCrudetm
Process technology and certain royalties payable to us) at 80 percent of
cost.
 
 We
have a multi-stage expansion plan. Expenditures are necessary and we will need
to secure additional financing to proceed according to the multi-stage expansion
plans. The inability to complete these financings on a timely basis or at all
would have a material adverse effect on our expansion plans potentially causing
the delay or cancellation of future phases of the Project. Nexen has the right,
in certain circumstances, to acquire some or all of our interest in the
expansion phases if we fail to meet all or some of our future phase obligations
(excluding our rights to the OrCrudetm
Process technology and certain royalties payable to us). See "Material
Agreements Related to the Joint Venture - The New COJO Agreements".
  62
 We may not be
able to draw down on the Revolving Credit Facility which may have
a material adverse
effect on our business.
  We
must satisfy a number of conditions precedent prior to each borrowing under the
Revolving Credit Facility, including that we have sufficient funding to complete
the Project. There can be no assurance that we will be able to satisfy all of
the conditions precedent, in which case we will not be able to access the
Revolving Credit Facility to satisfy our capital commitments in respect of the
Project.
  We
borrow funds in U.S. dollars.
  A
significant portion of our debt is denominated in U.S. dollars. We have hedged a
portion of this exposure through the completion of certain cross currency swaps
as noted in “Description of Debt Capital”. Fluctuations in exchange rates may
significantly increase the amount of debt recorded on our financial statements
and negatively impact our reported earnings.
  MATERIAL
CONTRACTS
  Set
forth below are agreements that may be considered material to OPTI:
  1.
                the Purchase and Sale Agreement
      between OPTI and Nexen as more particularly described under the heading
      “Material Agreements Related to the Joint
  Venture”;
  2.
                MOU between OPTI and Nexen as more
      particularly described under the heading "Material Agreements Related to
      the Joint Venture";
  3.
                the COJO Agreement and New COJO
      Agreements between OPTI and Nexen as more particularly described under the
      heading "Material Agreements Related to the Joint Venture";
      and
  4.
                the Technology Agreement among
      OPTI and Nexen as more particularly described under the heading "Material
      Agreements Related to the Joint
Venture".
  LEGAL
PROCEEDINGS AND REGULATORY ACTIONS
  There
are no material legal proceedings and regulatory actions against
us.
  TRANSFER
AGENTS AND REGISTRAR
  Valiant
Trust Company at its principal office in Calgary, Alberta is the transfer agent
and registrar of our Common Shares and BNY Trust Company of Canada at its
principal office in Toronto, Ontario is the transfer co-agent and registrar of
our Common Shares.
  INTEREST
OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
  Our
directors, officers and principal shareholders (and their known associates and
affiliates) have had no material interest, direct or indirect, in any
transaction within the three most recently completed financial years or during
the current financial year that has materially affected or will materially
affect us, other than as set forth in this AIF.
  63
 INTERESTS
OF EXPERTS
  PricewaterhouseCoopers
LLP are our auditors and are independent in accordance with the rules of
professional conduct of the Canadian Institute of Chartered Accountants.
McDaniel, our independent petroleum consultants, prepared the McDaniel Report,
referenced herein.  As at the date of the McDaniel report, the
principals of McDaniel, as a group, owned beneficially, directly or indirectly,
less than one percent of our outstanding Common Shares.  McDaniel did
not receive nor will they receive any interest, direct or indirect, in any
securities or other property of us or our affiliates in connection with the
preparation of its report.
  ADDITIONAL
INFORMATION
  Additional information
relating to us may be found on SEDAR at www.sedar.com.
  Additional
information including directors' and officers' remuneration and indebtedness,
principal holders of our securities and securities authorized for issuance under
equity compensation plans is contained in our information circular for our most
recent annual meeting of shareholders that involved the election of
directors.  Additional financial information is provided in our
comparative amended financial statements and our management's discussion and
analysis for our most recently completed financial year. Additional copies of
this AIF may be obtained from us, please contact:
  Investor
Relations
 OPTI
Canada Inc.
 2100,
555 - 4th Avenue
S.W.
 Calgary,
Alberta
 T2P
3E7
  64
 GLOSSARY
  In
this AIF, the following terms shall have the meanings set forth below, unless
otherwise indicated:
  "AE" means Alberta
Environment;
  "AIF" means this annual
information form dated March 24, 2009;
  "API" means degrees API, a
measure of hydrocarbon density;
  "Area of Mutual Interest" means
the area of mutual interest with Nexen as described in "Material Agreements
Related to the Joint Venture";
  "bbl" means barrels, which are
equal to 0.15899 cubic metres;
  "bbl/d" means barrels per
day;
  “boe/d” means barrels of oil
equivalent per day;
  "Cogeneration Facility" means
the cogeneration facility to be constructed in connection with the Long Lake
SAGD Operation, as further described under the heading entitled "The Project and
Futures Phases";
  "COJO Agreement" means the
Construction, Ownership and Joint Operation of the Long Lake Project Agreement
between the JV Participants;
  "Cottonwood Leases" means our
lands in the Cottonwood area;
  “EBITDA” means earnings before
interest, depreciation, taxes and amortization.
  "EUB" means the Alberta Energy
and Utilities Board.  Effective January 1, 2008, the Alberta Energy
and Utilities Board (EUB) has been realigned into two separate regulatory
bodies: the  Energy Resources Conservation Board and the Alberta
Utilities Commission.
  “ERCB” means the Energy
Resources Conservation Board, an independent, quasi-judicial agency of the
Government of Alberta that regulates the safe, responsible, and efficient
development of Alberta's energy resources: oil, natural gas, oil sands, coal,
and pipelines.
  “GHGs” means greenhouse gases,
including water vapour, carbon dioxide, methane, and ozone, among
others.
  "in-situ" means, when referring
to oil sands, a process for recovering bitumen from oil sands by means other
than surface mining;
  "Integrated OrCrudeTM Upgrader"
means an upgrader which uses the OrCrudeTM Process combined with additional third
party technology to upgrade bitumen and heavy oil to produce PSCTM and
syngas, as further described under the heading entitled "The OrCrudeTM Process -
Integrated OrCrudeTM Upgrader";
  “JV” means the joint venture
between OPTI and Nexen;
  “JV Participants means OPTI and
Nexen;
  65
 "Leismer Leases" means our
lands in the Leismer area;
  "Long Lake Leases" includes the
Project land and our interest in other lands in the Long Lake area;
  "Long Lake Project" or the
"Project" means
Phase 1 of the Long Lake SAGD Operation, Phase 1 of the Long Lake
Upgrader and the related lands;
  "Long Lake SAGD Operation" or
"SAGD Operation" means
the facilities to be constructed for the purpose of producing bitumen from the
Project lands using the SAGD process, together with the SAGD Pilot and the
Cogeneration Facility, all as further described under the heading entitled "The
Long Lake Project - Long Lake SAGD Operation";
  "Long Lake Upgrader" or "Upgrader" means the Integrated
OrCrudeTM Upgrader to be constructed for the purpose of upgrading bitumen
produced from the Project lands, as further described under the heading entitled
"The Long Lake Project - Long Lake Upgrader";
  "Management Committee" means
the committee comprised of representatives of each of OPTI and Nexen who
pursuant to the COJO Agreement and the New COJO Agreements will exercise
supervision and direction of the management and operation of the Project and
certain future phase developments;
  "McDaniel" means McDaniel &
Associates Consultants Ltd., an independent petroleum consulting
firm;
  "MMbbl" means millions of
barrels;
  "mmbtu" means millions of
British thermal units;
  “Nexen Transaction” means the
transaction, closed in January 2009, wherein OPTI sold  a 15 percent
working interest in its joint venture assets to Nexen, as further desceibed
under the heading “    “
 
 "OrCrudeTM Product" means the
partially-upgraded crude oil produced in the OrCrudeTM Process;
 
 "OrCrudeTM Process" means the
proprietary methods and means for upgrading bitumen and heavy oil based on
numerous U.S. and Canadian patents and patent applications;
 
 "Phase 1" means the Long
Lake Project, in a currently in a 65 percent (Nexen Inc.) / 35 percent (OPTI)
joint venture.  This phase consists of 72,000 (bbl/d) of
SAGD bitumen production integrated with an upgrading facility expected to
produce 58,500 bbl/d of products, primarily 39° API premium sweet
crude;
 
 "PSCTM"
means, generically, the premium, sweet, synthetic crude oil produced in the
Integrated OrCrudeTM Upgrader, which is produced by hydrocracking OrCrudeTM
Product;
 
 "SAGD" means steam assisted
gravity drainage, an in-situ process used to recover bitumen from oil sands
located too deep to be profitably mined;
 
 "SAGD Pilot" means
the  SAGD pilot project which was used to evaluate well design,
confirm reservoir performance and obtain site specific operating experience in
respect of the Long Lake Project;
  "syngas" means synthesis fuel
gas produced through gasification; and
  "Technology Agreement" means
the Technology Licence for Upgrading Technology Agreement between the JV
Participants.
  
 66
  APPENDIX
A
  RESERVES
DATA AND OTHER OIL AND GAS INFORMATION
 
  The
McDaniel Report, summarized below, reflects OPTI’s reserves and resources as of
December 31, 2008 and with a 50
percent working interest in the joint venture. On January 27, 2009, OPTI
announced that we had completed the sale of a 15 percent working interest in our
joint venture assets to Nexen. Effective January 1, 2009, OPTI has a 35 percent
working interest in all joint venture assets, including Phase 1 of the Long Lake
Project, all future phase reserves and resources, and future phases of
development.
  Reserves
and Future Net Revenue
  The
following tables of reserves and net present values of future net revenue for
OPTI have been prepared on the assumption that total proved plus probable plus
possible reserves are 1,147,842 mbbl of raw bitumen reserves and do not take
into account any additional bitumen resources. It should not be assumed that the
present values of future net revenue shown below are representative of the fair
market value of the reserves.
  Oil
      and Gas Reserves
                            Based
      on Forecast Prices and Costs(9)Synthetic Crude Oil
                            (PSCTM)
                          
                          
                          Bitumen
                          
                          
                          ButaneGross(1)
                          
                          
                          Net(1)
                          
                          
                          Gross(1)
                          
                          
                          Net(1)
                          
                          
                          Gross(1)
                          
                          
                          Net(1)(mbbl)
                          
                          
                          (mbbl)
                          
                          
                          (mbbl)
                          
                          
                          (mbbl)
                          
                          
                          (mbbl)
                          
                          
                          (mbbl)Proved
      Developed Producing(2)(5)(6)
                          
                          
                          49,992
                          
                          
                          
                          47,071
                          
                          
                          
                          1,143
                          
                          
                          
                          1,077
                          
                          
                          
                          1,909
                          
                          
                          
                          1,797Proved
      Developed Non-Producing(2)(7)Proved
      Undeveloped(2)(8)
                          
                          
                          159,634
                          
                          
                          
                          136,534
                          
                          
                          
                          14,927
                          
                          
                          
                          12,999
                          
                          
                          
                          6,095
                          
                          
                          
                          5,213Total
      Proved
                          
                          
                          209,626
                          
                          
                          
                          183,606
                          
                          
                          
                          16,071
                          
                          
                          
                          14,076
                          
                          
                          
                          8,004
                          
                          
                          
                          7,011Probable(3)
                          
                          
                          617,802
                          
                          
                          
                          503,542
                          
                          
                          
                          5,912
                          
                          
                          
                          4,360
                          
                          
                          
                          23,590
                          
                          
                          
                          19,227Total
      Proved Plus Probable
                          
                          
                          827,427
                          
                          
                          
                          687,147
                          
                          
                          
                          21,983
                          
                          
                          
                          18,436
                          
                          
                          
                          31,594
                          
                          
                          
                          26,237Possible
      (4)
                          
                          
                          75,037
                          
                          
                          
                          53,476
                          
                          
                          
                          (251
                          )
                          
                          
                          (475
                          )
                          
                          
                          2,865
                          
                          
                          
                          2,042Total
      Proved Plus Probable Plus Possible
                          
                          
                          902,465
                          
                          
                          
                          740,623
                          
                          
                          
                          21,732
                          
                          
                          
                          17,961
                          
                          
                          
                          34,459
                          
                          
                          
                          28,279
 
  Net
      Present Values of Future Net Revenue
                    Based
      on Forecast Prices and Costs(9)Before Deducting Income Taxes Discounted
      At
                  After Deducting Income Taxes Discounted
      At0%
                  5%
                  10%
                  15%
                  20%
                  0%
                  5%
                  10%
                  15%
                  20%(MM$)
                  (MM$)
                  (MM$)
                  (MM$)
                  (MM$)
                  (MM$)
                  (MM$)
                  (MM$)
                  (MM$)
                  (MM$)Proved
      Developed Producing(2)(6)
                  2,968
                  2,404
                  1,991
                  1,680
                  1,441
                  2,968
                  2,404
                  1,991
                  1,680
                  1,441Proved
      Non-Producing
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -
                  -Proved
      Undeveloped(2)(8)
                  8,755
                  4,325
                  2,355
                  1,394
                  885
                  6,580
                  3,250
                  1,777
                  1,060
                  680Total
      Proved
                  11,723
                  6,729
                  4,346
                  3,074
                  2,326
                  9,548
                  5,654
                  3,768
                  2,740
                  2,121Probable
      (3)
                  43,652
                  9,742
                  2,500
                  485
                  (191)
                  32,541
                  7,106
                  1,660
                  147
                  (352)Total
      Proved Plus Probable
                  55,376
                  16,471
                  6,846
                  3,559
                  2,135
                  42,089
                  12,760
                  5,428
                  2,887
                  1,769Possible
      4)
                  8,874
                  1,616
                  575
                  361
                  289
                  6,612
                  1,226
                  461
                  306
                  255Total
      Proved Plus Probable Plus Possible
                  64,249
                  18,087
                  7,421
                  3,920
                  2,424
                  48,701
                  13,986
                  5,889
                  3,194
                  2,024
  
 67
  The
following table presents the estimated total future net revenue of OPTI,
undiscounted, based on forecast prices and costs, as estimated in the McDaniel
Report. It should not be assumed that the estimated total future net revenue
shown below is representative of the fair market value of the
reserves.
  Total
      Future Net Revenue (Undiscounted)
                    Based
      on Forecast Prices and Costs(9)Revenue
                  
                  
                  Royalties
                  
                  
                  Operating
      Costs
                  
                  
                  Development
      Costs
                  
                  
                  Abandonment
      Costs
                  
                  
                  Future
      Net Revenue Before Income Taxes
                  
                  
                  Income
      Taxes
                  
                  
                  Future
      Net Revenue After Income Taxes(MM$)
                  
                  
                  (MM$)
                  
                  
                  (MM$)
                  
                  
                  (MM$)
                  
                  
                  (MM$)
                  
                  
                  (MM$)
                  
                  
                  (MM$)
                  
                  
                  (MM$)Total
      Proved(2)
                  
                  
                  24,832
                  
                  
                  
                  2,379
                  
                  
                  
                  8,344
                  
                  
                  
                  2,454
                  
                  
                  
                  60
                  
                  
                  
                  11,723
                  
                  
                  
                  2,176
                  
                  
                  
                  9,548Total
      Proved Plus Probable(2)(3)
                  
                  
                  124,120
                  
                  
                  
                  15,824
                  
                  
                  
                  36,692
                  
                  
                  
                  16,049
                  
                  
                  
                  309
                  
                  
                  
                  55,376
                  
                  
                  
                  13,287
                  
                  
                  
                  42,089Total
      Proved Plus Probable Plus Possible(2)(3)(4)
                  
                  
                  139,012
                  
                  
                  
                  18,609
                  
                  
                  
                  38,944
                  
                  
                  
                  17,011
                  
                  
                  
                  328
                  
                  
                  
                  64,250
                  
                  
                  
                  15,548
                  
                  
                  
                  48,701
 
  The
following table presents the estimated total future net revenue by production
group, of OPTI, based on forecast prices and costs, as estimated in the McDaniel
Report. It should not be assumed that the estimated total future net revenue by
production group shown below is representative of the fair market value of the
reserves.
  Future
      Net Revenue By Production Group
                    Based
      Upon Forecast Prices and Costs(9)Production
      Group
                  
                  Future
      Net Revenue Before Income Taxes (Discounted at 10%/Year)Total
                  
                  
                  Unit
      Basis(MM$)
                  
                  
                  ($/bbl
      of raw bitumen)Total
      Proved(2)
                  Bitumen,
      synthetic crude oil, and butane
                  
                  
                  4,346
                  
                  
                  
                  15.65Total
      Proved Plus Probable(2)(3)
                  Bitumen,
      synthetic crude oil, and butane
                  
                  
                  6,846
                  
                  
                  
                  6.49Total
      Proved Plus Probable Plus Possible(2)(3)(4)
                  Bitumen,
      synthetic crude oil, and butane
                  
                  
                  7,421
                  
                  
                  
                  6.47
   68
  Reserves
Reconciliation
  The
following table sets forth the changes between the reserve volume estimates made
as at December 31, 2008 and the corresponding estimates as at December 31, 2007,
based on forecast prices, net of royalties.
  Proved
                      
                      
                      Probable
                      
                      
                      Proved
      and 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, 2007
                      
                      
                      16,055
                      
                      
                      
                      201,709
                      
                      
                      
                      2,769
                      
                      
                      
                      220,553
                      
                      
                      
                      13,417
                      
                      
                      
                      417,864
                      
                      
                      
                      5,736
                      
                      
                      
                      437,017
                      
                      
                      
                      29,471
                      
                      
                      
                      619,573
                      
                      
                      
                      8,504
                      
                      
                      
                      657,548Extensions
                      
                      
                      16
                      
                      
                      
                      7,917
                      
                      
                      
                      165
                      
                      
                      
                      8,098
                      
                      
                      
                      6,456
                      
                      
                      
                      199,938
                      
                      
                      
                      2,760
                      
                      
                      
                      209,154
                      
                      
                      
                      6,472
                      
                      
                      
                      207,855
                      
                      
                      
                      2,925
                      
                      
                      
                      217,253Improved
      Recovery
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -Technical
      Revisions
                      
                      
                      1,685
                      
                      
                      
                      -
                      
                      
                      
                      5,070
                      
                      
                      
                      6,755
                      
                      
                      
                      (13,961
                      )
                      
                      
                      -
                      
                      
                      
                      15,094
                      
                      
                      
                      1,133
                      
                      
                      
                      (12,276
                      )
                      
                      
                      -
                      
                      
                      
                      20,164
                      
                      
                      
                      7,888Discoveries
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -Acquisitions
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -Dispositions
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -Economic
      Factors
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -Production
      (Estimate)
                      
                      
                      (1,685
                      )
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      (1,685
                      )
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      (1,685
                      )
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      (1,685
                      )Dec
      31, 2008
                      
                      
                      16,071
                      
                      
                      
                      209,626
                      
                      
                      
                      8,004
                      
                      
                      
                      233,701
                      
                      
                      
                      5,912
                      
                      
                      
                      617,802
                      
                      
                      
                      23,590
                      
                      
                      
                      647,304
                      
                      
                      
                      21,983
                      
                      
                      
                      827,427
                      
                      
                      
                      31,594
                      
                      
                      
                      881,004
  Undeveloped
Reserves
  The
following table sets forth the volumes of our share of gross proved undeveloped
reserves that were attributed for each of our product types based on forecast
prices:
  Synthetic
      Crude Oil (PSCTM)
                            
                            
                            Bitumen
                            
                            
                            Butane(mbbl)
                            
                            
                            (mbbl)
                            
                            
                            (mbbl)First
      Attributed
                            
                            
                            Synthetic
      Cumulative
                            
                            
                            First
      Attributed
                            
                            
                            Bitumen
      Cumulative
                            
                            
                            First
      Attributed
                            
                            
                            Butane
      Cumulative2005
                            
                            
                            175,060
                            
                            
                            
                            175,060
                            
                            
                            
                            19,989
                            
                            
                            
                            19,869
                            
                            
                            
                            2,403
                            
                            
                            
                            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
                            
                            
                            
                            6,095
  The
following table sets forth the volumes of our share of gross probable
undeveloped reserves that were attributed for each of our product types based on
forecast prices.
  Synthetic
      Crude Oil (PSCTM)
                          
                          
                          Bitumen
                          
                          
                          Butane(mbbl)
                          
                          
                          (mbbl)
                          
                          
                          (mbbl)First
      Attributed
                          
                          
                          Synthetic
      Cumulative
                          
                          
                          First
      Attributed
                          
                          
                          Bitumen
      Cumulative
                          
                          
                          First
      Attributed
                          
                          
                          Butane
      Cumulative2005
                          
                          
                          172,591
                          
                          
                          
                          172,591
                          
                          
                          
                          1,726
                          
                          
                          
                          1,726
                          
                          
                          
                          2,369
                          
                          
                          
                          2,3692006
                          
                          
                          (6,540
                          )
                          
                          
                          166,051
                          
                          
                          
                          3,554
                          
                          
                          
                          5,280
                          
                          
                          
                          (90
                          )
                          
                          
                          2,2792007
                          
                          
                          251,813
                          
                          
                          
                          417,864
                          
                          
                          
                          8,137
                          
                          
                          
                          13,417
                          
                          
                          
                          3,457
                          
                          
                          
                          5,7362008
                          
                          
                          194,073
                          
                          
                          
                          611,937
                          
                          
                          
                          (7,640
                          )
                          
                          
                          5,777
                          
                          
                          
                          17,628
                          
                          
                          
                          23,364
  
 69
 
  There
are proved and probable undeveloped resources associated with Phase 1 of the
Long Lake Project.  We plan to develop these reserves to maintain
sufficient bitumen feed to the Upgrader.  This development is expected
to occur over the life of the Project.
  There
are proved and probable undeveloped reserves associated with Phase
2.   We plan to be in a position to sanction Phase 2 in mid-2010
at the earliest.  Subsequent to Phase 2 sanctioning, development of
these reserves is expected to occur over the life of this project.
  Future
Development Costs
  We
anticipate that the future development costs will be financed through working
capital, existing debt facilities and internally generated cash
flow.
  In
the event such sources of funds are insufficient to fund the future development
costs, a combination of debt or equity financing may be required.  We
anticipate that the costs of such financing would be a small percentage of the
future development costs and the cost of such financing is implicit in the
discount rate used to calculate the net present values.  In the event
these financing costs were incurred, we would expect no change in reserves or
future net revenue, and does not expect it to make the development of the
property uneconomic.
 
 Future
      Development Costs
                    Based
      on Forecast Prices and CostsTotal
      Proved(2)
                  
                  
                  Total
      Proved Plus Probable(2)(3)(MM$)
                  
                  
                  (MM$)2009
                  
                  
                  109
                  
                  
                  
                  1392010
                  
                  
                  66
                  
                  
                  
                  1802011
                  
                  
                  141
                  
                  
                  
                  5212012
                  
                  
                  12
                  
                  
                  
                  8712013
                  
                  
                  44
                  
                  
                  
                  997Total
      for all years undiscounted
                  
                  
                  2,454
                  
                  
                  
                  16,049Total
      for all years discounted at 10%/year
                  
                  
                  939
                  
                  
                  
                  4,115
 
 
 Notes
to the preceding tables:
 (1)
              “Gross
      Reserves” are the reserves held by us before Crown royalties. “Net
      Reserves” are the reserves held by us after Crown
    royalties.
  (2)
              “Proved”
      reserves are those reserves that can be estimated with a high degree of
      certainty to be recoverable. It is likely that the actual remaining
      quantities recovered will exceed the estimated proved
      reserves.
  (3)
              “Probable”
      reserves are those additional reserves that are less certain to be
      recovered than proved reserves. It is equally likely that the actual
      remaining quantities recovered will be greater or less than the sum of the
      estimated proved plus probable
reserves.
  (4)
              “Possible”
      reserves are those additional reserves that are less certain to be
      recovered than probable reserves. There is a 10% probability that the
      actual remaining quantities recovered will exceed the sum of the estimated
      proved plus probable plus possible
reserves.
  (5)
              “Developed”
      reserves are those reserves that are expected to be recovered from
      existing wells and installed facilities or, if facilities have not been
      installed, that would involve a low expenditure (e.g. when compared to the
      cost of drilling a well) to put the reserves on
  production.
  (6)
              “Developed
      Producing” reserves are those reserves that are expected to be recovered
      from completion intervals open at the time of the estimate. These reserves
      may be currently producing or, if shut-in, they must have previously been
      on production, and the date of resumption of production must be known with
      reasonable certainty.
  (7)
              “Developed
      Non-Producing” reserves are those reserves that either have not been on
      production, or have previously been on production, but are shut in, and
      the date of resumption of production is
unknown.
  (8)
              “Undeveloped”
      reserves are those reserves expected to be recovered from know
      accumulations where a significant expenditure (for example, when compared
      to the cost of drilling a well) is required to render them capable of
      production. They must fully meet the requirements of the reserves
      classification (proved, probable, possible) to which they are
      assigned.
  (9)
              The
      pricing assumptions used in the McDaniel Report with respect to net values
      of future net revenue (forecast) as well as the inflation rates used for
      operating and capital costs are set forth below.  McDaniel is an
      independent qualified reserves evaluator appointed pursuant to NI
      51-101.
  
 70
  Oil
                    Synthetic
      Oil
                    Condensate
                    Butane
                    Natural
      Gas
                    Bitumen
                    Inflation
      Rate
                    Exchange
      RateWTI
      Crude Oil Price $US/bbl
                    Edmonton
      Light Oil Price $Cdn/bbl
                    WCS
                      Hardisity
      Oil Price $Cdn/bbl
                    Edmonton
      Synthetic Oil Price $Cdn/bbl
                    PSC
      at
                      Long
      Lake Synthetic Oil Price $Cdn/bbl
                    Edmonton
      Condensate Price $Cdn/bbl
                    Field
      Butane Price $Cdn/bbl
                    Alberta
      Spot Gas Price $Cdn/mmbtu
                    DilBit
      at Hardisty CDN$/Bbl
                    Bitumen
      Netback CDN$/Bbl
                    %/
      year
                    $US/$CdnForecast2009
                    60.00
                    69.60
                    53.65
                    73.60
                    74.31
                    71.60
                    47.35
                    7.02
                    53.65
                    40.23
                    2.0
                    0.8502010
                    71.40
                    83.00
                    63.84
                    85.00
                    85.73
                    85.00
                    57.08
                    7.59
                    63.84
                    48.20
                    2.0
                    0.8502011
                    83.20
                    91.40
                    70.26
                    92.90
                    93.64
                    93.50
                    63.20
                    8.01
                    70.26
                    52.90
                    2.0
                    0.9002012
                    90.20
                    93.90
                    72.16
                    94.90
                    95.66
                    96.00
                    64.92
                    8.34
                    72.16
                    54.39
                    2.0
                    0.9502013
                    97.40
                    96.30
                    74.02
                    96.30
                    97.07
                    98.50
                    66.55
                    8.58
                    74.02
                    55.83
                    2.0
                    1.0002014
                    99.40
                    98.30
                    75.54
                    97.80
                    98.59
                    100.50
                    67.97
                    8.77
                    75.54
                    56.99
                    2.0
                    1.0002015
                    101.40
                    100.30
                    77.06
                    99.30
                    100.10
                    102.60
                    69.39
                    8.96
                    77.06
                    58.10
                    2.0
                    1.0002016
                    103.40
                    102.30
                    78.58
                    100.80
                    101.62
                    104.60
                    70.71
                    9.10
                    78.58
                    59.25
                    2.0
                    1.0002017
                    105.40
                    104.20
                    80.10
                    102.67
                    103.51
                    106.50
                    72.02
                    9.29
                    80.10
                    60.45
                    2.0
                    1.0002018
                    107.60
                    106.40
                    81.78
                    104.84
                    105.69
                    108.80
                    73.54
                    9.48
                    81.78
                    61.68
                    2.0
                    1.0002019
                    109.70
                    108.50
                    83.37
                    106.91
                    107.78
                    110.90
                    75.05
                    9.67
                    83.37
                    62.90
                    2.0
                    1.0002020
                    111.90
                    110.70
                    85.04
                    109.08
                    109.96
                    113.20
                    76.56
                    9.86
                    85.04
                    64.12
                    2.0
                    1.0002021
                    114.10
                    112.80
                    86.72
                    111.14
                    112.05
                    115.30
                    77.97
                    10.05
                    86.72
                    65.44
                    2.0
                    1.0002022
                    116.40
                    115.10
                    88.46
                    113.41
                    114.33
                    117.70
                    79.58
                    10.24
                    88.46
                    66.72
                    2.0
                    1.0002023
                    118.80
                    117.50
                    90.29
                    115.78
                    116.72
                    120.10
                    81.17
                    10.48
                    90.29
                    68.12
                    2.0
                    1.0002024
                    121.18
                    119.85
                    92.09
                    118.09
                    119.05
                    122.50
                    82.79
                    10.69
                    92.09
                    69.48
                    2.0
                    1.0002025
                    123.60
                    122.25
                    93.94
                    120.45
                    121.43
                    124.95
                    84.45
                    10.90
                    93.94
                    70.87
                    2.0
                    1.0002026
                    126.07
                    124.69
                    95.81
                    122.86
                    123.86
                    127.45
                    86.14
                    11.12
                    95.81
                    72.29
                    2.0
                    1.0002027
                    128.59
                    127.19
                    97.73
                    125.32
                    126.34
                    130.00
                    87.86
                    11.34
                    97.73
                    73.73
                    2.0
                    1.0002028
                    131.16
                    129.73
                    99.69
                    127.83
                    128.87
                    132.60
                    89.62
                    11.57
                    99.69
                    75.21
                    2.0
                    1.0002029
                    133.79
                    132.32
                    101.68
                    130.38
                    131.44
                    135.25
                    91.41
                    11.80
                    101.68
                    76.71
                    2.0
                    1.0002030
                    136.46
                    134.97
                    103.71
                    132.99
                    134.07
                    137.96
                    93.24
                    12.04
                    103.71
                    78.24
                    2.0
                    1.0002031
                    139.19
                    137.67
                    105.79
                    135.65
                    136.76
                    140.72
                    95.10
                    12.28
                    105.79
                    79.81
                    2.0
                    1.0002032
                    141.98
                    140.42
                    107.90
                    138.36
                    139.49
                    143.53
                    97.00
                    12.52
                    107.90
                    81.41
                    2.0
                    1.0002033
                    144.82
                    143.23
                    110.06
                    141.13
                    142.28
                    146.40
                    98.94
                    12.77
                    110.06
                    83.03
                    2.0
                    1.000Thereafter
                    +2.0%/yr
                    +2.0%/yr
                    +2.0%/yr
                    +2.0%/yr
                    +2.0%/yr
                    +2.0%/yr
                    +2.0%/yr
                    +2.0%/yr
                    +2.0%/yr
                    +2.0%/yr
                    2.0
                    1.000
 Pricing
Assumptions:
  WTI,
Edmonton Light, Edmonton Synthetic, WCS Hardisty, Edmonton Condensate, Edmonton
Butane and Alberta Spot Gas Price forecasts were based on the McDaniel January
1, 2009 price forecast.  PSC pricing is based on a $0.70/bbl premium
to Edmonton synthetic.  Transportation costs for bitumen, PSC and
Butane were supplied by the JV Participants.
  Oil
Wells
  As
at December 31, 2008, we had an interest in 81 gross (40.5 net) SAGD well
pairs.  These well pairs are contained within the Long Lake SAGD
operation and are comprised of 78 gross (39 net) oil wells and 78 gross (39 net)
injection wells, the remainder are within the SAGD Pilot and are comprised of 3
gross (1.5 net) producing oil wells and 3 gross (1.5 net) injection
wells.
  Properties
with No Attributed Reserves
  The
Long Lake Leases comprise 98 sections. Proved, probable and possible reserves
have been assigned, in whole and in part, on 70 sections of these lands and 28
sections have no reserves assigned.  resources have been assigned to
some of these 28 sections. At January 26, 2009, we have a 35 percent working
interest in all of these lands.
  At
January 26, 2009, we have a 35 percent working interest in an additional306 sections of land,
also in the Athabasca region. These lands, contained primarily within the
Leismer and Cottonwood Leases, have had no reserves assigned to
them.
  There
are no work commitments associated with any of these lands.
  71
 Abandonment
and Reclamation Costs
  We
have abandonment and reclamation liabilities relating primarily to SAGD Pilot
facilities and wells, and facilities for the Upgrader and SAGD operation. The
future commercial development will result in additional drilling and the
construction of upgrading and resource facilities.
  We
estimate the abandonment liability, net of salvage, for these assets with
consideration given to the expected cost to abandon and reclaim wells,
facilities and surface area. These estimates are based on prevailing industry
conditions, regulatory requirements and past experience. Estimates are required
for the amount, timing and nature of the abandonment in order to determine the
present value of the liability. Financial estimates such as inflation and
interest rates also impact the calculation of the present value of the
abandonment liability.
  The
liability is estimated in the period in which the liability is incurred. These
estimates are prepared annually and adjustments are made quarterly for material
changes in the amount of the liability or the timing of abandonment. Where
material differences are identified, adjustments to the liabilities or accretion
expense are made on a prospective basis.
  Our
share of the present value of abandonment and reclamation costs that require
recognition in the amended financial statements at December 31, 2008 is $8
million for our 50 percent working interest. The total undiscounted future
amount of abandonment liabilities expected to be incurred is $151million based on
measurement criteria under Canadian GAAP. These liabilities relate to facilities
and wells completed or under construction at the end of 2008. At December 31,
2008, there are 81 gross wells for which abandonment liabilities have been
recognized.  These gross wells include the SAGD Pilot wells and the
commercial SAGD wells.  In addition, we have abandonment liabilities
in relation to SAGD and Upgrader facilities currently under
construction.  The undiscounted amount used in the constant dollar,
proved plus probable plus case of the McDaniel report is $56 million net to
us.
  We
incurred negligible abandonment costs in 2008 and expect to incur none in the
next two years.
  Tax
Horizon
  We
did not pay any current income taxes in our fiscal year ended December 31, 2008.
Considering the capital costs associated with Phase 1 only and pricing and
cost estimates developed by us and our existing tax pools, we do not anticipate
paying income taxes until approximately 2014, based on the Proved plus Probable
case in the McDaniel Report. This estimate will be impacted by, among other
factors, the final construction cost of the Project, commodity prices, foreign
exchange rates, operating costs, interest rates, expansions of the Project and
OPTI's other business activities. Changes in these factors from estimates used
by us could result in us paying income taxes earlier or later than
expected.
  72
 Costs
Incurred
  The
following table sets forth costs incurred by us for Oil and Gas activities for
the year ended December 31, 2008:
  ($
      millions) Property Acquisition Costs (1)Proved
      Properties
              Unproved
      Properties
              Exploration
      Costs
              Development
      Costs (2)$0
              $0
              $71
              $361
 
 Notes:
 (1)
              All
      of these costs were capitalized by
OPTI.
 (2)
              Development
      Costs do not include capital associated with the Upgrader.  In
      the year ended December 31, 2008, costs incurred by us in relation to the
      Upgrader were $282 million.
  Exploration
and Development Activities
  During
2008, no SAGD horizontal wells were drilled.
  Production
Estimates
  McDaniel estimates,
based on the proved plus probable case, that the Project will produce
on average approximately 41,150 bbl/d (20,575 bbl/d net to OPTI’s 50 percent
working interest) of raw bitumen in 2009.  The start-up of the
Upgrader and commencement of synthetic crude oil and butane sales occurred in
January, 2009.
  It
is assumed that adequate well pairs will be drilled to keep the upgrader full
until the cumulative recoverable 2P reserves are produced.  With
regards to the production profile in the near term, the production rate has been
based on McDaniel & Associates assumptions of well-pair productivity and
well-pair drilling schedule.  McDaniel holds different views regarding
well-pair productivity than OPTI and Nexen.  The result of which is the
requirement for additional wells in the next few years to reach facility
production capacity.
  Production
History
  The
Long Lake Project began producing bitumen in the second quarter of
2008.  The Upgrader started up in the first quarter of
2009.  During the initial operating period, we expect periods of
Upgrader down time but anticipate that the stability of operations will continue
to improve.  It is anticipated that the Project will ramp-up through
2009 and reach design rates of 72,000 bbl/d of bitumen, upgraded into 58,500
bbl/d of PSCTM and other products, in 2010.
  Prior
to stable Upgrader operations, the SAGD operation will consume a significant
amount of natural gas.  At full production, we expect to self-supply
the equivalent of 100 million cubic feet per day of natural gas through the use
of our proprietary integrated 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.  Further, they are calculated for SAGD operations only, as
the Upgrader was not yet operational in 2008.
 
 For an illustration of expected
netbacks upon reaching full commercial production, see “Estimated Future Project
Netbacks” on page 8 of this document.
  Q3
      2008
                    
                    
                    
                    Q4
      2008Bitumen
      production (bbl/day)(1)
                    
                    
                    5,215
                    
                    
                    
                    6,596
 
 Netback
 
 In
      CDN$/bbl (2)
                      
                      
                      Q3
      2008
                      
                      
                      
                      Q4
      2008$/bbl
                      
                      
                      $/bblRevenue
      (3)
                      
                      $
                      71.91
                      
                      
                      $
                      0.28Royalties
                      
                      
                      (0.67
                      )
                      
                      
                      (0.07
                      )Production
      costs (4)
                      
                      
                      (77.20
                      )
                      
                      
                      (78.33
                      )Netback
                      
                      $
                      (5.96
                      )
                      
                      $
                      (78.12
                      )
 
 
 Notes:
 (1)
                Bitumen
      production is OPTI’s share only.  Volumes prior to Q3 2008 are
      not considered material.
 (2)
                Per
      barrel calculations are based on bitumen
  production.
 (3)
                  Bitumen
      revenue per barrel is based on the value assigned to bitumen for royalty
      calculation purposes.(4)
                  Production
      costs only include SAGD operating
costs.
    73
  APPENDIX
B
  FORM
51-101 F2
 REPORT
ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR
  To
the board of directors of OPTI Canada Inc. (the "Company"):
  1.
              We
      have evaluated the Corporation's reserves data as at December 31, 2008.
      The reserves data are estimates of proved reserves and probable reserves
      and related future net revenue as at December 31, 2008, estimated using
      forecast prices and costs.
  2.
              The
      reserves data are the responsibility of the Company's management. Our
      responsibility is to express an opinion on the reserves data based on our
      evaluation.
  We
carried out our evaluation in accordance with standards set out in the Canadian
Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the
Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian
Institute of Mining, Metallurgy & Petroleum (Petroleum
Society).
  3.
              Those
      standards require that we plan and perform an evaluation to obtain
      reasonable assurance as to whether the reserves data are free of material
      misstatement. An evaluation also includes assessing whether the reserves
      data are in accordance with principles and definitions in the COGE
      Handbook.
  4.
              The
      following table sets forth the estimated future net revenue (before
      deduction of income taxes) attributed to proved plus probable reserves,
      estimated using forecast prices and costs and calculated using a discount
      rate of 10 percent, included in the reserves data of the Company evaluated
      by us, for the year ended December 31, 2008, and identifies the respective
      portions thereof that we have evaluated and reported on to the Company’s
      management:
  Net
      Present Value of Future Net Revenue
                (before
      income taxes, 10 percent discount rate, in $MM)Preparation
      Date of Evaluation Report
              Location
      of Reserves (Country or Foreign Geographic Area)
              Audited
              Evaluated
              Reviewed
              TotalFebruary
      11, 2009
              Canada
              -
              6,846
              -
              6,846
 
 5.
              In
      our opinion, the reserves data evaluated by us have, in all material
      respects, been determined and are in accordance with the COGE
      Handbook.  We express no opinion on the reserves data that we
      have reviewed but did not audit or
evaluate.
  6.
              We
      have no responsibility to update our reports referred to in paragraph 4
      for events and circumstances occurring after their respective preparation
      date.
  7.
              Because
      the reserves data are based on judgments regarding future events, actual
      results will vary and the variations may be material. However, any
      variations should be consistent with the fact that reserves are
      categorized according to the probability of their
  recovery.
  
 74
  
  Executed
as to our report referred to above:
  McDaniel
& Associates Consultants Ltd., Calgary, Alberta, Canada
  Dated
February 11, 2009
  
 (signed)"C.B. Kowalski P.Eng”
 Vice
President
 
 75
 APPENDIX
C
  
 FORM
51-101 F3
 REPORT
OF MANAGEMENT ON RESERVES DATA AND OTHER INFORMATION
  Management
of OPTI Canada Inc. (the "Corporation") are responsible for the preparation and
disclosure of information with respect to the Corporation's oil and gas
activities in accordance with securities regulatory requirements. This
information includes reserves data, which are estimates of proved reserves and
probable reserves and related future net revenue as at December 31, 2008,
estimated using forecast prices and costs and the related estimated future net
revenue.
  An
independent qualified reserves evaluator has evaluated the Corporation's
reserves data. The report of the independent qualified reserves evaluator is
presented in Appendix B to this Annual Information Form.
  The
Technical Committee of the board of directors of the Corporation
has:
  (a)
                reviewed the Corporation's
      procedures for providing information to the independent qualified reserves
      evaluator;
  (b)
                met with the independent qualified
      reserves evaluator to determine whether any restrictions affected the
      ability of the independent qualified reserves evaluator to report without
      reservation; and
  (c)
                reviewed the reserves data with
      management and the independent qualified reserves
      evaluator.
 The
Technical Committee of the board of directors has reviewed the Corporation's
procedures for assembling and reporting other information associated with oil
and gas activities and has reviewed that information with management. The board
of directors has, on the recommendation of the Technical Committee,
approved:
  (a)
                the content and filing with
      securities regulatory authorities of Form 51-101F1 containing reserves
      data and other oil and gas
information;
  (b)
                the filing Form 51-101F2 which is
      the report of the independent qualified reserves evaluator on the reserves
      data; and
  (c)
                the content and filing of this
      report.
 Because
the reserves data are based on judgements regarding future events, actual
results will vary and the variations may be material. However, any variations
should be consistent with the fact that reserves are categorized according to
the probability of their recovery.
  76
 
 (signed)
"Sid W.
Dykstra"
 President
and Chief Executive Officer
 
 
 (signed)
“William
King”
 Vice
President, Development
 
 
 (signed)
"Charles
Dunlap"
 Director
 
 
 (signed)
"Edythe (Dee)
Marcoux"
 Director
 
 
 Dated  March
24, 2009
  77
  APPENDIX
D
 AUDIT
COMMITTEE CHARTER
  A.           
FUNCTION
  The
Audit Committee is part of the board of directors and its function is to assist
the Board in fulfilling its stewardship with respect to: (i) financial
statements and financial reporting, (ii) the relationship with the external
auditor, (iii) the adequacy and effectiveness of internal controls and
management information systems and (iv) financial risk management. The Audit
Committee provides assistance by reviewing, reporting, and recommending such
matters to the Board for consideration and decision.
  B.           CONSTITUTION
  1.
              The
      Audit Committee members shall be appointed by the Board and serve at the
      pleasure of the Board until they are succeeded or resign. Where a vacancy
      occurs at any time in the membership of the Audit Committee, it shall be
      filled by the Board.
  2.
              The
      Audit Committee shall be constituted with a minimum of three directors,
      each of whom shall satisfy the independence, financial literacy and
      experience requirements of applicable statutes and
      regulations.
  3.
              A
      recording assistant for the Audit Committee shall be appointed by the
      Board.
  C.           COMMUNICATION,
AUTHORITY TO ENGAGE ADVISORS
  1.
              The
      Audit Committee shall have access to such officers and employees of the
      Corporation, the Corporation's external auditor and information respecting
      the Corporation as it considers necessary or advisable in order to perform
      its duties and responsibilities.
  2.
              The
      Audit Committee provides an avenue for communication with the external
      auditor and financial management and the Board. The external auditor shall
      have a direct line of communication to the Audit Committee through its
      Chair and shall report directly to the Audit
  Committee.
  3.
              In
      discharging its obligations and in appropriate circumstances, the Audit
      Committee may engage outside advisors at the expense of the
      Corporation.
  D.           
MEETINGS, MINUTES AND REPORTING
  1.
              The
      Audit Committee shall determine the number of, dates and times, place and
      the procedures for meetings provided
that:
  (a)
              the
      Audit Committee meets at least
quarterly;
  (b)
              the
      Audit Committee shall meet prior to Board meetings for the purpose of
      reviewing and preparing recommendations to the
  Board;
  (c)
              agendas
      and preparation documents are sent to members with sufficient time for
      study prior to the meetings;
  (d)
              there
      be a quorum of two members present in person or via
  phone;
   78
  (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;
   79
  (f)
              as
      may be required by applicable securities laws, rules and guidelines,
      either:
  (i)
              pre-approve
      all non-audit services to be provided by the external auditor to the
      Corporation (and its subsidiaries, if any), or, in the case of inadvertent
      non-audit services where the aggregate fees for such services is no more
      than five percent of all the fees paid to the external auditor, approve
      such non-audit services prior to the completion of the audit;
      or
  (ii)
              adopt
      specific policies and procedures for the engagement of the external
      auditor for the purposes of the provision of non-audit services;
      and
  (g)
              review
      and decide the hiring practices of the Corporation regarding partners and
      employees and former partners and employees of the present and former
      external auditor of the
Corporation.
  Financial Statements and
Financial Reporting
  1.
              The
      Audit Committee shall:
  (a)
              review
      with management and the external auditor, and recommend to the Board for
      decision, the annual financial statements of the Corporation and related
      financial reporting, including annual report, management's discussion and
      analysis and related press
releases;
  (b)
              upon
      completion of each audit, review with the external auditor the results of
      such audit, which includes but not be limited
  to:
  (i)
              reviewing
      the scope of the audit work
performed;
  (ii)
              reviewing
      the capability of the Corporation's key financial
    personnel;
  (iii)
              reviewing
      the co-operation received from the Corporation's financial personnel
      during the audit;
  (iv)
              reviewing
      the internal resources used;
  (v)
              reviewing
      significant transactions outside of the normal business of the
      Corporation; and
  (vi)
              reviewing
      significant proposed adjustments and recommendations for improving
      internal accounting controls, accounting principles or management
      systems;
  (c)
              review
      with management and the external auditor, and approve the interim
      financial statements of the Corporation and related financial reporting,
      including interim report, management's discussion and analysis and related
      press releases;
  (d)
              review
      Audit Committee information within the information/proxy circular and
      annual information form and recommend changes to the Board for
      decision;
  (e)
              review
      with management and recommend to the Board for decision, any financial
      statements of the Corporation which have not previously been approved by
      the Board and which are to be included in a prospectus or other public
      disclosure document of the
Corporation;
   80
  (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.
  
  81


MANAGEMENT’S
DISCUSSION AND ANALYSIS
  For the
year ended
  December
31, 2008
 
 
 
 MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
 The
following Management’s Discussion and Analysis (MD&A) dated February 24,
2009 should be read in conjunction with the audited financial statements for the
year ended December 31, 2008.
 
 FORWARD-LOOKING
INFORMATION
 The
MD&A is a review of our financial condition and results of operations. Our
financial statements are prepared based upon Canadian Generally Accepted
Accounting Principles (GAAP) and all amounts are in Canadian dollars unless
specified otherwise.  Certain statements contained herein are
forward-looking statements, including, but not limited to, statements relating
to: the expected production performance of the Long Lake Project; OPTI Canada
Inc.'s (OPTI) other business prospects, expansion plans and strategies; the
cost, development and operation of the Long Lake Project and OPTI's relationship
with Nexen Inc. (Nexen); OPTI's financial outlook respecting the estimate of the
netback for Phase 1 of the Project; OPTI's anticipated financial condition and
liquidity over the next 12 to 24 months; and our estimated future tax liability.
Forward-looking information typically contains statements with words such as
“intends,” "anticipate," "estimate," "expect," "potential," "could," “plan” or
similar words suggesting future outcomes. Readers are cautioned not to place
undue reliance on forward-looking information because it is possible that
expectations, predictions, forecasts, projections and other forms of
forward-looking information will not be achieved by OPTI. By its nature,
forward-looking information involves numerous assumptions, inherent risks and
uncertainties. A change in any one of these factors could cause actual events or
results to differ materially from those projected in the forward-looking
information. Although OPTI believes that the expectations reflected in such
forward-looking statements are reasonable, OPTI can give no assurance that such
expectations will prove to be correct.  Forward-looking statements are
based on current expectations, estimates and projections that involve a number
of risks and uncertainties which could cause actual results to differ materially
from those anticipated by OPTI and described in the forward-looking statements
or information.  The forward-looking statements are based on a number
of assumptions which may prove to be incorrect.  In addition to other
assumptions identified herein, OPTI has made assumptions regarding, among other
things: market costs and other variables affecting operating costs of the
Project;  the ability of the Long Lake Project joint venture partners
to obtain equipment, services and supplies, including labour, in a timely and
cost-effective manner; the availability and costs of financing; oil prices and
market price for the Premium Sweet Crude (PSCTM) output of the OrCrudeTM Upgrader;
foreign currency exchange rates and hedging risks;  government
regulations and royalty regimes; and the degree of risk that governmental
approvals may be delayed or withheld.  Other specific assumptions and
key risks and uncertainties are described elsewhere in this document and in
OPTI's other filings with Canadian securities
authorities.
 Readers
should be aware that the list of assumptions, risks and uncertainties set forth
herein are not exhaustive.  Readers should refer to OPTI's current
Annual Information Form (AIF), which is available at www.sedar.com, for a
detailed discussion of these assumptions, risks and uncertainties. The
forward-looking statements or information contained in this document are made as
of the date hereof and OPTI undertakes no obligation to update publicly or
revise any forward-looking statements or information, whether as a result of new
information, future events or otherwise, unless so required by applicable laws
or regulatory policies.
 
 2
 Reserve and Resource
Estimates: The estimates of resources and of economically recoverable
bitumen reserves contained herein are forward-looking statements. The estimates
are based upon a number of factors and assumptions made as of the date on which
the reserve and resource estimates were determined, such as geological and
engineering estimates which have inherent uncertainties, the assumed effects of
regulation by government agencies and estimates of future commodity prices and
operating costs, all of which may vary considerably from actual results. All
such estimates are, to some degree, uncertain and classifications of reserves
are only attempts to define the degree of uncertainty involved. The estimates
contained herein with respect to reserves and resources that may be developed
and produced in the future have been based upon volumetric calculations and upon
analogy to similar types of reserves and resources, rather than upon actual
production history. Estimates based on these methods generally are less reliable
than those based on actual production history. Subsequent evaluation of the same
reserves and resources based upon production history will result in variations,
which may be material, in the estimated reserves and resources.
  Additional
information relating to our Company, including our AIF, can be found at www.sedar.com.
 
 FINANCIAL
SUMMARY
 In
      millions
                        
                        Years
      ended December 312008
                        
                        
                        2007
                        
                        
                        2006Earnings
      (loss)
                        $
                        (257)
                        (1)
                        
                        $
                        (9
                        )
                        
                        $
                        (10
                        )Total
      oil sands expenditures (2)
                        
                        
                        775
                        
                        
                        
                        961
                        
                        
                        
                        1,056Working
      capital (deficiency)  (3)
                        
                        
                        (25
                        )
                        
                        
                        271
                        
                        
                        
                        554Shareholders’
      equity
                        $
                        
                        1,556
                        
                        
                        $
                        1,816
                        
                        
                        $
                        1,444Common
      shares outstanding (basic)
                        
                        195.9
                        (4)
                        
                        
                        195.4
                        
                        
                        
                        172.7
 
 Notes:
 (1)
      Includes $392 million pre-tax asset impairment provision related to
      working interest sale to Nexen.
 (2)
      Capital expenditures related to Phase 1 and future phase development.
      Capitalized interest, hedging gains/losses and non-cash additions or
      charges are excluded.
 (3)
      Includes current portion of interest reserve account where applicable and
      amounts due in June 2009 in relation to our $150 million revolving debt
      facility.  This $150 million facility was repaid and cancelled
      in January 2009.
 (4)
      Common shares outstanding at the end of 2008 after giving effect to the
      exercise of common share options would be approximately 203 million common
      shares.
 
 OVERVIEW
 OPTI Canada Inc. is
a Calgary, Alberta-based company focused on developing major oil sands projects
in Canada using our proprietary OrCrudeTM process. Our first project, Phase 1 of
the Long Lake Project (the Project), consists of 72,000 barrels per day of SAGD
(steam assisted gravity drainage) bitumen production integrated with an
upgrading facility. The Upgrader uses the OrCrudeTM process combined with
commercially available hydrocracking and gasification. Through gasification,
this configuration substantially reduces the exposure to and the need to
purchase natural gas. On a 100 percent basis, the Project is expected to produce
58,500 bbl/d of products, primarily 39 degree API Premium Sweet Crude (PSCTM)
with low sulphur content, making it a highly desirable refinery feedstock. Due
to its premium characteristics, we expect PSCTM to sell
at a price similar to West Texas Intermediate (WTI) crude oil. The Project is
being operated in a joint venture with Nexen Inc. (Nexen).
 
 
 3
 PROJECT
STATUS
 First
production of PSCTM from the Long Lake Project was achieved in January 2009.
Preparation is underway to transition gasifier feed from vacuum residue to
asphaltenes, the final step in Upgrader commissioning. Synthesis gas from the
Upgrader has been used in SAGD operations, decreasing operating costs by
reducing the requirement for purchased third-party natural gas.  During the initial operating period, we
expect periods of downtime
but anticipate that the stability of operations will continue to improve.
The Upgrader is currently gasifying but not producing PSCTM due to issues with
water supply and treating but is expected to resume production in the near
future.  Essentially all of the PSCTM produced to date has been used as
diluent.
 
 During
the final commissioning phase, prior to the operation of the solvent
deasphalting and thermal cracking units, there is a high percentage of diluent
that feeds the Upgrader and continues to the hydrocracker, forming part of the
PSCTM stream. We have produced over 20,000 bbl/d (gross) of on-spec PSCTM, with
between 10,000 and 12,000 bbl/d (gross) of this representing upgraded bitumen.
The remainder represents diluent processed through the Upgrader. The percentage
of diluent in the Upgrader feed will decrease as bitumen production
increases.
 
 We
expect Upgrader capacity during ramp-up will be capable of processing all of the
forecasted SAGD volumes and we expect the Project to reach full capacity of
approximately 58,500 bbl/d of PSCTM and other products in 12 to 18
months.
 
 The
reservoir continues to perform as expected given the amount of steam we have
injected. However, SAGD ramp-up has been affected by a variety of surface issues
that have limited the amount of steam we have been able to inject into the
reservoir over the past few months due to power disruptions, extreme cold
weather, and water temperature and treating issues. Since steam injection rates
directly impact bitumen production rates, and the ability to generate steam is
currently limited, bitumen production is lower than previously expected.
Solutions are being developed to place more heat into the front end of the
steaming process to supplement the heat returns from the reservoir. Given
steaming constraints, allocation of steam was necessary and accordingly only 32
of 81 well pairs are presently in production mode. January bitumen production
averaged approximately 13,000 bbl/d (gross). As steam capacity increases, the
remaining wells will be brought on-stream.
 ADVANCING
FUTURE PHASES
 Our
capital program for 2009 includes funds allocated to advance detailed
engineering on the SAGD and Upgrader facilities for Phase 2 of the Project and
also includes funds for additional core hole drilling to further delineate our
nearer-term development leases.
 
 Regulatory
approval for Phases 2 and 3 of SAGD development at Long Lake (Long Lake South)
was received in February 2009. Phase 2 sanctioning will depend on multiple
factors including initial performance of Phase 1, receiving regulatory approval
for Phase 2 SAGD operations, receiving clarity on proposed climate change
regulations, developing cost estimates and an improved economic environment. We
therefore do not expect to consider sanctioning Phase 2 until mid-2010 at the
earliest.
 
 4
 COMPLETION
OF ASSET SALE AND DEBT FACILITY AMENDMENT
 On
January 27, 2009, OPTI announced that we had completed the sale of a 15 percent
working interest in our joint venture assets to our partner Nexen for $735
million. Effective January 1, 2009 , OPTI has a 35 percent working interest in
all joint venture assets, including Phase 1 of the Project, all future phase
reserves and resources, and future phases of development.
 
 As a
result of the asset sale, our revolving debt facilities were amended on January
27, 2009. Significant changes include:
 •
              $150
      million revolving credit facility was repaid and
  cancelled;
 •
              $500
      million revolving credit facility was reduced to $350 million, a total of
      approximately $400 million was repaid through February 17, 2009, and
      applicable interest rates were increased by approximately 2 to 4
      percent depending on our debt
ratings;
 •
              First
      lien to earnings
      before interest, tax, depreciation and amortization (EBITDA)
      covenant commences in the third quarter of 2009 with a maximum ratio 2.5:1
      as defined in Note 10 to the audited financial statements for the year
      ended December 31, 2008 (previously the first quarter of 2009 and a ratio
      of 3.5:1);
 •
              Debt
      to capitalization ratio was increased to 70 percent from 65 percent also
      as defined in Note 10 to the audited financial statements for the year
      ended December 31, 2008; and
 •
              The
      Canadian measurement of our U.S. dollar-denominated debt was changed from
      a period end exchange rate to an average rate for the preceding
      quarter.
 
 CORPORATE
UPDATE
 OPTI’s
management team is transitioning as a result of the asset sale to
Nexen.  David Halford, Chief Financial Officer, Mary Bulmer, VP Human
Resources and Corporate Services, and Peter Duda, VP Operations will be leaving
to pursue other business opportunities. They will remain with OPTI for various
periods to continue to facilitate the transition.
 
 Travis
Beatty has been appointed Vice President, Finance and Chief Financial Officer of
OPTI effective March 1, 2009. Mr. Beatty joined OPTI in 2002 as Controller and
since then has also held the roles of Treasurer and Director, Planning. Mr.
Beatty is a Chartered Accountant and a Chartered Financial Analyst, and holds a
B.Comm from the University of Calgary.
 
 Al
Smith has been appointed Vice President, Marketing effective March 1, 2009. Mr.
Smith joined OPTI in 2006 as Director, Marketing. Mr. Smith is a professional
engineer in Alberta and is a member of both APEGGA and APEGBC. He holds a
B.A.Sc. in Chemical Engineering from the University of Waterloo.
 
 Going
forward, OPTI’s senior management team will consist of: Sid Dykstra, President
and Chief Executive Officer; Travis Beatty, VP Finance and CFO; Joe Bradford, VP
Legal and Administration and Corporate Secretary; Bill King, VP Development; and
Al Smith, VP Marketing.
  5
  RESERVES
AND RESOURCES
 OPTI
has a significant presence in the Athabasca oil sands, with a 35 percent
interest in over 385 sections of land on three leases:  Long Lake,
Leismer and Cottonwood.  We believe our existing lands will support
approximately 360,000 bbl/d of PSCTMproduction (126,000 bbl/d net to OPTI) from six phases including Long
Lake Phase 1. Based on reserve and resource estimates, we believe there is
potential for three phases at Long Lake, two phases at Leismer and one at
Cottonwood. With a limited delineation program in the 2007/2008 winter
drilling season, total reserve and resource volumes did not change
significantly.
 
 Reserves
 McDaniel
& Associates (McDaniel), our reserves and resources evaluator, has prepared
a report evaluating the bitumen reserves and synthetic oil reserves of the Long
Lake leases effective December 31, 2008. Due to the advanced nature of our Long
Lake Phase 2 project, previously recognized Contingent Resources are now booked
as probable and possible reserves.
 For
2008, McDaniel has also recognized probable and possible reserves associated
with lands outside the Phase 2 initial development area to include certain lands
pertaining to Phase 3 development. This is due, in part, to the inclusion of
Phase 3 lands in the Long Lake South Environmental Impact Assessment, requisite
levels of delineation being met on the Phase 3 lands, as well as McDaniels’
confidence in the development of these lands now that Phase 1 is
commercial.
 
 The
McDaniel evaluation of our lands recognizes the impact of upgrading on the
resources. Most of the raw bitumen will be upgraded and sold as PSCTM and butane,
and is shown as synthetic crude oil or butane reserves. Bitumen was sold prior
to Upgrader start-up, is planned to be sold during periods of Upgrader downtime,
and is shown as bitumen reserves.
 
 The
following table shows OPTI’s 50 percent working interest in the raw bitumen
reserves and the corresponding sales volumes at December 31, 2008, prior to
taking account of the sale of the 15 percent working interest.
 
 2008
(prior to the sale of the 15 percent working interest)
 Raw
      Bitumen
                                                      
                                                      
                                                      Gross Sales VolumesAll
      volumes are millions of barrels
                                                      
                                                      
                                                      
                                                      
                                                      PSCTM
                                                      
                                                      
                                                      Bitumen
                                                      
                                                      
                                                      ButaneProven
      (1)
                                                      
                                                      
                                                      278
                                                      
                                                      
                                                      
                                                      210
                                                      
                                                      
                                                      
                                                      16
                                                      
                                                      
                                                      
                                                      8Proven
      plus probable (2)
                                                      
                                                      
                                                      1,054
                                                      
                                                      
                                                      
                                                      827
                                                      
                                                      
                                                      
                                                      22
                                                      
                                                      
                                                      
                                                      32Proven
      plus probable plus possible (3)
                                                      
                                                      
                                                      1,148
                                                      
                                                      
                                                      
                                                      902
                                                      
                                                      
                                                      
                                                      22
                                                      
                                                      
                                                      
                                                      34
 
 6
 The
following table shows OPTI’s 35 percent working interest in the raw bitumen
reserves and the corresponding sales volumes as at December 31, 2008 after
taking account of the sale of the 15 percent working interest.
 
 2008
(subsequent to the sale of the 15 percent working interest)
 Raw
      Bitumen
                                
                                
                                Gross Sales VolumesAll
      volumes are millions of barrels
                                
                                
                                
                                
                                PSCTM
                                
                                
                                Bitumen
                                
                                
                                ButaneProven
      (1)
                                
                                
                                194
                                
                                
                                
                                147
                                
                                
                                
                                11
                                
                                
                                
                                6Proven
      plus probable (2)
                                
                                
                                738
                                
                                
                                
                                579
                                
                                
                                
                                15
                                
                                
                                
                                22Proven
      plus probable plus possible (3)
                                
                                
                                803
                                
                                
                                
                                632
                                
                                
                                
                                15
                                
                                
                                
                                24
  
 Notes
to both reserve tables:
 (1)
              Proven
      reserves are those reserves that can be estimated with a high degree of
      certainty to be recoverable.  It is likely that the actual
      remaining quantities recovered will exceed the estimated proven
      reserves.
 (2)
              Probable
      reserves are those additional reserves that are less certain to be
      recovered than proven reserves. It is equally likely that the actual
      remaining quantities recovered will be greater or less than the sum of the
      estimated proven plus probable
reserves.
 (3)
              Possible
      reserves are those additional reserves that are less certain to be
      recovered than probable reserves. There is a 10 percent probability that
      the remaining quantities actually recovered will be greater than the sum
      of proven plus probable plus possible
reserves.
 
 Resources
 In
addition to estimating our reserves, McDaniel has estimated bitumen resources on
all of OPTI’s lands including the Long Lake, the Leismer and the Cottonwood
leases.  A summary of the additional resource estimates as at December
31, 2008, on a 50 percent working interest basis prior to taking into account
the 15 percent working interest sale is shown below:
 
 2008
(prior to the sale of the 15 percent working interest)
 All
      volumes are millions of barrels
                                
                                Raw Bitumen(1)Remainder
      of Long Lake leases (2)
                                
                                
                                363Leismer
      (2)
                                
                                
                                954Cottonwood
      (3)
                                
                                
                                717Total
                                
                                
                                2,033
  7
 The
following table shows OPTI’s 35 percent working interest in the additional
resource estimates after taking account of the sale of the 15 percent working
interest.
 
 2008
(subsequent to the sale of the 15 percent working interest)
 All
      volumes are millions of barrels
                              
                              Raw Bitumen(1)Remainder
      of Long Lake leases (2)
                              
                              
                              254Leismer
      (2)
                              
                              
                              668Cottonwood
      (3)
                              
                              
                              502Total
                              
                              
                              1,424
 
 
 Notes
to both resource tables:
 (1)
              These
      estimates represent the "best estimate" of our resources, are not
      classified or recognized as reserves, and are in addition to our disclosed
      reserve volumes. These resource estimates are categorized primarily as
      Contingent Resources, with some categorized as Prospective Resources. See
      Notes 2 and 3 below.
 Contingent
      Resources are those quantities of petroleum estimated, as of a given date,
      to be potentially recoverable from known accumulations using established
      technology or technology under development, but which are not currently
      considered to be commercially recoverable due to one or more
      contingencies. Contingencies may include factors such as economic, legal,
      environmental, political, and regulatory matters, or a lack of markets. It
      is also appropriate to classify as Contingent Resources the estimated
      discovered recoverable quantities associated with a project in the early
      evaluation stage. There is no certainty that it will be commercially
      viable to produce any portion of the Contingent
  Resources.
 Prospective
      Resources are those quantities of petroleum estimated, as of a given date,
      to be potentially recoverable from undiscovered accumulations by
      application of future development projects. Prospective Resources have
      both an associated chance of discovery and a chance of development. There
      is no certainty that any portion of the Prospective Resources will be
      discovered. If discovered, there is no certainty that it will be
      commercially viable to produce any portion of the
    resources.
 (2)
              The
      resource estimates for Leismer and Long Lake are categorized as Contingent
      Resources. These volumes are classified as resources rather than reserves
      primarily due to less delineation and the absence of regulatory approvals,
      detailed design estimates and near-term development
  plans.
 (3)
              The
      resource estimate for Cottonwood is categorized as both Contingent and
      Prospective Resources. The estimate of 717 million barrels prior to the
      sale of the 15 percent working interest would be comprised of 274 MMbbl of
      Contingent Resources and 443 MMbbl of Prospective Resources. After taking
      account for the sale of the 15 percent working interest, the estimate of
      502 million barrels is comprised of 192 MMbbl of Contingent Resources and
      310 MMbbl of Prospective Resources. These Contingent Resource volumes are
      classified as resources rather than reserves primarily due to less
      delineation; the absence of regulatory approvals, detailed design
      estimates and near-term development plans; and less certainty of the
      economic viability of their recovery. In addition to those factors that
      result in Contingent Resources being classified as such, Prospective
      Resources are classified as such due to the absence of proximate
      delineation drilling.
  NETBACKS
 We
provide a financial outlook of our estimated netback for Phase 1 of the Project
that was last updated in our third quarter MD&A dated October 28, 2008. The
netback calculation shown below is consistent with this most recent update and
includes our estimates of revenue, royalties, operating costs and General and
Administrative (G&A) expenses per barrel of product sold.
 
 This
financial outlook is intended to provide investors with a measure of the ability
of our Project to generate netbacks assuming full production capacity. We
believe that the ability of the Project to generate cash to fund interest
payments and future phases of development is a key advantage of our Project and
important to our investors. The netback measure is the most appropriate
financial gauge to demonstrate this ability as corporate costs, interest, and
other non-cash items are excluded from the calculation. The financial outlook
may not be suitable for other purposes. Netbacks generated by our Project are
expected to be lower than shown in this outlook in the years following start-up
due to the lower production volumes during ramp-up and an initially higher
steam-to-oil ratio (SOR). The netback calculation as presented is a non-GAAP
measure. The closest GAAP measure to the netback calculation is cash flow from
operations. However, cash flow from operations includes many other corporate
items that affect cash and are independent of the operations of the
Project.
 8
 The
actual netbacks achieved by the Project could differ materially from these
estimates. The material risk factors that we have identified toward achieving
these netbacks are as outlined in the Forward-Looking Information section of
this document and in our 2007 Annual Information Form (AIF).  In
particular; the SAGD and Long Lake Upgrader facilities may not operate as
planned; the operating costs of the Project may vary considerably during the
operating period; our results of operations will depend upon the prevailing
prices of oil and natural gas in the worldwide market and those prices can
fluctuate substantially; we will be subject to foreign currency exchange
fluctuation exposure; and our operating cash flows will be directly affected by
the applicable royaltyregime
relating to our business.  The key assumptions relating to the netback
estimate are set out in the notes beneath the table.
 
 Estimated
Future Project Netbacks(1)
  In
      CDN$/bbl
                        
                        Post-payout
                        
                        
                        Pre-payout$/bbl
                        
                        
                        $/bblRevenue(1,2)
                        
                        $
                        86.33
                        
                        
                        $
                        86.33Royalties
      and G&A(3)
                        
                        
                        (8.43
                        )
                        
                        
                        (3.84
                        )Operating
      costs(4)Natural
      gas(5)
                        
                        
                        (3.90
                        )
                        
                        
                        (3.90
                        )Other
      variable(6)
                        
                        
                        (2.76
                        )
                        
                        
                        (2.76
                        )Fixed
                        
                        
                        (12.82
                        )
                        
                        
                        (12.82
                        )Property taxes
      and insurance(7)
                        
                        
                        (3.55
                        )
                        
                        
                        (3.55
                        )Netback
                        
                        $
                        54.87
                        
                        
                        $
                        59.46
  Notes:
 (1)
              The
      per barrel amounts are based on the expected yield for the Project of
      57,700 bbl/d of PSCTM and 800 bbl/d of butane, and assume that the Upgrader
      will have an on-stream factor of 96 percent. These numbers are cash costs
      only and do not reflect non-cash charges.  See “Forward-Looking
      Statements.”
 (2)
              For
      purposes of this projection, we assume a WTI price of US$75/bbl, foreign
      exchange rates of CDN$1.00 to US$0.85 and an electricity sales price of
      $106 per megawatt hour. Revenue includes sale of PSCtm,
      bitumen, butane and electricity.
 (3)
              Royaltiesare calculated
      based on a light/heavy differential of 30 percent of WTI. We anticipate
      payout for royalty purposes to occur in approximately 2022 based on the
      assumptions noted.
 (4)
              Costs
      are in 2009 dollars.
 (5)
              Natural
      gas costs are based on our long-term estimate for a SOR of
      3.0.
 (6)
              Includes
      approximately $1.00/bbl for greenhouse gas mitigation costs based on an
      approximate average 20 percent reduction of CO2
      emissions at a cost of $20 per tonne of CO2.
 (7)
              Property
      taxes are based on expected mill rates for
2009.
 
 Sustaining
capital costs required to maintain production at design rates of capacity are
estimated to be approximately $8 to $9 per barrel of PSCTM, assuming full design
rate production adjusted for long-term on-stream expectations.  The
netbacks as shown are prior to abandonment and reclamation costs.  We
do not include these costs due to the long-term nature of our
assets.
 9
 CAPITAL
EXPENDITURES
 Our
financial condition to date has been affected primarily by capital expenditures
in connection with the construction, commissioning and start-up of the Project,
related financings and the capital expenditures associated with the development
of future phases.
 
 The
Project is essentially complete as of December 31, 2008.  The
remaining capital costs relate to the completion of the steam expansion project,
expected in 2009, and the ash processing unit in the following
year.  The cost to complete these two projects is approximately $45
million net to OPTI.
  The
table below identifies historical expenditures incurred by us in relation to the
Project, other oil sands activities and other capital expenditures.
  In
      millions
                      
                      Year
      ended
                        2008
                      
                      
                      Year
      ended
                        2007
                      
                      
                      Year
      ended
                        2006Long
      Lake Project - Phase 1Upgrader
                      
                      $
                      282
                      
                      
                      $
                      529
                      
                      
                      $
                      476SAGD
                      
                      
                      195
                      
                      
                      
                      282
                      
                      
                      
                      440Sustaining
      capital and capitalized operations
                      
                      
                      164
                      
                      
                      
                      54
                      
                      
                      
                      -Total
      Long Lake Project
                      
                      
                      641
                      
                      
                      
                      865
                      
                      
                      
                      916Other
      oil sands activities
                      
                      
                      134
                      
                      
                      
                      96
                      
                      
                      
                      140Total
      oil sands expenditures
                      
                      
                      775
                      
                      
                      
                      961
                      
                      
                      
                      1,056Capitalized
      interest
                      
                      
                      177
                      
                      
                      
                      130
                      
                      
                      
                      47Other
      capital expenditures
                      
                      
                      35
                      
                      
                      
                      17
                      
                      
                      
                      6Realized
      gain on foreign currency hedging instruments
                      
                      
                      (114
                      )
                      
                      
                      -
                      
                      
                      
                      -Total
      cash expenditures
                      
                      
                      875
                      
                      
                      
                      1,108
                      
                      
                      
                      1,109Non-cash
      capital charges
                      
                      
                      309
                      
                      
                      
                      (212
                      )
                      
                      
                      66Total
      capital expenditures
                      
                      $
                      1,184
                      
                      
                      $
                      896
                      
                      
                      $
                      1,175
  For the
year ended December 31, 2008, we incurred capital expenditures of $1,184
million. Phase 1 expenditures related to Upgrader and SAGD were primarily
related to the completion of construction, commissioning and start-up of the
Upgrader, and ongoing construction of the steam expansion project. Sustaining
capital in 2008 related primarily to the installation of electric submersible
pumps on some of our wells and engineering and resource delineation for future
Phase 1 well pads.
 
 
 10
 For the
year, our share of the net SAGD operations was a net cost of $101
million.  The SAGD operating results during the year were comprised of
Premium Synthetic Heavy (PSH) sales of $268 million, power sales of $19 million,
operating costs of $141 million, diluent and feedstock volumes consumed costs of
$236 million and transportation costs of $11 million. These operating results
reflect early stage SAGD operations and relatively low production volumes during
the second half of 2008. During the three months ended September 30, 2008, our
net SAGD operating results resulted in a cost of $5 million. During the three
months ended December 31, 2008, our net SAGD operating results resulted in a
cost of $96 million. The fourth quarter net operations costs were due in part to
natural gas purchases of $22 million and diluent purchases of $70 million; with
the start-up of the Upgrader in January 2009, these costs will largely be
avoided. Continuing challenges with SAGD surface equipment also kept volumes
relatively low in the quarter. As a result of the timing of certain of our
purchases and light heavy spreads during the fourth quarter, our diluent costs
approximated our revenue from PSH.  We will not have exposure to
bitumen blend revenue or diluent costs in periods when the Upgrader is in normal
operation.
 
 The
expenditures of $134 million for other oil sands activities during the year
related to engineering costs and resource delineation for future phases. This
was comprised primarily of $56 million related to engineering and regulatory
work, $55 million related to core hole delineation and seismic costs associated
with future phases of development and $7 million in contract cancellation costs
related to a reduction in the scope of our 2008/2009 winter drilling
program.
 
 Capitalized
interest includes interest of $160 million on our senior secured notes (Notes)
and $17 million with respect to our revolving credit facilities. The other
capital expenditures of $36 million in the period related primarily to $21
million on corporate assets and $15 million for costs associated with the
working interest sale to Nexen.  Partially offsetting these costs is a
realized gain of $114 million related to our foreign currency
contracts.
 
 The
$309 million of non-cash capital charges related primarily to a $373 million
capitalized translation loss with respect to the re-measurement of our
U.S.-dollar-denominated long-term debt, cash and interest reserve account, and a
charge of $25 million for capitalized future taxes. The $373 million translation
loss was primarily the result of the translation to Canadian dollars of our
$1,750 million U.S.-dollar-denominated debt, due to a change in the exchange
rate from CDN$0.99 to US$1.00 at the end of 2007 to CDN$1.22 to US$1.00 at the
end of 2008. The translation loss was partially offset by realized gains of $114
million and unrealized gains of $91 million on forward exchange hedging
instruments.
 RESULTS
OF OPERATIONS
 Year Ended December 31,
2008
 
 In
      millions
                        
                        2008
                        
                        
                        2007
                        
                        
                        2006Interest
      income
                        
                        $
                        6
                        
                        
                        $
                        13
                        
                        
                        $
                        10Impairment
      related to asset sale
                        
                        
                        392
                        
                        
                        
                        -
                        
                        
                        
                        -General
      and administrative
                        
                        
                        18
                        
                        
                        
                        14
                        
                        
                        
                        10Amortization
      and accretion
                        
                        
                        6
                        
                        
                        
                        2
                        
                        
                        
                        22Financing
      charges
                        
                        
                        1
                        
                        
                        
                        12
                        
                        
                        
                        -Realized
      loss (gain) on commodity contracts
                        
                        
                        (2
                        )
                        
                        
                        -
                        
                        
                        
                        -Unrealized
      loss (gain) on commodity contracts
                        
                        
                        (67
                        )
                        
                        
                        4
                        
                        
                        
                        -Future
      tax expense (recovery)
                        
                        
                        (85
                        )
                        
                        
                        (9
                        )
                        
                        
                        (12
                        )
 
 *
Interest Income
 For the
year ended December 31, 2008 interest income decreased to $6 million from $13
million in 2007. The decrease was due to a decline in average cash and cash
equivalent balances as well as lower interest rates on investments.
   11
 
  Expenses, gains and
losses
 *
Impairment Related to Asset Sale
 To
consider impairment as of December 31, 2008, assets were grouped into categories
of depreciable assets, resource assets and unproved properties based on the
nature of the asset and an assessment of its depreciation basis. Each asset type
was assessed individually for impairment.
 
 We
allocated the sales proceeds to each asset type based on an estimate of fair
value. The sales proceeds allocated to depreciable assets were lower than the
book value of the asset; as a result, an impairment before taxes of $392 million
was recorded in 2008. The sales proceeds allocated to resource assets did not
alter the depletion rate by greater than 20 percent and, as a result, no gain or
loss was recorded. The sales proceeds for resource assets will be recorded as a
reduction to book value as of completion of the sale in 2009. The sales proceeds
for unproved properties will be recorded as a reduction to book value as of
completion of the sale in 2009. All of the Company’s remaining assets were
subject to a ceiling test and cost recovery test which concluded no further
impairment existed.   The ceiling test is described in Note 2 of
the financial statements.
 
 With
respect to the assets sold and the related impairment, there were a number of
business conditions which led to the sale and the impairment. These factors
include: restricted access to capital for OPTI as well as potential purchasers
of our assets; relatively low and declining commodity prices during the second
half of 2008; relatively low SAGD production volumes and delayed start-up of the
Upgrader. We expect that as these conditions improve, the fair value of our
assets will also increase.
 *
General and Administrative
 For the
year ended December 31, 2008, G&A expenses increased to $18 million
from $14 million in 2007. The increase for 2008 is due to higher levels of
corporate staffing.
 
 *
Amortization and Accretion
 For the
year ended December 31, 2008, amortization and accretion expenses were $6
million compared to $2 million in 2007. For 2008, the expense was primarily
related to an increase in the amortization of corporate assets.
 
 *
Financing Charges
 For the
year ended December 31, 2008 financing charges were $1 million compared to $12
million in 2007. Financing charges relate to the new $150 million revolving debt
facility established in June 2008 and to the issuance of US$750 million in
senior secured notes in 2007.  Our policy is to expense financing
costs as incurred.
 12
 *
Realized Gain on Commodity Contracts
 For the
year ended December 31, 2008, we had a realized gain of $2 million related to
our US$50/bbl commodity puts.
  *
Unrealized Loss (Gain) on Commodity Contracts
 For the
year ended December 31, 2008, we had a gain of $67 million compared to a loss of
$4 million in 2007. The gain in 2008 was due to an increase in the fair value of
our commodity contracts put in place for 2009 production. During 2008, spot
prices for WTI decreased from approximately US$92/bbl at the beginning of the
year to approximately US$41/bbl at year-end.
 
 *
Future Tax Expense (Recovery)
 Future
tax expense for the year ended December 31, 2008 is a recovery of $85 million
compared with $9 million in the corresponding period of 2007. The recovery of
future taxes in 2008 was primarily due to a reduction in book value associated
with the impairment of assets and the realized cross currency swap gains, offset
by future tax implications of foreign exchange movements and flow-through share
renunciations.
 
 *
Foreign Exchange Hedging
Instruments
 OPTI is
exposed to foreign exchange rate risk on our U.S.-dollar-denominated debt. To
partially mitigate this exposure, we have entered into US$875 million of foreign
exchange forwards to manage our exposure to repayment risk on our
U.S.-dollar-denominated long-term debt. The forward contracts provide for the
purchase of U.S. dollars and the sale of Canadian dollars at a rate of
approximately CDN$1.17 to US$1.00 with an expiry in April 2010.  With
respect to our U.S.-dollar-denominated debt, we believe that these forward
contracts provide protection against a decline in the value of the Canadian
dollar below CDN$1.17 to US$1.00 on a portion of our debt. The period-end value
of the forwards is an asset of $32 million. As noted under “Liquidity”, the
value of these derivatives affects our debt covenants as the value of these
contracts is included in the measurement of our debt for covenant
purposes.
 
 During
2008, the fair value adjustment for each of these contracts at the end of each
contract period is capitalized to property plant and equipment as the underlying
debt instrument was used to fund development of our Project. The value of the
currency derivatives increased from the inception of the contractsdue to a weakening
Canadian dollar as compared to the U.S. dollar. During the year ended December
31, 2008, we had a realized gain of $114 million
 13
 SELECTED
ANNUAL INFORMATION
 
 In
      millions
                    (except
      per share amounts)
                  
                  2008
                  
                  
                  2007
                  
                  
                  2006Interest
      income
                  
                  $
                  6
                  
                  
                  $
                  13
                  
                  
                  $
                  10Net
      loss
                  
                  
                  (257
                  )
                  
                  
                  (9
                  )
                  
                  
                  (10
                  )Net
      loss per share, basic and diluted
                  
                  
                  (1.31
                  )
                  
                  
                  (0.05
                  )
                  
                  
                  (0.06
                  )Total
      assets
                  
                  
                  4,558
                  
                  
                  
                  3,837
                  
                  
                  
                  3,374Total
      long-term liabilities
                  
                  
                  2,656
                  
                  
                  
                  1,831
                  
                  
                  
                  1,773
 
 The
amount of interest income in each year is primarily the result of cash and cash
equivalents available for investment. The amount of cash in each year is
influenced by the size and timing of financing activities, as well as capital
expenditures related to project development. The net loss has been influenced by
increasing general and administrative expenses as well as fluctuations in future
tax recoveries. Amortization expense increased significantly in 2007 as a result
of the expensing of pre-financing costs associated with the cancellation of
various credit facilities, thereby increasing the net loss for the year. During
2008, we recorded a before tax impairment of assets as a result of our working
interest sale of $392 million and a total future tax recovery of $85 million.
Our total assets have been increasing continuously as a result of expenditures
on the Project and future phase development, offset by the asset impairment at
December 31, 2008.  Increases in long-term financial liabilities are a
result of a weaker Canadian dollar increasing the measurement amount of our
U.S.-dollar-denominated debt and borrowings under our revolving credit
facilities.
 SUMMARY
FINANCIAL INFORMATION
 
 2008
                                              
                                              
                                              2007In
      millions
                                                (except
      per share amounts)
                                              
                                              
                                              Q4
                                              
                                              
                                              
                                              Q3
                                              
                                              
                                              
                                              Q2
                                              
                                              
                                              
                                              Q1
                                              
                                              
                                              
                                              Q4
                                              
                                              
                                              
                                              Q3
                                              
                                              
                                              
                                              Q2
                                              
                                              
                                              
                                              Q1Interest
      income
                                              
                                              $
                                              2
                                              
                                              
                                              $
                                              1
                                              
                                              
                                              $
                                              1
                                              
                                              
                                              $
                                              2
                                              
                                              
                                              $
                                              3
                                              
                                              
                                              $
                                              3
                                              
                                              
                                              $
                                              2
                                              
                                              
                                              $
                                              5Net
      earnings (loss)
                                              
                                              
                                              (250
                                              )
                                              
                                              
                                              3
                                              
                                              
                                              
                                              (8
                                              )
                                              
                                              
                                              (2
                                              )
                                              
                                              
                                              6
                                              
                                              
                                              
                                              (13
                                              )
                                              
                                              
                                              (2
                                              )
                                              
                                              
                                              -Earnings
      (loss) per share, basic and diluted
                                              
                                              
                                              (1.27
                                              )
                                              
                                              
                                              0.02
                                              
                                              
                                              
                                              (0.04
                                              )
                                              
                                              
                                              (0.01
                                              )
                                              
                                              
                                              0.03
                                              
                                              
                                              
                                              (0.07
                                              )
                                              
                                              
                                              (0.01
                                              )
                                              
                                              
                                              -
 
 Quarterly
variations in interest income are primarily the result of the amount of cash and
cash equivalents available for investment during the applicable period. The
amount of cash and cash equivalents is influenced by the size and nature of
financing activities and the level of investing activities during the period.
Earnings have been influenced by fluctuating interest income, increasing levels
of G&A expenses and fluctuating future tax expense.  In the third
quarter of 2007, we expensed financing charges of $11 million, which increased
our loss during the period. During the fourth quarter of 2007, we had a $9
million recovery of future taxes primarily as a result of a reduction in the
applicable federal tax rate that increased our earnings.  During the
second quarter of 2008, we had a $6 million loss on commodity contracts that
increased our loss during the period.  During the fourth quarter of
2008, we had a pre-tax asset impairment for accounting purposes related to our
working interest sale of $392 million and a future tax expense recovery,
primarily related to this impairment, of $85 million.
 
 14
 SHARE
CAPITAL
 At
January 31, 2009, OPTI had 195,929,526 common shares and 7,150,116 common share
options outstanding. The common share options have a weighted average exercise
price of $13.14 per share.  At January 31, 2009, OPTI’s fully diluted
shares outstanding were 203,079,642.
 
 Effective
November 2008, 5,991,000 common share warrants with an exercise price of $14.75
per share expired without being exercised. Effective June 2008, $202 million of
call obligations with an exercise price of $2.20 per share expired without being
exercised.
 
 LIQUIDITY
AND CAPITAL RESOURCES
 Liquidity
 For the
year ended December 31, 2008, cash used by operating activities was $7 million,
cash provided by financing activities was $651 million and cash used in
investing activities was $747 million. These changes, combined with a gain on
our U.S.-dollar-denominated cash of $9 million, resulted in a decrease in cash
and cash equivalents during the year of $93 million.
 
 During
2008 we funded our capital expenditures and ongoing start-up activities from
existing working capital and borrowings under our credit facilities. In 2009,
sales proceeds from the working interest sale to Nexen, operating cash flow and
availability under our revolving credit facilities are expected to fund our
capital expenditures.
 
 After
completion of the working interest sale to Nexen, the Company will have cash and
unused credit facilities of approximately $450 million. In order to continue to
access the revolving credit facility, we are required to meet a first lien to
EBITDA covenant commencing in the third quarter of 2009.  The most
significant risk to us not achieving this covenant is lower than expected
bitumen production and associated PSCTM sales. Commodity pricing is a less
significant risk in 2009 as a substantial portion of our production is
hedged.  We have hedged 6,000 bbl/d at a net price of approximately
US$76/bbl, which is a substantial portion of our expected 2009 PSCTM sales
volume.  An additional 500 bbl/d of 2009 production is hedged with a
US$77/bbl swap (risks associated with our hedging instruments are discussed in
more detail under “Financial Instruments”, below). If we have lower than
expected SAGD production or lower PSCTM sales, we may have to repay amounts
outstanding under the revolving credit facility or may be prevented from further
borrowings. The majority of our operating costs and interest costs are fixed.
Aside from changes in the price of natural gas, our costs will neither decrease
nor increase significantly as a result of fluctuations in WTI prices other than
with respect to royalties, which increase at WTI prices higher than
$55/bbl.
 
 We have
semi-annual interest payments of US$71 million in June and December of each year
until maturity of the Notes in 2014. Also, we estimate our share of capital
expenditures required to sustain production of Phase 1 at or near planned
capacity for the Project will be approximately $60 million per year for the next
five years. We expect to fund these payments from operating cash flow and from
existing financial resources.
 
 15
 A
significant portion of our capital budget for 2009 has been
pre-funded.  As part of the working interest sale to Nexen, we
provided $85 million to Nexen in January to be applied against our working
interest share of the 2009 joint venture capital budget of $114 million net to
OPTI.  On a gross basis, the budget is $325 million of which
approximately $200 million relates to sustaining capital including the
completion of an additional well pad, $100 million relates to Phase 2
engineering and $25 million relates to future phases and resource
development.
 
 Recent
developments in capital markets have restricted our access to new debt and
equity. Although our current financial resources are considered sufficient for
the next 12 to 24 months, further deterioration of commodity prices, delays in
ramp-up of SAGD production, or operating issues with the SAGD or Upgrader
operations could result in additional funding requirements earlier than we have
estimated.  Should the Company require such funding, it may be
difficult to obtain such financing on reasonable
 terms.
 
 If
Phase 2 is sanctioned, which is not currently scheduled for consideration prior
to mid-2010, we expect possible future capital requirements in excess of
operating cash flows.  Unless we have stable operations at or near
capacity for the Project and high commodity prices, such external financing
requirements would be significant.  We expect that these financing
requirements will come at a higher cost and contain more restrictions than the
financings completed to date by OPTI.  Current market conditions would
not support such a financing requirement so some improvement will be required in
order to support such development.  In addition, our joint venture
partner may evaluate the economics of future phases differently than we do and
will likely have a different evaluation of the ability to fund this
development.  As a result, Nexen may decide to proceed with
development of future phases, which may result in OPTI having to reduce our
working interest in such future phases.
 
 Our
debt facilities contain a number of provisions that serve to limit the amount of
debt we may incur. With respect to our revolving credit facility, the key
maintenance covenants are with respect to debt to capitalization and the ratio
of debt outstanding under the revolving credit facility to EBITDA. Maintenance
covenants are important as they are ongoing conditions that must be satisfied to
provide continued access to the revolving credit facility.
 
 The
first lien to EBITDA covenant, as amended in January 2009, is measured quarterly
and requires that this ratio is lower than 2.5:1 commencing for the quarter
ended September 30, 2009. The first three measurements of EBITDA for this
covenant will annualize EBITDA as measured from July 1, 2009, to the end of the
applicable covenant period. Thereafter, EBITDA will be based on a trailing four
quarters. Realized cash gains on commodity contracts, such as our existing puts
and forwards, are included in EBITDA for the purposes of the covenant. If we are
unable to generate sufficient EBITDA, we may be required to repay all or a
portion of amounts outstanding under that facility or be unable to make
additional borrowings under the revolving credit facility prior to the end of a
covenant quarter or will be required to request and obtain approval for a waiver
from our lenders under the facility.
 
 The
covenant as amended in January 2009 for debt to capitalization requires that we
do not exceed a ratio of 70 percent as calculated on a quarterly
basis.  The covenant is calculated based on the book value of debt and
equity. The book value of debt is adjusted for the effect of any foreign
exchange derivatives issued in connection with the debt that may be outstanding.
At December 31, 2008, this means that our debt would be reduced by the value of
our foreign exchange forward in the amount of $32 million. With respect to
U.S.-dollar-denominated debt, for purposes of the debt to capitalization ratio,
the debt is translated to Canadian dollars based on the average exchange rate
for the quarter. The debt to capitalization is therefore influenced by the
variability in the measurement of the foreign exchange forward, which is subject
to mark to market variability and average foreign exchange rate changes during
the quarter.
 
 16
 In
respect of new borrowings under the $350 million revolving credit facility prior
to reaching completion of the Project, we are required to have sufficient funds
(including cash and undrawn revolver) to fund our share of remaining Project
 costs.
 
 With
respect to our senior secured notes, the covenants are in place primarily to
limit the total amount of debt that OPTI may incur at any time. This limit is
most affected by the present value of our total proven reserves using forecast
prices discounted at 10 percent.  Based on our 2008 reserve report, as
adjusted for our new working interest in the joint venture, we have sufficient
capacity under this test to incur additional debt beyond our existing $350
million revolving credit facility and existing senior secured notes. Other
leverage factors, such as debt to capitalization and total debt to EBITDA, are
expected to be more constraining than this limitation.
 
 Capital
Resources
 Our
long-term debt currently consists of US$1,750 million of senior secured notes
and a $350 million revolving credit facility.  At February 17, 2009,
we have approximately $280 million of cash on hand and have drawn $87 million on
our $350 million revolving credit facility.
 
 At
December 31, 2008, our cash resources included cash of $217 million. Our cash
and cash equivalents are invested exclusively in money market instruments issued
by major Canadian banks. At December 31, 2008, $486 million had been drawn on
the $500 million revolving credit facility and $146 million had been drawn on
the $150 million revolving credit facility. As of February 17, 2009, after using
proceeds from the working interest sale to Nexen to fund a partial pay-down, $87
million remained outstanding on the $350 million revolving credit facility and
our $150 million revolving credit facility had been repaid and
cancelled.  We eliminated the working capital deficiency that existed
at December 31, 2008 as a result of the completion of the working interest sale
to Nexen on January 27, 2009.
 
 CREDIT
RATINGS
 OPTI,
OPTI's revolving credit facility and OPTI’s Notes are currently rated by Moody’s
Investor Service (Moody’s) and Standard and Poors (S&P).  Please
refer to the table below for the respective ratings.
 
 Type of Security
                Moody's
                S&POPTI
      Corporate Rating
                B1
                B+Revolving
      Credit Facility
                Ba3
                BB8.25%
      Notes
                B2
                BB7.875%
      Notes
                B2
                BB
  
 17
 The
Moody’s ratings have been under review for potential downgrade by Moody’s since
November 2008.  The S&P ratings have been on credit watch with
negative implications since November 2008.
 
 A
security rating is not a recommendation to buy, sell or hold securities and may
be subject to revision or withdrawal at any time by the rating
organization.
 
 CONTRACTUAL
OBLIGATIONS AND COMMITMENTS
 Commitments
for contracts and purchase orders at December 31, 2008, related to project
development are $22 million based on a working interest of 50
percent.
 
 During the12months ended December 31,
2008,our long-term debt
increased by $486million
due to borrowings under our $500 million revolving credit facility and the
short-term portion
increased by $146million
due to borrowings on our $150 million revolving credit
facility.
 
 The
following table shows our contractual obligations and commitments related to
financial liabilities at December 31, 2008. This table is prior to the
January 2009 working interest sale to Nexen, which would reduce payments under
our capital leases, operating leases and contracts and purchase orders by 30
percent.
 
 In
      millions
                Total
                < 181 days
                181- 365days
                2010-2011
                2012-2013
                2014 or laterAccounts
      payable and accrued liabilities
                $       200
                $   195
                $        5
                $         -
                $          -
                $           -Short-term
      debt(1)
                146
                146
                -
                -
                -
                -Long-term
      debt (Notes)(2)
                3,166
                86
                86
                345
                345
                2,304Long-term
      debt (Revolving)(3)
                486
                136
                -
                350
                -
                -Capital
      leases(4)
                106
                2
                3
                9
                8
                84Operating
      leases and other commitments(5)
                115
                6
                7
                28
                29
                45Contracts
      and purchase orders(6)
                22
                22
                -
                -
                -
                -Total
      commitments
                $  4,241
                $  593
                $   101
                $     732
                $  382
                $  2,433
 
 Notes:
 (1)
              Consists of
      CDN$146 million of borrowings on our short-term revolving debt facility.
      This facility was repaid and cancelled in January
  2009.
 (2)
              Consists of
      US$1,000 million and US$750 million under our
      Notes.  Amounts represent scheduled principal and interest
      payments.
 (3)
              Consists of
      $486 million drawn on the revolving credit facility. The repayment
      represents only the required reduction to reduce the facility to $350
      million in January 2009 and the final repayment of the facility at its
      scheduled maturity in 2011. In addition, we are contractually obligated
      for interest payments on borrowings and standby charges in respect to
      undrawn amounts under the revolving credit facility, which are not
      reflected in the above table as amounts cannot be estimated due to the
      revolving nature of the facility and variable interest rates. See
      “Liquidity” section for repayments completed as part of working interest
      sale.
 (4)
              Consists of
      our share of future payments under our product transportation agreements
      with respect to future tolls during the initial contract term at a working
      interest of 50 percent.
 (5)
              Consists of
      our share of payments under our product transportation agreements with
      respect to future tolls during the initial contract term at a working
      interest of 50 percent. This amount also includes our share of future
      commitments with respect to rail traffic transportation assuming a 50
      percent working interest.
 (6)
              Consists of
      our share of commitments associated with contracts and purchase orders in
      connection with the Project and our other oil sands
      activities.
  
 18
 OFF-BALANCE-SHEET
ARRANGEMENTS
 We have
no off-balance-sheet arrangements.
 
 CONTROLS
AND PROCEDURES
 Disclosure
Controls and Procedures
 The
Chief Executive Officer and the Chief Financial Officer are responsible for
establishing and maintaining disclosure controls and procedures (DC&P), as
such term is defined in National Instrument 52-109 Certification of Disclosure in
Issuers' Annual and Interim Filings,for OPTI. They have, as at the
financial year ended December 31, 2008, designed such DC&P, or caused them
to be designed under their supervision, to provide reasonable assurance that
information required to be disclosed by OPTI in its annual filings, interim
filings or other reports filed or submitted by OPTI under applicable securities
legislation is recorded, processed, summarized and reported within the time
periods specified in applicable securities legislation and that all material
information relating to OPTI is made known to them by others, particularly
during the periods in which OPTI's annual and interim filings are being
prepared.
 
 Under
the supervision of the Chief Executive Officer and the Chief Financial Officer,
OPTI conducted an evaluation of the effectiveness of our DC&P as at December
31, 2008. Based on this evaluation, the officers concluded that as of December
31, 2008, OPTI's disclosure controls and procedures provide reasonable assurance
that information required to be disclosed by OPTI in its annual filings, interim
filings or other reports that we file or submit under applicable securities
legislation is recorded, processed, summarized and reported within the time
periods specified in such legislation and that these controls and procedures
also provide reasonable assurance that material information relating to OPTI is
made known to our Chief Executive Officer and Chief Financial Officer by
others.
  It
should be noted that while our officers believe that OPTI’s disclosure controls
and procedures provide a reasonable level of assurance with regard to their
effectiveness, they do not expect that the disclosure controls and procedures or
internal controls over financial reporting will prevent all errors and fraud. A
control system, no matter how well conceived or operated, can provide only
reasonable, but not absolute, assurance that the objectives of the control
system are met.
 
 Internal
Controls over Financial Reporting
 The
Chief Executive Officer and the Chief Financial Officer are responsible for
establishing and maintaining internal control over financial reporting (ICFR),
as such term is defined in National Instrument 52-109 Certification of Disclosure in
Issuers' Annual and Interim Filings,for OPTI. They have, as at the
financial year ended December 31, 2008, designed ICFR, or caused it to be
designed under their supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with Canadian GAAP.  The control
framework our officers used to design OPTI's ICFR is the Internal Control -- Integrated
Framework (COSO Framework) published by The Committee of Sponsoring
Organizations of the Treadway Commission (COSO).
 
 19
 Under
the supervision of the Chief Executive Officer and the Chief Financial Officer,
OPTI conducted an evaluation of the effectiveness of our ICFR as at December 31,
2008 based on the COSO Framework. Based on this evaluation, the officers
concluded that as of December 31, 2008, OPTI's ICFR provides reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with Canadian
GAAP.
 
 There
were no changes in our internal control over financial reporting during the year
ended December 31, 2008 that materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
 
 CRITICAL
ACCOUNTING ESTIMATES
 Capital
Assets
 We
capitalize costs in connection with the development of oil sands projects. The
measurement of these costs at each financial statement date requires estimates
to be made with respect to construction progress, materials procurement and
drilling progress. An increase in the measurement amount of these items would
increase our property, plant and equipment and accrued liabilities
accordingly.
 
 Capital
assets are reviewed for impairment whenever events or conditions indicate that
the net carrying amount may not be recoverable from estimated future cash
flows.  We have evaluated the book value of our assets in connection
with the working interest sale to Nexen.  We have determined that the
related assets sold were impaired as of December 31, 2008 and as a result
recorded a loss of $392 million.  We have also evaluated the remaining
assets and determined that these costs are recoverable based on our ceiling test
as described in our accounting policies.
 
 The
quantity of reserves is subject to a number of estimates and projections,
including assessment of engineering data, projected future rates of production,
characteristics of bitumen reservoirs, commodity prices, foreign exchange rates,
operating costs and sustaining capital expenditures. These estimates and
projections are uncertain as we do not have any commercial production history to
assist in the development of these forward-looking estimates. However, all
reserve and associated financial information is evaluated and reported on by a
firm of qualified independent reserve evaluators in accordance with the
standards prescribed by applicable securities regulators.
 
 The
calculation of future cash flows based on these reserves is dependent on a
number of estimates, production volumes, facility performance, commodity prices,
royalties, operating costs, sustaining capital and foreign exchange rates. The
price used in our assessment of future cash flows is based on our independent
evaluators’ estimate of future prices and evaluated for reasonability by OPTI
against other available information.  Although the future prices used
are significantly higher than current prices, we believe these prices are
reasonable estimates for a long-term outlook.  In addition, lower
prices could be used without resulting in any additional
impairment.  Different or significantly lower price assumptions could
result in a ceiling test impairment.  Impairment and a corresponding
loss would be recognized in earnings in the period in which capitalized costs
exceeded estimated future cash flows.
 
 20
 Asset Retirement
Obligations
 We
measure asset retirement obligations at each financial statement date. The
estimate is based on our share of costs to reclaim the resource assets and
certain facilities related to the Project as well as other resource assets
associated with future phases. The liability is primarily related to reclamation
of the SAGD facility and drilling assets. To determine the future value of the
liability, we estimate the amount, timing and inflation of the associated
abandonment costs.  We then calculate the present value of the cost to
record the current asset retirement obligation using a credit-adjusted risk-free
rate. In some cases, due to the long-lived nature of the asset, the timing of
future abandonment cannot be made and no asset retirement obligation is
recorded. Due to the long-term nature of current and future project
developments, abandonment costs will be incurred over many years in the future.
As a result of these factors, different estimates could be used for such
abandonment costs and the associated timing. Assumptions of higher future
abandonment costs, higher inflation, higher credit-adjusted risk-free rates or
an assumption of earlier or specified timing of abandonment would cause the
asset retirement obligation and corresponding asset to increase. These changes
would also cause future accretion expenses to increase and future earnings to
decrease.
 
 Future
Taxes
 We
measure our future tax asset or liability based on estimates of temporary
differences between our book and tax assets. In addition, an estimate is
required for both the timing and tax rate of this reversal. Should these
estimates change, it could impact the measurement amount of our asset or
liability as well as future tax recovery or expense and earnings. These
estimates would not impact cash flow from operations.  At December 31,
2008, we have recorded a future tax asset.  The recognition of a
future tax asset requires further estimates that these taxes will be recoverable
in the future.  We have estimated future cash flow based on reports
from our independent engineers and concluded that, more likely than not, we will
be able to earn taxable earnings in excess of the future tax asset that we have
recorded.
 
 ACCOUNTING
POLICIES
 On
January 1, 2008, we adopted the following Canadian Institute of Chartered
Accountants (CICA) standards: Section 1535 “Capital Disclosures,” Section 3862
“Financial Instruments – Disclosures,” and Section 3863 “Financial Instruments –
Presentation.”
 
 Section
1535 requires the disclosure of OPTI’s objectives, policies and processes for
managing capital. This includes qualitative information regarding OPTI’s
objectives, policies and processes for managing capital and quantitative data
about what OPTI manages as capital. These disclosures are based on information
that is used internally by our management.
 
 21
 Sections
3862 and 3863 replace Section 3861 “Financial Instruments – Disclosure and
Presentation,” which revises financial instruments disclosure requirements and
leaves unchanged the presentation requirements. These new sections place
increased emphasis on disclosures about the nature and extent of risks arising
from financial instruments and how OPTI manages those risks.
 
 There
is no impact on our financial position or results of operations as a result of
the adoption of these sections.
 
 NEW
ACCOUNTING PRONOUNCEMENTS
 The
CICA issued a new accounting standard Section 3064 “Goodwill and Intangible
Assets” which OPTI will adopt for the reporting period beginning January 1,
2009. This standard replaces Section 3062 “Goodwill and Other Intangible Assets”
and Section 3450 “Research and Development Costs.” The new section establishes standards for the recognition, measurement,
presentation and disclosure of goodwill and intangible assets. The provisions
relating to the definition and initial recognition of intangible assets are
equivalent to the corresponding provisions of International Financial Reporting
Standard (IFRS) IAS 38, “Intangible Assets.” Emerging Issues Committee (EIC) 27
“Revenues and Expenditures During the Pre-Operating Period” is no longer
applicable for OPTI as we have adopted CICA 3064. Accounting Guidelines (AcG) 11
“Enterprises in the Development Stage” is amended to delete references to
deferred costs and to provide guidance on development costs as intangible assets
under Section 3064.
 
 As a
result of these changes and the adoption of these new standards, OPTI will
expense certain previously capitalized costs with retroactive effect on January
1, 2009 with a corresponding increase to opening deficit. The opening deficit
will be increased by approximately $75 million.  This increase will be
comprised of deferred costs related to SAGD start-up activities, translation of
OPTI’s U.S.-dollar debt, offset by gains related to financial derivatives
associated with OPTI’s debt and by a recovery of future tax
expense.
 
 IFRS
 The
Canadian Accounting Standards Board has announced that Canadian Generally
Accepted Accounting Principles (GAAP) no longer apply for all publically
accountable enterprises as of January 1, 2011. From that date forward, OPTI will
be required to report under International Financial Reporting Standards (IFRS)
as set out by the International Accounting Standards Board (IASB). Any
adjustments resulting from a change in policy are applied retroactively with
corresponding adjustment to opening retained earnings.
 
 OPTI is
currently in the initial stages of planning for the IFRS transition. A formal
changeover plan has not been approved by management. We are currently evaluating
potential areas impacted by the new standards including adoption criteria as
prescribed under IFRS1 – First-Time Adoption of International Financial
Reporting Standards.
 
 Business
Impact of IFRS
 OPTI
has recorded a pre-tax asset impairment for accounting purposes of $392 million
with respect to the working interest sale to Nexen.  Under IFRS this
loss would have been significantly higher as all of OPTI’s assets would have
been considered impaired based on the implied valuation. IFRS permits subsequent
recovery of such write downs in future periods to the extent that fair value
increases. Therefore, the cumulative effect of the Nexen working interest sale
at the date of adoption on January 1, 2011 will depend on a fair value
assessment of the assets as of December 31, 2010.
 
 22
 FINANCIAL
INSTRUMENTS
 The
Company considers its risks in relation to financial instruments in the
following categories:
 
 Credit
Risk
 Credit
risk is the risk that counterparty to a financial instrument will not discharge
its obligations, resulting in a financial loss to the Company. The Company has
policies and procedures in place that govern the credit risk it will assume. We
evaluate credit risk on an ongoing basis including an evaluation of counterparty
credit rating and counterparty concentrations measured by amount and percentage.
Our objective is to have no credit losses.
 
 The
primary sources of credit risk for the Company arise from the following
financial assets: (1) cash and cash equivalents; (2) accounts receivable; and
(3) derivatives contracts. The Company has not had any credit losses in the past
and the risk of financial loss is considered to be low given the counterparties
used by the Company. As at December 31, 2008, the Company has no financial
assets that are past due or impaired due to credit-risk-related
defaults.
 
 Liquidity
Risk
 Liquidity
risk is the risk that the Company will not be able to meet obligations
associated with financial liabilities. Our financial liabilities are comprised
of accounts payable and accrued liabilities, long-term debt and obligations
under capital leases. The Company frequently assesses its liquidity position and
obligations under its financial liabilities by preparing regular financial
forecasts. We mitigate liquidity risk by maintaining a sufficient cash balance
as well as maintaining sufficient current and projected liquidity to meet
expected future payments. Our financial liabilities arose primarily from the
development of the Project. As at December 31, 2008, the Company has met all of
the obligations associated with its financial liabilities.  As noted
under “Liquidity,” continued access to our revolving credit facility is a key
liquidity risk.
  Market
Risk
 Market
risk is the risk that the fair value (for assets or liabilities considered to be
held for trading and available for sale) or future cash flows (for assets or
liabilities considered to be held-to-maturity, other financial liabilities, and
loans and receivables) of a financial instrument will fluctuate because of
changes in market prices. We evaluate market risk on an ongoing basis. We assess
the impact of variability in identified market risks on our medium-term cash
requirements and impact with respect to covenants on our credit facilities. At
December 31, 2008, we had mitigation programs to reduce market risk related to
foreign exchange and commodity price changes. Changes in these market risks
related to foreign exchange would not have had an impact on our earnings as
translation gains and losses on our U.S.-dollar debt and related hedging
activities were capitalized. The primary market risks related to our commodity
contracts relates to future estimated prices for WTI. A $5 change in estimated
future WTI prices would change our unrealized loss by approximately $10 million
in U.S. dollars at December 31, 2008 as a result of an estimated change in the
value of our commodity contracts.
 
 23
 The
following sections describe these risks in relation to the Company’s key
financial instruments.
 
 *
Cash and Cash Equivalents
 The
Company has cash deposits with Canadian banks and has money market investments.
Counterparty selection is governed by the Company’s Treasury Policy, which
limits concentration of investments and requires that all instruments be rated
as investment grade by at least one rating agency. As at December 31, 2008 the
amount in cash and cash equivalents was $217 million and the maximum exposure to
a single counterparty was $51 million which is guaranteed by a Canadian
bank.
 
 At
December 31, 2008, the remaining terms on investments made by the Company are
less than 90 days with interest fixed over the period of investment. Maturity
dates for investments are established to ensure cash availability for project
development and interest payments. Investments are held to maturity and the
maturity value does not deviate with changes in market interest
rates.
 
 Our
cash balances are currently invested almost exclusively in money market
instruments with major Canadian banks in the form of banker’s acceptances or
term deposits. These instruments are widely offered by banks we deal with and
are considered direct obligations of the banks that offer them. We manage our
exposure to these banks in two primary ways: by limiting the amount invested
with a single issuer or guarantor and by investing for relatively short periods
of time. We do not expect any investment losses based on these money market
investments.
 
 *
Accounts Receivable
 Our
accounts receivable includes amounts due from Nexen Inc. related to project
development and Nexen Marketing related to marketing activities, interest earned
but not received on money market investments, and amounts due from the Canada
Revenue Agency in relation to GST refunds. The amounts due from Nexen increased
significantly subsequent to year-end as a result of the completion of the
working interest sale.  The agreement included $85 million as a
pre-funded amount for 2009 development activities. These funds will be released
as work is completed on the 2009 joint venture capital program. OPTI is entitled
to a refund of such dollars or contribution of further dollars in the event that
OPTI’s working interest share of 2009 joint venture capital expenditures is less
than or exceeds $85 million. The Company’s credit risk in regard to accounts
receivable therefore relates primarily to the risk of default by Nexen, which
has an investment-grade corporate rating from Moody’s Investor Service, and by
financial institutions with an investment grade rating. Therefore, we estimate
the risk of credit loss as low.
 
 *
Accounts Payable and Accrued Liabilities
 Accounts
payable and accrued liabilities are comprised primarily of amounts due in
respect of development of the Project and certain other corporate expenses.
Payment terms on these amounts are typically 30 to 60 days from receipt of
invoice and generally do not bear interest. The Company has met its obligations
in respect of these liabilities. As at December 31, 2008 accounts payable and
accrued liabilities were $200 million.
 
 24
 *
Debt and Obligations under Capital Lease
 The
terms of the Company’s debt and obligations under capital lease are described in
the notes to our audited financial statements as at December 31, 2008. The
Company has met its obligations in respect of these liabilities. The Company
accounts for its borrowings under all of its long-term debt and obligations
under capital lease on an amortized cost basis. As at December 31, 2008
long-term debt was $2,618 million, short-term debt was $146 million and
obligations under capital leases were $30 million.
 
 The
revolving credit facilities are variable interest rate facilities with borrowing
rates and duration established at the time of the initial borrowing or
subsequent extension. Our current borrowings have an approximate initial term of
90 days and therefore fluctuations in the value of such borrowings are not
material during the term they are outstanding. The Company is exposed to
interest rate changes if and when it extends each borrowing. The extent of the
exposure to interest rate risk depends on the amount outstanding under the
facility. As at December 31, 2008, there was $486 million drawn under the $500
million revolving credit facility and $146 million drawn under the $150 million
revolving credit facility.  As described under ”Capital Resources,”
these amounts were reduced in early 2009.  During 2008, a 1 percent
change in interest rates would not have had a material impact on the interest
expense due to the fixed nature of our senior notes and relatively low average
balance of our revolving credit facilities.
 
 Our
senior secured notes are comprised of US$1,750 million of debt which has fixed
U.S. dollar semi-annual interest payments. Changes in the exchange rate between
the Canadian dollar and U.S. dollar impact the carrying value of the senior
secured notes. A US$0.01 change in the exchange rate will impact the carrying
value of the senior secured notes by approximately US$18 million. A US$0.01
change in the exchange rate will change our interest costs by approximately
US$1.4 million. The exposure to exchange rate fluctuations has been partially
mitigated by the forward contracts described under “Foreign Exchange Hedging
Instruments.” These changes also influence our compliance with debt
covenants as described under ”Liquidity.”
 
 *
Derivative Contracts
 The
Company periodically uses derivative contracts to hedge certain of the Company’s
projected operational or financial risks. In the past, such instruments have
involved the use of interest rate swaps, cross-currency interest swaps,
currency-forward contracts and crude oil put options. Derivative contracts
outstanding at December 31, 2008 are described in the notes to our audited
financial statements as at December 31, 2008. These instruments are designated
as held-for-trading and are measured at fair value at each financial statement
date.
 
 As at
December 31, 2008, we had US$875 million of foreign currency forwards to manage
a portion of the exposure to the foreign exchange variations on the Company’s
long-term debt. Changes in the exchange rate between Canadian and U.S. dollars
change the value of these instruments. The foreign currency forwards at December
31, 2008 had a fair value of $32 million. The foreign exchange forwards are
measured by the present value of the difference between the settlement amounts
of the foreign currency forwards as measured in Canadian dollars. The
counterparties to the foreign currency forwards are major Canadian and
international banks. Our exposure to non-payment from any single institution is
less than 25 percent of the value of the forwards.
 
 25
 The
fair value of the foreign currency forwards is determined by calculating the
present value of the existing contract as measured in Canadian dollars in
reference to established market rates, primarily foreign exchange rates at the
end of the year and discounted at market interest rates. The foreign currency
forwards were valued primarily using a period-end foreign exchange rate of 1.22.
Based on the active market for the underlying market variables used in the
valuation, we do not believe other market assumptions with respect to these
variables could result in a materially different valuation than the one we have
determined. This conclusion is supported by an internal comparison completed by
OPTI to compare the valuation provided by each counterparty to the forwards. The
value of the foreign currency forwards would change by approximately $8 million
for each $0.01 change in the foreign exchange rate between U.S. and Canadian
dollars.  This change would have a corresponding impact on capitalized
costs in 2008 and on our earnings before taxes in 2009.
 
 We have
established commodity hedging contracts to mitigate the Company’s exposure of
future operations to decreases in the price of its synthetic crude oil. The
Company has chosen to use put options and commodity price swaps to mitigate a
portion of the exposure. As at December 31, 2008 the Company had deferred
premium put options covering 2.2 million barrels of 2009 production at a price
of US$80/bbl (deferred premiums to be paid on the expiration of the option are
$4/bbl); and commodity price swaps covering 0.2 million barrels of 2009
production at a price of US$77/bbl. The value of these financial instruments as
at December 31, 2008 was an asset of $78 million. The counterparties to the
commodity hedges are major Canadian and international banks. Our exposure to
non-payment from any single institution is approximately 60 percent of the value
of the commodity hedge, which is due from a major Canadian bank.
 
 The
fair value of the commodity hedges is determined by calculating the present
value of the existing contract as measured in Canadian dollars in reference to
established market rates, primarily future estimated prices for WTI and
period-end foreign exchange rates. Based on the active market for the underlying
market variables used in the evaluation, we do not believe other market
assumptions with respect to these variables could result in a materially
different valuation than the one we have determined. This conclusion is
supported by an internal comparison completed by OPTI to compare the valuation
provided by each counterparty to the contract. The value of the commodity hedges
would change by approximately US$2 million for each US$1/bbl change in future
estimated prices for WTI. This change would have a corresponding impact on our
earnings before taxes for the year.
 
 We view
the credit risk of these counterparties as low due to the diversification of the
instrument with a number of banks.
 
 26
 RISK
FACTORS
 Readers
should be aware that the list of assumptions, risks and uncertainties set forth
herein are not exhaustive. Readers should refer to OPTI's current Annual
Information Form (AIF), which is available at www.sedar.com, for a detailed
discussion of these assumptions, risks and uncertainties.
 
 Market
Risks
 We are
involved in a capital intensive industry.  Oil sands development
requires significant investment prior to any cash being returned to the business
in the form of operating cash flow. Our development cycle for each phase can be
greater than five years. This means significant external capital may be
required. In addition, a combination of poor operating results, requirement for
major repairs or improvements to our facilities and low commodity prices could
require us to seek additional capital during 2009. Recent developments in the
banking sector and the economy as a whole have meant such capital may be
restricted in terms of size, extremely expensive in historical terms, or not
available at all. Although the recent asset sale to Nexen has improved our
short-term financial position, there is no assurance that, should we require
additional capital in the future, we will be able to obtain such financing on a
timeline suitable for OPTI.
 
 Risk Factors During
Operations
 *
Oil Prices and Foreign Exchange
 Our
financial results will be dependent upon the future price of crude oil. Oil
prices fluctuate significantly in response to regional, national and global
supply and demand factors beyond our control. Political and economic
developments around the world can affect world oil supply and oil
prices.
 
 The
Long Lake Upgrader will ultimately produce a fully upgraded product called
PSCTM.
The price we will receive for PSCTM will be dependent on the demand for it and
will primarily be influenced by changes in the market price for WTI, which is
influenced by global market factors. To a lesser extent, the price we receive
for PSCtm
will be affected by regional factors such as supply of other synthetic and
conventional crude oils. Although we expect PSCtm
to trade at a price similar to WTI, PSCtm
will be a new synthetic crude oil product and no assurance can be given as to
its price and marketability. We have engaged Nexen Marketing, which has
extensive experience in marketing synthetic crude, to sell all of our production
from the Long Lake Project.
 
 After
the Long Lake Upgrader start-up and during periods when the Upgrader is not
operating, including planned and unplanned maintenance and repair, we may be
unable to upgrade the bitumen produced by the Project. During these periods,
bitumen would be mixed with diluent and sold as a bitumen blend. The blend would
be priced significantly lower than conventional light oil or PSCtm.
 
 Our
future results of operations will be impacted by certain factors outside of our
control, such as the gravity and quality of the bitumen produced from the Long
Lake leases, which can ultimately determine the amount of syngas and PSCtm
produced from the Long Lake Upgrader.
 
 Crude
oil prices are generally based on a U.S.-dollar market price, while most of our
operating and capital costs are denominated in Canadian dollars. Fluctuations in
exchange rates between the U.S. and Canadian dollars result in foreign currency
exchange exposure. Therefore, changes in the exchange rate will affect the price
we receive for PSCtm.
We have protected a portion of this exposure to oil price fluctuation from our
commodity contracts and have no protection from foreign exchange rates
fluctuations related to the sale of our products.
 
 27
 *
Operating Risk
 The
performance of the SAGD operation, the Long Lake Upgrader, or both may differ
from our expectations. There are many factors related to the characteristics of
the reservoir and SAGD operating facilities that could cause bitumen production
to be lower than anticipated.
 
 The
Long Lake Upgrader is comprised of a number of facilities that upgrade bitumen,
in part using high pressure and temperature. There are inherent risks in the
initial and ongoing operation of our facility. The processing of hydrocarbons
requires intensive planning and execution expertise. Problems during this
process could result in increases to cost, reduced production or damage to
facilities. All of these factors could negatively affect our results from
operations.
 
 
 *
Non-operator
 Nexen
is the operator of the Long Lake Project. We rely on Nexen’s operating expertise
to generate cash flow from the Project and to provide information on the status
and results of operations. There are no assurances that Nexen will be able to
generate financial results from the Project or that Nexen will be able to
provide adequate financial and operational information on a timely
basis.
 
 *
Natural Gas
 During
commercial operations, we will require a significant amount of natural gas to
provide energy to generate steam for SAGD operations. The integrated Project
design has mitigated a large amount of the risk, as syngas is expected to be
produced through the gasification process and will be used to provide energy to
the steam generation facilities. The amount of third-party natural gas purchases
required is largely determined by the SOR that is required for SAGD production.
If the SOR is higher than anticipated, we may be required to purchase natural
gas beyond existing forecasted levels at prevailing market rates. This would
cause our operating costs to increase and reduce our earnings.
 
 *
Reserves and Resources
 There
are numerous uncertainties inherent in estimating quantities of reserves and
resources, including many factors beyond our control, and no assurance can be
given that the indicated level of reserves or resources or recovery of bitumen
will be realized. In general, estimates of resources and of economically
recoverable bitumen reserves are based upon a number of factors and assumptions
made as of the date on which the reserve and resource estimates were determined,
such as geological and engineering estimates that have inherent uncertainties,
the assumed effects of regulation by governmental agencies and estimates of
future commodity prices and operating costs, all of which may vary considerably
from actual results. All such estimates are, to some degree, uncertain and
classifications of reserves are only attempts to define the degree of
uncertainty involved. For these reasons, estimates of the economically
recoverable bitumen, the classification of such reserves based on risk of
recovery, prepared by different engineers or by the same engineers at different
times, may vary substantially.
 
 28
 The
estimates with respect to reserves and resources that may be developed and
produced in the future have been based upon volumetric calculations and upon
analogy to similar types of reserves and resources, rather than upon actual
production history. Estimates based on these methods generally are less reliable
than those based on actual production history. Subsequent evaluation of the same
reserves and resources based upon production history will result in variations,
which may be material, in the estimated reserves and resources.
 
 Reserve
and resource estimates may require revision based on actual production
experience. Such figures have been determined based upon assumed oil prices and
operating costs. Market fluctuations of oil prices may render uneconomic the
recovery of certain grades of bitumen. Also, short-term factors relating to oil
sands resources may impair the profitability of the Project in any particular
period.
 
 Should
the reserve estimate change in future periods, there could be a material impact
on the fair value of our securities, our results of operations and our ability
to obtain financing.
 
 *
Commodities Risk
 During
regular operations, our exposure to natural gas prices is reduced as the Long
Lake Upgrader is expected to generate syngas, which will be used instead of
natural gas. In the long-term, we expect approximately two thirds of our natural
gas requirements will be generated by syngas with approximately one third being
supplied from purchased natural gas. Although we expect stable Upgrader
operations, during periods of Upgrader downtime we have significant exposure to
natural gas prices. During these periods, virtually all of the energy required
to generate steam for the SAGD operations will be from the purchase of natural
gas.
 
 During
periods when the Upgrader is not in operation, we will be producing raw bitumen
from the SAGD process. These bitumen barrels will be blended with a purchased
diluent and sold as a bitumen blend. The price per barrel of purchased diluent
will approximate WTI. The price we receive for this bitumen blend may vary
widely and may be at a significant discount to WTI. At low commodity prices and
high differentials between light oil and heavy oil in Northern Alberta as
experienced in late 2008, the revenue we receive for bitumen blend may
approximate the cost of the diluent.
 
 Project Development
Risk
 *
Financing Risk
 Continuing
access to our revolving credit facility is critical to our financial position,
as noted under “Liquidity,” and there are risks of failure to meet covenants
that would impair this access. The development of oil sands projects in
connection with the Project and our multi-stage expansion plan requires a
significant amount of capital investment that occurs over a number of years. We
currently do not have the capital or committed financing necessary to complete
our future phases of development and we expect to need to complete additional
debt or equity financing to obtain the funds necessary to complete future
phases. The cost of additional financing may not make future projects
economically feasible.
 
 29
 *
Regulatory Risk
 We are
subject to extensive Canadian federal, provincial and local laws and regulations
governing exploration, development, transportation, production, exports,
occupational health, protection and reclamation of the environment, safety and
other matters.
 
 Completed
phases of the Project will produce greenhouse gases (GHGs) and other industrial
air pollutants. The Canadian federal government has released a framework that
outlines proposed new requirements governing the emission of GHGs and other
industrial pollutants. It is possible that new federal or provincial
requirements with respect to GHGs and industrial air pollutants will be imposed.
This may require additional funding or facilities to comply with such
requirements.
 
 *
Risks to Future Phase Development
 We have
announced phased development for up to five additional phases of projects of a
similar size to the Project. The development of these phases is subject to a
number of risks, primarily in the areas of resource extent and quality, cost,
execution, long-term commodity price expectation and regulatory approval. If the
estimates of costs to complete these future phases are higher than anticipated,
these future phases may be deferred or cancelled. The execution of these future
phases requires specialized labour, module construction, engineering expertise
and construction management. As oil sands development in Alberta has been and
may be in the future at high levels of development activity, some or all of
these resources may not be available to us on the schedule that we require,
which could delay future development.  We have regulatory approval for
the Phase 2 upgrader, but do not have regulatory approval for any future phase
of SAGD development or upgraders. These regulatory approvals may delay or
restrict our development of future phases.
 
 *
Infrastructure Risk
 The
Project will depend on successful operation of certain infrastructure owned and
operated by others, including, without limitation:
 ·
              pipelines
      for the transportation of feedstocks and petroleum products to be sold
      ;
 ·
              pipelines
      for the transportation of natural
gas;
 ·
              a
      railway spur for the transportation of products and byproducts including
      sulfur;
 ·
              disposal
      facilities for by-products of the Project (e.g. sulphur);
    and
 ·
              electricity
      transmission systems for the provision and/or sale of
      electricity.
 
 The
failure of any or all of these utilities to supply service will negatively
impact the operation of the Project which, in turn, may have a material adverse
effect on our business or results of operations.
 
  30











graphPricewaterhouseCoopers
      LLP
                  Chartered
      Accountants
                  111
      5 Avenue SW, Suite 3100
                  Calgary,
      Alberta
                  Canada
      T2P 5L3
                  Telephone
      +1 403 509 7500
                  Facsimile
      +1 403 781 1825
 Auditors’
Report
  To
the Shareholders of OPTI Canada Inc.:
  We
have audited the balance sheets of OPTI Canada Inc. as at December 31, 2008 and
2007 and the statement of loss, comprehensive loss and deficit and cash flows
for each of the years in the two year period ended December 31, 2008. These
financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
  We
conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation.
  In
our opinion, these financial statements present fairly, in all material
respects, the financial position of the Company as at December 31, 2008 and 2007
and the results of its operations and its cash flows for each of the years in
the two year period ended December 31, 2008 in accordance with Canadian
generally accepted accounting principles.
  
 Chartered
Accountants Calgary, Alberta Canada
 February
24, 2009
      “PricewaterhouseCoopers”
refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership,
or, as the context requires, the PricewaterhouseCoopers
global network or other member firms of the network, each of which is a separate
and independent legal entity.







OPTI
CANADA INC.
 
 Balance
Sheets
 
 AS AT DECEMBER 312008
                                                            
                                                            
                                                            2007(Amounts
      in thousands of Canadian dollars)ASSETSCurrentCash
      and cash equivalents (note 2c)
                                                            
                                                            $
                                                            217,145
                                                            
                                                            
                                                            $
                                                            310,504Accounts and
      other receivables
                                                            
                                                            
                                                            22,807
                                                            
                                                            
                                                            
                                                            13,495Commodity
      contracts (note 3)
                                                            
                                                            
                                                            78,003
                                                            
                                                            
                                                            
                                                            -Future
      income taxes (note 6)
                                                            
                                                            
                                                            2,709
                                                            
                                                            
                                                            
                                                            -Interest
      reserve account (note 2j)
                                                            
                                                            
                                                            -
                                                            
                                                            
                                                            
                                                            137,328320,664
                                                            
                                                            
                                                            
                                                            461,327Future
      income tax asset (note 6)
                                                            
                                                            
                                                            44,417
                                                            
                                                            
                                                            
                                                            2,153Other
      long term assets (note 9c)
                                                            
                                                            
                                                            31,679
                                                            
                                                            
                                                            
                                                            -Property,
      plant and equipment (note 4)
                                                            
                                                            
                                                            4,160,901
                                                            
                                                            
                                                            
                                                            3,373,908$
                                                            4,557,661
                                                            
                                                            
                                                            $
                                                            3,837,388LIABILITIESCurrentAccounts
      payable and accrued liabilities
                                                            
                                                            $
                                                            199,907
                                                            
                                                            
                                                            $
                                                            190,723Short
      term debt (note 5)
                                                            
                                                            
                                                            145,500
                                                            
                                                            
                                                            
                                                            -345,407
                                                            
                                                            
                                                            
                                                            190,723Long-term
      debt (note 5)
                                                            
                                                            
                                                            2,618,000
                                                            
                                                            
                                                            
                                                            1,734,775Obligation
      under capital lease (note 11b)
                                                            
                                                            
                                                            30,195
                                                            
                                                            
                                                            
                                                            29,600Other
      long-term liabilities (note 7)
                                                            
                                                            
                                                            7,937
                                                            
                                                            
                                                            
                                                            66,6773,001,539
                                                            
                                                            
                                                            
                                                            2,021,775SHAREHOLDERS’ EQUITY(note 8)Capital
      stock
                                                            
                                                            
                                                            1,847,461
                                                            
                                                            
                                                            
                                                            1,837,253Warrants
                                                            
                                                            
                                                            -
                                                            
                                                            
                                                            
                                                            15,686Contributed
      surplus
                                                            
                                                            
                                                            31,080
                                                            
                                                            
                                                            
                                                            11,897Deficit
                                                            
                                                            
                                                            (322,419
                                                            )
                                                            
                                                            
                                                            (49,223
                                                            )1,556,122
                                                            
                                                            
                                                            
                                                            1,815,613$
                                                            4,557,661
                                                            
                                                            
                                                            $
                                                            3,837,388
 
 Commitments
(note 11)
 Subsequent
events (note 14)
 
 (signed)
      "Robert G. Puchniak"
              (signed)
      "Sid W. Dykstra"
 
 See
accompanying notes to the financial statements
 
 1
 OPTI
CANADA INC.
 
 Statements
of Loss, Comprehensive Loss and Deficit
 
 Years Ended December 312008
                        
                        
                        2007(Amounts
      in thousands of Canadian dollars, except per share
amounts)Interest
      income
                        
                        $
                        5,985
                        
                        
                        $
                        13,303ExpensesImpairment of
      assets (note 14)
                        
                        
                        391,686
                        
                        
                        
                        -General
      and administrative
                        
                        
                        17,616
                        
                        
                        
                        14,206Financing
      charges
                        
                        
                        893
                        
                        
                        
                        11,927Realized loss
      (gain) on commodity contracts
                        
                        
                        (1,653
                        )
                        
                        
                        -Unrealized loss
      (gain) on commodity contracts
                        
                        
                        (66,973
                        )
                        
                        
                        3,779Amortization
      and accretion
                        
                        
                        5,973
                        
                        
                        
                        2,011(347,542
                        )
                        
                        
                        31,923Loss
      before taxes
                        
                        
                        (341,557
                        )
                        
                        
                        (18,620
                        )Income
    taxesCapital
      taxes
                        
                        
                        -
                        
                        
                        
                        -Future
      tax recovery (note 6)
                        
                        
                        (85,025
                        )
                        
                        
                        (9,134
                        )(85,025
                        )
                        
                        
                        (9,134
                        )Net
      loss and comprehensive loss
                        
                        
                        (256,532
                        )
                        
                        
                        (9,486
                        )Deficit
      - beginning of year
                        
                        
                        (49,223
                        )
                        
                        
                        (12,453
                        )Adoption
      of new accounting policy (note 2m)
                        
                        
                        -
                        
                        
                        
                        (27,284
                        )Deficit
      - beginning of year
                        
                        
                        (49,223
                        )
                        
                        
                        (39,737
                        )Expiration
      of call options (note 8)
                        
                        
                        (16,664
                        )
                        
                        
                        -Deficit
      - end of year
                        
                        $
                        (322,419
                        )
                        
                        $
                        (49,223
                        )Loss
      per share, basic and diluted
                        
                        $
                        (1.31
                        )
                        
                        $
                        (0.05
                        )
 
 See
accompanying notes to the financial statements
 
 2
 OPTI
CANADA INC.
 
 Statement
of Cash Flows
   Years Ended December 312008
                                
                                
                                2007(Amounts
      in thousands of
                                  Canadian
      dollars)Cash provided by (used
      in)Operating
      activitiesNet
      loss
                                
                                $
                                (256,532
                                )
                                
                                $
                                (9,486
                                )Items
      not affecting cashAmortization
      and accretion expense
                                
                                
                                5,973
                                
                                
                                
                                2,011Stock
      based compensation expense
                                
                                
                                1,895
                                
                                
                                
                                1,356Impairment
      of assets
                                
                                
                                391,686
                                
                                
                                
                                -Unrealized
      loss (gain) on commodity contracts
                                
                                
                                (66,973
                                )
                                
                                
                                3,779Imputed
      interest on commodity contract liability
                                
                                
                                189
                                
                                
                                
                                -Unrealized foreign exchange
      gain
                                
                                
                                (317
                                )
                                
                                
                                -Future
      tax expense (recovery)
                                
                                
                                (85,025
                                )
                                
                                
                                (9,134
                                )(9,104
                                )
                                
                                
                                (11,474
                                )Asset
      retirement costs incurred
                                
                                
                                (9
                                )
                                
                                
                                (24
                                )Financing
      charges
                                
                                
                                893
                                
                                
                                
                                11,927Net
      change in non-cash working capital
                                
                                
                                1,157
                                
                                
                                
                                4,496(7,063
                                )
                                
                                
                                4,925Financing
      activities
                                  Increase
      in long-term debt
                                
                                
                                632,000
                                
                                
                                
                                930,700Repayments
      of long-term debt
                                
                                
                                -
                                
                                
                                
                                (612,820
                                )Proceeds
      from share issuances
                                
                                
                                7,041
                                
                                
                                
                                428,972Deferred
      financing charges
                                
                                
                                -
                                
                                
                                
                                -Share
      issue costs
                                
                                
                                (71
                                )
                                
                                
                                (16,768
                                )Financing
      charges
                                
                                
                                (893
                                )
                                
                                
                                (11,927
                                )Decrease
      in principle portion of capital lease obligation
                                
                                
                                (305
                                )
                                
                                
                                -Net
      change in non-cash working capital
                                
                                
                                13,241
                                
                                
                                
                                (4,793
                                )651,013
                                
                                
                                
                                713,364Investing
      activitiesProperty,
      plant and equipment additions
                                
                                
                                (987,134
                                )
                                
                                
                                (1,108,367
                                )Settlement
      of interest rate swap
                                
                                
                                113,762
                                
                                
                                
                                (2,201
                                )Decrease
      in short-term investments
                                
                                
                                -
                                
                                
                                
                                37,097Decrease
      (increase) in interest reserve account
                                
                                
                                158,398
                                
                                
                                
                                102,626Net
      change in non-cash working capital
                                
                                
                                (31,950
                                )
                                
                                
                                30,837(746,924
                                )
                                
                                
                                (940,008
                                )Foreign
      exchange gain (loss) on cash and cash equivalents held in foreign
      currency
                                
                                
                                9,615
                                
                                
                                
                                (4,443
                                )Increase
      (decrease) in cash
                                
                                
                                (93,359
                                )
                                
                                
                                (226,162
                                )Cash
      and cash equivalents - beginning of year
                                
                                
                                310,504
                                
                                
                                
                                536,666Cash
      and cash equivalents - end of year
                                
                                $
                                217,145
                                
                                
                                $
                                310,504
  See
accompanying notes to the financial statements
 
 3
 OPTI
CANADA INC.
 
 Statements
of Shareholders’ Equity
 
 
 Warrants
                
                
                Call
                  Obligations
                
                
                Common
      and Preferred
                  Shares
                
                
                Contributed
                  Surplus
                
                
                Deficit
                
                
                Total(Amounts
      in thousands of Canadian dollars)Balance
      at December 31, 2006
                
                
                15,686
                
                
                
                (16,664
                )
                
                
                1,447,679
                
                
                
                9,357
                
                
                
                (12,453
                )
                
                
                1,443,605Issued
      for cash
                
                
                -
                
                
                
                -
                
                
                
                352,156
                
                
                
                -
                
                
                
                -
                
                
                
                352,156Issued
      for cash - flow-though
                
                
                -
                
                
                
                -
                
                
                
                60,021
                
                
                
                -
                
                
                
                -
                
                
                
                60,021Share
      issue costs
                
                
                -
                
                
                
                -
                
                
                
                (16,768
                )
                
                
                -
                
                
                
                -
                
                
                
                (16,768
                )Stock
      options exercised
                
                
                -
                
                
                
                -
                
                
                
                16,795
                
                
                
                (1,548
                )
                
                
                -
                
                
                
                15,247Stock
      based compensation
                
                
                -
                
                
                
                -
                
                
                
                1,548
                
                
                
                4,088
                
                
                
                -
                
                
                
                5,636Tax
      effect on financing activities
                
                
                -
                
                
                
                -
                
                
                
                (7,514
                )
                
                
                -
                
                
                
                -
                
                
                
                (7,514
                )Adoption
      of new accounting policy
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                (27,284
                )
                
                
                (27,284
                )Net
      loss
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                (9,486
                )
                
                
                (9,486
                )Balance
      at December 31, 2007
                
                $
                15,686
                
                
                $
                (16,664
                )
                
                $
                1,853,917
                
                
                $
                11,897
                
                
                $
                (49,223
                )
                
                $
                1,815,613Share
      issue costs
                
                
                -
                
                
                
                -
                
                
                
                (71
                )
                
                
                -
                
                
                
                -
                
                
                
                (71
                )Stock
      options exercised
                
                
                -
                
                
                
                -
                
                
                
                4,870
                
                
                
                (1,030
                )
                
                
                -
                
                
                
                3,840Stock
      based compensation
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                5,076
                
                
                
                -
                
                
                
                5,076Expiration
      of call options
                
                
                -
                
                
                
                16,664
                
                
                
                -
                
                
                
                -
                
                
                
                (16,664
                )
                
                
                -Warrants
      exercised
                
                
                (549
                )
                
                
                -
                
                
                
                3,750
                
                
                
                -
                
                
                
                -
                
                
                
                3,201Reclassified
      expired warrants
                
                
                (15,137
                )
                
                
                -
                
                
                
                -
                
                
                
                15,137
                
                
                
                -
                
                
                
                -Tax
      effect on financing activities
                
                
                -
                
                
                
                -
                
                
                
                (15,005
                )
                
                
                -
                
                
                
                -
                
                
                
                (15,005
                )Net
      loss
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                (256,532
                )
                
                
                (256,532
                )Balance
      at December 31, 2008
                
                $
                -
                
                
                $
                -
                
                
                $
                1,847,461
                
                
                $
                31,080
                
                
                $
                (322,419
                )
                
                $
                1,556,122
 
 See
accompanying notes to the financial statements
 
 4
  OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
 
 1.
              SUMMARY
      OF OPERATIONS
 OPTI
Canada Inc. (OPTI) is a public Canadian company with its shares listed for
trading on the Toronto Stock Exchange (Symbol: OPC).  OPTI’s primary
activity is the Long Lake Project (the Project), in which OPTI has a 50 percent
working interest as at December 31, 2008.  Effective January 1, 2009,
OPTI has a 35 percent working interest in all the joint venture assets,
including Phase 1 of the Long Lake Project, all future phase reserves and
resources, and future phases of development. See note 14.
 
 
 2.
              SUMMARY
      OF SIGNIFICANT ACCOUNTING POLICIES
 a)
              Property,
      plant and equipment
 (i)Consolidation
 On
January 1, 2008, OPTI Long Lake LP (Partnership) was dissolved by a distribution
of assets to each of the partners, OPTI and OPTI GP Inc.  On January
1, 2008, OPTI GP Inc. was amalgamated with OPTI Canada Inc. Accordingly, the
2007 comparable financial results are consolidated.
 
 (ii)Petroleum and natural gas
properties
 OPTI
follows the full cost method of accounting for petroleum and natural gas
properties, whereby all costs of exploring for and developing petroleum and
natural gas reserves are capitalized. Costs include land acquisition costs,
geological and geophysical costs, carrying charges on non-productive properties,
costs of drilling both productive and non-productive wells, costs of testing the
bitumen upgrading process, related overhead and pre-operating costs. The
capitalized costs, less undeveloped land costs, are depleted using the
unit-of-production method based upon estimated proved reserves before
royalties.  To date, no depletion has been recorded as commercial
operations have not commenced.
 
 Impairment
is recognized if the carrying amount of the property, plant and equipment
(PP&E) exceeds the sum of the undiscounted cash flows expected to result
from proved reserves (ceiling test). Cash flows are calculated based on an
estimate of future prices. In circumstances of impairment, the impairment would
be calculated as the amount by which carrying amounts of the PP&E exceed the
net present value of future cash flows from proved plus risked probable
reserves. The risk-free interest rate is used to arrive at the net present value
of the future cash flows. Any excess carrying value above the net present value
of OPTI’s future cash flows would be recorded as a permanent impairment. The
costs of unproved properties are excluded from the ceiling test calculation and
subject to a separate impairment test. In circumstances of impairment, the
impairment would be calculated as the amount by which carrying amounts of
unproved properties exceed the net present value of future cash flows. The
impaired amount would be moved to the full cost amount subject to depletion.
Effective January 1, 2009 operating costs net of revenue will be expensed with
retroactive adjustment of prior costs (See note 2 l(iii)a)
 
 Proceeds
from the sale of oil and gas properties reduce PP&E, with no gain or loss
recognized, unless such a sale would significantly alter the rate of depletion
and depreciation.
 
 (iii)Major facilities
 Major
facilities including the Upgrader and related equipment, and operating costs net
of revenues in relation to major facilities that are considered to be in the
development stage, are capitalized. Judgment is required to determine whether
operations are in the development stage. The factors considered include whether
commercially viable production levels have been achieved, whether the plant is
producing a saleable product, whether the plant is operating at pre-determined
operating levels in relation to commercial operations or other factors as
circumstances warrant. Once the operations are no longer considered development
stage, revenue is recognized and operating costs are recorded in earnings during
the year.
 
 An
impairment loss is recognized on major facilities when the carrying amount is
not recoverable and exceeds its fair value. The carrying amount is not
recoverable if the carrying amount exceeded the sum of the undiscounted cash
flows from expected use and eventual disposition. If the carrying amount is not
recoverable, an impairment loss is measured as the amount by which the assets
exceed the discounted future cash flows from the major facilities
assets.
  5
  OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
 2.   
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
 (iv)Asset retirement obligations
 OPTI
recognizes the fair value of the liability for asset retirement obligations in
the period it is incurred with a corresponding increase to the carrying amount
of the related asset. The initial obligation recognized is accreted over time
until the future period in which the obligation is settled. The related asset
will be amortized over its estimated useful life using straight line or the unit
of production method once commercial operations commence.
 
 (v)Corporate assets
 Corporate
office assets are recorded at cost less accumulated amortization which is
calculated using the declining balance method at rates of 30 percent to 50
percent per annum.
 
 (vi)Capitalized interest
 Prior
to the commencement of commercial operations, OPTI capitalizes interest costs in
relation to its long-term debt for major development projects.
 
 (vii)Foreign currency translation
 Monetary
assets and liabilities are translated at exchange rates in effect on the balance
sheet date. Other assets and related depreciation, depletion and amortization,
other liabilities and expenses are translated at rates in effect at the date of
the transaction. Prior to the commencement of commercial operations, OPTI
capitalizes foreign exchange gains or losses in relation to the revaluations of
its U.S. dollar (US$) denominated cash and cash equivalents, related derivatives
and long-term debt used for major development projects. Exchange gains and
losses resulting from operating activities are included in
earnings.
 
 b)
              Joint
      venture
 A
significant portion of OPTI’s activities are conducted within a joint venture.
The accounts reflect OPTI’s proportionate interest in such
activities.
 
 c)
              Cash
      and cash equivalents
 Cash
and cash equivalents include cash, bankers’ acceptances, term deposits and
bankers’ deposit notes that carry terms less than 91 days at the date of
purchase.
 
 d)
              Leases
 Leases
that transfer substantially all the benefits, risks and rewards of ownership to
OPTI are recorded as capital leases and classified as PP&E with a
corresponding increase to obligations under capital
leases.  Amortization is capitalized up until commencement of
commercial operations.  All other leases are classified as operating
leases under which leasing costs are expensed in the period
incurred.  Prior to the commencement of commercial operations, OPTI is
capitalizing operating lease payments.
 
 e)
              Income
      taxes
 OPTI
uses the liability method of accounting for income taxes. Future tax assets and
liabilities are recognized based on differences in the financial statement
carrying amount for assets and liabilities and the associated tax
balance.  Future taxes are measured based on substantially enacted tax
rates in the period in which the temporary differences are expected to be
realized or settled. The asset must be more likely than not to be realized,
otherwise a valuation allowance reduces the tax asset.
 
 f)
              Flow-through
      shares
 Tax
deductions for income tax purposes related to exploratory and development
activities funded by flow-through share arrangements are renounced to investors
in accordance with income tax legislation. Share capital is reduced, with a
corresponding increase to the future tax liability, by the estimated cost of the
tax deductions when such deductions are renounced to the investors.
 
 
 6
 
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
 
 2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
 g)
              Stock-based
      compensation plans
 Stock
options granted to directors, officers, employees and consultants are accounted
for using the fair value method under which compensation expense is recorded
based on the estimated fair value of the options at the grant date using the
Black-Scholes option pricing model.  Compensation cost is either
expensed or capitalized over the vesting period with a corresponding increase in
contributed surplus.  When stock options are exercised, the cash
proceeds along with the amount previously recorded as contributed surplus are
recorded as share capital.
 
 h)
              Loss
      per share
 Loss
per share is calculated using net earnings or loss and the weighted average
number of common shares outstanding during the year. For the year ended December
31, 2008, the weighted average number of common shares of all classes
outstanding is 195.7 million (December 31, 2007 - 177.4 million) and diluted is
195.7 million (December 31, 2007 - 181.6 million). OPTI uses the treasury stock
method of calculating diluted earnings or loss per common share. There is no
difference in basic or diluted loss per share.
 
 i)
              Use
      of estimates
 The
preparation of the financial statements in accordance with Canadian generally
accepted accounting principles (Canadian GAAP) requires management to make
estimates and assumptions that affect reported amounts and presentation of
assets, liabilities, revenues, expenses and disclosures of contingencies and
commitments. Such estimates primarily relate to unsettled transactions and
events at the balance sheet date which are based on information available to
management at each financial statement date. Actual results could differ from
those estimated.
 
 The
estimate of the percentage of completion of various projects at the financial
statement date affects PP&E additions and the related accrued liability.
Various estimates are required in consideration of impairment of capitalized
costs. Consideration of impairment includes estimates relating to future cash
flows, regulatory approval, and commodity prices.
 
 For
petroleum and natural gas properties, OPTI assesses impairment using management
estimates of total proved oil and gas reserves, commodity prices and capital and
operating costs required to develop those reserves. By their nature, these
estimates and the related future net cash flows are subject to measurement
uncertainty, and the impact of differences between actual and estimated amounts
on the financial statements of future periods could be material. Our reserve
estimates, which have been estimated by independent engineering firms, are
subject to change as additional information becomes available or if different
assumptions are used.
 
 The
estimate related to asset retirement obligations requires estimates of the
amount and timing of future abandonment liabilities, inflation, and interest
rates. The recognition of amounts in relation to stock-based compensation
requires estimates related to valuation of stock options at the time of
issuance.  Future taxes require estimates as to the realization of
future tax assets and the timing of reversal of tax assets and liabilities. The
fair value of the commodity contracts and foreign exchange hedging instruments
are calculated using valuation models that require estimates as to future market
prices.
 
 By
their nature, these estimates are subject to measurement uncertainty and the
effect of changes in such estimates on the financial statements for current and
future periods could be significant.
 
 j)
              Interest
      reserve account
 Cash
is considered to be restricted when its availability is limited to a specified
purpose.  At December 31, 2007, OPTI’s restricted cash balance was
connected with the Senior Secured Notes.  The loan agreements required
OPTI to maintain an account to fund anticipated interest payments through
December 2008.
 
 k)
              Capitalized
      foreign exchange hedging instruments gain or
  loss
 Prior
to the commencement of commercial operations, OPTI capitalizes to PP&E gains
or losses in relation to the fair market valuation of its foreign exchange
hedging instrumentswhich have not been
designated for hedge accounting.
 
 7
 
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
 2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
 l)
              New
      standards
 (i)Capital disclosures
 On
January 1, 2008, OPTI adopted the Canadian Institute of Chartered Accountants
(CICA) handbook section 1535 “Capital Disclosures.” Section 1535 requires the
disclosure of OPTI’s objectives, policies and processes for managing capital.
This includes qualitative information regarding OPTI’s objectives, policies and
processes for managing capital and quantitative data about what OPTI manages as
capital. These disclosures are based on information used internally by OPTI’s
management.  See note 10.
 
 (ii)Financial instruments
 On
January 1, 2008, OPTI adopted the CICA handbook section 3862 “Financial
Instruments - Disclosures,” and section 3863 “Financial Instruments -
Presentation.”  Sections 3862 and 3863 replace section 3861 “Financial
Instruments - Disclosure and Presentation” which revises financial instruments
disclosure requirements and leaves unchanged its presentation requirements.
These new sections place increased emphasis on disclosures about the nature and
extent of risks arising from financial instruments and how OPTI manages those
risks. See discussion in OPTI’s 2008 annual Management’s Discussion and Analysis
(“MD&A”) under the heading “Financial Instruments.”
 
 (iii)Future accounting changes
 a.
              The
      CICA issued a new accounting standard section 3064 “Goodwill and
      Intangible Assets” which is effective for OPTI on January 1,
      2009.  This standard replaces section 3062 “Goodwill and Other
      Intangible Assets” and section 3450 “Research and Development
      Costs.”  The new section establishes standards for the
      recognition, measurement, presentation and disclosure of goodwill and
      intangible assets.  The provisions relating to the definition
      and initial recognition of intangible assets are equivalent to the
      corresponding provisions of International Financial Reporting Standard IAS
      38, “Intangible Assets.”  Emerging Issues Committee (EIC)
      abstract 27 “Revenues and Expenditures During the Pre-Operating Period”
      will no longer apply once section 3064 is adopted.  Accounting
      Guideline (AcG) 11 “Enterprises in the Development Stage” is amended to
      delete references to deferred costs and to provide guidance on development
      costs as intangible assets under section
3064.
 
 In
accordance with OPTI’s existing accounting policies, OPTI has capitalized gains
and losses related to the translation of OPTI’s U.S. dollar debt, capitalized
operations, as well as unrealized gains and losses related to certain financial
derivatives associated with its long-term debt. As a result of the adoption of
this new accounting standard, these capitalized amounts will no longer meet the
criteria for capitalization. As such, OPTI will expense these items with
retroactive effect on January 1, 2009 with a corresponding adjustment to opening
deficit with restatement of comparative amounts as applicable.
 
 The
magnitude of these adjustments is expected to be approximately $92 million
before tax increase to retained deficit. This is comprised primarily of the
value of the foreign exchange hedging contracts at December 31, 2008 whose value
reflects the then current and future value of foreign exchange and interest
rates.
 
 b.
              On
      February 13, 2008 the CICA Accounting Standards Board announced that
      Canadian public reporting issuers will be required to report under
      International Financial Reporting Standards (IFRS) in 2011. Prior to the
      adoption date, certain MD&A disclosures are required, beginning for
      the fourth quarter of 2008. OPTI is currently evaluating the impact of
      these new standards.
 
 m)
              Adoption
      of new accounting policies
 On
January 1, 2007, OPTI adopted the Canadian Institute of Chartered Accountants
(CICA) handbook sections 1530 “Comprehensive Income,” section 3251 “Equity,”
section 3855 “Financial Instruments - Recognition and Measurement” and section
3865 “Hedges.” These standards result in changes in the accounting for financial
instruments and hedges as well as introduce comprehensive income as a separate
component of shareholders’ equity. As required, these standards have been
adopted prospectively and comparative amounts for the prior periods have not
been restated.
   8
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)


2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
 (i)Comprehensive income
 Comprehensive
income is comprised of net earnings or loss and other comprehensive income
(OCI). OCI represents the change in equity for a period that arises from
unrealized gain and losses on available-for-sale securities and changes in the
fair market value of derivative instruments designated as cash flow hedges. OPTI
does not currently have any transactions that give rise to OCI, therefore OPTI’s
net loss and comprehensive loss for the years ended December 31, 2007 and 2008
are the same amount.
 
 (ii)Equity
 This
section establishes the standards for presentation of equity and changes in
equity during the period. The section requires separate presentation of changes
in equity for the period arising from net income, OCI, contributed surplus,
retained earnings, share capital and reserves. Accumulated OCI is included in
the balance sheet as a separate component of shareholders’ equity.
 
 (iii)Financial instruments
 This
section establishes standards for the recognition and measurement of financial
instruments, which is comprised of financial assets, financial liabilities,
derivatives and non-financial derivatives.
 
 A
financial asset is cash or a contractual right to receive cash or another
financial asset, including equity, from another party. A financial liability is
the contractual obligation to deliver cash or another financial asset to another
party.
 
 A
derivative is a financial instrument whose value changes in response to a
specified variable, requires little or no net investment and is settled at a
future date. An embedded derivative is a derivative that is a part of a
non-derivative contract and not directly related to that contract. Under this
standard, embedded derivatives must be accounted for as a separate financial
instrument. A non-financial derivative is a contract that can be settled net in
cash or another financial instrument.
 
 Under
this standard, all financial instruments are initially recorded at fair-value
and are subsequently accounted for based on one of five classifications: held
for trading, held-to-maturity, other financial liabilities, loans and
receivables or available-for-sale. The classification of a financial instrument
depends on its characteristics and the purpose for which it was
acquired.
 
 A)
              Held
      for trading
 Held
for trading financial instruments are financial assets or financial liabilities
that are purchased with the intention of selling or repurchasing in the near
term. Any financial instrument can be designated as held for trading as long as
its fair value can be reliably measured. A derivative is classified as held for
trading unless designated as and considered an effective hedge. Held for trading
instruments are recorded at fair value with any subsequent gains or losses from
changes in the fair value included in earnings.
 
 OPTI’s
commodity contracts and foreign exchange hedging instruments are derivatives and
accounted for as held for trading financial instruments and are recorded at fair
value.
 
 B)
              Held-to-maturity
 Held-to-maturity
investments are non-derivative financial assets with fixed or determinable
payments and a fixed maturity that OPTI has the intent and ability to hold to
maturity. These financial assets are measured at amortized cost using the
effective interest method. Any gains or losses arising from the sale of a
held-to-maturity investment are included in earnings. All of OPTI’s cash
equivalents and the interest reserve account are designated as held-to-maturity
investments.
 
 The
fair values of cash equivalents, short-term investments and the interest reserve
account approximate their carrying value due to their short-term
nature.
 
 9
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
 2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
 C)
              Other
      financial liabilities
 Items
classified as other financial liabilities, excluding asset retirement
obligation, on OPTI’s financial statements are accounted for at amortized cost
using the effective interest method. Any gains or losses in the realization of
other financial liabilities are included in earnings.
 
 D)
              Receivables
 Items
classified as receivables in OPTI’s financial statements are accounted for at
amortized cost using the effective interest method. Any gains or losses on the
realization of receivables are included in earnings.
 
 The
fair value of accounts and other receivables and accounts payable and accrued
liabilities approximate their carrying values due to the short-term nature of
these instruments. All costs related to debt issuance are expensed as
incurred.
 
 E)
              Available-for-sale
 Available-for-sale
assets are those financial assets that are not classified as held for trading,
held-to-maturity or loans and receivables. Available-for-sale instruments are
recorded at fair value. Any gains or losses arising from the change in fair
value is recorded in OCI and upon the sale of the instrument or
other-than-temporary impairment, the cumulative gain or loss is included in
earnings.
 
 OPTI has not designated any financial
instruments as available-for-sale assets.
 
 Fair
values are based upon quoted market prices available from active markets or are
otherwise determined using a variety of valuation techniques and models using
quoted market prices.
 
 Effective
January 1, 2007, transaction costs relating to all financial instruments are
expensed as incurred. As a result, $38 million of deferred financing costs, net
of taxes of $11 million, have been charged to opening deficit.
 
 
 3.
              COMMODITY
      CONTRACTS
 OPTI
has deferred premium West Texas Intermediate put options that provide a US$80
per barrel strike price for 6,000 bbl/d through 2009. At December 31, 2008 these
instruments had an estimated value of $73 million. The cost of the put options
are paid as the contracts expire and have been included in accounts payable and
accrued liabilities. Additionally, OPTI has crude swaps at US$77 per barrel for
500 barrels a day through 2009, with an estimated value of $5 million at
December 31, 2008.
 
 
 4.
                PROPERTY,
      PLANT AND EQUIPMENT
 2008
                            
                            
                            2007Long
      Lake Project
                            
                            $
                            3,699,068
                            
                            
                            $
                            3,027,730Other
      oil sands activities
                            
                            
                            422,728
                            
                            
                            
                            294,319Corporate
      assets
                            
                            
                            3,555
                            
                            
                            
                            17,470Asset
      retirement cost
                            
                            
                            7,763
                            
                            
                            
                            7,454Capital
      lease
                            
                            
                            30,195
                            
                            
                            
                            29,6004,163,309
                            
                            
                            
                            3,376,573Accumulated
      amortization - corporate assets
                            
                            
                            (2,408
                            )
                            
                            
                            (2,665
                            )$
                            4,160,901
                            
                            
                            $
                            3,373,908
 
 
 
 
 10
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
 
 4.    
PROPERTY, PLANT AND EQUIPMENT (CONTINUED)
 During
the year ended December 31, 2008, OPTI capitalized $3 million (2007 - $5
million) of general and administrative expenses, $177 million (2007 - $130
million) of interest and $372 million of net foreign exchange losses (2007 -
$235 million gain).  With the exception of corporate assets, no depletion,
depreciation or amortization has been recorded as commercial operations have not
commenced. The cost of unproved property was $423 million (2007 - $289 million).
As a result of the asset sale noted in note 14, subsequent events, an impairment
loss before taxes of $392 million was recorded in 2008.
 
 For
the calculation of the December 31, 2008 ceiling test, the benchmark prices for
West Texas Intermediate in US$/barrel were as follows: 2009 - $60.00; 2010 -
$71.40; 2011 - $83.20; 2012 - $93.90; 2013 - $97.40; and thereafter annual
increases of 2 percent. See note 2a(ii) for discussion of impairment
policy.
 
 OPTI
is engaged in the development of oil sands projects. Since inception, OPTI has
been developing the Long Lake Project and proceeding with the development of
future phases. OPTI is considered to be in the development stage as the Upgrader
has not commenced operations.
 
 Years
      endedAmounts
      capitalized
                    
                    Inception
                      to
      2008
                    
                    
                    2008
                    
                    
                    2007Revenue
                    
                    $
                    296,555
                    
                    
                    $
                    286,931
                    
                    
                    $
                    -Operating
      costs
                    
                    
                    (498,563
                    )
                    
                    
                    (428,114
                    )
                    
                    
                    (36,995
                    )Standby
      charges on debt
                    
                    
                    (33,210
                    )
                    
                    
                    (1,603
                    )
                    
                    
                    (3,491
                    )Foreign
      exchange gain (loss)
                    
                    
                    (167,318
                    )
                    
                    
                    (372,625
                    )
                    
                    
                    235,164Foreign
      exchange hedging instruments gain (loss)
                    
                    
                    145,241
                    
                    
                    
                    207,049
                    
                    
                    
                    (56,982
                    )Interest
                    
                    
                    (368,179
                    )
                    
                    
                    (177,480
                    )
                    
                    
                    (130,109
                    )General
      and administrative costs
                    
                    
                    (22,751
                    )
                    
                    
                    (2,636
                    )
                    
                    
                    (4,538
                    )Future
      tax
                    
                    
                    (7,048
                    )
                    
                    
                    (25,047
                    )
                    
                    
                    13,109
 
 
 5.
              DEBT
      FACILITIES
 OPTI’s
debt consists of the following:
 2008
                              
                              
                              2007Senior
      secured notes (a)
                              
                              $
                              2,131,500
                              
                              
                              $
                              1,734,775$500
      million revolving credit facility (b)
                              
                              
                              486,500
                              
                              
                              
                              -Long-term
      debt
                              
                              
                              2,618,000
                              
                              
                              
                              1,734,775Short-term
      debt: $150 million revolving credit facility (c)
                              
                              
                              145,500
                              
                              
                              
                              -Total
      debt
                              
                              $
                              2,763,500
                              
                              
                              $
                              1,734,775
 
 a)
              Senior
      secured notes
 OPTI
has US$1,000 million senior secured notes which bear interest at a fixed 8.25
percent and mature on December 15, 2014. These notes are collateralized by a
second priority security interest on all OPTI’s existing and future property.
OPTI may redeem up to 35 percent of these notes prior to December 15, 2009 with
net proceeds from certain equity offerings. At any time prior to December 31,
2010, OPTI may redeem these notes at the principal amount, plus the applicable
premium and accrued interest and at any time after December 31, 2010 at
redemption prices between 104.13 percent and 100 percent of the principal
amount.
 
 OPTI
also has US$750 million senior secured notes. These notes bear interest at a
fixed 7.875 percent and mature December 15, 2014. The other terms and conditions
associated with these notes are substantially the same as the notes described
above.
 
 See
note 10 for discussion of the debt covenants.
 
 11
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
 5.    
DEBT FACILITIES (CONTINUED)
 b)
              $500
      million revolving credit facility
 OPTI
has a $500 million revolving credit facility due December 15, 2011. Amounts
drawn under this facility can take the form of prime rate based loans, bankers’
acceptances, LIBOR loans or letters of credit. The facility will bear interest
at the prime rate, bankers’ acceptance rate or at LIBOR plus a spread above the
reference rate between 1.0 percent and 2.5 percent per annum. This facility is
collateralized by a first priority security interest on all present and after
acquired property of OPTI. The revolving credit facility includes certain
conditions precedent to all borrowings which include a sufficient funding test
related to the Project.  At December 31, 2008, $486.5 million was
outstanding under this facility. Subsequent to December 31, 2008, the $500
million revolving credit facility was reduced to $350 million. See note 14,
Subsequent events.
 
 c)
              $150
      million revolving credit facility
 On
June 23, 2008, OPTI established a $150 million revolving credit facility due
June 22, 2009. Borrowings under this facility can take the form of prime rate
based loans, bankers’ acceptances, LIBOR loans or letters of credit. Borrowings
will bear interest at the prime rate, bankers’ acceptance rate or at LIBOR plus
a spread above the reference rate between 1.0 percent and 2.5 percent per annum.
This facility is collateralized by a first priority security interest on all
present and after acquired property of OPTI. This facility includes certain
conditions precedent to all borrowings which include a sufficient funding test
related to the Project. At December 31, 2008, $145.5 million was outstanding
under this facility.  Subsequent to December 31, 2008, this $150
million revolving credit facility was repaid and cancelled. See note 14,
Subsequent events.
 
 
 6.
              FUTURE
      INCOME TAXES
 The
provision for income taxes reflects an effective tax rate of 25 percent (2007 -
49 percent) which differs from the statutory tax rate of 29.5 percent (2007 -
32.1 percent).  The reasons for the difference are discussed
below.
 
 2008
                    
                    
                    2007Recovery
      based on book earnings
                    
                    $
                    (100,759
                    )
                    
                    $
                    (5,981
                    )Impact
      of future tax rate and timing changes
                    
                    
                    15,307
                    
                    
                    
                    (3,588
                    )Resource
      allowance
                    
                    
                    -
                    
                    
                    
                    -Stock-based
      compensation
                    
                    
                    559
                    
                    
                    
                    435Large
      corporation tax
                    
                    
                    -
                    
                    
                    
                    -Other
                    
                    
                    (132
                    )
                    
                    
                    -Future
      tax recovery
                    
                    $
                    (85,025
                    )
                    
                    $
                    (9,134
                    )
 
 Significant components of OPTI’s future
tax liabilities (assets) are as follows:
 2008
                            
                            
                            2007Book
      value in excess of tax value - capital assets
                            
                            $
                            265,952
                            
                            
                            $
                            74,197Book
      value in excess of tax value - long-term debt
                            
                            
                            (23,663
                            )
                            
                            
                            25,928Asset
      retirement obligation
                            
                            
                            (1,984
                            )
                            
                            
                            (1,767
                            )Benefit
      of share issuance costs
                            
                            
                            (9,198
                            )
                            
                            
                            (15,561
                            )Losses
      for income tax purposes
                            
                            
                            (278,233
                            )
                            
                            
                            (84,950
                            )Future tax asset
                            
                            
                            (47,126
                            )
                            
                            
                            (2,153
                            )Short-term future tax asset
                            
                            
                            (2,709
                            )
                            
                            
                            -Long-term future tax asset
                            
                            $
                            (44,417
                            )
                            
                            $
                            (2,153
                            )
 
 At
December 31, 2008, the expiry dates of losses for income tax purposes are $3
million in 2009, $10 million in 2010, $9 million in 2014, $16 million in 2015,
$117 million in 2026, $685 million in 2027, and $278 million in
2028.
   12
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
 7.
              OTHER LONG TERM
      LIABILITIES
 OPTI’s
other long term liabilities consists of the following:
 2008
                  
                  
                  2007Foreign
      exchange hedging instruments (a)
                  
                  $
                  -
                  
                  
                  $
                  59,607Asset
      retirement obligation (b)
                  
                  
                  7,937
                  
                  
                  
                  7,070$
                  7,937
                  
                  
                  $
                  66,677
 
 a)
              Foreign
      exchange hedging instruments
 In
2008, OPTI settled its existing foreign currency hedging instruments for a net
realized gain of $114 million. These instruments consisted of a US$200 million
foreign exchange forward contract and US$875 million of cross currency swaps.
OPTI’s new foreign exchange hedging instruments are in other long-term assets
and discussed in note 9c.
 
 b)
              Asset
      retirement obligation
 OPTI’s
obligations with respect to asset retirement relate to reclamation of sites and
facilities on which the Project operations are situated. The obligation is
recognized in the period in which the obligation is created based on the
estimated future reclamation cost using an average discount rate of 11.5 percent
and estimated inflation of 3 percent annually. The total undiscounted future
obligation is $151 million.
 
 CONTINUITY
      OF ASSET RETIREMENT OBLIGATIONPresent
      value of obligation at January 1, 2007
                            
                            $
                            5,832New
      obligations during the year
                            
                            
                            835Asset
      retirement costs incurred
                            
                            
                            (24
                            )Accretion
      expense
                            
                            
                            427Present
      value of obligation at December 31, 2007
                            
                            
                            7,070New
      obligations during the year
                            
                            
                            309Asset
      retirement costs incurred
                            
                            
                            (9
                            )Accretion
      expense
                            
                            
                            567Present
      value of obligation at December 31, 2008
                            
                            $
                            7,937
 
 OPTI
estimates its obligations related to drilling activities will be settled over
approximately the next 20 years and obligations relating to resource assets will
be settled in approximately 55 years. OPTI’s upgrading facilities related to the
Project have retirement obligations with indeterminate settlement dates and for
which present value cannot be reasonably determined because the asset currently
has an indeterminable useful life. An asset retirement obligation for these
assets will be recorded in the period in which the lives of the assets become
reasonably determinable.
 
 13
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
 8.
              SHAREHOLDERS’
      EQUITY
 a)     Authorized
 Unlimited
number of common shares and preferred shares without nominal or par
value.
 
 b)
              Issued
      and outstanding
 
 NUMBER
      OF SHARES
                                    (thousands)
                                  
                                  
                                  AMOUNTCommon
      shares - January 1, 2007
                                  
                                  
                                  172,684
                                  
                                  
                                  $
                                  1,447,679Issued
      for cash (c)
                                  
                                  
                                  18,535
                                  
                                  
                                  
                                  352,156Issued
      for cash - flow-through (c)
                                  
                                  
                                  2,430
                                  
                                  
                                  
                                  60,021Common
      share options exercised
                                  
                                  
                                  1,707
                                  
                                  
                                  
                                  18,343Share
      issue costs
                                  
                                  
                                  
                                  
                                  
                                  
                                  (16,768
                                  )Tax
      effect on flow-through shares and share issue costs
                                  
                                  
                                  
                                  
                                  
                                  
                                  (7,514
                                  )Common
      shares - December 31, 2007
                                  
                                  
                                  195,356
                                  
                                  
                                  
                                  1,853,917Common
      share options exercised
                                  
                                  
                                  357
                                  
                                  
                                  
                                  4,870Warrants
      exercised
                                  
                                  
                                  217
                                  
                                  
                                  
                                  3,750Share
      issue costs
                                  
                                  
                                  
                                  
                                  
                                  
                                  (71
                                  )Tax
      effect on flow-through shares and share issue costs
                                  
                                  
                                  
                                  
                                  
                                  
                                  (15,005
                                  )Common
      shares - December 31, 2008
                                  
                                  
                                  195,930
                                  
                                  
                                  $
                                  1,847,461Call
      obligations - December 31, 2007
                                  
                                  
                                  
                                  
                                  
                                  
                                  (16,664
                                  )Expiration
      of call obligations (e)
                                  
                                  
                                  
                                  
                                  
                                  
                                  16,664Call
      obligations - December 31, 2008
                                  
                                  
                                  
                                  
                                  
                                  
                                  -Total
      capital stock - December 31, 2008
                                  
                                  
                                  195,930
                                  
                                  
                                  $
                                  1,847,461
 
 c)     2007
equity issuance
 On
November 21, 2007 OPTI issued 18,534,500 common shares at a price of $19.00 per
common share and 2,430,000 flow-through common shares at a price of $24.70 per
common share for aggregate gross proceeds of $412 million.
 
 d)     Outstanding
warrants
 OPTI
had common share warrants outstanding that entitled the holders to purchase a
total of 5,991,000 common shares at a price of $14.75 each. These warrants
expired in November 2008.
 
 e)     Call
obligations
 On
June 30, 2008, $202 million of outstanding call obligations expired unexercised
by OPTI.  The call obligations consisted of unconditional and
irrevocable call options whereby OPTI, at its option, could have required a
subscription for either a convertible preferred share or a common share for the
face amount of the call obligation.  The exercise price per share of
the call obligations was $2.20 per share.  The amount of the expired
call obligations has been recorded as an adjustment to Deficit.
    14
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
   8.
SHAREHOLDERS’ EQUITY (CONTINUED)
 f)      Outstanding
stock options
 OPTI
may grant stock options to executives, certain employees, consultants, and
directors as determined by the Board of Directors.  The exercise price
of each option is determined by the Board based on the current market price of
OPTI’s common shares at the date of the grant.  Vesting rights are
determined at the discretion of the Board. Under OPTI’s plans, options vest at
the time of grant or over a five-year period. The maximum number of options that
are allowed to be issued under the stock option plan is approximately 15
million. Options outstanding expire at dates up to 2018.
 
 OPTIONS
      OUTSTANDING
                          
                          OPTIONS
                            (thousands)
                          
                          
                          EXERCISE
      PRICE
                            PER
      SHAREBalance
      January 1, 2007
                          
                          
                          8,136
                          
                          
                          $
                          11.69Granted
                          
                          
                          1,003
                          
                          
                          
                          19.58Forfeited
                          
                          
                          (224
                          )
                          
                          
                          15.77Exercised
                          
                          
                          (1,707
                          )
                          
                          
                          9.82Balance
      December 31, 2007
                          
                          
                          7,208
                          
                          
                          $
                          13.03Granted
                          
                          
                          761
                          
                          
                          
                          15.74Forfeited
                          
                          
                          (452
                          )
                          
                          
                          17.80Exercised
                          
                          
                          (357
                          )
                          
                          
                          10.76Balance
      December 31, 2008
                          
                          
                          7,160
                          
                          
                          $
                          13.14
 
 OPTIONS
      OUTSTANDING
                            
                            
                            EXERCISABLE
      OPTIONSEXERCISE
      PRICE RANGE
                            
                            THOUSANDS
      OF OPTIONS
                            
                            
                            REMAINING
      CONTRACTUAL LIFE (YEARS)
                            
                            
                            WEIGHTED
      AVERAGE EXERCISE PRICE
                            
                            
                            THOUSANDS
      OF OPTIONS
                            
                            
                            WEIGHTED
      AVERAGE EXERCISE PRICE$1.95
      to $4.99
                            
                            
                            281
                            
                            
                            
                            2.7
                            
                            
                            $
                            4.22
                            
                            
                            
                            260
                            
                            
                            $
                            4.32$5.00
      to $9.99
                            
                            
                            2,890
                            
                            
                            
                            1.7
                            
                            
                            
                            9.06
                            
                            
                            
                            2,834
                            
                            
                            
                            9.12$10.00
      to $14.99
                            
                            
                            1,153
                            
                            
                            
                            5.7
                            
                            
                            
                            10.97
                            
                            
                            
                            782
                            
                            
                            
                            10.95$15.00
      to $19.99
                            
                            
                            2,009
                            
                            
                            
                            8.5
                            
                            
                            
                            18.14
                            
                            
                            
                            465
                            
                            
                            
                            18.54$20.00
      to $23.50
                            
                            
                            827
                            
                            
                            
                            7.6
                            
                            
                            
                            21.27
                            
                            
                            
                            257
                            
                            
                            
                            21.23Balance
      December 31, 2008
                            
                            
                            7,160
                            
                            
                            
                            5.0
                            
                            
                            $
                            13.14
                            
                            
                            
                            4,598
                            
                            
                            $
                            10.79
  g)    Stock-based
compensation
 During
the year ended December 31, 2008, there were 760,500 (2007 - 1,002,500) common
share options granted which had a total fair value of $4 million (2007 - $7
million). The fair value was calculated at the date of each grant using the
following assumptions: a risk free interest rate of 3.5 percent (2007 - 4.0
percent), a term of ten years (2007 - ten years) and an average volatility of 45
percent (2007 - 36 percent). Stock-based compensation costs for the year ended
December 31, 2008 are $5 million (2007 - $4 million), of which $2 million is
included in general and administrative expenses (2007 - $1 million) and $3
million is included in PP&E (2007 - $3 million).
   15
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
  8.
SHAREHOLDERS’ EQUITY (CONTINUED)
 h)    Contributed
surplus
 The
following outlines changes in contributed surplus:
 
 Balance
      January 1, 2007
                          
                          
                          9,357Capitalized
      stock-based compensation
                          
                          
                          2,732Expensed
      stock-based compensation
                          
                          
                          1,356Stock
      options exercised
                          
                          
                          (1,548
                          )Balance
      December 31, 2007
                          
                          $
                          11,897Capitalized
      stock-based compensation
                          
                          
                          3,181Expensed
      stock-based compensation
                          
                          
                          1,895Reclassified
      expired warrants
                          
                          
                          15,137Stock
      options exercised
                          
                          
                          (1,030
                          )Balance
      December 31, 2008
                          
                          $
                          31,080
 
 
 9.
              FINANCIAL
      INSTRUMENTS AND RISK MANAGEMENT
 a)
              Fair
      values
 OPTI’s
      financial instruments include cash equivalents, interest reserve account,
      accounts receivable and accounts payable and accrued liabilities. Due to
      the short-term nature of the instruments, the carrying values approximate
      the fair values. The commodity contracts, cross currency interest rate
      swaps and foreign exchange contracts are considered to be held-for-trading
      and are recorded at fair value. OPTI’s senior secured notes and the
      revolving credit facilities are recorded at cost. At December 31, 2008,
      the estimated fair value of the notes is US$934 million (CAD$1,137
      million) and the carrying value of the revolving credit facilities
      approximates their fair value due to their variable rate, first priority
      security position and short-term duration of instruments outstanding under
      the facilities.
 
 b)
              Risk
      management
 OPTI
      provides a risk management discussion as required by the CICA handbook
      section 3862 “Financial Instruments - Disclosures” on its exposure to and
      management of credit risk, liquidity risk and market risk in the 2008
      annual MD&A under the heading “Financial
  Instruments”.
 
 c)
              Foreign
      exchange hedging instruments
 At
      December 31, 2008, OPTI has foreign exchange forward contracts to provide
      for a fixed Canadian dollar (CAD) payment of $1,028 million in exchange
      for receipt of US$875 million on April 16, 2010 at a rate of approximately
      $1.17 Canadian dollars per U.S. dollar. Prior to the commencement of
      commercial operations, any gains or losses based on mark to market of the
      contract are capitalized to property, plant and
  equipment.
 
 d)
              Commodity
      contracts
 During
      2008, OPTI purchased put options that provide a price floor for a portion
      of its anticipated 2009 production.  See note
  3.
 
 
 10.
              CAPITAL
      MANAGEMENT
 OPTI’s objectives when managing its capital
are:
 •
              to
      manage capital in a manner that will maintain compliance with its
      financial covenants;
 •
              to
      manage a strong capital base so as to maintain investor, creditor and
      market confidence and to sustain future development of the
      business;
 •
              to
      maintain an appropriate balance between debt and equity sources of
      financing; and
 •
              to
      maintain sufficient undrawn credit capacity to provide
      liquidity.
   16
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
   10.
CAPITAL MANAGEMENT (CONTINUED)
 OPTI
defines its capital as follows:
 •
              capital
      stock; and
 •
              debt,
      including long and short-term
portions.
 
 As
OPTI does not have commercial operations, virtually all of our capital to date
has resulted from the issuance of debt and equity.  To date, OPTI has
been funded with both long-term debt and equity. A description of debt and
related changes in the period is described in note 5. Equity capital for OPTI is
described in note 8. We expect to generate positive operating cash flows to
support funding for interest costs and future expenditures once bitumen
production rises and the Upgrader is operating stably. The sale of a portion of
the Long Lake Project in January 2009 is expected to provide an additional
financing for 2009.
 
 OPTI
is a public company and has established access in past transactions to both
public and private debt and equity markets. OPTI anticipates continued long-term
access to both the debt and equity markets to fund future growth of the
business. In the short term, there may be times where access to debt and equity
markets is restricted or unavailable.
 
 All
of OPTI’s debt facilities set certain limitations on its capital structure
primarily through financial covenants. Measurement of the ratios for this
purpose is defined in the relevant credit agreement. OPTI is presently in
compliance with these financial maintenance covenants:
 
 Financial
      Ratio
                      Covenant(1)
                      Calculated
      ratio at December 31,2008
                      2007Debt
      to Capitalization (2)
                      Maximum
      65%
                      64%
                      50%First
      Lien to EBITDA (3)
                      Minimum
      3.5:1
                      N/A(4)
                      N/A(4)
 
 (1)
Covenants noted are as of December 31, 2008. On January 27, 2009, the facilities
were renegotiated and resulted in adjustments to the covenants. See note
14.
 (2)
"Debt to Capitalization” means, as at any date of determination, the ratio of
Total Consolidated Debt to Total Capitalization (net of the effect of any
currency Hedge Agreements relating to any Debt included therein). "Total
Capitalization" means, as at any date of determination, the aggregate of Total
Consolidated Debt, and Shareholders' Equity on such date.
 (3)
EBITDA (defined here as total revenue less direct costs and selling and
administrative costs) is not a recognized measure under GAAP, does not have a
standardized meaning prescribed by GAAP and therefore may not be comparable to
similar measures presented by other issuers. First Lien for the purposes of this
ratio includes the debt outstanding under the revolving credit
facilities.
 (4)
Under the amended revolving credit facility, the first time this covenant is
applicable is the third quarter of 2009, previously it was to be assessed for
the first quarter of 2009.
 
 With
respect to our senior secured notes, the covenants are in place primarily to
govern the total amount of debt that OPTI may incur at any time. This limit is
most affected by the present value of our total proved reserves using forecast
prices discounted at 10 percent. We have sufficient capacity under this test to
incur additional debt beyond our existing $350 million revolving credit
facility. Other leverage factors, such as debt to capitalization, interest
coverage ratios and total debt to EBITDA are expected to be more constraining of
future than this limitation. Under certain payment related defaults under our
revolving credit facility, we may be required to offer to repay our senior
secured notes.
 
 OPTI
sets internal targets for its financial ratios that are similar to the
requirements in the debt agreements.  These internal targets support
evaluation of the timing and amount of new debt and equity that balance creation
of value for stakeholders with the management of risks associated with debt.
Capital funding plans and targets are set annually based on expected growth
programs and forecasted financial results for the business.
 
 17
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
  10. 
CAPITAL MANAGEMENT (CONTINUED)
 In
management’s opinion, OPTI has met its objectives as outlined and has available
borrowing capacity under its debt facilities. Ongoing access to its revolving
credit facility requires that production levels for the project continue to ramp
up so that the company can meet its financial ratios described
above.
 
 11.
              COMMITMENTS
 a)
              Project
      commitments
 OPTI
has commitments in connection with contracts and purchase orders of $22 million
at December 31, 2008.   Commitment amounts are measured within contracts
and purchase orders through letters of intent, scheduled work releases and
forecast expenditures for labor and equipment utilization. These commitments
will be realized in incurred expenditures over time as certain milestones are
met, work is completed, or both.
 
 b)
              Lease
      obligations and other commitments
 OPTI
has an agreement with Enbridge Pipelines (Athabasca) Inc. that provides for
the storage, measurement and transportation of crude oil and other liquids
between the Athabasca main line and the Long Lake site. This agreement is
considered to be a capital lease for accounting purposes. This agreement has a
primary term of 25 years and an option for renewal of five additional years.
Capital lease payments on this agreement for the next five years and thereafter
are as follows:
 
 2009
                              
                              $
                              4,6462010
                              
                              
                              4,6462011
                              
                              
                              4,6472012
                              
                              
                              4,3152013
                              
                              
                              4,149Thereafter
                              
                              
                              79,517Total
      including interest
                              
                              
                              101,920Less
      imputed interest
                              
                              
                              (71,725
                              )Capital
      lease obligation
                              
                              $
                              30,195
 
 The
above table is based on OPTI’s 50 percent working interest in the Long Lake
Project as of December 31, 2008. Capital lease obligation as at January 27, 2009
was $21.1 million based on a 35 percent working interest. See note
14.
 
 OPTI
has an agreement with Enbridge Pipelines (Athabasca) Inc. for transportation of
oil products from Long Lake to Hardisty.  The initial term of this
agreement extends to 2012. OPTI also has an agreement with Pembina Oil Sands
Pipeline L.P. for a pipeline which transports synthetic crude oil, for use as a
diluent, available to the Long Lake site. This agreement has an initial term of
25 years. These two pipeline agreements are considered to be operating leases
for accounting purposes. During the fourth quarter, OPTI entered into a long
term traffic guarantee agreement with Canadian National Railway Company (CN)
under which traffic is moved to and from the Project site by rail and CN invests
in upgrades to the Athabasca Northern Railway rail line. The rail line will
move, amongst other commodities, sulphur, catalysts, and construction materials
to and from the Project site for periods up to 2032. Prior to the commencement
of commercial operations, OPTI capitalizes operating lease
payments.
 
 18
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
  11.
COMMITMENTS (CONTINUED)
 Operating
lease payments on these agreements for the next five years and thereafter are as
follows:
 
 2009
                          
                          
                          13,4182010
                          
                          
                          14,2792011
                          
                          
                          13,7252012
                          
                          
                          14,1772013
                          
                          
                          14,414Thereafter
                          
                          
                          44,728Total
                          
                          
                          114,741
 
 The
above table is based on OPTI’s 50 percent working interest in the Long Lake
Project. Actual commitments are $80 million based on a 35 percent working
interest in the Long Lake Project. See note 14.
 
 
 12.
              COMPARATIVE
      FIGURES
 Certain
of the comparative figures have been reclassified to conform to the presentation
adopted in the current period.
 
 
 13.
              SUPPLEMENTAL
      INFORMATION TO STATEMENT OF CASH
FLOW
 
 2008
                      
                      
                      2007Cash
      taxes paid
                      
                      $
                      -
                      
                      
                      $
                      -Cash
      interest received
                      
                      
                      5,909
                      
                      
                      
                      23,281Cash
      interest paid
                      
                      
                      173,511
                      
                      
                      
                      142,049Non-cash
      changes to property, plant and equipment
                      
                      
                      (73,734
                      )
                      
                      
                      (206,994
                      )Non-cash
      changes to capital stock
                      
                      
                      (13,246
                      )
                      
                      
                      (5,966
                      )
 
 2008
                          
                          
                          2007Change
      in non-cash working capitalAccounts
      and other receivables
                          
                          $
                          (10,224
                          )
                          
                          $
                          (6,014
                          )Accounts
      payable and accrued liabilities
                          
                          
                          (7,328
                          )
                          
                          
                          36,554Net
      change in non-cash working capital
                          
                          $
                          (17,552
                          )
                          
                          $
                          30,540Operating
      activities
                          
                          $
                          1,157
                          
                          
                          $
                          4,496Financing
      activities
                          
                          
                          13,241
                          
                          
                          
                          (4,793
                          )Investing
      activities
                          
                          
                          (31,950
                          )
                          
                          
                          30,837Net
      change in non-cash working capital
                          
                          $
                          (17,552
                          )
                          
                          $
                          30,540
 
 
 14.
              SUBSEQUENT
      EVENTS
 On
January 27, 2009, OPTI completed a sale of a 15 percent working interest in its
joint venture assets to Nexen Inc. (Nexen) for $735
million.  Effective January 1, 2009, OPTI has a remaining 35 percent
working interest in all the joint venture assets, including Phase 1 of the Long
Lake Project, all future phase reserves and resources, and future phases of
development.  As part of the sale, Nexen retained $85 million of the
proceeds to pre-fund OPTI’s share of 2009 joint venture capital requirements.
 
 To
consider impairment as of December 31, 2008, assets were grouped to depreciable
assets, resource assets and unproved properties based on the nature of the asset
and an assessment of their depreciation basis. Each asset type was assessed
individually for impairment.
 
 19
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
 14.
SUBSEQUENT EVENTS (CONTINUED)
 We
allocated the sales proceeds to each asset type based on an estimate of fair
value. The sales proceeds allocated to depreciable assets were lower than the
book value of the asset, as a result a loss before taxes of $392 million was
recorded in 2008. The sales proceeds allocated to resource assets did not alter
the depletion rate by greater than 20 percent and as a result no gain or loss
was recorded. The sales proceeds will be recorded as a reduction to book value
as of completion of the sale in 2009. The sales proceeds for unproved properties
and resource assets will be recorded as a reduction to book value as of
completion of the sale in 2009. The remaining assets were subject to a ceiling
test and cost recovery test which concluded no further impairment
existed.
 
 Additionally,
as a result of the asset sale, the revolving debt facilities were amended on
January 27, 2009. Significant changes include:
 •
              $150
      million revolving credit facility was repaid and
  cancelled;
 •
              $500
      million revolving credit facility was reduced to $350 million, $400
      million was repaid through February 25, 2009 and applicable interest rates
      were increased by approximately 2 to 4 percent depending on our debt
      rating;
 •
              First
      lien to EBITDA covenant commences in the third quarter of 2009 with a
      maximum ratio 2.5:1 as defined in Note 10 (previously the first quarter of
      2009 and a ratio of 3.5:1);
 •
              Debt
      to Capitalization ratio was  increased to 70 percent from 65
      percent as defined in Note 10; and
 •
              The
      Canadian measurement of our U.S. dollar denominated debt was changed from
      a period end exchange rate to the average rate for the preceding quarter
      for debt covenant calculation
purposes.
 
 
 15.
              RECONCILIATION
      TO US GAAP
 The
financial statements of OPTI have been prepared in accordance with generally
accepted accounting principles (GAAP) in Canada. With respect to OPTI, these
principles conform in all material respects to those in the United States for
items of measurement except for the following:
  
  STATEMENT
      OF LOSS RECONCILIATION (CAD $000)
                    
                    Year-ended
      December 312008
                    
                    
                    2007Net
      loss in accordance with CDN GAAP
                    
                    $
                    (256,532
                    )
                    
                    $
                    (9,486
                    )Revenue
      capitalized (a)
                    
                    
                    286,931
                    
                    
                    Pre-operating
      expenses capitalized (a)
                    
                    
                    (388,118
                    )
                    
                    
                    (36,995
                    )Depletion
      expense (a)
                    
                    
                    (11,875
                    )
                    
                    Standby
      charges capitalized (b)
                    
                    
                    (1,603
                    )
                    
                    
                    (3,491
                    )Foreign
      exchange gain (loss) capitalized (b)
                    
                    
                    (372,625
                    )
                    
                    
                    235,164Foreign
      currency hedging instruments capitalized (b)
                    
                    
                    207,049
                    
                    
                    
                    (56,982
                    )Reduction
      (increase) in future tax (a,b,d)
                    
                    
                    16,002
                    
                    
                    
                    (9,426
                    )Flow-through
      share premium (c)
                    
                    
                    13,778
                    
                    
                    
                    8,959Tax
      effect of flow-through shares (c)
                    
                    
                    (15,005
                    )
                    
                    
                    (11,706
                    )Deferred
      financing charges expensed (d)
                    
                    
                    893
                    
                    
                    
                    11,927Deferred
      financing amortization (d)
                    
                    
                    (7,481
                    )
                    
                    
                    (6,144
                    )Asset
      impairment under Canadian GAAP (e)
                    
                    
                    391,686
                    
                    
                    Asset
      impairment under US GAAP (e)
                    
                    
                    (354,274
                    )
                    
                    Net
      earnings (loss) in accordance with US GAAP
                    
                    $
                    (491,174
                    )
                    
                    $
                    121,820Earnings
      (loss) per share, basic and diluted
                    
                    $
                    (2.51
                    )
                    
                    $
                    0.69
  
 20
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
   15. 
RECONCILATION TO US GAAP (CONTINUED)
 
  BALANCE
      SHEET RECONCILIATION
                      
                      AT
      DECEMBER 31, 2008
                      
                      
                      AT
      DECEMBER 31, 2007(CAD
      $000)
                      
                      CDN
      GAAP
                      
                      
                      US
      GAAP
                      
                      
                      CDN
      GAAP
                      
                      
                      US
      GAAPAssetsProperty,
      plant and equipment (a,b)
                      
                      $
                      4,160,901
                      
                      
                      $
                      3,973,965
                      
                      
                      $
                      3,373,908
                      
                      
                      $
                      3,438,084Accumulated
      depletion expense (a)
                      
                      
                      -
                      
                      
                      
                      (15,358
                      )
                      
                      
                      -
                      
                      
                      
                      (3,483
                      )Deferred
      financing charges (d)
                      
                      
                      -
                      
                      
                      
                      39,362
                      
                      
                      
                      -
                      
                      
                      
                      44,211LiabilitiesLiability
      relating to flow-through share premium (c)
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      -
                      
                      
                      
                      13,778Future
      income tax liability (asset) (a,b,d)
                      
                      
                      (47,126
                      )
                      
                      
                      (67,032
                      )
                      
                      
                      (2,153
                      )
                      
                      
                      4,259Shareholders’
      equityCapital
      stock (c)
                      
                      
                      1,847,461
                      
                      
                      
                      1,902,532
                      
                      
                      
                      1,837,253
                      
                      
                      
                      1,877,319Deficit
                      
                      
                      (322,419
                      )
                      
                      
                      (512,409
                      )
                      
                      
                      (49,223
                      )
                      
                      
                      (4,570
                      )Total
      Shareholders’ equity
                      
                      
                      1,556,122
                      
                      
                      
                      1,421,203
                      
                      
                      
                      1,815,613
                      
                      
                      
                      1,900,332
  
  a)
              Under
      Canadian GAAP, OPTI’s resource activities are considered to be in the
      pre-operating stage and are therefore capitalized under full cost
      accounting guidelines. There is no comparable standard for US GAAP which
      allows capitalization of pre-operating activities. These operations would
      be recorded as revenue and operating costs with a depletion provision
      calculated on a unit of production basis. The resulting decrease in the
      book value of PP&E reduces the related future tax
      liability.
 
 b)
              Under
      Canadian GAAP during the pre-operating period, standby fees associated
      with borrowing facilities, foreign exchange gains or losses, unrealized
      gains or losses on the interest rate swap and unrealized gains or losses
      associated with the foreign currency hedging instruments associated with
      borrowing facilities and the related future tax impact can be capitalized.
      Under US GAAP, during the pre-operating period these costs would be
      expensed as incurred and any gains or losses on derivative instruments not
      designated as a hedging instrument are recognized into
      earnings.
 
 c)
              Under
      Canadian GAAP, the proceeds from the issuance of flow-through shares are
      recorded in equity at their face value. Under US GAAP, the proceeds must
      be allocated between the sale of the shares and the sale of the tax
      benefit. A liability is created for the difference between the market
      price of the existing shares and the price the investor paid for the
      flow-through shares.  In November 2007, OPTI issued 2,430,000
      flow-through common shares at a price of $24.70 per share for gross
      proceeds of $60 million which has resulted in a $14 million liability.
      When the tax benefits are renounced to shareholders, the difference
      between this liability and the value of the tax basis given up is recorded
      as tax expense. Under Canadian GAAP the value of the tax basis given up
      reduces the value of the flow-through shares issued. During March 2008,
      OPTI fully renounced the tax deductions to investors in relation to the
      flow-through shares issued in 2007 and recorded the related entries to
      future tax.
 
 d)
              On
      January 1, 2007, OPTI adopted to Canadian Institute of Chartered
      Accountants section 3855 “Financial Instruments - Recognition and
      Measurement.” As a result of the adoption, all previously recorded
      deferred financing charges, net of future tax, are recorded as an
      adjustment to opening deficit. Under this new section, all transactions
      costs relating to financial instruments are to be expensed as incurred.
      Under US GAAP, debt transactions costs are deferred and amortized over the
      life of the associated debt.
 
 e)
              OPTI
      recognized an impairment at December 31, 2008 related to the pending sale
      of assets under Canadian GAAP. The book value of assets sold under US GAAP
      is lower based on the capitalized pre-operating costs discussed in (d)
      above and results in a lower impairment. As such, the Canadian GAAP loss
      was reversed out of net income and the US GAAP loss was
    added.
   21
 OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
   15.
RECONCILATION TO US GAAP (CONTINUED)
 f)
              The
      statement of cash flows are prepared in accordance with Canadian GAAP and
      conform in all material respects to US GAAP except that Canadian GAAP
      allows for the presentation of operating cash flow before changes in
      non-cash working capital in the statement of cash flows. This total cannot
      be presented under US GAAP.
 
 g)
              Under
      Canadian full cost accounting rules, impairment is recognized if the
      carrying amount of the PP&E exceeds the sum of the undiscounted cash
      flows expected to result from proved reserves using estimated future
      prices and costs (the “ceiling test”). Under the full cost method of
      accounting as set forth by the US Securities and Exchange Commission, the
      ceiling test differs from Canadian GAAP in that future net revenues from
      proved reserves are based on prices and costs as at the balance sheet date
      (“constant dollar pricing”) and are discounted at 10 percent. Management
      has reviewed the valuation of the Long Lake Project and other oil sands
      properties and estimates that the fair market value of these properties
      exceeds their carrying amount.
 
 h)
              The
      components of accounts payable and accrued liabilities are as
      follows:
 
 December 31, 2008
                      
                      
                      December 31, 2007CAD
      $000’sAccounts
      payable
                      
                      $
                      19,686
                      
                      
                      $
                      14,242Accrued
      liabilities
                      
                      
                      180,221
                      
                      
                      
                      176,481Total
                      
                      $
                      199,907
                      
                      
                      $
                      190,723
 
 i)
              For
      US GAAP purposes, OPTI is considered to be a development stage company and
      the financial statements should be labeled as such. In the statement of
      shareholders’ equity, OPTI’s deficit should be labeled as deficit
      accumulated during the development stage. Additional disclosure required
      for a development stage company are as
follows:
 
 December
      31, 2008
                      
                      
                      December
      31, 2007CAD
      $000’sProperty,
      plant and equipment under Canadian GAAP
                      
                      $
                      4,160,901
                      
                      
                      $
                      3,373,908Revenue
      capitalized (a)
                      
                      
                      296,555
                      
                      
                      
                      9,624Pre-operating
      expenses capitalized (a)
                      
                      
                      (458,568
                      )
                      
                      
                      (70,449
                      )Standby
      charges capitalized (b)
                      
                      
                      (33,210
                      )
                      
                      
                      (31,607
                      )Foreign
      exchange gain (loss) capitalized (b)
                      
                      
                      (167,318
                      )
                      
                      
                      205,307Foreign
      exchange hedging instruments capitalized (b)
                      
                      
                      145,241
                      
                      
                      
                      (61,808
                      )Impairment
      difference (e)
                      
                      
                      37,412
                      
                      
                      
                      -Capitalized
      future tax (b)
                      
                      
                      (7,048
                      )
                      
                      
                      13,109Property,
      plant, and equipment under US GAAP
                      
                      $
                      3,973,965
                      
                      
                      $
                      3,438,084
 
 J) Recent
Accounting Pronouncements
  The
Company has assessed new and revised accounting pronouncements that have been
issued that are not yet effective:
  In
May 2008, the FASB issued Statement of Financial Accounting Standards
No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” This
standard became effective November 15, 2008 following the SEC’s approval of
the Public Company Accounting Oversight Board Auditing amendments to AU Section,
411 “The Meaning of Present Fairly in Conformity with Generally Accepted
Accounting Principles.” The statement is intended to improve financial reporting
by identifying a consistent hierarchy for selecting accounting principles to be
used in preparing financial statements that are presented in conformity with
U.S. GAAP. The adoption of this standard did not have a material impact on
OPTI’s Financial Statements.
 
 22
 
  OPTI
CANADA INC.
 Notes
to the Financial Statements
 (Tabular
amounts are in thousands of Canadian dollars, unless otherwise
stated)
   As
of January 1, 2009, SFAS 141(R), “Business Combinations,” replaces SFAS
141. This revised standard requires assets and liabilities acquired in a
business combination, contingent consideration, and certain acquired
contingencies to be measured at their fair values as of the date of acquisition.
In addition, acquisition-related and restructuring costs are to be recognized
separately from the business combination. This new standard will only impact
acquisitions occurring on or after January 1, 2009
  As
of January 1, 2009, SFAS No. 160, “Noncontrolling Interests in
Financial Statements, an Amendment of ARB No. 51” will come into effect.
This standard requires a noncontrolling interest in a subsidiary to be
classified as a separate component of equity. The standard also changes the way
the U.S. GAAP Statement of Earnings is presented by requiring net earnings to
include the amounts attributable to both the parent and the noncontrolling
interest and to disclose these respective amounts. The adoption of this standard
will not have any impact on OPTI’s Financial Statements.
 
 As
of December 31, 2009, OPTI will be required to prospectively adopt the new
reserves requirements that arise from the completion of the SEC’s project, Modernization of Oil and Gas
Reporting. The new rules include provisions that permit the use of
new technologies to establish proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserves volumes.
Additionally, oil and gas reserves will be reported using an average price based
upon the prior 12-month period rather than year-end prices. The new
rules will affect the reserve estimate used in the calculation of DD&A
and the ceiling test for U.S. GAAP purposes. The Company is assessing the impact
these new rules will have on its Financial Statements








23




ADDITIONAL
DISCLOSURE




Certifications
and Disclosure Regarding Controls and Procedures.




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




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




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




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




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






40 -
F2


Notices
Pursuant to Regulation BTR.







None.




Identification
of the Audit Committee.







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




Audit
Committee Financial Expert.




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




Code
of Ethics.




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




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




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




Principal
Accountant Fees and Services.







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




Pre-Approval
Policies and Procedures.







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






40-F3




Off-Balance
Sheet Arrangements.







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




Tabular
Disclosure of Contractual Obligations.







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




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




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




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




Notes:





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


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


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


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


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


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




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UNDERTAKING
AND CONSENT TO SERVICE OF PROCESS




A.           Undertaking.




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




B.
            Consent
      to Service of Process.




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




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




SIGNATURES




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




OPTI
Canada Inc.




By: ___________________________


Name:


Title:






40 -
F5